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"ifrs-full:ShorttermInvestmentsClassifiedAsCashEquivalents", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag861": { "value": "98000000", "decimals": -6, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalentsClassifiedAsPartOfDisposalGroupHeldForSale", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag870": { "value": "44000000", "decimals": -6, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalentsClassifiedAsPartOfDisposalGroupHeldForSale", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag926": { "value": "326000000", "decimals": -6, "dimensions": { "concept": "enel:CashAndCashEquivalentsClassifiedAsDiscontinuedOperations", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag874": { "value": "543000000", "decimals": -6, "dimensions": { "concept": "enel:CashAndCashEquivalentsClassifiedAsDiscontinuedOperations", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag11": { "value": "\n

\n
Basis of presentation
\n\n

\n\n

\n

\n

\n

\n
1. Form and content of the consolidated financial statements
\n
Enel SpA has its registered office in Viale Regina Margherita
\n
137, Rome, Italy, and since 1999 has been listed on the Milan
\n
stock exchange.
\n
There were no changes in the company name in 2022.
\n\n
Enel is an energy multinational and is one of the world\u2019s
\n
leading integrated operators in the electricity and gas in-
\n
dustries, with a special focus on Europe and Latin America.
\n

\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 comprise the financial state-
\n
ments of Enel SpA, its subsidiaries and Group holdings in
\n
associates and joint ventures, as well as the Group\u2019s share of
\n
the assets, liabilities, costs and revenue of joint operations
\n
(\u201cthe Group\u201d).
\n
A list of the subsidiaries, associates, joint operations and
\n
joint ventures included in the consolidation scope is at-
\n
tached.
\n\n
These consolidated financial statements were approved
\n
and authorized for publication by the Board of Directors on
\n
March 16, 2023.
\n

\n\n
These consolidated financial statements have been audited
\n
by KPMG SpA.
\n
Basis of presentation
\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 have been prepared in accor-
\n
dance with international accounting standards (Internation-
\n
al Accounting Standards - IAS and International Financial
\n
Reporting Standards - IFRS) issued by the International Ac-
\n
counting Standards Board (IASB), the interpretations of the
\n
IFRS Interpretations Committee (IFRSIC) and the Standing
\n
Interpretations Committee (SIC), recognized in the Europe-
\n
an Union pursuant to Regulation (EC) no. 1606/2002 and in
\n

\n\n
effect as of the close of the year. All of these standards and
\n
interpretations are hereinafter referred to as the \u201cIFRS-EU\u201d.
\n
The consolidated financial statements have also been pre-
\n
pared in conformity with measures issued in implementa-
\n
tion of Article 9, paragraph 3, of Legislative Decree 38 of
\n
February 28, 2005.
\n
The consolidated financial statements consist of the con-
\n
solidated income statement, the statement of consolidated
\n
comprehensive income, the statement of consolidated fi-
\n
nancial position, the statement of changes in consolidated
\n
equity and the consolidated statement of cash flows and
\n
the related notes.
\n
The assets and liabilities recognized in the statement of
\n
financial position are classified on a \u201ccurrent/non-current
\n
basis\u201d, with separate reporting of assets held for sale and
\n
liabilities included in disposal groups held for sale. Current
\n
assets, which include cash and cash equivalents, are assets
\n
that are intended to be realized, sold or consumed during
\n
the normal operating cycle of the Group; current liabilities
\n
are liabilities that are expected to be settled during the nor-
\n
mal operating cycle of the Group.
\n
The income statement classifies costs on the basis of their
\n
nature, with separate reporting of profit/(loss) from continu-
\n
ing operations and profit/(loss) from discontinued opera-
\n
tions attributable to owners of the Parent and to non-con-
\n
trolling interests.
\n\n
The consolidated cash flow statement is prepared using the
\n
indirect method, with separate reporting of any cash flows
\n
by operating, investing and financing activities associated
\n
with discontinued operations.
\n
Note that the items reported in the cash flow statement also
\n
include any impacts deriving from companies classified as
\n
discontinued operations. In particular, although the Group
\n
does not diverge from the provisions of IAS 7 in the classi-
\n
fication of items:
\n
\u2022 cash flows from operating activities report cash flows
\n
from core operations, interest on loans granted and ob-
\n
tained and dividends received from associates or joint
\n
ventures;
\n
\u2022 investing activities comprise investments in property, plant
\n
and equipment and intangible assets and disposals of such
\n
assets and contract assets related to service concession
\n
arrangements. They include, also, the effects of business
\n
combinations in which the Group acquires or loses control
\n
of companies, as well as other minor investments;
\n
\u2022 cash flows from financing activities include cash flows
\n
generated by liability management transactions and leas-
\n
es, dividends and interim dividends paid to owners of
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n\n
the Parent and non-controlling interests and the effects
\n
of transactions in non-controlling interests that do not
\n
change the status of control of the companies involved;
\n
\u2022 a separate item is used to report the impact of exchange
\n
rates on cash and cash equivalents and their impact on
\n
profit or loss is eliminated in full in order to neutralize the
\n
effect on cash flows from operating activities.
\n
For more information on cash flows as reported in the
\n
statement of cash flows, please see the note 46 \u201cCash
\n
flows\u201d.
\n

\n\n
The consolidated financial statements have been prepared
\n
on a going concern basis using the cost method, with the
\n
exception of items measured at fair value in accordance
\n
with IFRS, as explained in the measurement bases applied
\n
to each individual item, and of non-current assets and
\n
disposal groups classified as held for sale, which are mea-
\n
sured at the lower of their carrying amount and fair value
\n
less costs to sell.
\n
The consolidated financial statements are presented in
\n
euro, the functional currency of the Parent Enel SpA. All
\n
figures are shown in millions of euro unless stated other-
\n
wise.
\n
The consolidated income statement, the statement of fi-
\n
nancial position and the consolidated statement of cash
\n
flows report transactions with related parties, the defini-
\n
tion of which is given in note 2.2 \u201cSignificant accounting
\n
policies\u201d.
\n
The consolidated financial statements provide compara-
\n
tive information in respect of the previous year.
\n

\n\n

\n\n
2. Accounting policies
\n\n
2.1 Use of estimates and management
\n
judgment
\n
Preparing the consolidated financial statements under IF-
\n
RS-EU requires management to take decisions and make
\n
estimates and assumptions that may impact the carrying
\n
amount of revenue, costs, assets and liabilities and the
\n
related disclosures concerning the items involved as well
\n
as contingent assets and liabilities at the reporting date.
\n
The estimates and management\u2019s judgments are based
\n
on previous experience and other factors considered rea-
\n
sonable in the circumstances. They are formulated when
\n
the carrying amount of assets and liabilities is not easily
\n
determined from other sources. The actual results may
\n
therefore differ from these estimates. The estimates and
\n
assumptions are periodically revised and the effects of any
\n
changes are reflected through profit or loss if they only in-
\n
volve that period. If the revision involves both the current
\n
and future periods, the change is recognized in the period
\n
in which the revision is made and in the related future pe-
\n
riods.
\n
In order to enhance understanding of the consolidated
\n
financial statements, the following sections examine the
\n
main items affected by the use of estimates and the cases
\n
that reflect management judgments to a significant de-
\n
gree, underscoring the main assumptions used by man-
\n
agement in measuring these items in compliance with the
\n
IFRS-EU. The critical element of such valuations is the use
\n
of assumptions and professional judgments concerning
\n
issues that are by their very nature uncertain.
\n
Changes in the conditions underlying the assumptions
\n
and judgments could have a substantial impact on future
\n
results.
\n
The information included in the consolidated financial
\n
statements is selected on the basis of a materiality analysis
\n
carried out in accordance with the requirements of Prac-
\n
tice Statement 2 \u201cMaking Materiality Judgments\u201d, issued by
\n
the International Accounting Standards Board (IASB).
\n
With regard to the effects of climate change issues, the
\n
Group believes that climate change represents an implic-
\n
it element in the application of the methodologies and
\n
models used to perform estimates in the valuation and/or
\n
measurement of certain accounting items. Furthermore,
\n
the Group has also taken account of the impact of climate
\n
change in the significant judgments made by manage-
\n
ment. In this regard, the main items included in the consol-
\n
idated financial statements at December 31, 2022 affected
\n
by management\u2019s use of estimates and judgments refer
\n
to the impairment of non-financial assets and obligations
\n
connected with the energy transition, including those for
\n
decommissioning and site restoration of certain genera-
\n
tion plants. For further details on these items, see note 19
\n
\u201cProperty, plant and equipment\u201d, note 24 \u201cGoodwill\u201d, and
\n
note 40 \u201cProvisions for risks and charges\u201d.
\n
Use of estimates
\n
Revenue from contracts with customers
\n
Revenue from supply of electricity and gas to end users is
\n
recognized at the time the electricity or gas is delivered and
\n
includes, in addition to amounts invoiced on the basis of pe-
\n
riodic (and pertaining to the year) meter readings or on the
\n
volumes notified by distributors and transporters, an esti-
\n
mate of the electricity and gas delivered during the period
\n
but not yet invoiced that is equal to the difference between
\n
the amount of electricity and gas delivered to the distribu-
\n
tion network and that invoiced in the period, taking account
\n
of any network losses. Revenue between the date of the last
\n
meter reading and the year-end is based on estimates of
\n

\n\n

\n\n

\n\n
the daily consumption of individual customers, primarily de-
\n
termined on their historical information, adjusted to reflect
\n
the climate factors or other matters that may affect the es-
\n
timated consumption.
\n
For more details on such revenue, see note 11.a \u201cRevenue
\n
from sales and services\u201d.
\n
Impairment of non-financial assets
\n
When the carrying amount of property, plant and equip-
\n
ment, investment property, intangible assets, right-of-use
\n
assets, goodwill and investments in associates/joint ven-
\n
tures exceeds its recoverable amount, which is the higher
\n
of the fair value less costs to sell and the value in use, the
\n
assets are impaired.
\n
Such impairments are carried out in accordance with the
\n
provisions of IAS 36, as described in greater detail in note
\n
24 \u201cGoodwill\u201d.
\n
In order to determine the recoverable amount, the Group
\n
generally adopts the value in use criterion. Value in use is
\n
based on the estimated future cash flows generated by
\n
the asset, discounted to their present value using a pre-tax
\n
discount rate that reflects the current market assessment
\n
of the time value of money and of the specific risks of the
\n
asset.
\n
Future cash flows used to determine value in use are based
\n
on the most recent Business Plan, approved by the man-
\n
agement, containing forecasts for volumes, revenue, oper-
\n
ating costs and investments. These projections cover the
\n
next three years. For subsequent years, account is taken of:
\n
\u2022 assumptions concerning the long-term evolution of
\n
the main variables considered in the calculation of cash
\n
flows, as well as the average residual useful life of the
\n
assets or the duration of the concessions, based on the
\n
specific characteristics of the businesses;
\n
\u2022 a long-term growth rate equal to the long-term growth
\n
of electricity demand and/or inflation (depending on the
\n
country and business) that does not in any case exceed
\n
the average long-term growth rate of the market in-
\n
volved.
\n
The recoverable amount is sensitive to the estimates and
\n
assumptions used in the calculation of cash flows and the
\n
discount rates applied. Nevertheless, possible changes in
\n
the underlying assumptions on which the calculation of
\n
such amounts is based could generate different recover-
\n
able amounts. The analysis of each group of non-financial
\n
assets is unique and requires management to use esti-
\n
mates and assumptions considered prudent and reason-
\n
able in the specific circumstances.
\n
In line with its business model and in the context of the
\n
acceleration of the decarbonization of the generation mix
\n
and driving the energy transition process, the Group has
\n
also carefully assessed whether climate change issues
\n
have affected the reasonable and supportable assump-
\n
tion used to estimated expected cash flows. In this regard,
\n
where necessary, the Group has also taken account of the
\n
long-term impact of climate change, in particular by con-
\n
sidering in the estimation of the terminal value a long-term
\n
growth rate in line with the change in electricity demand
\n
determined using energy models for each country.
\n
Information on the main assumptions used to estimate
\n
the recoverable amount of assets with reference to the
\n
impacts relating to climate change, as well as information
\n
on changes in these assumptions, is provided in note 24
\n
\u201cGoodwill\u201d.
\n
Expected credit losses on financial assets
\n
At the end of each reporting period, the Group recognizes
\n
a loss allowance for expected credit losses on trade re-
\n
ceivables and other financial assets measured at amortized
\n
cost, debt instruments measured at fair value through oth-
\n
er comprehensive income, contract assets and all other
\n
assets in scope.
\n
Loss allowances for financial assets are based on assump-
\n
tions about risk of default and on the measurement of ex-
\n
pected credit losses. Management uses judgment in mak-
\n
ing these assumptions and selecting the inputs for the
\n
impairment calculation, based on the Group\u2019s past experi-
\n
ence, current market conditions as well as forward-looking
\n
estimates at the end of each reporting period.
\n
The expected credit loss (i.e., ECL) \u2013 determined consid-
\n
ering probability of default (PD), loss given default (LGD),
\n
and exposure at default (EAD) \u2013 is the difference between
\n
all contractual cash flows that are due in accordance with
\n
the contract and all cash flows that are expected to be re-
\n
ceived (including all shortfalls) discounted at the original
\n
effective interest rate (EIR).
\n
In particular, for trade receivables, contract assets and
\n
lease receivables, including those with a significant fi-
\n
nancial component, the Group applies the simplified ap-
\n
proach, determining expected credit losses over a period
\n
corresponding to the entire life of the asset, generally
\n
equal to 12 months.
\n
Based on the specific reference market and the regulatory
\n
context of the sector, as well as expectations of recovery
\n
after 90 days, for such assets, the Group mainly applies a
\n
default definition of 180 days past due to determine ex-
\n
pected credit losses, as this is considered an effective in-
\n
dication of a significant increase in credit risk. Accordingly,
\n
financial assets that are more than 90 days past due are
\n
generally not considered to be in default, except for some
\n
specific regulated markets.
\n
For trade receivables and contract assets the Group mainly
\n
applies a collective approach based on grouping trade re-
\n
ceivables and contract assets into specific clusters, taking
\n
into account the specific regulatory and business context.
\n
Only if the trade receivables are deemed to be individually
\n
significant by management and there is specific informa-
\n
tion about any significant increase in credit risk, does the
\n
Group apply an analytical approach.
\n

\n\n

\n\n

\n\n
In case of individual assessment, PD is mainly obtained
\n
from an external provider.
\n
Conversely, for collective assessment, trade receivables
\n
are grouped based on shared credit risk characteristics
\n
and past due information, considering a specific definition
\n
of default.
\n
Based on each business and local regulatory framework as
\n
well as differences in customer portfolios also in terms of
\n
risk, default rates and recovery expectations, specific clus-
\n
ters are defined.
\n
The contract assets are considered to have substantially
\n
the same risk characteristics as the trade receivables for
\n
the same types of contracts.
\n
In order to measure the ECL for trade receivables on a
\n
collective basis, as well as for contract assets, the Group
\n
considers the following assumptions related to ECL pa-
\n
rameters:
\n
\u2022 PD, assumed as to be the average default rate, is cal-
\n
culated on a cluster basis and taking into consideration
\n
minimum 24-month historical data;
\n
\u2022 LGD is function of the default bucket\u2019s recovery rates,
\n
discounted at the EIR; and
\n
\u2022 EAD is estimated as the carrying exposure at the report-
\n
ing date net of cash deposits, including invoices issued
\n
but not expired and invoices to be issued.
\n
Based on specific management evaluations, the for-
\n
ward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
possible future events and macroeconomic scenarios,
\n
which may affect the risk of the portfolio or the financial
\n
instrument.
\n
For additional details on the key assumptions and inputs
\n
used please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n
Depreciable amount of certain elements of Italian
\n
hydroelectric plants subsequent to enactment of Law
\n
134/2012
\n
Italian regulations governing large-scale hydroelectric
\n
concessions were significantly modified by the \u201cSimpli-
\n
fications Decree\u201d (Decree Law 135 of 2018 ratified with
\n
Law 12 of February 11, 2019). The regulations introduce a
\n
number of innovations which, if applied to existing con-
\n
cessions, would require a review of the useful lives of cer-
\n
tain investments in hydroelectric plants in order to reflect
\n
the possibility that, at the end of the concession, some
\n
assets could be transferred free of charge to the new
\n
concession holder. However, in estimating the useful lives
\n
of these plants, management, with the support of a legal
\n
opinion, considered the foreseeable outcome of the ap-
\n
peals promptly lodged by the Company \u2013 and others \u2013 and
\n
the related constitutionality issues, which have also been
\n
raised by industrial associations. Consequently, we believe
\n
that the legislation raises serious constitutionality issues
\n
that will be effectively recognized in the appropriate fora.
\n
Accordingly, management deemed it appropriate not to
\n
reflect the changes introduced by the regulations and
\n
therefore has continued to measure the useful lives of the
\n
plants as has been done in previous years under the pre-
\n
vious regulatory system, considering this to be the most
\n
realistic estimate.
\n
Law 134 of August 7, 2012 containing \u201curgent measures for
\n
growth\u201d (published in the Gazzetta Ufficiale of August 11,
\n
2012), introduced a sweeping overhaul of the rules gov-
\n
erning hydroelectric concessions. Among its various pro-
\n
visions, the law establishes that five years before the expi-
\n
ration of a major hydroelectric water diversion concession
\n
and in cases of lapse, relinquishment or revocation, where
\n
there is no prevailing public interest for a different use of
\n
the water, incompatible with its use for hydroelectric gen-
\n
eration, the competent public entity shall organize a pub-
\n
lic call for tenders for the award for consideration of the
\n
concession for a period ranging from 20 to a maximum of
\n
30 years.
\n
In order to ensure operational continuity, the law also gov-
\n
erns the methods of transferring ownership of the busi-
\n
ness unit necessary to operate the concession, including
\n
all legal relationships relating to the concession, from the
\n
outgoing concession holder to the new concession holder,
\n
in exchange for payment of a price to be determined in ne-
\n
gotiations between the departing concession holder and
\n
the grantor agency, taking due account of the following
\n
elements:
\n
\u2022 for intake and governing works, penstocks and outflow
\n
channels, which under the consolidated law governing
\n
waters and electrical plants are to be relinquished free of
\n
charge (Article 25 of Royal Decree 1775 of December 11,
\n
1933), the revalued cost less government capital grants,
\n
also revalued, received by the concession holder for the
\n
construction of such works, depreciated for ordinary
\n
wear and tear;
\n
\u2022 for other property, plant and equipment, the market val-
\n
ue, meaning replacement value, reduced by estimated
\n
depreciation for ordinary wear and tear.
\n
While acknowledging that the new regulations introduce
\n
important changes as to the transfer of ownership of the
\n
business unit with regard to the operation of the hydro-
\n
electric concession, the practical application of these
\n
principles faces difficulties, given the uncertainties that
\n
do not permit the formulation of a reliable estimate of the
\n
value that can be recovered at the end of existing conces-
\n
sions (residual value).
\n
Accordingly, management has decided it could not pro-
\n
duce a reasonable and reliable estimate of residual value.
\n
The fact that the legislation requires the new concession
\n
holder to make a payment to the departing concession
\n

\n\n

\n\n

\n\n

\n
holder prompted management to review the depreciation
\n
schedules for assets classified as to be relinquished free
\n
of charge prior to Law 134/2012 (until the year ended on
\n
December 31, 2011, given that the assets were to be relin-
\n
quished free of charge, the depreciation period was equal
\n
to the closest date between the term of the concession
\n
and the end of the useful life of the individual asset), calcu-
\n
lating depreciation no longer over the term of the conces-
\n
sion but, if longer, over the useful life of the individual as-
\n
sets. If additional information becomes available to enable
\n
the calculation of residual value, the carrying amounts of
\n
the assets involved will be adjusted prospectively.
\n
Determining the fair value of financial instruments
\n
The fair value of financial instruments is determined on the
\n
basis of prices directly observable in the market, where
\n
available, or, for unlisted financial instruments, using spe-
\n
cific valuation techniques (mainly based on present val-
\n
ue) that maximize the use of observable market inputs. In
\n
rare circumstances where this is not possible, the inputs
\n
are estimated by management taking due account of the
\n
characteristics of the instruments being measured.
\n
For more information on financial instruments measured
\n
at fair value, please see note 52 \u201cAssets and liabilities mea-
\n
sured at fair value\u201d.
\n
In accordance with IFRS 13, the Group includes a mea-
\n
surement of credit risk, both of the counterparty (Credit
\n
Valuation Adjustment or CVA) and its own (Debit Valua-
\n
tion Adjustment or DVA), in order to adjust the fair value
\n
of financial instruments for the corresponding amount of
\n
counterparty risk, using the method discussed in note 52
\n
\u201cAssets and liabilities measured at fair value\u201d.
\n
Changes in the assumptions made in estimating the input
\n
data could have an impact on the fair value recognized for
\n
those instruments, especially in current conditions where
\n
markets are volatile and the economic outlook is highly un-
\n
certain and subject to rapid change.
\n
Development expenditure
\n
In order to determine the recoverability of development
\n
expenditure, the recoverable amount is estimated mak-
\n
ing assumptions regarding any further cash outflow that is
\n
expected to be incurred before the asset is ready for use
\n
or sale, the discount rates to be applied and the expected
\n
period of benefits.
\n
Pensions and other post-employment benefits
\n
Some of the Group\u2019s employees participate in pension
\n
plans offering benefits based on their wage history and
\n
years of service. Certain employees are also eligible for
\n
other post-employment benefit schemes.
\n
The expenses and liabilities of such plans are calculated on
\n
the basis of estimates carried out by consulting actuaries,
\n
who use a combination of statistical and actuarial elements
\n
in their calculations, including statistical data on past years
\n
and forecasts of future costs. Other components of the
\n
estimation that are considered include mortality and re-
\n
tirement rates as well as assumptions concerning future
\n
developments in discount rates, the rate of wage increas-
\n
es, the inflation rate and trends in healthcare cost.
\n
These estimates can differ significantly from actual devel-
\n
opments owing to changes in economic and market con-
\n
ditions, increases or decreases in retirement rates and the
\n
lifespan of participants, as well as changes in the effective
\n
cost of healthcare.
\n
Such differences can have a substantial impact on the
\n
quantification of pension costs and other related expens-
\n
es.
\n
For more details on the main actuarial assumptions adopt-
\n
ed, please see note 39.
\n\n
Provisions for risks and charges
\n
For more details on provisions for risks and charges, please
\n
see note 40 \u201cProvisions for risks and charges\u201d.
\n
Note 57 \u201cContingent assets and liabilities\u201d also provides
\n
information regarding the most significant contingent as-
\n
sets and liabilities for the Group at year end.
\n
Litigation
\n
The Group is involved in various civil, administrative and tax
\n
disputes connected with the normal pursuit of its activi-
\n
ties that could give rise to significant liabilities. It is not al-
\n
ways objectively possible to predict the outcome of these
\n
disputes. The assessment of the risks associated with this
\n
litigation is based on complex factors whose very nature
\n
requires recourse to management judgments, even when
\n
taking account of the contribution of external advisors as-
\n
sisting the Group, about whether to classify them as con-
\n
tingent liabilities or liabilities.
\n
Provisions have been recognized to cover all significant li-
\n
abilities for cases in which legal counsel feels an adverse
\n
outcome is likely and a reasonable estimate of the amount
\n
of the expense can be made.
\n
Obligations associated with generation plants, including
\n
decommissioning and site restoration
\n
Generation activities may entail obligations for the opera-
\n
tor with regard to future interventions that will have to be
\n
performed following the end of the operating life of the
\n
plant.
\n
Such interventions may involve the decommissioning of
\n
plants and site restoration, or other obligations linked to
\n
the type of generation technology involved. The nature of
\n
such obligations may also have a major impact on the ac-
\n
counting treatment used for them.
\n
In the case of nuclear power plants, where the costs re-
\n
gard both decommissioning and the storage of waste fuel
\n
and other radioactive materials, the estimation of the fu-
\n

\n\n

\n\n

\n\n

\n\n

\n\n
ture cost is a critical process, given that the costs will be
\n
incurred over a very long span of time, estimated at up to
\n
100 years.
\n
The obligation, based on financial and engineering as-
\n
sumptions, is calculated by discounting the expected fu-
\n
ture cash flows that the Group considers it will have to pay
\n
to meet the obligations it has assumed.
\n
The discount rate used to determine the present value of
\n
the liability is the pre-tax risk-free rate and is based on the
\n
economic parameters of the country in which the plant is
\n
located.
\n
That liability is quantified by management on the basis of
\n
the technology existing at the measurement date and is re-
\n
viewed each year, taking account of developments in stor-
\n
age, decommissioning and site restoration technology, as
\n
well as the ongoing evolution of the legislative framework
\n
governing health and environmental protection.
\n
Subsequently, the value of the obligation is adjusted to re-
\n
flect the passage of time and any changes in estimates.
\n
Please see note 40 \u201cProvisions for risks and charges\u201d for
\n
more information on discount rates, undiscounted esti-
\n
mated costs and their timing, which are used to calculate
\n
the plant decommissioning and site restoration provision.
\n
Onerous contracts
\n
In order to identify an onerous contract, the Group esti-
\n
mates the non-discretionary costs necessary to fulfil the
\n
obligations assumed (including any penalties) under the
\n
contract and the economic benefits that are presumed to
\n
be obtained from the contract.
\n

\n\n
Leases
\n
When the interest rate implicit in the lease cannot be read-
\n
ily determined, the Group uses the incremental borrowing
\n
rate (IBR) at the lease commencement date to calculate
\n
the present value of the lease payments. This is the inter-
\n
est rate that the lessee would have to pay to borrow over a
\n
similar term, and with a similar security, the funds neces-
\n
sary to obtain an asset of a similar value to the rightofuse
\n
asset in a similar economic environment. When no observ-
\n
able inputs are available, the Group estimates the IBR mak-
\n
ing assumptions to reflect the terms and conditions of the
\n
lease and certain lessee-specific estimates.
\n
One of the most significant judgments for the Group is de-
\n
termining this IBR necessary to calculate the present value
\n
of the lease payments required to be paid to the lessor.
\n
The Group approach to determine an IBR is based on the
\n
assessment of the following three key components:
\n
\u2022 the risk free rate, that consider the currency flows of the
\n
lease payments, the economic environment where the
\n
lease contract has been negotiated and also the lease
\n
term;
\n
\u2022 the credit spread adjustment, in order to calculate an IBR
\n
that is specific for the lessee considering any underlying
\n
Parent or other guarantee;
\n
\u2022 the lease related adjustments, in order to reflect into the
\n
IBR calculation the fact that the discount rate is directly
\n
linked to the type of the underlying asset, rather than
\n
being a general incremental borrowing rate. In particu-
\n
lar, the risk of default is mitigated for the lessors as they
\n
have the right to reclaim the underlying asset itself.
\n
For more information on lease liabilities, please see note
\n
48 \u201cFinancial instruments by category\u201d.
\n
Income tax
\n
Recovery of deferred tax assets
\n
At December 31, 2022, the consolidated financial state-
\n
ments report deferred tax assets in respect of tax loss-
\n
es or tax credits usable in subsequent years and income
\n
components whose deductibility is deferred in an amount
\n
whose future recovery is considered by management to be
\n
highly probable.
\n
The recoverability of such assets is subject to the achieve-
\n
ment of future profits sufficient to absorb such tax losses
\n
and to use the benefits of the other deferred tax assets.
\n
Significant management judgment is required to assess
\n
the probability of recovering deferred tax assets, consid-
\n
ering all negative and positive evidence, and to determine
\n
the amount that can be recognized, based upon the likely
\n
timing and the level of future taxable profits together with
\n
future tax planning strategies and the tax rates applicable
\n
at the date of reversal. However, where the Group should
\n
become aware that it is unable to recover all or part of rec-
\n
ognized tax assets in future years, the consequent adjust-
\n
ment would be taken to profit or loss in the year in which
\n
this circumstance arises.
\n
The recoverability of deferred tax assets is reviewed at the
\n
end of each period. Deferred tax assets not recognized
\n
are reassessed at each reporting date in order to verify the
\n
conditions for their recognition.
\n
For more detail in deferred tax assets recognized or not
\n
recognized, please see note 25 \u201cDeferred tax assets and
\n
liabilities\u201d.
\n
Management judgment
\n
Identification of cash generating units (CGUs)
\n
For impairment testing, if the recoverable amount cannot
\n
be determined for an individual asset, the Group identi-
\n
fies the smallest group of assets that generate largely in-
\n
dependent cash inflows. The smallest group of assets that
\n
generates cash inflows that are largely independent of the
\n

\n\n

\n\n

\n\n
cash inflows from other assets or group of assets is a CGU.
\n
Identifying such CGUs involves management judgments
\n
regarding the specific nature of the assets and the busi-
\n
ness involved (geographical segment, business segment,
\n
regulatory framework, etc.) and the evidence that the cash
\n
inflows of the group of assets are largely independent of
\n
those associated with other assets (or groups of assets).
\n
The assets of each CGU are also identified on the basis of
\n
the manner in which management manages and monitors
\n
those assets within the business model adopted. In partic-
\n
ular, the number and scope of the CGUs are updated sys-
\n
tematically to reflect the impact of new business combi-
\n
nations and reorganizations carried out by the Group, and
\n
to take account of external factors that could influence the
\n
ability of assets to generate independent cash inflows.
\n
In particular, if certain specific identified assets owned by
\n
the Group are impacted by adverse economic or operating
\n
conditions that undermine their capacity to contribute to
\n
the generation of cash flows, they can be isolated from the
\n
rest of the assets of the CGU, undergo separate analysis of
\n
their recoverability and be impaired where necessary.
\n
The CGUs identified by management to which the goodwill
\n
recognized in these consolidated financial statements has
\n
been allocated and the criteria used to identify the CGUs
\n
are indicated in note 24 \u201cGoodwill\u201d.
\n
Determining the useful life of non-financial assets
\n
In determining the useful life of property, plant and equip-
\n
ment and intangible assets with a finite useful life, the
\n
Group considers not only the future economic benefits \u2013
\n
contained in the assets \u2013 obtained through their use, but
\n
also many other factors, such as physical wear and tear,
\n
the technical, commercial or other obsolescence of the
\n
product or service produced with the asset, legal or similar
\n
limits (e.g., safety, environmental or other restrictions) on
\n
the use of the asset, if the useful life of the asset depends
\n
on the useful life of other assets.
\n
Furthermore, in estimating the useful lives of the assets
\n
concerned, the Group has taken account of its commit-
\n
ment under the Paris Agreement. For more information on
\n
this issue, please see note 19 \u201cProperty, plant and equip-
\n
ment\u201d.
\n
Determination of the existence of control
\n
Under the provisions of IFRS 10, control is achieved when
\n
the Group is exposed, or has rights, to variable returns
\n
from its involvement with the investee and has the ability
\n
to affect those returns through its power over the investee.
\n
Power is defined as the current ability to direct the relevant
\n
activities of the investee based on existing substantive
\n
rights.
\n
The existence of control does not depend solely on owner-
\n
ship of a majority investment, but rather it arises from sub-
\n
stantive rights that each investor holds over the investee.
\n
Consequently, management must use its judgment in as-
\n
sessing whether specific situations determine substantive
\n
rights that give the Group the power to direct the relevant
\n
activities of the investee in order to affect its returns.
\n
For the purpose of assessing control, management an-
\n
alyzes all facts and circumstances including any agree-
\n
ments with other investors, rights arising from other con-
\n
tractual arrangements and potential voting rights (call
\n
options, warrants, put options granted to non-controlling
\n
shareholders, etc.). These other facts and circumstances
\n
could be especially significant in such assessment when
\n
the Group holds less than a majority of voting rights, or
\n
similar rights, in the investee.
\n
Furthermore, even if it holds more than half of the voting
\n
rights in an entity, the Group considers all the relevant
\n
facts and circumstances in assessing whether it controls
\n
the investee.
\n
The Group reassesses whether or not it controls an in-
\n
vestee if facts and circumstances indicate that there are
\n
changes to one or more of the elements considered in
\n
verifying the existence of control.
\n
As reported in Enel\u2019s consolidated financial statements at
\n
December 31, 2022, the Enel Group holds minor interests
\n
in Enel Green Power Rus LLC and Enel X Rus LLC.
\n
In the wake of the Ukrainian conflict, a number of measures
\n
were adopted or undertaken that resulted in the termina-
\n
tion of Enel\u2019s management and coordination role at the
\n
Russian companies in which the Group holds investments.
\n
These measures include: (i) the resignation of all non-in-
\n
dependent directors and all managers of non-Russian
\n
nationality; (ii) the termination of intercompany contracts;
\n
and (iii) the modification of the organizational structure of
\n
the Enel Group in order to terminate reporting by the staff
\n
or business functions to Enel.
\n
At December 31, 2022 the Enel Group continues to control
\n
the companies from an accounting point of view, in com-
\n
pliance with \u201cIFRS 10 - Consolidated Financial Statements\u201d.
\n
Determination of the existence of joint control and of
\n
the type of joint arrangement
\n
Under the provisions of IFRS 11, a joint arrangement is an
\n
agreement where two or more parties have joint control.
\n
Joint control exists only when the decisions over the rele-
\n
vant activities require the unanimous consent of the par-
\n
ties that share joint control.
\n
A joint arrangement can be configured as a joint venture
\n
or a joint operation. Joint ventures are joint arrangements
\n
whereby the parties that have joint control have rights to
\n
the net assets of the arrangement. Conversely, joint op-
\n
erations are joint arrangements whereby the parties that
\n

\n\n

\n\n

\n\n
have joint control have rights to the assets and obligations
\n
for the liabilities relating to the arrangement.
\n
In order to determine the existence of the joint control
\n
and the type of joint arrangement, management must ap-
\n
ply judgment and assess its rights and obligations arising
\n
from the arrangement. For this purpose, the management
\n
considers the structure and legal form of the arrangement,
\n
the terms agreed by the parties in the contractual arrange-
\n
ment and, when relevant, other facts and circumstances.
\n
Following that analysis, the Group has considered its in-
\n
terest in Asociaci\u00f3n Nuclear Asc\u00f3-Vandell\u00f3s II as a joint
\n
operation.
\n
The Group re-assesses whether or not it has joint control
\n
if facts and circumstances indicate that changes have oc-
\n
curred in one or more of the elements considered in veri-
\n
fying the existence of joint control and the type of the joint
\n
arrangement.
\n
In the wake of the Ukrainian conflict, a number of mea-
\n
sures were adopted or undertaken that resulted in the
\n
termination of Enel\u2019s management of Rusenergosbyt LLC
\n
(Group\u2019s associate). These measures include the resigna-
\n
tion of all non-independent directors and all managers of
\n
non-Russian nationality and the termination of reporting
\n
by the staff or business functions to Enel.
\n
At December 31, 2022 the Enel Group continues to exer-
\n
cise joint control of the company from an accounting point
\n
of view, in accordance with \u201cIFRS 11 - Joint arrangements\u201d.
\n
For more information on the Group\u2019s investments in joint
\n
ventures, please see note 26 \u201cEquity-accounted invest-
\n
ments\u201d.
\n
Determination of the existence of significant influence
\n
over an associate
\n
Associates are those in which the Group exercises signifi-
\n
cant influence, i.e., the power to participate in the financial
\n
and operating policy decisions of the investee but not ex-
\n
ercise control or joint control over those policies. In gener-
\n
al, it is presumed that the Group has a significant influence
\n
when it has an ownership interest of 20% or more.
\n
In order to determine the existence of significant influence,
\n
management must apply judgment and consider all facts
\n
and circumstances.
\n
The Group re-assesses whether or not it has significant
\n
influence if facts and circumstances indicate that there
\n
are changes to one or more of the elements considered in
\n
verifying the existence of significant influence.
\n
For more information on the Group\u2019s equity investments in
\n
associates, please see note 26 \u201cEquity-accounted invest-
\n
ments\u201d.
\n
Application of \u201cIFRIC 12 - Service concession
\n
arrangements\u201d to concessions
\n
IFRIC 12 applies to \u201cpublic-to-private\u201d service concession
\n
arrangements, which can be defined as contracts under
\n
which the operator is obligated to provide public services,
\n
i.e., give access to major economic and social services for
\n
a certain period of time, on behalf of a public entity (the
\n
grantor). In these contracts, the grantor conveys to an op-
\n
erator the right to manage the infrastructure used to pro-
\n
vide services.
\n
More specifically, IFRIC 12 gives guidance on the account-
\n
ing by operators for \u201cpublic-to-private\u201d service conces-
\n
sion arrangements in the event that:
\n
\u2022 the grantor controls or regulates what services the op-
\n
erator must provide with the infrastructure, to whom it
\n
must provide them, and at what price; and
\n
\u2022 the grantor controls \u2013 through ownership, beneficial en-
\n
titlement or otherwise \u2013 any significant residual interest
\n
in the infrastructure at the end of the term of the ar-
\n
rangement.
\n
In assessing the applicability of these requirements for the
\n
Group, as operator, management carefully analyzed exist-
\n
ing concessions.
\n
On the basis of that analysis, the provisions of IFRIC 12 are
\n
applicable to some of the infrastructure of a number of
\n
companies that operate primarily in Brazil.
\n
Further details about the infrastructure used in the service
\n
concession arrangements in the scope of IFRIC 12 are pro-
\n
vided in note 20 \u201cInfrastructure within the scope of \u2018IFRIC
\n
12 - Service concession arrangements\u2019\u201d.
\n
Revenue from contracts with customers
\n
In the process of applying IFRS 15, the Group has made the
\n
following judgments (further details about the most signif-
\n
icant effect on the Group\u2019s revenue are provided in note
\n
11.a \u201cRevenue from sales and services\u201d).
\n
The Group carefully analyzes the contractual terms and
\n
conditions on a jurisdictional level in order to determine
\n
when a contract exists and the terms of that contract\u2019s en-
\n
forceability so as to apply IFRS 15 only to such contracts.
\n
When a contract includes multiple promised goods or ser-
\n
vices, in order to assess if they should be accounted for
\n
separately or as a group, the Group considers both the in-
\n
dividual characteristics of goods/services and the nature of
\n
the promise within the context of the contract, also evalu-
\n
ating all the facts and circumstances relating to the specific
\n
contract under the relevant legal and regulatory framework.
\n
To evaluate when a performance obligation is satisfied, the
\n
Group evaluates when the control of the goods or services
\n
is transferred to the customer, assessed primarily from the
\n
perspective of the customer.
\n

\n\n

\n\n

\n\n

\n

\n
For each performance obligation, and in relation to the
\n
type of transaction:
\n
\u2022 revenue is recognized over time on the basis of the prog-
\n
ress towards complete satisfaction of the performance
\n
obligation, as in the case of the provision of services.
\n
The measurement of progress towards complete satis-
\n
faction of a performance obligation is carried out con-
\n
sistently for performance obligations and similar circum-
\n
stances using an \u201coutput\u201d or \u201cinput\u201d method. In particu-
\n
lar, the cost incurred method (cost-to-cost method) is
\n
considered appropriate for measuring progress except
\n
when a specific analysis of the contract counsels the use
\n
of an alternative method. If it should prove impossible to
\n
reasonably assess progress towards satisfaction of the
\n
performance obligation, the Group recognizes revenue
\n
only to the extent of the incurred costs that are consid-
\n
ered recoverable;
\n
\u2022 if, on the other hand, the performance obligation is sat-
\n
isfied at a given moment, as in the case of the supply
\n
of goods, revenue is recognized at the point in time in
\n
which the customer obtains the control of the goods,
\n
considering all relevant indicators.
\n
The Group considers all relevant facts and circumstanc-
\n
es in determining whether a contract includes variable
\n
consideration (i.e., consideration that may vary or de-
\n
pends upon the occurrence or non-occurrence of a fu-
\n
ture event). In estimating variable consideration, the Group
\n
uses the method that better predicts the consideration to
\n
which it will be entitled, applying it consistently throughout
\n
the contract and for similar contracts, also considering all
\n
available information, and updating such estimates until
\n
the uncertainly is resolved. The Group includes the esti-
\n
mated variable consideration in the transaction price only
\n
to the extent that it is highly probable that a significant re-
\n
versal in the cumulative revenue recognized will not occur
\n
when the uncertainty is resolved.
\n
The Group considers that it is an agent in some con-
\n
tracts in which it is not primarily responsible for fulfilling
\n
the contract and therefore it does not control goods or
\n
services before they are being transferred to customers.
\n
For example, the Group acts as an agent in some contracts
\n
for electricity/gas network connection services and other
\n
related activities depending on local legal and regulatory
\n
framework.
\n
For contracts that have more than one performance obli-
\n
gation (e.g., \u201cbundled\u201d sale contracts), the Group generally
\n
allocates the transaction price to each performance ob-
\n
ligation in proportion to its stand-alone selling price. The
\n
Group determines stand-alone selling prices considering
\n
all information and using observable prices when they are
\n
available in the market or, if not, using an estimation meth-
\n
od that maximizes the use of observable inputs and apply-
\n
ing it consistently to similar arrangements.
\n
If the Group evaluates that a contract includes an option
\n
for additional goods or services (e.g., customer loyalty pro-
\n
grams or renewal options) that represents a material right,
\n
it allocates the transaction price to this option since the
\n
option gives rise to an additional performance obligation.
\n\n
The Group assesses recoverability of the incremental costs
\n
of obtaining a contract either on a contract-by-contract
\n
basis, or for a group of contracts if those costs are associ-
\n
ated with the group of contracts.
\n
The Group supports the recoverability of such costs on
\n
the basis of its experience with other similar transactions
\n
and evaluating various factors, including potential renew-
\n
als, amendments and follow-on contracts with the same
\n
customer.
\n
The Group amortizes such costs over the average custom-
\n
er term. In order to determine this expected period of ben-
\n
efit from the contract, the Group considers its past experi-
\n
ence (e.g., \u201cchurn rate\u201d), the predictive evidence from sim-
\n
ilar contracts and available information about the market.
\n

\n\n
Power Purchase Agreements
\n
Power Purchase Agreements (PPAs), which provide for the
\n
physical delivery of energy and which do not comply with
\n
the requirements of IFRS 10 for the existence of control
\n
or joint control over a company or an asset, and IFRS 16
\n
for the recognition of a lease, but which comply with the
\n
definition of a derivative under IFRS 9, are accounted for
\n
on the basis of the own use exemption when the relevant
\n
conditions are met.
\n
For more information on Virtual PPAs complying with the
\n
definition of derivative pursuant to IFRS 9, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n
Classification and measurement of financial assets
\n
At initial recognition, in order to classify financial assets
\n
as financial assets at amortized cost, at fair value through
\n
other comprehensive income and at fair value through
\n
profit or loss, management assesses both the contractual
\n
cash-flow characteristics of the instrument and the busi-
\n
ness model for managing financial assets in order to gen-
\n
erate cash flows.
\n
In order to evaluate the contractual cash-flow characteris-
\n
tics of the instrument, management performs the SPPI test
\n
at an instrument level, in order to determine if it gives rise to
\n
cash flows that are solely payments of principal and inter-
\n
est (SPPI) on the principal amount outstanding, performing
\n
specific assessment on the contractual clauses of the finan-
\n
cial instruments, as well as quantitative analysis, if required.
\n
The business model determines whether cash flows will
\n

\n\n

\n\n

\n

\n

\n\n
result from collecting contractual cash flows, selling the
\n
financial assets, or both.
\n
For more details, please see note 48 \u201cFinancial instruments
\n
by category\u201d.
\n
Hedge accounting
\n
Hedge accounting is applied to derivatives in order to re-
\n
flect into the financial statements the effect of risk man-
\n
agement strategies.
\n
Accordingly, at the inception of the transaction the Group
\n
documents the hedge relationship between hedging in-
\n
struments and hedged items, as well as its risk manage-
\n
ment objectives and strategy. The Group also assesses,
\n
both at hedge inception and on an ongoing basis, wheth-
\n
er hedging instruments are highly effective in offsetting
\n
changes in the fair values or cash flows of hedged items.
\n
On the basis of management\u2019s judgment, the effectiveness
\n
assessment based on the existence of an economic rela-
\n
tionship between the hedging instruments and the hedged
\n
items, the dominance of credit risk in the changes in fair
\n
value and the hedge ratio, as well as the measurement of
\n
the ineffectiveness, is evaluated through a qualitative as-
\n
sessment or a quantitative computation, depending on the
\n
specific facts and circumstances and on the characteristics
\n
of the hedged items and the hedging instruments.
\n
For cash flow hedges of forecast transactions designated
\n
as hedged items, management assesses and documents
\n
that they are highly probable and present an exposure to
\n
changes in cash flows that affect profit or loss.
\n
For additional details on the key assumptions about effec-
\n
tiveness assessment and ineffectiveness measurement,
\n
please refer to note 51.1 \u201cDerivatives designated as hedging
\n
instruments\u201d.
\n
Leases
\n
The complexity of the assessment of the lease contracts,
\n
and also their long-term expiring date, requires consider-
\n
able professional judgments for application of IFRS 16. In
\n
particular, this regards:
\n
\u2022 the application of the definition of a lease to the cases
\n
typical of the sectors in which the Group operates;
\n
\u2022 the identification of the non-lease component into the
\n
lease arrangements;
\n
\u2022 the evaluation of any renewable and termination options
\n
included in the lease in order to determine the term of
\n
leases, also considering the probability of their exercise
\n
and any significant leasehold improvements on the un-
\n
derlying asset, taking due consideration of recent inter-
\n
pretations issued by the IFRS Interpretations Committee;
\n
\u2022 the identification of any variable lease payments that
\n
depend on an index or a rate to determine whether the
\n
changes of the latter impact the future lease payments
\n
and also the amount of the right-of-use asset;
\n
\u2022 the estimate of the discount rate to calculate the pres-
\n
ent value of the lease payments; further details on as-
\n
sumptions about this rate are provided in the paragraph
\n
\u201cUse of estimates\u201d.
\n
For more information on leases, please see note 21 \u201cLeas-
\n
es\u201d.
\n
Uncertainty over income tax treatments
\n
The Group determines whether to consider each uncer-
\n
tain income tax treatment separately or together with one
\n
or more other uncertain tax treatments as well as whether
\n
to reflect the effect of uncertainty by using the most like-
\n
ly amount or the expected value method, based on which
\n
approach better predicts the resolution of the uncertainty
\n
for each uncertain tax treatments, taking account of local
\n
tax regulations.
\n
The Group makes significant use of professional judgment
\n
in identifying uncertainties about income tax treatments
\n
and reviews the judgments and estimates made in the event
\n
of a change in facts and circumstances that could change
\n
its assessment of the acceptability of a specific tax treat-
\n
ment or the estimate of the effects of uncertainty, or both.
\n
For more information on income taxes, please see note 17
\n
\u201cIncome taxes\u201d.
\n

\n

\n\n\n

\n

\n
2.2 Significant accounting policies
\n\n
Related parties
\n
Related parties are mainly those that share the same con-
\n
trolling entity with Enel SpA, the companies that directly or
\n
indirectly are controlled by Enel SpA, the associates or joint
\n
ventures (including their subsidiaries) of Enel SpA, or the
\n
associates or joint ventures (including their subsidiaries) of
\n
any Group company. Related parties also include entities
\n
that operate post-employment benefit plans for employ-
\n
ees of Enel SpA or its associates (specifically, the FOPEN
\n
and FONDENEL pension funds), as well as the members
\n
of the boards of statutory auditors, and their immediate
\n
family, and the key management personnel, and their im-
\n
mediate family, of Enel SpA and its subsidiaries. Key man-
\n
agement personnel comprises management personnel
\n
who have the power and direct or indirect responsibility
\n
for the planning, management and control of the activities
\n
of the Company. They include directors (whether executive
\n
or not).
\n

\n\n\n
Subsidiaries
\n
Subsidiaries are all entities over which the Group has con-
\n
trol. The Group controls an entity, regardless of the nature
\n
of the formal relationship between them, when it is ex-
\n
posed, or has rights, to variable returns deriving from its
\n
involvement and has the ability, through the exercise of its
\n
power over the investee, to affect its returns.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
The figures of the subsidiaries are consolidated on a full
\n
line-by-line basis as from the date control is acquired until
\n
such control ceases.
\n

\n\n\n

\n

\n
Consolidation procedures
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2022 in accordance with the accounting
\n
policies adopted by the Group.
\n
If a subsidiary uses different accounting policies from
\n
those adopted in preparing the consolidated financial
\n
statements for similar transactions and facts in similar cir-
\n
cumstances, appropriate adjustments are made to ensure
\n
conformity with Group accounting policies.
\n
Assets, liabilities, revenue and expenses of a subsidiary ac-
\n
quired or disposed of during the year are included in or
\n
excluded from the consolidated financial statements, re-
\n
spectively, from the date the Group gains control or until
\n
the date the Group ceases to control the subsidiary.
\n\n
Profit or loss for the year and the other comprehensive
\n
income are attributed to the owners of the Parent and
\n
non-controlling interests, even if this results in a loss for
\n
non-controlling interests.
\n
All intercompany assets and liabilities, equity item, revenue,
\n
expenses and cash flows relating to transactions between
\n
entities of the Group are eliminated in full.
\n
Changes in ownership interest in subsidiaries that do not
\n
result in loss of control are accounted for as equity trans-
\n
actions, with the carrying amounts of the controlling and
\n
non-controlling interests adjusted to reflect changes in
\n
their interests in the subsidiary. Any difference between
\n
the amount to which non-controlling interests are adjust-
\n
ed and the fair value of the consideration paid or received
\n
is recognized in consolidated equity.
\n

\n\n\n
When the Group ceases to have control over a subsidiary,
\n
any interest retained in the entity is remeasured to its fair
\n
value, recognized through profit or loss, at the date when
\n
control is lost, recognizing any gain or loss from the loss
\n
of control through profit or loss. In addition, any amounts
\n
previously recognized in other comprehensive income in
\n
respect of the former subsidiary are accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n\n

\n\n\n

\n\n

\n\n
Investments in associates and joint ventures
\n
An associate is an entity over which the Group has signifi-
\n
cant influence. Significant influence is the power to partic-
\n
ipate in decisions concerning the financial and operating
\n
policies of the investee without having control or joint con-
\n
trol over the investee.
\n
A joint venture is a joint arrangement over which the Group
\n
exercises joint control and has rights to the net assets of
\n
the arrangement. Joint control is the sharing of control of
\n
an arrangement, whereby decisions about the relevant ac-
\n
tivities require unanimous consent of the parties sharing
\n
control.
\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method.
\n
Under the equity method, these investments are initial-
\n
ly recognized at cost and any goodwill arising from the
\n
difference between the cost of the investment and the
\n
Group\u2019s share of the net fair value of the investee\u2019s identifi-
\n
able assets and liabilities at the acquisition date is included
\n
in the carrying amount of the investment.
\n
After the acquisition date, their carrying amount is adjust-
\n
ed to recognize changes in the Group\u2019s share of profit or
\n
loss of the associate or joint venture in Group profit or loss.
\n
Adjustments to the carrying amount may also be neces-
\n
sary following changes in the Group\u2019s share in the asso-
\n
ciate or joint venture as a result of changes in the other
\n
comprehensive income of the investee. The Group\u2019s share
\n
of these changes is recognized in the Group\u2019s other com-
\n
prehensive income.
\n
Distributions received from joint venture and associates
\n
reduce the carrying amount of the investments.
\n
Gains and losses resulting from transactions between the
\n
Group and the associates or joint ventures are eliminated
\n
to the extent of the interest in the associate or joint ven-
\n
ture.
\n
The financial statements of the associates or joint ventures
\n
are prepared for the same reporting period as the Group.
\n
When necessary, adjustments are made to bring the ac-
\n
counting policies in line with those of the Group.
\n
After application of the equity method, the Group deter-
\n
mines whether it is necessary to recognize an impairment
\n
loss on its investment in an associate or joint venture. If
\n
there is objective evidence of a loss of value, the entire
\n
carrying amount of the investment undergoes impairment
\n
testing pursuant to IAS 36 as a single asset. For more in-
\n
formation on impairment, please see the section \u201cImpair-
\n
ment of non-financial assets\u201d in note 2.1 \u201cUse of estimates
\n
and management judgment\u201d.
\n
If the investment ceases to be an associate or a joint ven-
\n
ture, the Group recognizes any retained investment at its
\n
fair value, through profit or loss. Any amounts previously
\n
recognized in other comprehensive income in respect of
\n
the former associate or joint venture are accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\n
If the ownership interest in an associate or a joint venture is
\n
reduced, but the Group continues to exercise a significant
\n
influence or joint control, the Group continues to apply
\n
the equity method and the share of the gain or loss that
\n
had previously been recognized in other comprehensive
\n
income relating to that reduction is accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n

\n\n

\n

\n\n

\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n\n

\n\n

\n\n
When a portion of an investment in an associate or joint
\n
venture meets the criteria to be classified as held for sale,
\n
any retained portion of an investment in the associate or
\n
joint venture that has not been classified as held for sale
\n
is accounted for using the equity method until disposal of
\n
the portion classified as held for sale takes place.
\n
Joint operations are joint arrangements whereby the
\n
Group, which holds joint control, has rights to the assets
\n
and obligations for the liabilities relating to the arrange-
\n
ment. For each joint operation, the Group recognized as-
\n
sets, liabilities, costs and revenue on the basis of the pro-
\n
visions of the arrangement rather than the interest held.
\n
Where there is an increase in the interest in a joint ar-
\n
rangement that meets the definition of a business:
\n
\u2022 if the Group acquires control, and had rights over the
\n
assets and obligations for the liabilities of the joint ar-
\n
rangement immediately before the acquisition date,
\n
then the transaction represents a business combination
\n
achieved in stages. Consequently, the Group applies the
\n
requirements for a business combination achieved in
\n
stages, including the remeasurement of the interest it
\n
held previously in the joint operation at its fair value at
\n
the acquisition date;
\n
\u2022 if the Group obtains joint control (i.e., it already had an
\n
interest in a joint operation without holding joint control),
\n
the interest previously held in the joint operation shall
\n
not be remeasured.
\n
For more information on the Group\u2019s investments in asso-
\n
ciates and joint ventures, please see note 26 \u201cEquity-ac-
\n
counted investments\u201d.
\n

\n\n

\n\n

\n\n\n
Translation of foreign currency items
\n
Transactions in currencies other than the functional cur-
\n
rency are initially recognized at the spot exchange rate
\n
prevailing on the date of the transaction.
\n
Monetary assets and liabilities denominated in a foreign
\n
currency other than the functional currency are subse-
\n
quently translated using the closing exchange rate (i.e., the
\n
spot exchange rate prevailing at the reporting date).
\n
Non-monetary assets and liabilities denominated in for-
\n
eign currency that are recognized at historical cost are
\n
translated using the exchange rate at the date of the
\n
transaction. Non-monetary assets and liabilities in foreign
\n
currency measured at fair value are translated using the
\n
exchange rate at the date the fair value was determined.
\n
Any exchange differences are recognized through profit or
\n
loss.
\n
In determining the spot exchange rate to use on initial rec-
\n
ognition of the related asset, expense or income (or part
\n
of it) on the derecognition of a non-monetary asset or
\n
non-monetary liability relating to advance consideration in
\n
foreign currency paid or received, the date of the transac-
\n
tion is the date on which the Group initially recognizes the
\n
non-monetary asset or non-monetary liability associated
\n
with the advance consideration.
\n
If there are multiple advance payments or receipts, the
\n
Group determines the transaction date for each payment
\n
or receipt of advance consideration.
\n

\n

\n\n\n
Translation of financial statements
\n
denominated in a foreign currency
\n
For the purposes of the consolidated financial statements,
\n
all revenue, expenses, assets and liabilities are stated in
\n
euro, which is the presentation currency of the Parent.
\n
In order to prepare the consolidated financial statements,
\n
the financial statements of consolidated companies with
\n
functional currencies other than the presentation curren-
\n
cy used in the consolidated financial statements are trans-
\n
lated into euros by applying the closing exchange rate to
\n
the assets and liabilities, including goodwill and consolida-
\n
tion adjustments, and the average exchange rate for the
\n
period to the income statement items on the condition it
\n
approximates the exchange rates prevailing at the date of
\n
the respective transactions.
\n
Any resulting exchange gains or losses are recognized as
\n
a separate component of equity in a special reserve. The
\n
gains and losses are recognized proportionately in the
\n
income statement on the disposal (partial or total) of the
\n
subsidiary.
\n
When the functional currency of a consolidated company
\n
is the currency of a hyperinflationary economy, the Group
\n
restates the financial statements in accordance with IAS
\n
29 before applying the specific conversion method set out
\n
below.
\n
In order to consider the impact of hyperinflation on the
\n
local currency exchange rate, the financial position and
\n
performance (i.e., assets, liabilities, equity items, revenue
\n
and expenses) of a company whose functional currency is
\n
the currency of a hyperinflationary economy are translated
\n
into the Group\u2019s presentation currency (the euro) using the
\n
exchange rate prevailing at the reporting date, except for
\n
comparative amounts presented in the previous year\u2019s fi-
\n
nancial statements which are not adjusted for subsequent
\n
changes in the price level or subsequent changes in ex-
\n
change rates.
\n

\n\n\n

\n\n
Business combinations
\n
Business combinations initiated before January 1, 2010
\n
and completed within that financial year are recognized on
\n
the basis of IFRS 3 (2004).
\n
Such business combinations were recognized using the
\n
purchase method, where the purchase cost is equal to the
\n
fair value at the date of the exchange of the assets ac-
\n
quired and the liabilities incurred or assumed, plus costs
\n
directly attributable to the acquisition. This cost was allo-
\n
cated by recognizing the assets, liabilities and identifiable
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n
contingent liabilities of the acquired company at their fair
\n
values. Any positive difference between the cost of the
\n
acquisition and the fair value of the net assets acquired
\n
attributable to the owners of the Parent was recognized
\n
as goodwill. If the difference is negative, it is recognized
\n
through profit or loss.
\n\n
The carrying amount of non-controlling interests was de-
\n
termined in proportion to the interest held by non-con-
\n
trolling shareholders in the net assets. In the case of busi-
\n
ness combinations achieved in stages, at the date of ac-
\n
quisition any adjustment to the fair value of the net assets
\n
acquired previously was recognized in equity; the amount
\n
of goodwill was determined for each transaction separate-
\n
ly based on the fair values of the acquiree\u2019s net assets at
\n
the date of each exchange transaction.
\n

\n\n
Business combinations carried out as from January 1, 2010
\n
are recognized on the basis of IFRS 3 (2008), which is re-
\n
ferred to as IFRS 3 (Revised) hereafter.
\n
More specifically, business combinations are recognized
\n
using the acquisition method, where the purchase cost
\n
(the consideration transferred) is equal to the fair value at
\n
the purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments is-
\n
sued by the purchaser. The consideration transferred in-
\n
cludes the fair value of any asset or liability resulting from
\n
a contingent consideration arrangement.
\n
Costs directly attributable to the acquisition are recog-
\n
nized through profit or loss.
\n
The consideration transferred is allocated by recognizing
\n
the assets, liabilities and identifiable contingent liabili-
\n
ties of the acquired company at their fair values as at the
\n
acquisition date. The excess of the consideration trans-
\n
ferred, measured at fair value as at the acquisition date,
\n
the amount of any non-controlling interest in the acquiree
\n
plus the fair value of any equity interest in the acquiree
\n
previously held by the Group (in a business combination
\n
achieved in stages) over the net amount of the identifiable
\n
assets acquired and the liabilities incurred or assumed
\n
measured at fair value is recognized as goodwill. If the dif-
\n
ference is negative, the Group verifies whether it has cor-
\n
rectly identified all the assets acquired and liabilities as-
\n
sumed and reviews the procedures used to determine the
\n
amounts to recognize at the acquisition date. If after this
\n
assessment the fair value of the net assets acquired still
\n
exceeds the total consideration transferred, this excess
\n
represents the profit on a bargain purchase and is recog-
\n
nized through profit or loss.
\n
The carrying amount of non-controlling interests is deter-
\n
mined either in proportion to the interest held by non-con-
\n
trolling shareholders in the net identifiable assets of the
\n
acquiree or at their fair value as at the acquisition date.
\n
In the case of business combinations achieved in stages, at
\n
the date of acquisition of control the previously held equi-
\n
ty interest in the acquiree is remeasured to fair value and
\n
any positive or negative difference is recognized in profit
\n
or loss.
\n
Any contingent consideration is recognized at fair value at
\n
the acquisition date. Subsequent changes to the fair val-
\n
ue of the contingent consideration classified as an asset
\n
or a liability, or as a financial instrument within the scope
\n
of IFRS 9, are recognized in profit or loss. If the contin-
\n
gent consideration is not within the scope of IFRS 9, it is
\n
measured in accordance with the appropriate IFRS-EU.
\n
Contingent consideration that is classified as equity is not
\n
re-measured, and its subsequent settlement is accounted
\n
for within equity.
\n
If the fair values of the assets, liabilities and contingent li-
\n
abilities can only be calculated on a provisional basis, the
\n
business combination is recognized using such provisional
\n
values. Any adjustments resulting from the completion of
\n
the measurement process are recognized within 12 months
\n
of the date of acquisition, restating comparative figures.
\n

\n

\n\n

\n

\n\n\n
Fair value measurement
\n
For all fair value measurements and disclosures of fair val-
\n
ue, that are either required or permitted by IFRS, the Group
\n
applies IFRS 13.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The fair value measurement assumes that the transaction
\n
to sell an asset or transfer a liability takes place in the prin-
\n
cipal market, i.e., the market with the greatest volume and
\n
level of activity for the asset or liability. In the absence of a
\n
principal market, it is assumed that the transaction takes
\n
place in the most advantageous market to which the Group
\n
has access, i.e., the market that maximizes the amount
\n
that would be received to sell the asset or minimizes the
\n
amount that would be paid to transfer the liability.
\n
The fair value of an asset or a liability is measured using
\n
the assumptions that market participants would use when
\n
pricing the asset or liability, assuming that market partic-
\n
ipants act in their economic best interest. Market partici-
\n
pants are independent, knowledgeable sellers and buyers
\n
who are able to enter into a transaction for the asset or the
\n
liability and who are motivated but not forced or otherwise
\n
compelled to do so.
\n
When measuring fair value, the Group considers the char-
\n
acteristics of the asset or liability, in particular:
\n
\u2022 for a non-financial asset, a fair value measurement takes
\n
into account a market participant\u2019s ability to generate
\n
economic benefits by using the asset in its highest and
\n
best use or by selling it to another market participant
\n
that would use the asset in its highest and best use;
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
\u2022 for liabilities and own equity instruments, the fair val-
\n
ue reflects the effect of non-performance risk, i.e., the
\n
risk that an entity will not fulfill an obligation, including
\n
among others the credit risk of the Group itself;
\n
\u2022 in the case of groups of financial assets and financial lia-
\n
bilities with offsetting positions in market risk or credit risk,
\n
managed on the basis of an entity\u2019s net exposure to such
\n
risks, it is permitted to measure fair value on a net basis.
\n
In measuring the fair value of assets and liabilities, the
\n
Group uses valuation techniques that are appropriate in
\n
the circumstances and for which sufficient data are avail-
\n
able, maximizing the use of relevant observable inputs and
\n
minimizing the use of unobservable inputs.
\n

\n\n\n

\n

\n

\n
Property, plant and equipment
\n
Property, plant and equipment is stated at cost, net of
\n
accumulated depreciation and accumulated impairment
\n
losses, if any. Such cost includes expenses directly attrib-
\n
utable to bringing the asset to the location and condition
\n
necessary for its intended use.
\n\n
The cost is also increased by the present value of the es-
\n
timate of the costs of decommissioning and restoring the
\n
site on which the asset is located where there is a legal
\n
or constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
The accounting treatment of changes in the estimate of
\n
these costs, the passage of time and the discount rate is
\n
discussed in note 40 \u201cProvisions for risks and charges\u201d.
\n

\n\n
Property, plant and equipment transferred from custom-
\n
ers to connect them to the electricity distribution network
\n
and/or to provide them with other related services is ini-
\n
tially recognized at its fair value at the date on which con-
\n
trol is obtained.
\n\n
Borrowing costs that are directly attributable to the ac-
\n
quisition, construction or production of a qualifying asset,
\n
i.e., an asset that takes a substantial period of time to get
\n
ready for its intended use or sale, are capitalized as part
\n
of the cost of the assets themselves. Borrowing costs as-
\n
sociated with the purchase/construction of assets that do
\n
not meet such requirement are expensed in the period in
\n
which they are incurred.
\n

\n\n
Certain assets that were revalued at the IFRS-EU transi-
\n
tion date or in previous periods are recognized at their fair
\n
value, which is considered to be their deemed cost at the
\n
revaluation date.
\n
Where individual items of major components of property,
\n
plant and equipment have different useful lives, the com-
\n
ponents are recognized and depreciated separately.
\n
Subsequent costs are recognized as an increase in the
\n
carrying amount of the asset when it is probable that fu-
\n
ture economic benefits associated with the cost incurred
\n
to replace a part of the asset will flow to the Group and the
\n
cost of the item can be measured reliably. All other costs
\n
are recognized in profit or loss as incurred.
\n
The cost of replacing part or all of an asset is recognized
\n
as an increase in the carrying amount of the asset and is
\n
depreciated over its useful life; the carrying amount of the
\n
replaced unit is derecognized through profit or loss.
\n\n
Property, plant and equipment, net of its residual value,
\n
is depreciated on a straight-line basis over its estimated
\n
useful life, which is reviewed annually. Any changes in de-
\n
preciation criteria shall be applied prospectively. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\n
Depreciation begins when the asset is available for use.
\n
The estimated useful life of the main items of property,
\n
plant and equipment is as follows:
\n
Civil buildings 10-60 years
\n
Buildings and civil works incorporated in plants 10-100 years
\n
Hydroelectric power plants:
\n
- penstock 10-65 years
\n
- mechanical and electrical machinery 10-65 years
\n
- other fixed hydraulic works 10-100 years
\n
Thermal power plants:
\n
- boilers and auxiliary components 20-40 years
\n
- gas turbine components 10-40 years
\n
- mechanical and electrical machinery 5-40 years
\n
- other fixed hydraulic works 60 years
\n
Nuclear power plants 50 years
\n
Geothermal power plants:
\n
- cooling towers 20 years
\n
- turbines and generators 10-50 years
\n
- turbine parts in contact with fluid 10 years
\n
- mechanical and electrical machinery 20-40 years
\n
Wind power plants:
\n
- towers 20-30 years
\n
- turbines and generators 20-30 years
\n
- mechanical and electrical machinery 15-30 years
\n
Solar power plants:
\n
- mechanical and electrical machinery 15-30 years
\n
Public and artistic lighting:
\n
- public lighting installations 10-20 years
\n
- artistic lighting installations 20 years
\n
Transport lines 10-60 years
\n
Transformer stations 20-55 years
\n
Distribution plants:
\n
- high-voltage lines 10-60 years
\n
- primary transformer stations 10-50 years
\n
- low and medium-voltage lines 10-50 years
\n
Meters:
\n
- electromechanical meters 5-40 years
\n
- electricity balance measurement equipment 10 years
\n
- electronic meters 15 years
\n
Charging stations 7-15 years
\n

\n\n

\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n\n
The useful life of leasehold improvements is determined
\n
on the basis of the term of the lease or, if shorter, on the
\n
duration of the benefits produced by the improvements
\n
themselves.
\n
Land is not depreciated as it has an indefinite useful life.
\n

\n\n
Assets recognized under property, plant and equipment
\n
are derecognized either upon their disposal (i.e., at the
\n
date the recipient obtains control) or when no future eco-
\n
nomic benefit is expected from their use or disposal. Any
\n
gain or loss, recognized through profit or loss, is calculat-
\n
ed as the difference between the net disposal proceeds,
\n
determined in accordance with the transaction price re-
\n
quirements of IFRS 15, and the carrying amount of the
\n
derecognized assets.
\n

\n\n
Assets to be relinquished free of charge
\n
The Group\u2019s plants include assets to be relinquished free
\n
of charge at the end of the concessions. These mainly
\n
regard major water diversion works and the public lands
\n
used for the operation of the thermal power plants.
\n
Within the Italian regulatory framework in force until 2011,
\n
if the concessions are not renewed, at those dates all in-
\n
take and governing works, penstocks, outflow channels
\n
and other assets on public lands were to be relinquished
\n
free of charge to the State in good operating condition.
\n
Accordingly, depreciation on assets to be relinquished was
\n
calculated over the shorter of the term of the concession
\n
and the useful life of the assets.
\n
In the wake of the legislative changes introduced with Law
\n
134 of August 7, 2012, the assets previously classified as
\n
assets \u201cto be relinquished free of charge\u201d connected with
\n
the hydroelectric water diversion concessions are now
\n
considered in the same manner as other categories of
\n
\u201cProperty, plant and equipment\u201d and are therefore depre-
\n
ciated over the useful life of the asset (where this exceeds
\n
the term of the concession), as discussed in the section
\n
above on the \u201cDepreciable amount of certain elements of
\n
Italian hydroelectric plants subsequent to enactment of
\n
Law 134/2012\u201d, which you are invited to consult for more
\n
details.
\n
In accordance with Spanish laws 29/1985 and 46/1999,
\n
hydroelectric power stations in Spanish territory operate
\n
under administrative concessions at the end of which the
\n
plants will be returned to the government in good oper-
\n
ating condition. The terms of the concessions extend up
\n
to 2078.
\n
A number of generation companies that operate in Lat-
\n
in America hold administrative concessions with similar
\n
conditions to those applied under the Spanish concession
\n
system. These concessions will expire in Argentina in 2087,
\n
in Brazil in 2047, in Costa Rica in 2031, in Panama in 2060
\n
and in Guatemala in 2062.
\n\n
Infrastructure serving a concession not within the scope
\n
of \u201cIFRIC 12 - Service concession arrangements\u201d
\n
As regards the distribution of electricity, the Group is a
\n
concession holder in Italy for this service. The concession,
\n
granted by the Ministry for Economic Development, was
\n
issued free of charge and terminates on December 31,
\n
2030. If the concession is not renewed upon expiry, the
\n
grantor is required to pay an indemnity. The amount of the
\n
indemnity will be determined by agreement of the parties
\n
using appropriate valuation methods, based on both the
\n
carrying amount of the assets themselves and their prof-
\n
itability.
\n
In determining the indemnity, such profitability will be rep-
\n
resented by the present value of future cash flows. The in-
\n
frastructure serving the concession is owned and available
\n
to the concession holder. It is recognized under \u201cProperty,
\n
plant and equipment\u201d and is depreciated over the useful
\n
lives of the assets.
\n
Enel also operates under administrative concessions for
\n
the distribution of electricity in other countries (including
\n
Spain and Romania). These concessions give the right to
\n
build and operate distribution networks for an indefinite
\n
period of time.
\n

\n\n\n
Infrastructure within the scope of \u201cIFRIC 12 -
\n
Service concession arrangements\u201d
\n
Under a \u201cpublic-to-private\u201d service concession arrange-
\n
ment within the scope of \u201cIFRIC 12 - Service concession
\n
arrangements\u201d the operator acts as a service provider and,
\n
in accordance with the terms specified in the contract, it
\n
constructs/upgrades infrastructure used to provide a
\n
public service and/or operates and maintains that infra-
\n
structure for the years of the concession.
\n
The Group, as operator, does not account for the infra-
\n
structure within the scope of IFRIC 12 as property, plant
\n
and equipment and it recognizes and measures revenue
\n
in accordance with IFRS 15 for the services it performs. In
\n
particular, when the Group provides construction or up-
\n
grade services, depending on the characteristics of the
\n
service concession arrangement, it recognizes:
\n
\u2022 a financial asset, if the Group has an unconditional con-
\n
tractual right to receive cash or another financial asset
\n
from the grantor (or from a third party at the direction
\n
of the grantor), that is the grantor has little discretion
\n
to avoid payment. In this case, the grantor contractually
\n
guarantees to pay to the operator specified or deter-
\n
minable amounts or the shortfall between the amounts
\n
received from the users of the public service and spec-
\n
ified or determinable amounts (defined by the contract),
\n
and such payments are not dependent on the usage of
\n
the infrastructure; and/or
\n
\u2022 an intangible asset, if the Group receives the right (a li-
\n
cense) to charge users of the public service provided. In
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
such a case, the operator does not have an uncondition-
\n
al right to receive cash because the amounts are contin-
\n
gent on the extent that the public uses the service.
\n
If the Group (as operator) has a contractual right to re-
\n
ceive an intangible asset (a right to charge users of public
\n
service), borrowing costs are capitalized using the criteria
\n
specified in note 19 \u201cProperty, plant and equipment\u201d.
\n
However, for construction/upgrade services, both types of
\n
consideration are classified as a contract asset during the
\n
construction/upgrade period.
\n
For more details about such consideration, please see
\n
note 11.a \u201cRevenue from sales and services\u201d.
\n

\n\n\n
Leases
\n
The Group holds property, plant and equipment for its
\n
various activities under lease contracts. At inception of
\n
a contract, the Group assesses whether a contract is, or
\n
contains, a lease.
\n
For contracts entered into or changed on or after January
\n
1, 2019, the Group has applied the definition of a lease un-
\n
der IFRS 16, that is met if the contract conveys the right to
\n
control the use of an identified asset for a period of time in
\n
exchange for consideration.
\n
Conversely, for contracts entered into before January 1,
\n
2019, the Group determined whether the arrangement
\n
was or contained a lease under IFRIC 4.
\n
Group as a lessee
\n
At commencement or on modification of a contract that
\n
contains a lease component
\n
and one or more additional
\n
lease or non-lease components
\n
, the Group allocates the
\n
consideration in the contract to each lease component on
\n
the basis of its relative stand-alone price.
\n
The Group recognizes a right-of-use asset and a lease lia-
\n
bility at the commencement date of the lease (i.e., the date
\n
the underlying asset is available for use).
\n
The right-of-use asset represents a lessee\u2019s right to use an
\n
underlying asset for the lease term; it is initially measured
\n
at cost, which includes the initial amount of lease liabili-
\n
ty adjusted for any lease payments made at or before the
\n
commencement date less any lease incentives received,
\n
plus any initial direct costs incurred and an estimate of
\n
costs to retire and remove the underlying asset and to re-
\n
store the underlying asset or the site on which it is located.
\n
Right-of-use assets are subsequently depreciated on a
\n
straight-line basis over the shorter of the lease term and
\n
the estimated useful lives of the right-of-use assets, as
\n
follows:
\n
Average residual life (years)
\n
Buildings 6
\n
Ground rights of renewable energy plants 31
\n
Vehicles and other means of transport 5
\n
If the lease transfers ownership of the underlying asset to
\n
the Group at the end of the lease term or if the cost of the
\n
right-of-use asset
\n
reflects the fact that the Group will exer-
\n
cise a purchase option, depreciation is calculated using the
\n
estimated useful life of the underlying asset.
\n
In addition, the right-of-use assets are subject to impair-
\n
ment and adjusted for any remeasurement of lease liabili-
\n
ties.
\n
The lease liability is initially measured at the present value of
\n
lease payments to be made over the lease term. In calcu-
\n
lating the present value of lease payments, the Group uses
\n
the lessee\u2019s incremental borrowing rate at the lease com-
\n
mencement date when the interest rate implicit in the lease
\n
is not readily determinable.
\n
Variable lease payments that do not depend on an index or
\n
a rate are recognized as expenses in the period in which the
\n
event or condition that triggers the payment occurs.
\n
After the commencement date, the lease liability is mea-
\n
sured at amortized cost using the effective interest method
\n
and is remeasured upon the occurrence of certain events.
\n
The Group applies the short-term lease recognition ex-
\n
emption to its lease contracts that have a lease term of 12
\n
months or less from the commencement date. It also ap-
\n
plies the low-value assets recognition exemption to lease
\n
contracts for which the underlying asset is of low-value
\n
whose amount is estimated not material. For example, the
\n
Group has leases of certain office equipment (i.e., personal
\n
computers, printing and photocopying machines) that are
\n
considered of low-value. Lease payments on short-term
\n
leases and leases of low-value assets are recognized as
\n
expense on a straight-line basis over the lease term.
\n
The Group presents right-of-use assets that do not meet
\n
the definition of investment property in \u201cProperty, plant
\n
and equipment\u201d and lease liabilities in \u201cBorrowings\u201d.
\n
Consistent with the requirement of the standard, the
\n
Group presents separately the interest expense on lease
\n
liabilities under \u201cOther financial expense\u201d and the depreci-
\n
ation charge on the right-of-use assets under \u201cDeprecia-
\n
tion, amortization and impairment losses\u201d.
\n
Group as a lessor
\n
When the Group acts as a lessor, it determines at the lease
\n
inception date whether each lease is a finance lease or an
\n
operating lease.
\n
Leases in which the Group essentially transfers all the risks
\n
and rewards associated with ownership of the underlying
\n
asset are classified as finance leases; otherwise, they are
\n
classified as operating leases. To make this assessment, the
\n
Group considers the indicators provided by IFRS 16. If a con-
\n
tract contains lease and non-lease components, the Group
\n
allocates the consideration in the contract applying IFRS 15.
\n
The Group accounts for rental income arising from oper-
\n
ating leases on a straight-line basis over the lease terms
\n
and it recognizes it as other revenue.
\n

\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
Investment property
\n
Investment property consists of the Group\u2019s real estate
\n
held to earn rentals and/or for capital appreciation rath-
\n
er than for use in the production or supply of goods and
\n
services.
\n
Investment property is measured at acquisition cost less
\n
any accumulated depreciation and any accumulated im-
\n
pairment losses.
\n
Investment property, excluding land, is depreciated on a
\n
straight-line basis over the useful lives of the related as-
\n
sets.
\n
Impairment losses are determined on the basis of the cri-
\n
teria following described.
\n
The breakdown of the fair value of investment property is
\n
detailed in note 52 \u201cAssets and liabilities measured at fair
\n
value\u201d.
\n
Investment property is derecognized either when it has
\n
been transferred (i.e., at the date the recipient obtains
\n
control) or when it is permanently withdrawn from use
\n
and no future economic benefit is expected from its dis-
\n
posal. Any gain or loss, recognized through profit or loss,
\n
is calculated as the difference between the net disposal
\n
proceeds, determined in accordance with the transaction
\n
price requirements of IFRS 15, and the carrying amount of
\n
the derecognized assets.
\n
Transfers are made to (or from) investment property only
\n
when there is a change in use.
\n

\n\n\n

\n

\n\n

\n
Intangible assets
\n
Intangible assets are identifiable assets without physical
\n
substance controlled by the Group and capable of gen-
\n
erating future economic benefits. They are measured at
\n
purchase or internal development cost when it is probable
\n
that the use of such assets will generate future economic
\n
benefits and the related cost can be reliably determined.
\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n\n
Development expenditure is recognized as an intangible
\n
asset only when Group can demonstrate the technical fea-
\n
sibility of completing the asset, its intention and ability to
\n
complete development and to use or sell the asset and the
\n
availability of resources to complete the asset.
\n
Research costs are recognized as expenses.
\n

\n\n
Intangible assets with a finite useful life are recognized net
\n
of accumulated amortization and any impairment losses.
\n
Amortization is calculated on a straight-line basis over the
\n
asset\u2019s estimated useful life, which is reassessed at least
\n
annually; any changes in amortization policies are reflected
\n
on a prospective basis. For more information on estimating
\n
useful life, please see note 2.1 \u201cUse of estimates and man-
\n
agement judgment\u201d.
\n
Amortization commences when the asset is ready for use.
\n
Consequently, intangible assets not yet available for use
\n
are not amortized, but are tested for impairment at least
\n
annually.
\n
The Group\u2019s intangible assets have a finite useful life, with the
\n
exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amortized,
\n
but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annually
\n
to determine whether the indefinite useful life continues to
\n
be supportable. If not, the change in useful life from indefinite
\n
to finite is accounted for as a change in accounting estimate.
\n
Intangible assets are derecognized either at the time of
\n
their disposal (at the date when the recipient obtains con-
\n
trol) or when no future economic benefit is expected from
\n
their use or disposal. Any gain or loss, recognized through
\n
profit or loss, is calculated as the difference between the
\n
net consideration received in the disposal, determined
\n
in accordance with the provisions of IFRS 15 concern-
\n
ing the transaction price, and the carrying amount of the
\n
derecognized assets.
\n
The estimated useful life of the main intangible assets,
\n
distinguishing between internally generated and acquired
\n
assets, is as follows:
\n
Development expenditure:
\n
- internally generated 5 years
\n
- acquired 3-26 years
\n
Industrial patents and intellectual property rights:
\n
- internally generated 3-10 years
\n
- acquired 3-10 years
\n
Concessions, licenses, trademarks and similar rights:
\n
- internally generated 20 years
\n
- acquired 10-18 years
\n
Other:
\n
- internally generated 2-28 years
\n
- acquired 3-15 years
\n
The Group also presents costs to obtain a contract with a
\n
customer capitalized in accordance with IFRS 15 as intan-
\n
gible assets.
\n
The Group recognized such costs as an asset only if:
\n
\u2022 the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group would
\n
not have incurred them if the contract had not been ob-
\n
tained;
\n
\u2022 the Group expects to recover them, through reimburse-
\n
ments (direct recoverability) or the margin (indirect re-
\n
coverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the cap-
\n
italization criteria are met.
\n
Capitalized customer contract costs are amortized on a
\n
systematic basis, consistent with the pattern of the trans-
\n
fer of the goods or services to which they relate, and un-
\n
dergo impairment testing to identify any impairment loss-
\n
es to the extent that the carrying amount of the asset rec-
\n
ognized exceeds the recoverable amount.
\n

\n

\n\n

\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n\n

\n\n
The Group amortizes the capitalized customer contract
\n
costs
\n
on a straight-line basis over the expected period of
\n
benefit from the contract (i.e., the average term of the cus-
\n
tomer relationship);
\n
any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n

\n

\n\n\n

\n\n

\n\n
Goodwill
\n
Goodwill represents the future economic benefits arising
\n
from other assets acquired in a business combination that
\n
are not individually identified and separately recognized.
\n
For further details, please see the section of the account-
\n
ing policies \u201cBusiness combinations\u201d.
\n
Goodwill arising on the acquisition of subsidiaries is rec-
\n
ognized separately. After initial recognition, goodwill is not
\n
amortized, but is tested for impairment at least annually as
\n
part of the CGU to which it pertains.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU that is expect-
\n
ed to benefit from the synergies of the combination.
\n
Goodwill relating to equity investments in associates and
\n
joint venture is included in their carrying amount.
\n

\n\n

\n\n

\n\n\n

\n\n
Impairment of non-financial assets
\n
At each reporting date, property, plant and equipment, in-
\n
vestment property, intangible assets, right-of-use assets,
\n
goodwill and equity investments in associates/joint ven-
\n
tures are reviewed to determine whether there is evidence
\n
of impairment.
\n
CGUs to which goodwill, intangible assets with an indef-
\n
inite useful life and intangible assets not yet available for
\n
use are allocated are tested for recoverability annually or
\n
more frequently if there is evidence suggesting that the
\n
assets can be impaired.
\n
If such evidence exists, the recoverable amount of any in-
\n
volved asset is estimated on the basis of the use of the as-
\n
set and its future disposal, in accordance with the Group\u2019s
\n
most recent Business Plan. For the estimate of the recov-
\n
erable amount, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The recoverable amount is determined for an individual as-
\n
set, unless the asset do not generate cash inflows that are
\n
largely independent of those from other assets or groups
\n
of assets and therefore it is determined for the CGU to
\n
which the asset belongs.
\n
If the carrying amount of an asset or of a CGU to which it
\n
is allocated is greater than its recoverable amount, an im-
\n
pairment loss is recognized in profit or loss and presented
\n
under \u201cDepreciation, amortization and other impairment
\n
losses\u201d.
\n
Impairment losses of CGUs are firstly charged against the
\n
carrying amount of any goodwill attributed to it and then
\n
against the other assets, in proportion to their carrying
\n
amount.
\n
If the reasons for a previously recognized impairment loss
\n
no longer apply, the carrying amount of the asset is restored
\n
through profit or loss, under \u201cDepreciation, amortization
\n
and other impairment losses\u201d, in an amount that shall not
\n
exceed the carrying amount that the asset would have had
\n
if the impairment loss had not been recognized. The origi-
\n
nal amount of goodwill is not restored even if in subsequent
\n
years the reasons for the impairment no longer apply.
\n
If certain specific identified assets owned by the Group are
\n
impacted by adverse economic or operating conditions
\n
that undermine their capacity to contribute to the gener-
\n
ation of cash flows, they can be isolated from the rest of
\n
the assets of the CGU, undergo separate analysis of their
\n
recoverability and be impaired where necessary.
\n

\n

\n\n

\n

\n\n\n

\n
Inventories
\n
Inventories are measured at the lower of cost and net re-
\n
alizable value except for inventories involved in trading ac-
\n
tivities, which are measured at fair value with recognition
\n
through profit or loss. Cost is determined on the basis of
\n
average weighted cost, which includes related ancillary
\n
charges. Net estimated realizable value is the estimated
\n
normal selling price net of estimated costs to sell or, where
\n
applicable, replacement cost.
\n
For the portion of inventories held to discharge sales that
\n
have already been made, the net realizable value is deter-
\n
mined on the basis of the amount established in the con-
\n
tract of sale.
\n\n
Inventories include environmental certificates (for example,
\n
green certificates, energy efficiency certificates and Euro-
\n
pean CO
\n
2
\n
emissions allowances and guarantees of origin)
\n
exceeding compliance in the reporting period. As regards
\n
CO
\n
2
\n
emissions allowances, inventories are allocated be-
\n
tween the trading portfolio and the compliance portfolio,
\n
i.e., those used for compliance with greenhouse gas emis-
\n
sions requirements.
\n

\n

\n\n
Inventories also include nuclear fuel stocks, use of which is
\n
determined on the basis of the electricity generated.
\n
Materials and other consumables (including energy com-
\n
modities) held for use in production are not written down
\n
if it is expected that the final product in which they will be
\n
incorporated will be sold at a price sufficient to enable re-
\n
covery of the cost incurred.
\n

\n

\n\n\n
Financial instruments
\n
Financial instruments are any contract that gives rise to a
\n
financial asset of one entity and a financial liability or eq-
\n
uity instrument of another entity; they are recognized and
\n
measured in accordance with IAS 32 and IFRS 9.
\n
A financial asset or liability is recognized in the consolidat-
\n
ed financial statements when, and only when, the Group
\n
becomes party to the contractual provision of the instru-
\n
ment (i.e., the trade date).
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n

\n\n

\n
Trade receivables arising from contracts with customers, in
\n
the scope of IFRS 15, are initially measured at their trans-
\n
action price (as defined in IFRS 15) if such receivables do
\n
not contain a significant financing component or when the
\n
Group applies the practical expedient allowed by IFRS 15.
\n
Conversely, the Group initially measures financial assets
\n
other than the above-mentioned trade receivables at their
\n
fair value plus, in the case of a financial asset not measured
\n
at fair value through profit or loss, transaction costs.
\n
Financial assets are classified, at initial recognition, as fi-
\n
nancial assets at amortized cost, at fair value through oth-
\n
er comprehensive income and at fair value through profit
\n
or loss, on the basis of both the Group\u2019s business model
\n
and the contractual cash-flow characteristics of the in-
\n
strument.
\n
For this purpose, the assessment to determine whether
\n
the instrument gives rise to cash flows that are solely pay-
\n
ments of principal and interest (SPPI) on the principal amount
\n
outstanding is referred to as the SPPI test and is performed at
\n
an instrument level.
\n
The Group\u2019s business model for managing financial assets
\n
refers to how it manages its financial assets in order to gener-
\n
ate cash flows. The business model determines whether cash
\n
flows will result from collecting contractual cash flows, selling
\n
the financial assets, or both.
\n
For purposes of subsequent measurement, financial assets
\n
are classified in four categories:
\n
\u2022 financial assets measured at amortized cost (debt instru-
\n
ments);
\n
\u2022 financial assets at fair value through OCI with reclassifica-
\n
tion of cumulative gains and losses (debt instruments);
\n
\u2022 financial assets designated at fair value through OCI with
\n
no reclassification of cumulative gains and losses upon
\n
derecognition (equity instruments); and
\n
\u2022 financial assets at fair value through profit or loss.
\n

\n\n

\n

\n

\n

\n\n
Financial assets measured at amortized cost
\n
This category mainly includes trade receivables, other fi-
\n
nancial assets and loan assets.
\n
Financial assets at amortized cost are held within a busi-
\n
ness model whose objective is to hold financial assets in
\n
order to collect contractual cash flows and whose con-
\n
tractual terms give rise, on specified dates, to cash flows
\n
that are solely payments of principal and interest on the
\n
principal amount outstanding.
\n
Such assets are initially recognized at fair value, adjusted
\n
for any transaction costs, and subsequently measured at
\n
amortized cost using the effective interest method and are
\n
subject to impairment.
\n
Gains and losses are recognized in profit or loss when the
\n
asset is derecognized, modified or impaired.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Debt instruments
\n
This category mainly includes:
\n
\u2022 listed debt securities held by the Group reinsurance
\n
company and not classified as held for trading; and
\n
\u2022 tax credits deriving from application of Decree Law
\n
34/2020 (so-called \u201cRevival Decree\u201d).
\n
Financial assets at fair value through other comprehensive
\n
income are assets held within a business model whose
\n
objective is achieved by both collecting contractual cash
\n
flows and selling financial assets and whose contractual
\n
cash flows give rise, on specified dates, to cash flows that
\n
are solely payments of principal and interest on the princi-
\n
pal amount outstanding.
\n
Changes in fair value for these financial assets are recog-
\n
nized in other comprehensive income as well as loss al-
\n
lowances that do not reduce the carrying amount of the
\n
financial assets.
\n
When a financial asset is derecognized (e.g., at the time
\n
of sale), the cumulative gains and losses previously recog-
\n
nized in equity (except impairment and foreign exchange
\n
gains and losses to be recognized in profit or loss) are re-
\n
versed to profit or loss.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Equity instruments
\n
This category includes mainly equity investments in other
\n
entities irrevocably designated as such upon initial recog-
\n
nition.
\n
Gains and losses on these financial assets are never reclas-
\n
sified to profit or loss. The Group may transfer the cumula-
\n
tive gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of the
\n
cost of the investment.
\n

\n\n

\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes: securities, equity invest-
\n
ments in other companies, financial investments in fund
\n
held for trading and financial assets designated as at fair
\n
value through profit or loss at initial recognition.
\n
Financial assets at fair value through profit or loss are:
\n
\u2022 financial assets with cash flows that are not solely pay-
\n
ments of principal and interest, irrespective of the busi-
\n
ness model;
\n
\u2022 financial assets held for trading because acquired or
\n
incurred principally for the purpose of selling or repur-
\n
chasing in short term;
\n

\n\n

\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n\n

\n\n
\u2022 debt instruments designated upon initial recognition,
\n
under the option allowed by IFRS 9 (fair value option),
\n
if doing so eliminates, or significantly reduces, an ac-
\n
counting mismatch;
\n
\u2022 derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments.
\n
Such financial assets are initially recognized at fair value
\n
with subsequent gains and losses from changes in their
\n
fair value recognized through profit or loss.
\n
This category also includes listed equity investments
\n
which the Group had not irrevocably elected to classify at
\n
fair value through OCI. Dividends on such investments are
\n
also recognized as other income in the income statement
\n
when the right of payment has been established.
\n
Financial assets that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n\n

\n\n

\n\n
Impairment of financial assets
\n
At each reporting date, the Group recognizes a loss allow-
\n
ance for expected credit losses on trade receivables and
\n
other financial assets measured at amortized cost, debt
\n
instruments measured at fair value through other com-
\n
prehensive income (FVOCI), contract assets and all other
\n
assets within the scope of IFRS 9.
\n
In compliance with IFRS 9, as from January 1, 2018, the
\n
Group adopted a new impairment model based on the
\n
determination of expected credit losses (ECL) using a for-
\n
ward-looking approach. In essence, the model provides
\n
for:
\n
\u2022 the application of a single framework for all financial as-
\n
sets;
\n
\u2022 the recognition of expected credit losses on an ongoing
\n
basis and the updating of the amount of such losses at
\n
the end of each reporting period, reflecting changes in
\n
the credit risk of the financial instrument;
\n
\u2022 the measurement of expected losses on the basis of
\n
reasonable information, obtainable without undue cost,
\n
about past events, current conditions and forecasts of
\n
future conditions.
\n
For trade receivables, contract assets and lease receiv-
\n
ables, including those with a significant financial compo-
\n
nent, the Group adopts the simplified approach, determin-
\n
ing expected credit losses over a period corresponding to
\n
the entire life of the asset, generally equal to 12 months.
\n
For all financial assets other than trade receivables, con-
\n
tract assets and lease receivables, the Group applies the
\n
general approach under IFRS 9, based on the assessment
\n
of a significant increase in credit risk since initial recogni-
\n
tion. Under such approach, a loss allowance on financial
\n
assets is recognized at an amount equal to the lifetime
\n
expected credit losses, if the credit risk on those financial
\n
assets has increased significantly, since initial recognition,
\n
considering all reasonable and supportable information,
\n
including also forward-looking inputs.
\n
If at the reporting date the credit risk on financial assets
\n
has not increased significantly since initial recognition,
\n
the Group measures the loss allowance for those financial
\n
assets at an amount equal to 12-month expected credit
\n
losses.
\n
For financial assets on which a loss allowance equal to life-
\n
time expected credit losses has been recognized in the
\n
previous reporting period, the Group measures the loss al-
\n
lowance at an amount equal to 12-month expected credit
\n
losses when the condition regarding a significant increase
\n
in credit risk is no longer met.
\n
The Group recognizes in profit or loss, as an impairment
\n
gain or loss, the amount of expected credit losses (or re-
\n
versal) that is required to adjust the loss allowance at the
\n
reporting date to the amount that is required to be recog-
\n
nized in accordance with IFRS 9.
\n
The Group applies the low credit risk exemption, avoid-
\n
ing the recognition of loss allowances at an amount equal
\n
to lifetime expected credit losses due to a significant in-
\n
crease in credit risk of debt securities at fair value through
\n
OCI, whose counterparty has a strong financial capacity
\n
to meet its contractual cash-flow obligations (e.g., invest-
\n
ment grade).
\n
For more information on the impairment of financial as-
\n
sets, please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n

\n

\n\n

\n

\n\n

\n

\n\n\n
Cash and cash equivalents
\n
This category includes deposits that are available on de-
\n
mand or at very short term, as well as highly liquid short-
\n
term financial investments that are readily convertible into
\n
a known amount of cash and which are subject to insignif-
\n
icant risk of changes in value.
\n
In addition, for the purpose of the consolidated statement
\n
of cash flows, cash and cash equivalents do not include
\n
bank overdrafts at period-end.
\n

\n\n\n

\n\n

\n\n
Financial liabilities at amortized cost
\n
This category mainly includes borrowings, trade payables,
\n
lease liabilities and debt instruments.
\n
Financial liabilities, other than derivatives, are recognized
\n
when the Group becomes a party to the contractual claus-
\n
es of the instrument and are initially measured at fair value
\n
adjusted for directly attributable transaction costs. Finan-
\n
cial liabilities are subsequently measured at amortized cost
\n
using the effective interest rate method. The effective in-
\n
terest rate is the rate that exactly discounts the estimated
\n
future cash payments or receipts over the expected life
\n
of the financial instrument or a shorter period, where ap-
\n
propriate, to the carrying amount of the financial asset or
\n
liability.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n\n

\n\n
Financial liabilities at fair value through profit or loss
\n
Financial liabilities at fair value through profit or loss in-
\n
clude financial liabilities held for trading and financial lia-
\n
bilities designated upon initial recognition as at fair value
\n
through profit or loss.
\n
Financial liabilities are classified as held for trading if they
\n
are incurred for the purpose of repurchasing in the near
\n
term. This category also includes derivative financial in-
\n
struments entered into by the Group that are not desig-
\n
nated as hedging instruments in hedge relationships as
\n
defined by IFRS 9. Separated embedded derivatives are
\n
also classified as at fair value through profit or loss unless
\n
they are designated as effective hedging instruments.
\n
Gains or losses on liabilities at fair value through profit or
\n
loss are recognized through profit or loss.
\n
Financial liabilities designated upon initial recognition at
\n
fair value through profit or loss are designated at the initial
\n
date of recognition, only if the criteria in IFRS 9 are satis-
\n
fied.
\n
In this case, the portion of the change in fair value attribut-
\n
able to own credit risk is recognized in other comprehen-
\n
sive income.
\n
The Group has not designated any financial liability as at
\n
fair value through profit or loss, upon initial recognition.
\n
Financial liabilities that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n\n

\n\n

\n\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022 the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022 the Group has transferred substantially all the risks and
\n
rewards associated with the asset, transferring its rights
\n
to receive the cash flows of the asset or assuming a con-
\n
tractual obligation to pay such cash flows to one or more
\n
beneficiaries under a contract that meets the require-
\n
ments provided by IFRS 9 (the \u201cpass through test\u201d);
\n
\u2022 the Group has not transferred or retained substantially
\n
all the risks and rewards associated with the asset but
\n
has transferred control over the asset.
\n
Financial liabilities are derecognized when they are extin-
\n
guished, i.e., when the contractual obligation has been dis-
\n
charged, cancelled or expired.
\n
When an existing financial liability is replaced by another
\n
from the same lender on substantially different terms, or
\n
the terms of an existing liability are substantially modi-
\n
fied, such an exchange or modification is treated as the
\n
derecognition of the original liability and the recognition
\n
of a new liability. The difference in the respective carrying
\n
amounts is recognized in profit or loss.
\n

\n\n

\n\n

\n\n\n

\n\n

\n\n
Derivative financial instruments
\n
A derivative is a financial instrument or another contract:
\n
\u2022 whose value changes in response to the changes in an
\n
underlying variable such as an interest rate, commodity
\n
or security price, foreign exchange rate, a price or rate
\n
index, a credit rating or other variable;
\n
\u2022 that requires no initial net investment, or one that is
\n
smaller than would be required for a contract with similar
\n
response to changes in market factors;
\n
\u2022 that is settled at a future date.
\n
Derivative instruments are classified as financial assets or
\n
liabilities depending on the positive or negative fair value
\n
and they are classified as \u201cheld for trading\u201d within \u201cOther
\n
business models\u201d and measured at fair value through prof-
\n
it or loss, except for those designated as effective hedging
\n
instruments.
\n
All derivatives held for trading are classified as current as-
\n
sets or liabilities.
\n
Derivatives not held for trading purposes, but measured at
\n
fair value through profit or loss since they do not qualify for
\n
hedge accounting, and derivatives designated as effective
\n
hedging instruments are classified as current or not cur-
\n
rent on the basis of their maturity date and the Group in-
\n
tention to hold the financial instrument till maturity or not.
\n
For more details about derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n\n
Embedded derivatives
\n
An embedded derivative is a derivative included in a \u201ccom-
\n
bined\u201d contract (the so-called \u201chybrid instrument\u201d) that
\n
contains another non-derivative contract (the so-called
\n
host contract) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows.
\n
The main Group contracts that may contain embedded
\n
derivatives are contracts to buy or sell non-financial items
\n
with clauses or options that affect the contract price, vol-
\n
ume or maturity.
\n
A derivative embedded in a hybrid contract containing a
\n
financial asset host is not accounted for separately. The fi-
\n
nancial asset host together with the embedded derivative
\n
is required to be classified in its entirety as a financial asset
\n
at fair value through profit or loss.
\n
Contracts that do not represent financial instruments to
\n
be measured at fair value are analyzed in order to identify
\n
any embedded derivatives, which are to be separated and
\n
measured at fair value. This analysis is performed when the
\n
Group becomes party to the contract or when the contract
\n
is renegotiated in a manner that significantly changes the
\n
original associated cash flows.
\n
Embedded derivatives are separated from the host con-
\n
tract and accounted for as derivatives when:
\n
\u2022 the host contract is not a financial instrument measured
\n
at fair value through profit or loss;
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n\n
\u2022 the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the host
\n
contract;
\n
\u2022 a separate contract with the same terms as the embed-
\n
ded derivative would meet the definition of a derivative.
\n
Embedded derivatives that are separated from the host
\n
contract are recognized in the consolidated financial
\n
statements at fair value with changes recognized in profit
\n
or loss (except when the embedded derivative is part of a
\n
designated hedge relationship).
\n

\n\n\n
Contracts to buy or sell non-financial items
\n
In general, contracts to buy or sell non-financial items that
\n
are entered into and continue to be held for receipt or
\n
delivery in accordance with the Group\u2019s normal expected
\n
purchase, sale or usage requirements are out of the scope
\n
of IFRS 9 and then recognized as executory contracts, ac-
\n
cording to the \u201cown use exemption\u201d.
\n
A contract to buy or sell non-financial items is classified as
\n
\u201cnormal purchase or sale\u201d if it is entered into:
\n
\u2022 for the purpose of the physical settlement;
\n
\u2022 in accordance with the entity\u2019s expected purchase, sale
\n
or usage requirements.
\n
Moreover, contracts to buy or sell non-financial items with
\n
physical settlement (for example, fixed-price forward con-
\n
tracts on energy commodities) that do not qualify for the
\n
own use exemption are recognized as derivatives mea-
\n
sured at fair value from the trade date only if:
\n
\u2022 they can be settled net in cash; and
\n
\u2022 they are not entered into in accordance with the Group\u2019s
\n
expected purchase, sale or usage requirements.
\n
Trading contracts are valued at fair value through profit or
\n
loss; the results of the measurement of changes in the fair
\n
value of contracts still outstanding at the reporting date
\n
are recognized on a net basis under the item \u201cNet results
\n
from commodity contracts\u201d, while at the settlement date:
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the sale of energy com-
\n
modities as well as the related revenue, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cRevenue from sales
\n
and services\u201d;
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the purchase of energy
\n
commodities as well as the related cost, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cElectricity, gas and
\n
fuel\u201d and \u201cServices and other materials\u201d.
\n
Contracts to buy or sell non-financial items falling with-
\n
in the scope of application of IFRS 9 can also be subse-
\n
quently designated as hedging instruments if they satisfy
\n
the requirements for hedge accounting.
\n
The Group analyzes all contracts to buy or sell non-fi-
\n
nancial assets on an ongoing basis, with a specific focus
\n
on forward purchases and sales of electricity and energy
\n
commodities, in order to determine if they shall be classi-
\n
fied and treated in accordance with IFRS 9 or if they have
\n
been entered into for \u201cown use\u201d.
\n

\n

\n\n\n
Offsetting financial assets and liabilities
\n
The Group offsets financial assets and liabilities when:
\n
\u2022 there is a legally enforceable right to set off the recog-
\n
nized amounts; and
\n
\u2022 there is the intention of settling on a net basis or realiz-
\n
ing the asset and settling the liability simultaneously.
\n

\n\n
Hyperinflation
\n
In a hyperinflationary economy, the Group adjusts
\n
non-monetary items, equity and items deriving from in-
\n
dex-linked contracts up to the limit of recoverable amount,
\n
using a price index that reflects changes in general pur-
\n
chasing power.
\n
The effects of initial application are recognized in equity
\n
net of tax effects. Conversely, during the hyperinflation-
\n
ary period (until it ceases), the gain or loss resulting from
\n
adjustments is recognized in profit or loss and disclosed
\n
separately in financial income and expense.
\n
Starting from 2018, this standard applies to the Group\u2019s
\n
transactions in Argentina, whose economy has been de-
\n
clared hyperinflationary from July 1, 2018.
\n\n

\n
Non-current assets (or disposal groups)
\n
classified as held for sale and discontinued
\n
operations
\n\n
Non-current assets (or disposal groups) are classified as
\n
held for sale if their carrying amount will be recovered
\n
principally through a sale transaction, rather than through
\n
continuing use.
\n
This classification criterion is applicable only when
\n
non-current assets (or disposal groups) are available in
\n
their present condition for immediate sale and the sale is
\n
highly probable.
\n
If the Group is committed to a sale plan involving loss of
\n
control of a subsidiary and the requirements provided for
\n
under IFRS 5 are met, all the assets and liabilities of that
\n
subsidiary are classified as held for sale when the classi-
\n
fication criteria are met, regardless of whether the Group
\n
will retain a non-controlling interest in its former subsidiary
\n
after the sale.
\n
The Group applies these classification criteria as envisaged
\n
in IFRS 5 to an investment, or a portion of an investment, in
\n
an associate or a joint venture. Any retained portion of an
\n
investment in an associate or a joint venture that has not
\n
been classified as held for sale is accounted for using the
\n
equity method until disposal of the portion that is classified
\n
as held for sale takes place.
\n
Non-current assets (or disposal groups) and liabilities of
\n
disposal groups classified as held for sale are presented
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n

\n\n
separately from other assets and liabilities in the state-
\n
ment of financial position.
\n
The amounts presented for non-current assets or for the
\n
assets and liabilities of disposal groups classified as held
\n
for sale are not reclassified or re-presented for prior peri-
\n
ods presented.
\n
Immediately before the initial classification of non-current
\n
assets (or disposal groups) as held for sale, the carrying
\n
amounts of such assets (or disposal groups) are measured
\n
in accordance with the accounting standard applicable to
\n
those assets or liabilities. Non-current assets (or disposal
\n
groups) classified as held for sale are measured at the low-
\n
er of their carrying amount and fair value less costs to sell.
\n
Impairment losses for any initial or subsequent write-down
\n
of the assets (or disposal groups) to fair value less costs to
\n
sell and gains for their reversals are recognized in profit or
\n
loss from continuing operations.
\n
Non-current assets are not depreciated (or amortized)
\n
while they are classified as held for sale or while they are
\n
part of a disposal group classified as held for sale.
\n
If the classification criteria are no longer met, the Group
\n
ceases to classify the non-current assets (or disposal
\n
group) as held for sale. In this case they are measured at
\n
the lower of:
\n
\u2022 the carrying amount before the asset (or disposal group)
\n
was classified as held for sale, adjusted for any depre-
\n
ciation, amortization or reversals of impairment losses
\n
that would have been recognized if the asset (or disposal
\n
group) had not been classified as held for sale; and
\n
\u2022 the recoverable amount, which is equal to the greater of
\n
its fair value net of costs to sell and its value in use, as
\n
calculated at the date of the subsequent decision not
\n
to sell.
\n
Any adjustment to the carrying amount of a non-current
\n
asset that ceases to be classified as held for sale is includ-
\n
ed in profit or loss from continuing operations.
\n

\n\n\n
A discontinued operation is a component of the Group
\n
that either has been disposed of, or is classified as held
\n
for sale, and:
\n
\u2022 represents a separate major business line or geograph-
\n
ical segment;
\n
\u2022 is part of a single coordinated plan to dispose of a sep-
\n
arate major business line or geographical segment; or
\n
\u2022 is a subsidiary acquired exclusively with a view to resale.
\n
The Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022 the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022 the post-tax gain or loss recognized on the measure-
\n
ment at fair value less costs to sell or on the disposal of
\n
the assets or disposal groups constituting the discon-
\n
tinued operation.
\n
The corresponding amount is restated in the income
\n
statement for prior periods presented in the financial
\n
statements, so that the disclosures relate to all operations
\n
that are discontinued by the end of the current report-
\n
ing period. If the Group ceases to classify a component
\n
as held for sale, the results of the component previously
\n
presented in discontinued operations are reclassified and
\n
included in profit or loss from continuing operations for all
\n
periods presented.
\n

\n

\n\n

\n

\n\n\n

\n\n
Environmental certificates
\n
Some Group companies are affected by national regula-
\n
tions governing green certificates, guarantees of origin
\n
and energy efficiency certificates (so-called white certifi-
\n
cates), as well as the European \u201cEmissions Trading System\u201d.
\n
Green certificates and guarantees of origin accrued in
\n
proportion to electricity generated by renewable energy
\n
plants and energy efficiency certificates accrued in pro-
\n
portion to energy savings achieved that have been certified
\n
by the competent authority are treated as non-monetary
\n
government operating grants and are recognized at fair
\n
value, under other operating profit, with recognition of an
\n
asset under other non-financial assets, if the certificates
\n
are not yet credited to the ownership account, or under
\n
inventories, if the certificates have already been credited
\n
to that account.
\n
At the time the certificates are credited to the ownership
\n
account, they are reclassified from other assets to inven-
\n
tories.
\n
Revenue from the sale of such certificates is recognized
\n
under revenue, with a corresponding decrease in invento-
\n
ries.
\n
For the purposes of accounting for charges arising from
\n
such regulatory requirements, the Group uses the \u201cnet li-
\n
ability approach\u201d.
\n
Under this accounting policy, any environmental certifi-
\n
cates received free of charge and those self-produced as
\n
a result of Group\u2019s operations that will be used for com-
\n
pliance purposes are recognized at nominal value (nil). In
\n
addition, charges incurred for obtaining (in the market or
\n
in some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the re-
\n
porting period are recognized through profit or loss on an
\n
accrual basis under other operating costs, as they repre-
\n
sent \u201csystem charges\u201d consequent to compliance with a
\n
regulatory requirement.
\n

\n\n

\n\n\n
Employee benefits
\n
Liabilities related to employee benefits paid upon or after
\n
ceasing employment in connection with defined benefit
\n
plans or other long-term benefits accrued during the em-
\n
ployment period are determined separately for each plan,
\n
using actuarial assumptions to estimate the amount of the
\n
future benefits that employees have accrued at the report-
\n
ing date (using the projected unit credit method). More
\n
specifically, the present value of the defined benefit obli-
\n
gation is calculated by using a discount rate determined
\n
on the basis of market yields at the end of the reporting
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n

\n
period on high-quality corporate bonds. If there is no deep
\n
market for high-quality corporate bonds in the currency in
\n
which the bond is denominated, the corresponding yield
\n
of government securities is used.
\n
The liability, net of any plan assets, is recognized on an
\n
accrual basis over the vesting period of the related rights.
\n
These appraisals are performed by independent actuaries.
\n
If the plan assets exceed the present value of the related
\n
defined benefit obligation, the surplus (up to the limit of
\n
any cap) is recognized as an asset.
\n
As regards the liabilities/(assets) of defined benefit plans,
\n
the cumulative actuarial gains and losses from the actuari-
\n
al measurement of the liabilities, the return on the plan as-
\n
sets (net of the associated interest income) and the effect
\n
of the asset ceiling (net of the associated interest) are rec-
\n
ognized in other comprehensive income when they occur.
\n
For other long-term benefits, the related actuarial gains
\n
and losses are recognized through profit or loss.
\n
In the event of a change being made to an existing defined
\n
benefit plan or the introduction of a new plan, any past
\n
service cost is recognized immediately in profit or loss.
\n
In addition, the Group is involved in defined contribution
\n
plans under which it pays fixed contributions to a separate
\n
entity (a fund) and has no legal or constructive obligation
\n
to pay further contributions if the fund does not hold suf-
\n
ficient assets to pay all employee benefits relating to em-
\n
ployee service in the current and prior periods. Such plans
\n
are usually aimed to supplement pension benefits due to
\n
employees post-employment. The related costs are rec-
\n
ognized through profit or loss on the basis of the amount
\n
of contributions paid in the period.
\n\n
Termination benefits
\n
Liabilities for benefits due to employees for the early ter-
\n
mination of employee service arise out of the Group\u2019s de-
\n
cision to terminate an employee\u2019s employment before the
\n
normal retirement date or an employee\u2019s decision to ac-
\n
cept an offer of benefits in exchange for the termination
\n
of employment. The event that gives rise to an obligation is
\n
the termination of employment rather than employee ser-
\n
vice. Termination
\n
benefits are recognized at the earlier of
\n
the following dates:
\n
\u2022 when the entity can no longer withdraw its offer of ben-
\n
efits; and
\n
\u2022 when the entity recognizes a cost for a restructuring
\n
that is within the scope of IAS 37 and involves the pay-
\n
ment of termination benefits.
\n
The liabilities are measured on the basis of the nature of
\n
the employee benefits. More specifically, when the bene-
\n
fits represent an enhancement of other post-employment
\n
benefits, the associated liability is measured in accordance
\n
with the rules governing that type of benefits. Otherwise, if
\n
the termination benefits due to employees are expected to
\n
be settled wholly before 12 months of the close of the pe-
\n
riod in which the benefits are recognized, the entity mea-
\n
sures the liability in accordance with the requirements for
\n
short-term employee benefits; if they are not expected to
\n
be settled wholly before 12 months of the close of period
\n
in which the benefits are recognized, the entity measures
\n
the liability in accordance with the requirements for other
\n
long-term employee benefits.
\n

\n

\n\n\n
Share-based payments
\n
The Group undertakes share-based payment transactions
\n
settled with equity instruments as part of the remunera-
\n
tion policy adopted for the Chief Executive Officer/General
\n
Manager and for key management personnel.
\n
The most recent long-term incentive plans provide for
\n
the grant to recipients of an incentive represented by an
\n
equity component (settled with equity instruments) and
\n
a monetary component (paid in cash), which will accrue if
\n
specific conditions are met. The monetary component is
\n
classified as a cash-settled transaction if it is based on the
\n
price (or value) of the equity instruments of the company
\n
that issued the plan or, in other cases, as another long-
\n
term employee benefit.
\n
In order to settle the equity component through the bonus
\n
award of Enel shares, a program for the purchase of trea-
\n
sury shares to support these plans was approved. For more
\n
details on share-based incentive plans, please see note 53
\n
\u201cShare-based payments\u201d.
\n
For the equity component, the Group recognizes the ser-
\n
vices rendered by employees as personnel expenses over
\n
the period in which the conditions for remaining in service
\n
and for achieving certain results must be satisfied (vesting
\n
period) and indirectly estimates their value, and the corre-
\n
sponding increase in a specific equity item, on the basis
\n
of the fair value of the equity instruments (i.e., the issuer
\n
shares) at the grant date. This fair value is based on the ob-
\n
servable market price of the share, taking account of the
\n
terms and conditions under which the shares were grant-
\n
ed (with the exception of vesting conditions excluded from
\n
the measurement of fair value).
\n
The overall expense recognized is adjusted at each report-
\n
ing date until the vesting date to reflect the best estimate
\n
available to the Group of the number of equity instru-
\n
ments for which the service and performance conditions
\n
other than market conditions will be satisfied, so that the
\n
amount recognized at the end is based on the effective
\n
number of equity instruments that satisfy the service and
\n
performance conditions other than market conditions at
\n
the vesting date.
\n
No expense is recognized for awards which ultimately do
\n
not vest because the performance conditions other than
\n
market conditions and/or the service conditions have not
\n
been satisfied. Conversely, the transactions are consid-
\n
ered to have vested irrespective of whether the market or
\n
non-vesting conditions are satisfied, provided that all oth-
\n
er vesting conditions are met.
\n
If the incentive based on equity instruments is paid in cash,
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n\n
the Group recognizes the services rendered by employ-
\n
ees as personnel expenses over the vesting period and a
\n
corresponding liability measured at the fair value of the li-
\n
ability incurred. Subsequently, and until its extinction, the
\n
liability is remeasured at fair value at each reporting date,
\n
considering the best possible estimate of the incentive
\n
that will vest, with changes in fair value recognized under
\n
personnel expenses. If the right to receive the monetary
\n
incentive does not vest because one or more conditions
\n
are not met, the related liability is reversed.
\n

\n\n

\n\n\n

\n
Provisions for risks and charges
\n
Provisions are recognized where there is a legal or con-
\n
structive obligation as a result of a past event at the end
\n
of the reporting period, the settlement of which is expect-
\n
ed to result in an outflow of resources whose amount can
\n
be reliably estimated. Where the impact is significant, the
\n
accruals are determined by discounting expected future
\n
cash flows using a pre-tax discount rate that reflects the
\n
current market assessment of the time value of money
\n
and, if applicable, the risks specific to the liability.
\n
If the provision is discounted, the periodic adjustment of
\n
the present value for the time factor is recognized as a fi-
\n
nancial expense.
\n
When the Group expects some or all charges to be reim-
\n
bursed, the reimbursement is recognized as a separate
\n
asset, but only when the reimbursement is virtually certain.
\n\n
Where the liability relates to decommissioning and/or site
\n
restoration in respect of property, plant and equipment,
\n
the initial recognition of the provision is made against the
\n
related asset and the expense is then recognized in profit
\n
or loss through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of
\n
nuclear waste and other radioactive materials, the provi-
\n
sion is recognized against the related operating costs.
\n

\n\n
A liability for restructuring refers to a program planned
\n
and controlled by management that materially changes
\n
the scope of a business undertaken by the Group or the
\n
manner in which the business is conducted. Such a liabil-
\n
ity is recognized when a constructive obligation is estab-
\n
lished, i.e., when the Group has approved a detailed formal
\n
restructuring plan and has started to implement the plan
\n
or has announced its main features to those affected by it.
\n
Provisions do not include liabilities in respect of uncertain
\n
income tax treatments that are recognized as tax liabilities.
\n
The Group could provide a warranty in connection with
\n
the sale of a product (whether a good or service) from
\n
contracts with customers in the scope of IFRS 15, in ac-
\n
cordance with the contract, the law or its customary busi-
\n
ness practices. In this case, the Group assesses whether
\n
the warranty provides the customer with assurance that
\n
the related product will function as the parties intended
\n
because it complies with agreed-upon specifications or
\n
whether the warranty provides the customer with a service
\n
in addition to the assurance that the product complies
\n
with agreed-upon specifications.
\n
After the assessment, if the Group establishes that an
\n
assurance warranty is provided, it recognizes a separate
\n
warranty liability and corresponding expense when trans-
\n
ferring the product to the customer, as additional costs of
\n
providing goods or services, without attributing any of the
\n
transaction price (and therefore revenue) to the warranty.
\n
The liability is measured and presented as a provision.
\n
Otherwise, if the Group determines that a service warran-
\n
ty is provided, it accounts for the promised warranty as a
\n
performance obligation in accordance with IFRS 15, recog-
\n
nizing the contract liability as revenue over the period the
\n
warranty service is provided and the costs associated as
\n
they are incurred.
\n
Finally,
\n
if the warranty includes both an assurance element
\n
and a service element and the Group cannot reasonably
\n
account for them separately, then it accounts for both of
\n
the warranties together as a single performance obliga-
\n
tion.
\n
In the case of contracts in which the unavoidable costs of
\n
meeting the obligations under the contract exceed the
\n
economic benefits expected to be received under it (oner-
\n
ous contracts), the Group recognizes a provision as the
\n
lower of the excess of unavoidable costs of meeting the
\n
obligations (i.e., costs that relate directly to the contract,
\n
whether incremental or resulting from an allotment of oth-
\n
er costs) under the contract over the economic benefits
\n
expected to be received under it and any compensation or
\n
penalty arising from failure to fulfil it.
\n
Changes in estimates of accruals to the provisions ad-
\n
dressed here are recognized through profit or loss in the
\n
period in which the changes occur, with the exception of
\n
those in the costs of decommissioning, retiring and/or res-
\n
toration resulting from changes in the timetable and costs
\n
necessary to extinguish the obligation or from a change
\n
in the discount rate. These changes increase or decrease
\n
the carrying amount of the related assets and are taken to
\n
profit or loss through depreciation. Where they increase
\n
the carrying amount of the assets, it is also determined
\n
whether the new carrying amount of the assets is fully re-
\n
coverable. If this is not the case, a loss equal to the unre-
\n
coverable amount is recognized through profit or loss.
\n
Decreases in estimates are recognized up to the carrying
\n
amount of the assets. Any excess is recognized immedi-
\n
ately in profit or loss.
\n
For more information on the estimation criteria adopted
\n
in determining provisions for retiring and/or restoration of
\n
property, plant and equipment, especially those associated
\n
with decommissioning nuclear power plants and storage
\n
of waste fuel and other radioactive materials, please see
\n
note 2.1 \u201cUse of estimates and management judgment\u201d.
\n

\n

\n

\n\n\n
Revenue from contracts with customers
\n
The Group recognizes revenue from contracts with cus-
\n
tomers at an amount that reflects the consideration at
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n

\n

\n
which the Group expects to be entitled in exchange for
\n
those goods or services, using the five-step model envis-
\n
aged by IFRS 15:
\n
\u2022 identify the contract with the customer (step 1) as from
\n
when the contract is legally enforceable. If the criteria en-
\n
visaged for step 1 are not met, any consideration received
\n
from the customer is generally recognized as an advance;
\n
\u2022 identify the performance obligations in the contract (step
\n
2), that is, all goods or services promised in the contract,
\n
separating them into performance obligations to account
\n
for separately, if they are both capable of being distinct
\n
and distinct within the context of the contract, or, as an
\n
exception, as a single performance obligation, if they are
\n
a series of distinct goods or services that are substantially
\n
the same and that have the same pattern of transfer to
\n
the customer over time.
\n\n
For each distinct good or service identified, the Group
\n
determines whether it acts as a principal or agent. When
\n
the Group acts as agent, it recognizes revenue (corre-
\n
sponding to any fee or commission) on a net basis;
\n

\n\n
\u2022 determine the transaction price at inception of the con-
\n
tract (step 3) considering:
\n
\u2013 the amount of consideration to which the Group ex-
\n
pects to be entitled in exchange for transferring goods
\n
or services to a customer, excluding amounts collected
\n
on behalf of third parties (e.g., some sale taxes and val-
\n
ue-added taxes);
\n\n
\u2013 variable consideration, non-cash consideration re-
\n
ceived from a customer, consideration payable to a
\n

\n\n
customer and a significant financing component. The
\n
transaction price is updated each reporting period for
\n
any changes in circumstances;
\n
\u2022 allocate the transaction price (step 4) at contract incep-
\n
tion to each separate performance obligation, including
\n
any option to acquire additional goods or services that
\n
represents a material right (deferring the relative revenue
\n
until those future goods or services are transferred or
\n
the option expires), generally on the basis of the relative
\n
stand-alone selling price of each distinct good or service
\n
promised in the contract;
\n\n
\u2022 recognize revenue (step 5), when (or as) each perfor-
\n
mance obligation is satisfied by transferring the promised
\n
good or service to the customer.
\n

\n\n
The Group does not disclose the information about the
\n
remaining performance obligations in existing contracts if
\n
the performance obligation is part of a contract that has
\n
an original expected duration of one year or less and if the
\n
Group recognizes revenue in the amount to which it has a
\n
right to invoice the customer.
\n
More information on the application of this revenue recog-
\n
nition model is provided in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and in note 11.a \u201cRevenue from
\n
sales and services\u201d.
\n

\n\n
Other revenue
\n
The Group recognizes revenue other than that deriving
\n
from contracts with customers mainly referring to:
\n\n
\u2022 revenue from the sale of energy commodities based on
\n
contracts with physical settlement, which do not qualify
\n
for the own use exemption and therefore is recognized
\n
at FVTPL in accordance with IFRS 9;
\n

\n\n
\u2022 changes in the fair value of settled contracts to sell ener-
\n
gy commodities with physical settlement, which do not
\n
qualify for the own use exemption and therefore are rec-
\n
ognized at FVTPL in accordance with IFRS 9;
\n
\u2022 operating lease revenue accounted for on an accrual
\n
basis in accordance with the substance of the relevant
\n
lease agreement.
\n\n
Other operating income
\n
Other operating income primarily includes gains on dis-
\n
posal of assets that are not an output of the Group\u2019s ordi-
\n
nary activities and government grants.
\n
Government grants, including non-monetary grants at fair
\n
value, are recognized where there is reasonable assurance
\n
that they will be received and that the Group will comply
\n
with all conditions attaching to them as set by the govern-
\n
ment, government agencies and similar bodies whether
\n
local, national or international.
\n
When loans are provided by governments at a below-mar-
\n
ket rate of interest, the benefit is regarded as a govern-
\n
ment grant. The loan is initially recognized and measured
\n
at fair value and the government grant is measured as the
\n
difference between the initial carrying amount of the loan
\n
and the funds received. The loan is subsequently measured
\n
in accordance with the requirements for financial liabilities.
\n
Government grants are recognized in profit or loss on a
\n
systematic basis over the periods in which the Group rec-
\n
ognizes as expenses the costs that the grants are intended
\n
to compensate.
\n
Where the Group receives government grants in the form
\n
of a transfer of a non-monetary asset for the use of the
\n
Group, it accounts for both the grant and the asset at the
\n
fair value of the non-monetary asset received at the date
\n
of the transfer.
\n
Capital grants, including non-monetary grants at fair val-
\n
ue, i.e., those received to purchase, build or otherwise ac-
\n
quire non-current assets (for example, an item of property,
\n
plant and equipment or an intangible asset), are deducted
\n
from the carrying amount of the asset and are recognized
\n
in profit or loss over the depreciable/amortizable life of
\n
the asset as a reduction in the depreciation/amortization
\n
charge. If there is insufficient information to enable ade-
\n
quate attribution to the fixed assets to which they refer,
\n
capital grants are recognized as deferred income under
\n
other liabilities, and credited to profit or loss on a system-
\n
atic basis over the useful life of the asset.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n\n

\n

\n

\n

\n
Financial income and expense from derivatives
\n
Financial income and expense from derivatives include:
\n\n
\u2022 income and expense from derivatives measured at fair
\n
value through profit or loss on interest rate and currency
\n
risk;
\n

\n\n\n
\u2022 income and expense from fair value hedge derivatives
\n
on interest rate risk;
\n
\u2022 income and expense from cash flow hedge derivatives
\n
on interest rate and currency risks.
\n

\n\n
Other financial income and expense
\n
For all financial assets and liabilities measured at amortized
\n
cost and interest-bearing financial assets classified as at
\n
fair value through other comprehensive income, interest
\n
income and expense are recognized using the effective
\n
interest rate method.
\n
Interest income is recognized to the extent that it is prob-
\n
able that the economic benefits will flow to the Group and
\n
the amount can be reliably measured.
\n
Other financial income and expense include also changes
\n
in the fair value of financial instruments other than deriv-
\n
atives.
\n

\n\n

\n\n\n
Dividends
\n
Dividends are recognized when the unconditional right to
\n
receive payment is established.
\n
Dividends and interim dividends payable to the Parent\u2019s
\n
shareholders and non-controlling interests are recognized
\n
as changes in equity in the period in which they are ap-
\n
proved by the Shareholders\u2019 Meeting and the Board of Di-
\n
rectors, respectively.
\n

\n\n\n

\n
Income taxes
\n
Current income taxes
\n
Current income taxes for the year, which are recognized
\n
under \u201cIncome tax liabilities\u201d net of payments on account,
\n
or under \u201cTax assets\u201d where there is a credit balance, are
\n
determined using an estimate of taxable income and in
\n
conformity with the applicable regulations.
\n
Such liabilities and assets are determined using the tax
\n
rates and tax laws that are enacted or substantively en-
\n
acted by the end of the reporting period in the countries
\n
where taxable income has been generated.
\n
Current income taxes are recognized in profit or loss with
\n
the exception of current income taxes related to items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n\n
Deferred tax
\n
Deferred tax liabilities and assets are calculated on the
\n
temporary differences between the carrying amounts of
\n
liabilities and assets in the financial statements and their
\n
corresponding amounts recognized for tax purposes on
\n
the basis of tax rates in effect on the date the temporary
\n
difference will reverse, which is determined on the basis of
\n
tax rates that are enacted or substantively enacted as at
\n
the end of the reporting period.
\n
Deferred tax liabilities are recognized for all taxable tem-
\n
porary differences, except when such liability arises from
\n
the initial recognition of goodwill or in respect of taxable
\n
temporary differences associated with investments in sub-
\n
sidiaries, associates and joint ventures, when the Group
\n
can control the timing of the reversal of the temporary dif-
\n
ferences and it is probable that the temporary differences
\n
will not reverse in the foreseeable future.
\n
Deferred tax assets are recognized for all deductible tem-
\n
porary differences, the carry forward of tax losses and any
\n
unused tax credits. For more information concerning the
\n
recoverability of such assets, please see the appropriate
\n
section of the discussion of estimates.
\n
Deferred taxes and liabilities are recognized in profit or
\n
loss, with the exception of those in respect of items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n
Deferred tax assets and deferred tax liabilities are offset
\n
only if there is a legally enforceable right to offset current
\n
tax assets with current tax liabilities and when they relate
\n
to income taxes levied by the same taxation authority on
\n
either the same taxable entity or different taxable entities
\n
which intend either to settle current tax liabilities and as-
\n
sets on a net basis, or to realize the assets and settle the
\n
liabilities simultaneously, in each future period in which
\n
significant amounts of deferred tax liabilities or assets are
\n
expected to be settled or recovered.
\n

\n

\n\n
Uncertainty over income tax treatments
\n
In defining \u201cuncertainty\u201d, it shall be considered whether a
\n
particular tax treatment will be accepted by the relevant
\n
taxation authority. If it is deemed probable that the tax
\n
treatment will be accepted (where the term \u201cprobable\u201d is
\n
defined as \u201cmore likely than not\u201d), then the Group recog-
\n
nizes and measures its current/deferred tax asset or liabil-
\n
ities applying the requirements in IAS 12.
\n
Conversely, when the Group feels that it is not likely that
\n
the taxation authority will accept the tax treatment for
\n
income tax purposes, the Group reflects the uncertainty
\n
in the manner that best predicts the resolution of the un-
\n
certain tax treatment. The Group determines whether to
\n
consider each uncertain tax treatment separately or to-
\n
gether with one or more other uncertain tax treatments
\n
based on which approach provides better predictions of
\n
the resolution of the uncertainty. In assessing whether and
\n
how the uncertainty affects the tax treatment, the Group
\n
assumes that a taxation authority will accept or not an un-
\n
certain tax treatment supposing that the taxation authority
\n

\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
will examine amounts it has a right to examine and have full
\n
knowledge of all related information when making those
\n
examinations. The Group reflects the effect of uncertainty
\n
in accounting for current and deferred tax using the ex-
\n
pected value or the most likely amount, whichever method
\n
better predicts the resolution of the uncertainty.
\n
Since uncertain income tax positions meet the definition
\n
of income taxes, the Group presents uncertain tax liabili-
\n
ties/assets as current tax liabilities/assets or deferred tax
\n
liabilities/assets.
\n

\n\n

\n\n\n
3. New and amended standards and interpretations
\n
The Group has applied the following standards, interpre-
\n
tations and amendments that took effect as from January
\n
1, 2022:
\n
\u2022 \u201cAmendments to IFRS 3 - Reference to the Conceptual
\n
Framework\u201d issued in May 2020. The amendments are
\n
intended to replace a reference to the definitions of as-
\n
sets and liabilities provided by the Revised Conceptual
\n
Framework for Financial Reporting issued in March 2018
\n
(Conceptual Framework) without significantly changing
\n
its provisions.
\n
The amendments also add to IFRS 3 a requirement that,
\n
for transactions and other events within the scope of
\n
\u201cIAS 37 - Provisions, contingent liabilities and contingent
\n
assets\u201d or \u201cIFRIC 21 - Levies\u201d, an acquirer applies IAS 37
\n
or IFRIC 21 (instead of the Conceptual Framework) to
\n
identify the liabilities it has assumed in a business com-
\n
bination.
\n
Finally, the amendments clarify the existing guidelines
\n
in IFRS 3 for contingent assets acquired in a business
\n
combination, specifying that, if it is not sure that an as-
\n
set exists at the acquisition date, the contingent asset
\n
shall not be recognized.
\n
\u2022 \u201cAmendments to IAS 16 - Property, Plant and Equipment:
\n
Proceeds before Intended Use\u201d, issued in May 2020. The
\n
amendments prohibit a company from deducting from
\n
the cost of property, plant and equipment amounts re-
\n
ceived from selling items produced while the company is
\n
preparing the asset for its intended use. Instead, a com-
\n
pany will recognize such sales proceeds and related cost
\n
in profit or loss.
\n
\u2022 \u201cAmendments to IAS 37 - Onerous Contracts - Costs
\n
of Fulfilling a Contract\u201d, issued in May 2020. The amend-
\n
ments specify which costs an entity includes in deter-
\n
mining the cost of fulfilling a contract for the purpose of
\n
assessing whether the contract is onerous. To this end,
\n
the cost of fulfilling a contract comprises the costs that
\n
relate directly to the contract. These consist of the incre-
\n
mental costs of fulfilling that contract or the allotment of
\n
other costs that relate directly to fulfilling contracts.
\n
\u2022 \u201cAnnual improvements to IFRS Standards 2018-2020\u201d,
\n
issued in May 2020. The document mainly comprises
\n
amendments to the following standards:
\n
\u2013 First-Time Adoption of International Financial Report-
\n
ing Standards\u201d; the amendment simplifies the appli-
\n
cation of IFRS 1 by an investee (subsidiary, associate
\n
or joint venture) that becomes a first-time adopter of
\n
IFRS Standards after its parent has already adopted
\n
them. More specifically, if the investee adopts the IF-
\n
RSs after its parent and applies IFRS 1.D16 (a), then
\n
the investee can elect to measure the cumulative
\n
translation differences for all foreign operations at
\n
the amounts that would be included in the parent\u2019s
\n
consolidated financial statements, based on parent\u2019s
\n
date of transition to the IFRSs;
\n
\u2013 \u201cIFRS 9 - Financial Instruments\u201d; with regard to fees
\n
included in the \u201c10 per cent\u201d test for derecognition
\n
of financial liabilities, the amendment clarifies the
\n
fees that an entity includes when assessing whether
\n
the terms of a new or modified financial liability are
\n
substantially different from the terms of the original
\n
financial liability. In determining those fees paid net
\n
of fees received, the borrower shall include only fees
\n
paid or received between the borrower and the lend-
\n
er, including fees paid or received by either the bor-
\n
rower or lender on the other party\u2019s behalf;
\n
\u2013 \u201cIFRS 16 - Leases\u201d; the International Accounting Stan-
\n
dards Board amended Illustrative Example 13 accom-
\n
panying \u201cIFRS 16 - Leases\u201d. Specifically, the amend-
\n
ment eliminates the potential for confusion in the
\n
application of IFRS 16 created by the way in which
\n
Illustrative Example 13 had illustrated the require-
\n
ments for lease incentives. The example had included
\n
a reimbursement relating to leasehold improvements
\n
without explaining whether the reimbursement quali-
\n
fied as a lease incentive. The amendment removes the
\n
illustration of a reimbursement relating to leasehold
\n
improvements from the example;
\n
\u2013 \u201cIAS 41 - Agriculture\u201d; the amendment removes the
\n
requirement for entities to exclude cash flows for tax-
\n
ation when measuring fair value. Accordingly, entities
\n
shall use pre-tax cash flows and a pre-tax rate to dis-
\n
count those cash flows.
\n
The application of the amendments for 2022 did not have
\n
a material impact on these consolidated financial state-
\n
ments.
\n

\n\n

\n\n

\n\n
4. Argentina - Hyperinflationary economy:
\n
impact of the application of IAS 29
\n
As from July 1, 2018, the Argentine economy has been con-
\n
sidered hyperinflationary based on the criteria established by
\n
\u201cIAS 29 - Financial reporting in hyperinflationary economies\u201d.
\n
This designation is determined following an assessment of a
\n
series of qualitative and quantitative circumstances, including
\n
the presence of a cumulative inflation rate of more than 100%
\n
over the previous three years.
\n
For the purposes of preparing the consolidated financial
\n
statements at December 31, 2022, and in accordance with
\n
IAS 29, certain items of the statements of financial position of
\n
the investees in Argentina have been remeasured by applying
\n
the general consumer price index to historical data in order
\n
to reflect changes in the purchasing power of the Argentine
\n
peso at the reporting date for those companies.
\n
Bearing in mind that the Enel Group acquired control of the
\n
Argentine companies on June 25, 2009, the remeasurement
\n
of the non-monetary financial statement figures was con-
\n
ducted by applying the inflation indices starting from that
\n
date. In addition to being already reflected in the opening
\n
statement of financial position, the accounting effects of that
\n
remeasurement also include changes during the period. More
\n
specifically, the effect of the remeasurement of non-mone-
\n
tary items, the equity items and the income statement items
\n
recognized in 2022 was recognized in a specific line of the
\n
income statement under financial income and expense. The
\n
associated tax effect was recognized in taxes for the year.
\n
In order to also take account of the impact of hyperinflation
\n
on the exchange rate of the local currency, the income state-
\n
ment balances expressed in the hyperinflationary currency
\n
have been translated into the Group\u2019s presentation currency
\n
(euro) applying, in accordance with IAS 21, the closing ex-
\n
change rate rather than the average rate for the year in order
\n
to adjust these amounts to present values.
\n
The cumulative changes in the general price indices from De-
\n
cember 31, 2018 until December 31, 2022 are shown in the
\n
following table:
\n
Periods
\n
Cumulative change
\n
in general consumer
\n
price index
\n
From July 1, 2009 to December 31, 2018 346.30%
\n
From January 1, 2019 to December 31, 2019 54.46%
\n
From January 1, 2020 to December 31, 2020 35.41%
\n
From January 1, 2021 to December 31, 2021 49.73%
\n
From January 1, 2022 to December 31, 2022 97.08%
\n
In 2022, the application of IAS 29 generated net financial in-
\n
come (gross of tax) of \u20ac290 million.
\n
The following tables report the effects of IAS 29 on the bal-
\n
ance at December 31, 2022 and the impact of hyperinflation
\n
on the main income statement items for 2022, differentiating
\n
between that concerning the revaluation on the basis of the
\n
general consumer price index and that due to the applica-
\n
tion of the closing exchange rate rather than the average ex-
\n
change rate for the period, in accordance with the provisions
\n
of IAS 21 for hyperinflationary economies.
\n
Millions of euro
\n
Cumulative hyperinflation
\n
effect at Dec. 31, 2021
\n
Hyperinflation effect for the
\n
period Exchange differences
\n
Cumulative hyperinflation
\n
effect at Dec. 31, 2022
\n
Total assets 1,366 1,183 (560) 1,989
\n
Total liabilities 346 359 (150)
\n
555
\n
Equity 1,020 824
\n
(1)
\n
(410) 1,434
\n
(1) The figure includes profit for year equal to \u20ac98 million.
\n
Millions of euro
\n
IAS 29 effect IAS 21 effect Total effect at Dec. 31, 2022
\n
Revenue 254 (356) (102)
\n
Costs 280
\n
(1)
\n
(449)
\n
(2)
\n
(169)
\n
Operating profit (26) 93 67
\n
Net financial income/(expense) (46) (1) (47)
\n
Net income/(expense) from hyperinflation 290 - 290
\n
Pre-tax profit/(loss) 218 92 310
\n
Income taxes 120 (3) 117
\n
Loss for the year (owners of the Parent and non-controlling interests) 98 95 193
\n
Attributable to owners of the Parent 73 51 124
\n
Attributable to non-controlling interests 25 44 69
\n
(1) Includes impact on depreciation, amortization and impairment losses of \u20ac42 million.
\n
(2) Includes impact on depreciation, amortization and impairment losses of \u20ac(169) million.
\n

\n\n

\n\n

\n\n
5. Climate change disclosures
\n
The move towards \u201cnet zero\u201d is under way worldwide and
\n
the processes of decarbonization and electrification of the
\n
global economy are crucial to avoiding the serious conse-
\n
quences of an increase in temperatures of over 1.5 \u00b0C.
\n
With this outlook, the Group has set its strategic guide-
\n
lines as follows:
\n
\u2022 allocate capital to support a decarbonized electricity
\n
supply;
\n
\u2022 enable the electrification of customers\u2019 energy demand;
\n
\u2022 leverage the creation of value along the value chain;
\n
\u2022 bring forward achievement of the sustainable \u201cnet-zero\u201d
\n
goals to 2040.
\n
Considering the risks related to climate change and the
\n
commitments established under the Paris Agreement, the
\n
Group has decided to achieve the carbon neutrality objec-
\n
tives in advance and reflect its impact on assets, liabilities,
\n
and profit or loss, highlighting its significant and foresee-
\n
able impacts as required under the Conceptual Frame-
\n
work of the international accounting standards.
\n
In this regard, in accordance with the provisions of the
\n
document published by the IFRS Foundation on Novem-
\n
ber 20, 2020, the Group provides explicit information in the
\n
notes to these consolidated financial statements regard-
\n
ing how climate change is reflected in our accounts.
\n
For a more effective and comprehensive communication
\n
concerning climate change disclosures prepared as part
\n
of the notes to these consolidated financial statements,
\n
we have mapped this disclosure as shown below, providing
\n
references to the various sections where issues associated
\n
with climate change are addressed.
\n
Topic Note Content
\n
Estimates and
\n
judgments
\n
concerning climate
\n
change
\n
Note 2.1 \u201cUse of estimates and
\n
management judgment\u201d
\n
\u2022 Reference to management\u2019s use of estimates and judgments with regard to
\n
climate change (taking account of their materiality within financial reporting).
\n
\u2022 Focus on estimating expected cash flows from specific assets/CGUs (section:
\n
\u201cImpairment of non-financial assets\u201d).
\n
\u2022 Focus of the effects of the Group\u2019s commitments under the Paris Agreement
\n
and their impact on the estimation of the useful life of the assets involved
\n
(section \u201cDetermining the useful life of non-financial assets\u201d).
\n
Sustainable
\n
investment
\n
Note 19 \u201cProperty, plant and equipment\u201d
\n
Note 23 \u201cIntangible assets\u201d
\n
\u2022 Focus on assets involved in renewable generation, infrastructure connected
\n
with the development of the grid and investment in expanding the e-Mobility,
\n
e-City, e-Industries, and e-Home businesses.
\n
\u2022 Focus on the development of intellectual property for achieving strategic
\n
objectives such as decarbonization, electrification and the development of
\n
platform models.
\n
Measurement of non-
\n
financial assets
\n
Note 12.e \u201cDepreciation, amortization
\n
and other impairment losses\u201d
\n
Note 19 \u201cProperty, plant and equipment\u201d
\n
Note 24 \u201cGoodwill\u201d
\n
\u2022 Focus on the effects related to the commitments of the Group in line with
\n
the Paris Agreement with regard to the measurement of non-financial as-
\n
sets, with particular regard to the residual useful life of certain assets and
\n
impairment testing.
\n
Provisions
\n
Note 40 \u201cProvisions for risks and
\n
charges\u201d
\n
\u2022 Focus on the impact of climate change on provisions for risks and charges,
\n
in particular generation plants, including those for decommissioning and re-
\n
storation of sites, and provisions for restructuring plans linked to the energy
\n
transition (which include decarbonization and digitization).
\n
Sustainable finance
\n
Note 48.3 \u201cBorrowings\u201d
\n
Note 59 \u201cEvents after the reporting
\n
period\u201d
\n
Focus on:
\n
\u2022 issues of sustainability-linked bonds connected with the achievement of su-
\n
stainability objectives in line with the SDGs issued by the United Nations;
\n
\u2022 green bonds used to finance specific sustainable Group projects and initia-
\n
tives;
\n
\u2022 sustainable loans connected with the achievement of Sustainable Develop-
\n
ment Goals (SDGs).
\n
Share-based
\n
payments
\n
Note 53 \u201cShare-based payments\u201d
\n
\u2022 Description of long-term incentive plans anchored to achievement of speci-
\n
fic climate-related targets.
\n
Environmental
\n
compliance
\n
Note 12.f \u201cOther operating expenses\u201d
\n
\u2022 Description of costs relating to environmental compliance required by natio-
\n
nal and international regulations, in particular for greenhouse gas emission
\n
quotas, green certificates and energy efficiency certificates.
\n
Note 40 \u201cProvisions for risks and
\n
charges\u201d
\n
\u2022 Description of costs generated by not having sufficient environmental certi-
\n
ficates to meet environmental compliance regulations.
\n
Note 2.2 \u201cSignificant accounting policies\u201d
\n
\u2022 Description of accounting treatment of environmental certificates (sections:
\n
\u201cEnvironmental certificates\u201d and \u201cInventories\u201d).
\n

\n\n

\n\n

\n\n

\n\n
6. Discontinued operations
\n
Within the European area, the Enel Group has decided to
\n
dispose of important business lines, particularly in Russia,
\n
Romania and Greece, leading to their assets being reclas-
\n
sified as discontinued operations for the purposes of \u201cIFRS
\n
5 - Non-current assets held for sale and discontinued op-
\n
erations\u201d.
\n
The consolidated income statement reports the profit/
\n
(loss) result from discontinued operations in a separate
\n
line.
\n
In accordance with the provisions of IFRS 5, which governs
\n
the presentation in the financial statements of profit or
\n
loss and the disclosures to be provided in the explanatory
\n
note on non-current assets held for sale and discontinued
\n
operations, the income statement below reports the re-
\n
sults of discontinued operations for 2022 and 2021.
\n
The items are shown net of intercompany transactions
\n
which have been completely eliminated.
\n
The figures for 2021, presented for comparative purposes
\n
only, pursuant to \u201cIFRS 5 - Non-current assets held for sale
\n
and discontinued operations\u201d, have been restated to en-
\n
sure they are uniform and comparable with those for 2022.
\n
Millions of euro
\n
2022 2021 Change
\n
Revenue 3,562 2,288 1,274
\n
Costs 4,858 2,166 2,692
\n
Pre-tax profit/(loss) from discontinued operations (1,296) 122 (1,418)
\n
Income taxes (52) 23 (75)
\n
Capital gains/(losses) from disposal of discontinued operations (1,054) - (1,054)
\n
Profit/(Loss) from discontinued operations (2,298) 99 (2,397)
\n
In accordance with the provisions of IFRS 5, the facts
\n
and circumstances that led to the reclassification are de-
\n
scribed below.
\n
Russia
\n
On June 16, 2022, Enel SpA signed two separate agree-
\n
ments with PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d for the sale of the
\n
entire stake held in PJSC Enel Russia, equal to 56.43% of
\n
the share capital of the latter.
\n
Following the agreements of June 16, 2022, on October 12,
\n
2022, Enel SpA finalized the sale of the entire stake held
\n
in PJSC Enel Russia, equal to 56.43% of the share capital
\n
of the latter, to PJSC Lukoil and the Closed Combined Mu-
\n
tual Investment Fund \u201cGazprombank-Frezia\u201d, for a total of
\n
about \u20ac137 million. The transaction was closed with the
\n
fulfillment of the conditions to which the sale was subject,
\n
including authorization of the operation by the President
\n
of the Russian Federation pursuant to paragraph 5 of De-
\n
cree 520 of August 5, 2022.
\n
Upon completion of the sale, Enel sold all power genera-
\n
tion assets in Russia, which include approximately 5.6 GW
\n
of conventional capacity and approximately 300 MW of
\n
wind capacity at various stages of development, ensuring
\n
continuity for its employees and customers.
\n
The overall transaction had a negative impact on the
\n
Group\u2019s profit of about \u20ac
\n
1,551 million, mainly reflecting the
\n
release of the translation reserve of \u20ac1,054 million, and the
\n
value adjustment of about \u20ac497 million.
\n
For more information, please see the section on \u201cBusiness
\n
combinations\u201d.
\n
Romania
\n
On December 14, 2022, Enel SpA entered into an Exclusiv-
\n
ity Agreement with Greek company Public Power Corpora-
\n
tion SA (PPC) in relation to the potential disposal of all the
\n
equity stakes held by Enel Group in Romania. In this regard,
\n
the value of the net assets of Enel Romania was adjusted
\n
to the expected sale price, with recognition of a value ad-
\n
justment of \u20ac696 million. On February 4, 2023, Enel SpA,
\n
following the announcement released on December 14,
\n
2022, announced that the period of exclusive negotiations
\n
with Greek company PPC in relation to the potential dis-
\n
posal of all the equity stakes held by Enel Group in Romania
\n
had been extended.
\n

\n\n

\n\n

\n\n

\n

\n

\n

\n\n

\n\n
Greece
\n
Enel Green Power has begun the process of finding a po-
\n
tential investor interested in a partnership for the manage-
\n
ment and development of Enel Green Power Hellas within
\n
the Stewardship business model.
\n
The status of the negotiations under way suggest that a
\n
sale is highly probable. Accordingly, the requirements es-
\n
tablished by \u201cIFRS 5 - Non-current assets held for sale and
\n
discontinued operations\u201d have been met for the classifica-
\n
tion of the Greek assets as \u201cdiscontinued operations\u201d.
\n
For more details on the financial position by business line
\n
and geographical area of assets classified as discontinued
\n
operations, please see the section \u201cPerformance by prima-
\n
ry segment (Business Line) and secondary segment (Geo-
\n
graphical Area)\u201d.
\n
The details of cash flows relating to discontinued opera-
\n
tions are provided below, as already separately shown in
\n
the cash flows statement.
\n
Millions of euro
\n
2022 2021 Change
\n
Cash flows from operating activities - discontinued operations (391) 280 (671)
\n
Cash flows used in investing activities - discontinued operations (351) (453) 102
\n
Cash flows from/(used in) financing activities - discontinued operations 656 118 538
\n
Cash flows - discontinued operations (86) (55) (31)
\n

\n\n

\n\n\n

\n

\n
7. Restatement of comparative disclosures
\n
Discontinued operations
\n\n
The 2021 consolidated income statement and statement
\n
of consolidated comprehensive income have been adjust-
\n
ed to take account of the presentation of discontinued
\n
operations as required by the \u201cIFRS 5 - Non-current assets
\n
held for sale and discontinued operations\u201d.
\n
For more details, please refer to the note \u201cDiscontinued
\n
operations\u201d.
\n
Impact on the consolidated income statement
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Revenue 88,006 (2,287) 85,719
\n
Costs 82,848 (2,157) 80,691
\n
Net results from commodity contracts 2,522 1 2,523
\n
Operating profit 7,680 (129) 7,551
\n
Financial income from derivatives 2,718 (1) 2,717
\n
Other financial income 1,882 (20) 1,862
\n
Financial expense from derivatives 1,257 (1) 1,256
\n
Other financial expense 6,114 (27) 6,087
\n
Net income from hyperinflation 20 - 20
\n
Share of profit/(loss) of equity-accounted investments 571 - 571
\n
Pre-tax profit 5,500 (122) 5,378
\n
Income taxes 1,643 (23) 1,620
\n
Profit/(Loss) from continuing operations 3,857 (99) 3,758
\n
Attributable to owners of the Parent 3,857 (760) 3,097
\n
Attributable to non-controlling interests - 661 661
\n
Profit/(Loss) from discontinued operations - 99 99
\n
Attributable to owners of the Parent - 92 92
\n
Attributable to non-controlling interests - 7 7
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling interests) 3,857 - 3,857
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Impact on the consolidated comprehensive income
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Profit for the year 3,857 3,857
\n
Other comprehensive income/(expense) that may be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Effective portion of change in the fair value of cash flow hedges (725) (10) (735)
\n
Change in the fair value of hedging costs 195 (1) 194
\n
Share of the other comprehensive expense of equity-accounted
\n
investments
\n
(645) - (645)
\n
Change in the fair value of financial assets at FVOCI 11 - 11
\n
Change in translation reserve (90) 5 (85)
\n
Cumulative other comprehensive income that may be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
66
\n
Other comprehensive income/(expense) that may not be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Remeasurement of net liabilities/(assets) for defined benefit plans 30 (1) 29
\n
Change in fair value of equity investments in other companies - - -
\n
Cumulative other comprehensive income that may not be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
11
\n
Total other comprehensive expense for the year (1,224) - (1,224)
\n
Comprehensive income/(expense) for the year 2,633 - 2,633
\n
Attributable to:
\n
- owners of the Parent 2,562 2,562
\n
- non-controlling interests 71 71
\n

\n\n
The figures presented in the comments and the tables of
\n
the notes to these consolidated financial statements at
\n
December 31, 2022 are uniform and comparable with each
\n
other.
\n
Segment reporting
\n
Figures at December 31, 2021 for the Business Line Enel X
\n
have been adjusted to take account of the transfer of cer-
\n
tain net assets and related revenue and expenses to the new
\n
Business Line Enel X Way, which are shown under \u201cHolding,
\n
Services and Other\u201d. This change affected segment report-
\n
ing but did not produce any changes in the overall figures
\n
for the Group, although a number reclassifications of values
\n
were made within the various business lines.
\n
The figures presented in the comments and the tables of
\n
the notes to these consolidated financial statements at De-
\n
cember 31, 2022 are uniform and comparable with each
\n
other.
\n

\n\n

\n\n

\n

\n
Changes in the consolidation scope
\n\n
8. Main acquisitions and disposals during the year
\n
In the two periods under review, the consolidation scope
\n
changed as a result of a number of transactions.
\n
2021
\n
\u2022 On January 8, 2021, 100% of Tynemouth Energy Storage
\n
was sold for \u20ac1 million. The sale did not have any significant
\n
impact on profit or loss.
\n
\u2022 On January 20, 2021, Enel Green Power Bulgaria was sold
\n
for a total \u20ac35 million. The sale did not have any significant
\n
impact on profit or loss.
\n
\u2022 On March 10, 2021, Enel Green Power Italia acquired 100%
\n
of e-Solar Srl, the owner of a photovoltaic project with an
\n
authorized capacity of 170.11 MW, for \u20ac2.7 million.
\n
\u2022 On March 29, 2021, Enel X Srl acquired 100% of CityPoste
\n
Payment SpA, an Italian company that offers consumers
\n
access to payment services through both physical and dig-
\n
ital channels, enabling them to carry out numerous types of
\n
transactions with private- and public-sector entities.
\n
\u2022 In the 1st Quarter of 2021, the consolidation scope
\n
changed with the global consolidation of Australian renew-
\n
able energy companies previously accounted for using the
\n
equity method due to a change in governance arrange-
\n
ments at the companies, without the acquisition of an ad-
\n
ditional interest. The purchase price allocation process was
\n
completed in December 2021 and essentially confirmed
\n
the carrying amount of the net assets acquired following
\n
an impairment loss of about \u20ac9 million.
\n
\u2022 On May 13, 2021, EGP Solar 1 LLC was sold for a total of
\n
about \u20ac4 million.
\n
\u2022 In the first nine months of 2021, Enel Green Power Espa\u00f1a
\n
acquired 100% of 30 renewables companies for a total of
\n
\u20ac86 million.
\n
\u2022 On September 8, 2021, Genability was sold by Enel X North
\n
America for about \u20ac6 million.
\n
\u2022 The purchase price allocation process for Viva Labs AS,
\n
acquired on September 17, 2020 by Enel X International,
\n
was completed in September, following which the carry-
\n
ing amounts recognized at the acquisition date were con-
\n
firmed.
\n
Other changes
\n
In addition to the above changes in the consolidation
\n
scope, the following transactions, although they do not
\n
represent transactions involving the acquisition or loss of
\n
control, gave rise to a change in the interest held by the
\n
Group in the investees:
\n
\u2022 on March 15, Enel SpA launched a partial voluntary ten-
\n
der offer for up to a maximum of 7,608,631,104 shares
\n
of Enel Am\u00e9ricas, equal to 10% of the share capital at
\n
that date. The offer period began on March 15 and end-
\n
ed on April 13, 2021.The tender offer was subject to the
\n
effectiveness of the merger of EGP Am\u00e9ricas SpA into
\n
Enel Am\u00e9ricas SA, which took place on April 1, 2021. The
\n
total price was \u20ac1,271 million. Following completion of
\n
the partial voluntary tender offer and the completion of
\n
the EGP Am\u00e9ricas merger, Enel owns about 82.3% of the
\n
outstanding share capital of Enel Am\u00e9ricas;
\n
\u2022 on November 24, Enel Green Power RSA 2 (Pty) Ltd sold
\n
a stake in the investments held in Oyster Bay Wind Farm,
\n
Garob Wind Farm, Aced Renewables Hidden Valley and
\n
Soetwater Wind Farm for a total of ZAR 340 million, cor-
\n
responding to about \u20ac19 million. Following the transac-
\n
tion, the Group\u2019s interest in those companies decreased
\n
from 60% to 55%;
\n
\u2022 on December 3, Enel SpA finalized the sale of the entire
\n
stake held in Open Fiber SpA, equal to 50% of the latter\u2019s
\n
share capital, to Macquarie Asset Management and CDP
\n
Equity SpA for a total of about \u20ac2,733 million. The capital
\n
gain realized by the Group on a consolidated basis came
\n
to about \u20ac1,763 million.
\n
2022
\n
\u2022 On January 3, 2022, Enel Produzione SpA acquired 100%
\n
of ERG Hydro Srl (subsequently renamed Enel Hydro Ap-
\n
pennino Centrale Srl and merged into Enel Produzione
\n
SpA on December 1, 2022), owner of generation plants
\n
with an installed capacity of about 527 MW and an annu-
\n
al output of approximately 1.5 TWh, for a consideration
\n
of about \u20ac1,267 million; in December 2022, the identifi-
\n
cation of the fair value of the acquired assets and liabil-
\n
ities was completed, with the recognition of goodwill of
\n
approximately \u20ac349 million.
\n
\u2022 On February 17, 2022, Enel Green Power Espa\u00f1a acquired
\n
100% of Stonewood Desarrollos SLU for about \u20ac14 mil-
\n
lion representing the licenses acquired for the devel-
\n
opment and construction of photovoltaic systems. The
\n
acquisition had no impact on profit or loss.
\n
\u2022 On March 3, 2022, Enel X Germany sold its entire stake
\n
in Cremzow KG and Cremzow Verwaltungs for about \u20ac12
\n
million.
\n
\u2022 On June 30, 2022, Enel Green Power SpA sold to Al
\n
Rayyan Holding LLC (controlled by the Qatar Investment
\n
Authority) 50% of its stake in EGP Matimba NewCo 1 Srl,
\n
indirect owner of six companies in South Africawith an
\n

\n\n

\n\n

\n\n
installed capacity of about 740 MW, for about \u20ac108 mil-
\n
lion, which has been paid in full.
\n
\u2022 On July 25, 2022, Enel X Srl sold to Mooney SpA, for
\n
about \u20ac140 million, settled in the form of financial re-
\n
ceivables, its entire stakes in Enel X Financial Services,
\n
CityPoste Payment, PayTipper and Junia Insurance and
\n
their subsidiaries.
\n
\u2022 On August 24, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas, closed the sale of its entire stake in CGTF -
\n
Central Geradora Termel\u00e9trica Fortaleza SA to ENEVA
\n
SA for a consideration of about \u20ac89 million. The trans-
\n
action had a negative impact on profit or loss of about
\n
\u20ac210 million, including impairment losses on assets of
\n
\u20ac73 million, a capital loss of \u20ac135 million and transaction
\n
costs connected with the sale of \u20ac2 million.
\n
\u2022 In the first nine months of 2022, Enel Green Power Ro-
\n
mania acquired 100% of Prowind Windfarm Bogdanesti,
\n
Prowind Windfarm Deleni, Prowind Windfarm Ivesti and
\n
Prowind Windfarm Viisoara for a total of about 35 mil-
\n
lion.
\n
\u2022 On October 12, 2022, Enel finalized the sale of its entire
\n
stake in PJSC Enel Russia, equal to 56.43% of the latter\u2019s
\n
share capital, to PJSC Lukoil and the Closed Combined
\n
Mutual Investment Fund \u201cGazprombank-Frezia\u201d, for a to-
\n
tal of about \u20ac137 million. The transaction had a negative
\n
impact on reported Group profit of around \u20ac1.5 billion,
\n
mainly reflecting the release of a currency translation.
\n
\u2022 On December 9, 2022, Enel Chile SA finalized the sale
\n
of its entire 99.09% stake in the share capital of listed
\n
Chilean power transmission company Enel Transmisi\u00f3n
\n
Chile SA to Sociedad Transmisora Metropolitana SpA,
\n
controlled by Inversiones Grupo Saesa Ltda, for about
\n
\u20ac1.3 billion. The transaction generated a capital gain of
\n
about \u20ac1.1 billion.
\n
\u2022 On December 22, 2022, Enel closed the sale of a 50%
\n
quota in its wholly-owned subsidiary Gridspertise Srl to
\n
the international private equity fund CVC Capital Part-
\n
ners Fund VIII for a total of approximately \u20ac300 million.
\n
The transaction had a positive impact on profit or loss of
\n
about \u20ac520 million.
\n
\u2022 On December 23, 2022, Enel Green Power India Private
\n
Limited finalized an agreement with Norfund following
\n
which the latter made an investment in Avikiran Surya
\n
India Private Limited by subscribing shares issued by the
\n
company totaling 49% of the paid-up share capital. The
\n
transaction had a negative impact of about \u20ac4 million on
\n
profit or loss, of which \u20ac2 million from the remeasure-
\n
ment at fair value of the residual interest and a capital
\n
loss of \u20ac2 million.
\n
\u2022 On December 29, 2022, Enel Brasil SA, a subsidiary of
\n
Enel Am\u00e9ricas SA, finalized the sale of its entire stake
\n
in the Brazilian power distribution company Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), equal to about 99.9%
\n
of the latter\u2019s share capital, to Equatorial Participa\u00e7\u00f5es
\n
e Investimentos SA, a subsidiary of Equatorial Energia
\n
SA, for a total of about \u20ac1.5 billion (of which about \u20ac269
\n
million for the equity portion and about \u20ac1.2 billion as
\n
repayment of intercompany loans). The transaction had
\n
a negative impact on profit or loss of about \u20ac1 billion.
\n
Other changes
\n
In addition to the above changes in the consolidation
\n
scope, the following transactions, although they do not
\n
represent transactions involving the acquisition or loss of
\n
control, gave rise to a change in the interest held by the
\n
Group in the investees:
\n
\u2022 on March 1, 2022, the merger between Emgesa SA ESP
\n
(acquiring entity), Codensa SA ESP, Enel Green Power
\n
Colombia SAS ESP and ESSA 2 (merged entities) was
\n
completed. The new name of the surviving company is
\n
Enel Colombia SA ESP. Following the transaction, the
\n
Group\u2019s stake in Emgesa SA ESP (now Enel Colombia SA
\n
ESP) increased from 39.89% to about 47.18%;
\n
\u2022 on March 24, 2022, Enel X International Srl finalized an
\n
agreement with a holding company controlled by Sixth
\n
Cinven Fund and a holding company controlled by Sev-
\n
enth Cinven Fund to indirectly acquire about 79.4% of
\n
the share capital of Ufinet Latam SLU (for \u20ac1,320 million)
\n
and at the same time sold 80.5% of the share capital of
\n
that company to Seventh Cinven Fund (for \u20ac1,186 mil-
\n
lion). Enel X International also received about \u20ac207 mil-
\n
lion from Ufinet as a distribution of available reserves.
\n
Consequently, Enel X International now holds an indirect
\n
stake of 19.5% in Ufinet, of which it had previously held
\n
20.6%. The transaction generated a positive net cash
\n
flow of about \u20ac73 million and had a positive impact on
\n
operating performance of about \u20ac220 million;
\n
\u2022 on June 15, 2022, Enel Kansas LLC sold 50% of its stake
\n
in Rocky Caney Holdings LLC for about \u20ac34 million. Fol-
\n
lowing the transaction, the interest of Enel Kansas LLC in
\n
Rocky Caney Holdings LLC decreased from 20% to 10%.
\n
The transaction generated a capital gain of about \u20ac7 mil-
\n
lion;
\n
\u2022 on June 16, 2022, EGPNA REP Holdings LLC sold 50% of its
\n
stake in EGPNA Renewable Energy Partners LLC for about
\n
\u20ac60 million. Following the transaction, EGPNA REP Hold-
\n
ings LLC holds 10% of EGPNA Renewable Energy Partners
\n
LLC. The transaction generated a capital loss of about \u20ac7
\n
million;
\n
\u2022 on July 14, 2022, Enel, acting through its wholly-owned
\n
subsidiary Enel X, acquired 50% of the share capital of
\n
Mooney SpA. Based on an enterprise value of 100% for
\n
Mooney of \u20ac1,385 million, Enel X paid a total of about
\n
\u20ac225 million (including price adjustment) for the equity
\n
portion and about \u20ac125 million for the purchase of an ex-
\n
isting claim of Schumann Investments SA against Mooney;
\n
\u2022 on December 2022, Enel Green Power Hellas SA sold the
\n
entire stake held in associated companies of the Cy-
\n

\n\n

\n\n

\n\n

\n
clades. The transaction did not have a significant impact
\n
on profit or loss;
\n
\u2022 on December 6, 2022, Enel X Chile SpA sold its entire
\n
stake in Sociedad de Inversiones K Cuatro SpA, Sumin-
\n
istradora de buses K Cuatro SpA and Enel X AMPCI Ebus
\n
Chile SpA for about \u20ac35 million (uncollected as of De-
\n
cember 31, 2022). The transaction did not have a signifi-
\n
cant impact on profit or loss;
\n
\u2022 on December 30, 2022, Enel Green Power Canada Inc.
\n
sold its 49% stake in Pincher Creek LP and Riverview LP
\n
for about \u20ac56 million. The transaction did not result in
\n
the loss of control in the companies.
\n\n
Acquisition of ERG Hydro Srl
\n
On January 3, 2022, Enel Produzione SpA acquired 100% of
\n
ERG Hydro Srl (subsequently renamed Enel Hydro Appen-
\n
nino Centrale Srl and merged into Enel Produzione SpA on
\n
December 1, 2022), owner of generation plants with an in-
\n
stalled capacity of about 527 MW and an annual output of
\n
approximately 1.5 TWh, for about \u20ac1,267 million.
\n
At December 2022, the identification of the fair value of
\n
the acquired assets and liabilities was completed, with the
\n
recognition of goodwill of \u20ac349 million.
\n
Millions of euro
\n
Carrying amount
\n
before January 3, 2022
\n
Adjustments for
\n
purchase price
\n
allocation
\n
Amount recognized
\n
at January 3, 2022
\n
Property, plant and equipment 605 167 772
\n
Intangible assets 1 170 171
\n
Other non-current assets 15 10 25
\n
Cash and cash equivalents 69 - 69
\n
Other current assets 94 - 94
\n
Deferred tax liabilities (4) (102) (106)
\n
Provisions for risk and charges and employee benefits (35) (7) (42)
\n
Current liabilities (65) - (65)
\n
Net assets acquired 680 238 918
\n
Cost of the acquisition 1,267 - 1,267
\n
(of which paid in cash) 1,265 - 1,265
\n
Goodwill 587 (238) 349
\n

\n\n
Sale of Ufinet
\n
On March 24, 2022 Enel X International Srl sold 1.1% of
\n
Ufinet.
\n
The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Price for acquisition of 79.4% through exercise of call option with Sixth Cinven Fund (1,320)
\n
Distribution of Ufinet reserves 207
\n
Price for sale of 80.5% to Seventh Cinven Fund 1,186
\n
Net cash flow of transaction 73
\n
Capital gain on sale of interest (1.1%) (6)
\n
Release of OCI reserve (24)
\n
Net capital gain on sale 43
\n
Fair value measurement of interest already held (19.5%) 177
\n
Total financial impact 220
\n
Following the transaction, the residual investment in Ufinet
\n
was classified under other investments measured at fair
\n
value through other comprehensive income. Previously it
\n
had been accounted for using the equity method.
\n

\n\n

\n\n

\n\n
Sale of EGP Matimba NewCo 1
\n
On June 30, 2022, Enel Green Power SpA sold to Al Rayyan
\n
Holding LLC (controlled by the Qatar Investment Authority)
\n
50% of its stake in EGP Matimba NewCo 1 Srl, indirect own-
\n
er of six projects in South Africa, for about \u20ac108 million,
\n
which has been paid in full.
\n
Millions of euro
\n
Total net assets held for sale with loss of control 220
\n
Interest sold (50%) 110
\n
Sale price 108
\n
Gain/(Loss) on sale (2)
\n
Fair value measurement of interest already held (2)
\n
Total financial impact (4)
\n
Following the transaction, the residual equity investment in
\n
EGP Matimba 1 and its subsidiaries was classified among
\n
equity-accounted investments and it was remeasured at
\n
fair value with a negative impact on profit or loss of about
\n
\u20ac2 million. Following this remeasurement, the value of the
\n
residual equity investment is \u20ac108 million.
\n
Sale of Enel X Financial Services, CityPoste Payment, PayTipper and Junia Insurance
\n
On July 25, 2022, Enel X Srl sold to Mooney SpA, for about
\n
\u20ac140 million, settled in the form of financial receivables, its
\n
entire stakes in Enel X Financial Services, CityPoste Pay-
\n
ment, PayTipper and Junia Insurance and their subsidiaries.
\n
Millions of euro
\n
Value of the transaction 140
\n
Net assets sold (73)
\n
Capital gain on sale 67
\n
The transaction produced a capital gain of \u20ac67 million.
\n
Sale of Central Geradora Termel\u00e9trica Fortaleza SA
\n
On August 24, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas, sold its entire stake in CGTF - Central Geradora
\n
Termel\u00e9trica Fortaleza SA to ENEVA SA for \u20ac89 million.
\n
During 2022, in line with the provisions of \u201cIFRS 5 -
\n
Non-current assets held for sale and discontinued oper-
\n
ations\u201d, the net assets of CGTF - Central Geradora Ter-
\n
mel\u00e9trica Fortaleza SA were classified as held for sale and
\n
their value was adjusted to the expected sale price in the
\n
amount of \u20ac73 million.
\n
Millions of euro
\n
Sale price 89
\n
Net assets sold 125
\n
Reversal of OCI reserve (99)
\n
Capital loss (135)
\n
Adjustment of pre-sale plant value (73)
\n
Financial impact (208)
\n
With the closing of the sale, a capital loss of about \u20ac135
\n
million was recognized, mainly due to the release of the
\n
translation reserve, plus other transaction costs of \u20ac2 mil-
\n
lion and the associated tax impact of \u20ac37 million.
\n

\n\n

\n\n

\n\n
Sale of PJSC Enel Russia
\n
On October 12, 2022, Enel finalized the sale of the entire stake
\n
held in PJSC Enel Russia, equal to 56.43% of the share capital
\n
of the latter, to PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d, for a total of about
\n
\u20ac137 million. The sale had an overall negative impact on profit
\n
or loss of about \u20ac1,551 million, mainly due to the release of the
\n
translation reserve, in the amount of about \u20ac1,054 million. The
\n
financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 137
\n
Net assets sold 137
\n
Reversal of OCI reserve (1,054)
\n
Capital loss (1,054)
\n
Adjustment of pre-sale plant value (497)
\n
Financial impact (1,551)
\n
For more information on the transaction, please see the
\n
section \u201cDiscontinued operations\u201d.
\n
Sale of Enel Transmisi\u00f3n Chile SA
\n
On December 9, 2022, Enel Chile SA finalized the sale of
\n
its entire 99.09% stake in the share capital of listed Chilean
\n
power transmission company Enel Transmisi\u00f3n Chile SA to
\n
Sociedad Transmisora Metropolitana SpA, controlled by In-
\n
versiones Grupo Saesa Ltda, for a total amount of \u20ac1,342
\n
million. The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 1,342
\n
Net assets sold 230
\n
Goodwill 61
\n
Capital gain on sale 1,051
\n
The transaction had a tax effect of \u20ac347 million.
\n
Sale of Gridspertise Srl
\n
On December 22, 2022, Enel SpA, acting through Enel
\n
Grids Srl, closed the sale of a 50% quota in its whol-
\n
ly-owned subsidiary Gridspertise Srl to the international
\n
private equity fund CVC Capital Partners Fund VIII for a to-
\n
tal of approximately \u20ac300 million. The financial effects of
\n
the transaction are as follows.
\n
Millions of euro
\n
Total net assets held for sale with loss of control 80
\n
Interest sold (50%) 40
\n
Sale price 299
\n
Release of OCI reserve 2
\n
Capital gain 261
\n
Fair value measurement of residual interest 259
\n
Total financial impact 520
\n
Following the transaction, the residual investment in in
\n
Gridspertise Srl and its subsidiaries was accounted using
\n
the equity method. After fair value measurement, the value
\n
of the residual investment is \u20ac259 million.
\n
The transaction had a tax effect of \u20ac8 million.
\n

\n\n

\n\n

\n

\n

\n\n

\n
Sale of Celg Distribui\u00e7\u00e3o SA
\n
On December 29, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas SA, finalized
\n
the sale of its entire stake in the
\n
Brazilian power distribution company Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (Enel Goi\u00e1s)
\n
, equal to about 99.9% of the latter\u2019s
\n
share capital
\n
, to Equatorial Participa\u00e7\u00f5es e Investimentos
\n
SA,
\n
a subsidiary of Equatorial Energia SA, for a total of
\n
about \u20ac1,548 million, of which \u20ac269 million for the equity
\n
portion and \u20ac1,279 million as repayment of intercompany
\n
loans. The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 269
\n
Net assets sold 269
\n
Release of OCI reserve (208)
\n
Capital loss on disposal (208)
\n
Adjustment of pre-sale value (827)
\n
Financial impact (1,035)
\n
The sale had a negative impact on profit or loss of about
\n
\u20ac1,035 million, of which about \u20ac208 million mainly attrib-
\n
utable to the release of the OCI reserve and \u20ac827 million in
\n
respect of impairment losses (of which \u20ac85 million relating
\n
to goodwill).
\n
The sale generated transaction costs of \u20ac4 million and a
\n
tax effect of \u20ac8 million.
\n

\n\n
9. Disclosure of impact of Russia-Ukraine conflict and assets
\n
operated in Russia
\n
Impact of the Russian invasion of Ukraine
\n
on the Integrated Annual Report at
\n
December 31, 2022
\n
During 2022, the Enel Group constantly monitored the ef-
\n
fects of the international crisis on its business activities in
\n
Russia (with particular regard to provisioning of materials,
\n
services and labor), also assessing developments in mar-
\n
ket variables (e.g., exchange rates, interest rates). The Enel
\n
Group also took account of developments connected with
\n
the counter-sanctions envisaged by Russia targeting in-
\n
vestments held in the country.
\n
In addition, the Enel Group assessed the indirect impacts
\n
of the war in Ukraine on business activities, the financial
\n
situation and economic performance in the main euro-ar-
\n
ea countries in which it operates, with particular regard to
\n
shortages of raw materials from the areas affected by the
\n
conflict and the generalized increase in commodity prices.
\n
In consideration of the various recommendations of na-
\n
tional and supranational supervisory bodies
\n
(46)
\n
concerning
\n
this issue and in a constantly evolving scenario, character-
\n
ized by considerable regulatory uncertainty and high and
\n
volatile prices, the Enel Group is constantly monitoring the
\n
macroeconomic and business variables that enable a best
\n
estimate of the potential impacts associated with regula-
\n
tory changes, sanctions and restrictions on asset holdings,
\n
as well as on suppliers and contracts applicable to the Enel
\n
Group.
\n
In this regard, it should be noted that no significant im-
\n
pacts related to the Russia-Ukraine conflict have emerged
\n
at December 31, 2022.
\n
Enel sells entire holding of 56.43% in PJSC
\n
Enel Russia
\n
On June 16, 2022, Enel SpA signed two separate agree-
\n
ments with PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d for the sale of the
\n
entire stake held in PJSC Enel Russia, equal to 56.43% of the
\n
share capital of the latter, for a total of about \u20ac137 million.
\n
During the 2nd Quarter of 2022, in order to reduce the risk
\n
(46) ESMA Public Statements no. 71-99-1864 of March 14, 2022 and no. 32-63-1277 of May 13, 2022 and no. 32-63-1320 of October 28, 2022; CONSOB warning
\n
notices in the weekly notices of March 9-14, 2022 and March 10-21, 2022, and no. 3/22 of May 19, 2022.
\n

\n\n

\n
for Enel SpA of the measures issued by the European Union,
\n
the United States and Russia regarding Russian sanctions
\n
and counter-sanctions, a number of measures have been
\n
taken to terminate Enel SpA\u2019s management and coordina-
\n
tion role with Enel Russia. These measures included: (i) the
\n
designation by Enel of only independent directors, of Rus-
\n
sian nationality, at the recent election of the company\u2019s
\n
board of directors; (ii) the appointment of a new general
\n
manager, also of Russian nationality, who reports exclusively
\n
to the board of directors; (iii) the termination, where possi-
\n
ble, of intercompany contracts; (iv) the modification of the
\n
organizational structure of the Enel Group in order to ter-
\n
minate reporting by the staff or business functions of Enel
\n
Russia to their Enel counterparts; and (v) the consequent
\n
interruption of any reporting flows between Enel SpA and
\n
Enel Russia.
\n
The transaction was closed and the consideration paid in
\n
October 2022, following the fulfillment of certain condi-
\n
tions to which the sale is subject,
\n
including approval of the
\n
transaction by the President of the Russian Federation in
\n
accordance with paragraph 5 of Decree 520 of August 5,
\n
2022.
\n
The accounting effects of the sale of the PJSC Enel Russia
\n
Group are shown in note 8 \u201cMain acquisitions and dispos-
\n
als during the year\u201d.
\n
It should also be noted that the Enel Group continues to
\n
hold the following equity investments in Russia:
\n
\u2022 Enel Green Power Rus LLC (a 100% indirect subsidiary of
\n
Enel SpA), a company that provides services for the de-
\n
velopment of renewable projects and which holds 100%
\n
interests in four renewable generation companies;
\n
\u2022 Enel X Rus LLC (a 99% indirect subsidiary of Enel SpA);
\n
\u2022 an investment, equal to 49.5%, in a joint venture (Rusen-
\n
ergosbyt LLC) operating in the End-user Markets Busi-
\n
ness Line.
\n\n

\n
10. Performance and financial position by primary segment (Business
\n
Line) and secondary segment (Geographical Area)
\n\n
The representation of financial position and performance
\n
by business line and geographical area presented here is
\n
based on the approach used by management in monitor-
\n
ing Group performance for the two years being compared.
\n

\n

\n\n
Performance by primary segment (Business Line)
\n
Results for 2022
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-
\n
user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments To ta l
\n
Revenue and other income from third parties 53,239 6,669 19,806 58,478 2,143 182 140,517 - 140,517
\n
Revenue and other income from
\n
transactions with other segments
\n
23,096 2,498 3,226 3,674 66 2,053 34,613 (34,613) -
\n
Total revenue 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Total costs 71,189 5,873 13,918 62,517 1,544 2,503 157,544 (34,580) 122,964
\n
Net results from commodity contracts 551 183 - 1,608 (13) (5) 2,324 41 2,365
\n
Depreciation and amortization 802 1,456 2,852 498 223 255 6,086 - 6,086
\n
Impairment losses 562 53 1,047 1,177 102 17 2,958 - 2,958
\n
Impairment gains (52) (2) (117) (132) (17) 1 (319) - (319)
\n
Operating profit/(loss) 4,385 1,970 5,332 (300) 344 (546) 11,185 8 11,193
\n
Capital expenditure 990
\n
(2)
\n
6,386
\n
(3)
\n
5,547
\n
(4)
\n
721 371
\n
(5)
\n
332 14,347 - 14,347
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(3) Does not include \u20ac42 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac110 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n

\n\n

\n\n

\n\n
Results for 2021
\n
(1) (2) (3)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-
\n
user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments To ta l
\n
Revenue and other income from third parties 22,334 7,011 16,994 36,097 1,372 1,911 85,719 - 85,719
\n
Revenue and other income from
\n
transactions with other segments
\n
10,269 2,161 3,248 1,302 56 2,101 19,137 (19,137) -
\n
Total revenue 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
Total costs 32,327 4,547 13,142 36,372 1,102 2,649 90,139 (19,130) 71,009
\n
Net results from commodity contracts 537 (55) - 2,006 - (3) 2,485 38 2,523
\n
Depreciation and amortization 902 1,237 2,612 399 202 240 5,592 - 5,592
\n
Impairment losses 2,561 387 192 1,067 36 52 4,295 - 4,295
\n
Impairment gains (8) (5) (30) (156) (6) - (205) - (205)
\n
Operating profit/(loss) (2,642) 2,951 4,326 1,723 94 1,068 7,520 31 7,551
\n
Capital expenditure 822 5,662
\n
(4)
\n
5,296 643 285 289 12,997 - 12,997
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
(3) The figures for the Business Line Enel X have been adjusted to take account of the transfer of certain net assets and related revenue and expenses to the
\n
new Business Line Enel X Way, which are shown under \u201cHolding, Services and Other\u201d.
\n
(4) Does not include \u20ac111 million regarding units classified as held for sale or discontinued operations.
\n
Performance by secondary segment (Geographical Area)
\n
Results for 2022
\n
(1)
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments To ta l
\n
Revenue and other income from third parties 83,337 32,725 20,949 77 2,183 266 980 140,517
\n
Revenue and other income from
\n
transactions with other segments
\n
171 108 385 10 31 - (705) -
\n
Total revenue 83,508 32,833 21,334 87 2,214 266 275 140,517
\n
Total costs 81,880 25,388 14,811 66 1,126 174 (481) 122,964
\n
Net results from commodity contracts 4,679 (2,215) 56 6 (148) (9) (4) 2,365
\n
Depreciation and amortization 2,209 1,784 1,393 2 430 75 193 6,086
\n
Impairment losses 886 478 1,553 1 18 5 17 2,958
\n
Impairment gains (39) (271) (7) - - - (2) (319)
\n
Operating profit/(loss) 3,251 3,239 3,640 24 492 3 544 11,193
\n
Capital expenditure 4,640 2,316 4,289
\n
(2)
\n
224
\n
(3)
\n
2,491 164
\n
(4)
\n
223
\n
(5)
\n
14,347
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac94 million regarding units classified as held for sale.
\n
(3) Does not include \u20ac4 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac40 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac18 million regarding units classified as held for sale or discontinued operations.
\n
Results for 2021
\n
(1) (2)
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments To ta l
\n
Revenue and other income from third parties 44,282 20,800 16,956 49 1,479 240 1,913 85,719
\n
Revenue and other income from
\n
transactions with other segments
\n
1,135 252 1 (35) 34 1 (1,388) -
\n
Total revenue 45,417 21,052 16,957 14 1,513 241 525 85,719
\n
Total costs 40,751 17,412 12,867 59 748 135 (963) 71,009
\n
Net results from commodity contracts 1,967 543 53 40 (81) 4 (3) 2,523
\n
Depreciation and amortization 2,107 1,754 1,177 4 356 65 129 5,592
\n
Impairment losses 1,747 1,797 536 1 161 32 21 4,295
\n
Impairment gains (22) (170) (9) (2) - - (2) (205)
\n
Operating profit/(loss) 2,801 802 2,439 (8) 167 13 1,337 7,551
\n
Capital expenditure 3,842 2,202 3,722 456 2,293 217
\n
(3)
\n
265 12,997
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
(3) Does not include \u20ac111 million regarding units classified as held for sale or discontinued operations.
\n

\n\n

\n\n

\n\n
Financial position by primary segment (Business Line)
\n
At December 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 8,530 41,519 40,377 44 553 805 91,828 (3) 91,825
\n
Intangible assets 397 5,723 20,035 4,172 647 623 31,597 - 31,597
\n
Non-current and current
\n
contract assets
\n
- 50 500 - 72 53 675 (11) 664
\n
Trade receivables 7,667 3,730 5,706 8,426 618 1,304 27,451 (9,715) 17,736
\n
Other 7,928 540 2,551 2,716 480 2,535 16,750 (7,897) 8,853
\n
Operating assets 24,522
\n
(1)
\n
51,562
\n
(2)
\n
69,169
\n
(3)
\n
15,358
\n
(4)
\n
2,370
\n
(5)
\n
5,320 168,301 (17,626) 150,675
\n
Trade payables 8,034 4,173 4,297 8,647 705 1,394 27,250 (9,187) 18,063
\n
Non-current and current
\n
contract liabilities
\n
95 323 7,527 76 10 22 8,053 (89) 7,964
\n
Sundry provisions 3,979 921 3,263 380 101 1,095 9,739 (68) 9,671
\n
Other 3,475 1,802 6,691 6,740 300 4,454 23,462 (7,908) 15,554
\n
Operating liabilities 15,583
\n
(6)
\n
7, 2 1 9
\n
(7)
\n
21,778
\n
(8)
\n
15,843
\n
(9)
\n
1,116
\n
(10)
\n
6,965
\n
(11)
\n
68,504 (17,252) 51,252
\n
(1) Of which \u20ac190 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac1,951 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac1,855 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac1,160 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac80 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac87 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac185 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac390 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac476 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac11 million regarding units classified as held for sale or discontinued operations.
\n
(11) Of which \u20ac4 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2021
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 9,384 36,205 38,635 49 486 713 85,472 - 85,472
\n
Intangible assets 216 5,016 21,473 4,030 670 631 32,036 - 32,036
\n
Non-current and current
\n
contract assets
\n
1 1 525 - 60 21 608 43 651
\n
Trade receivables 4,814 2,601 6,731 6,533 559 1,347 22,585 (6,493) 16,092
\n
Other 4,319 826 2,614 3,812 345 2,287 14,203 (6,107) 8,096
\n
Operating assets 18,734
\n
(2)
\n
44,649
\n
(3)
\n
69,978 14,424 2,120
\n
(4)
\n
4,999 154,904 (12,557) 142,347
\n
Trade payables 5,730 3,701 4,390 7,129 695 1,259 22,904 (5,920) 16,984
\n
Non-current and current
\n
contract liabilities
\n
102 216 7,316 62 13 13 7,722 (75) 7,647
\n
Sundry provisions 4,586 936 3,810 466 52 1,297 11,147 (89) 11,058
\n
Other 4,125 1,901 8,104 4,575 141 3,659 22,505 (6,245) 16,260
\n
Operating liabilities 14,543 6,754
\n
(5)
\n
23,620 12,232 901
\n
(6)
\n
6,228 64,278 (12,329) 51,949
\n
(1) The figures for the Business Line Enel X have been adjusted to take account of the transfer of certain net assets and related revenue and expenses to the
\n
new Business Line Enel X Way, which are shown under \u201cHolding, Services and Other\u201d.
\n
(2) Of which \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac999 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac136 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac28 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac57 million regarding units classified as held for sale or discontinued operations.
\n

\n\n

\n\n

\n\n
Financial position by secondary segment (Geographical Area)
\n
At December 31, 2022
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 30,327 23,167 21,099 2,397 13,722 1,002 111 91,825
\n
Intangible assets 3,200 16,173 10,534 331 602 129 628 31,597
\n
Non-current and current contract
\n
assets
\n
73 9 493 48 19 16 6 664
\n
Trade receivables 7,086 4,369 5,037 1,127 268 66 (217) 17,736
\n
Other 4,947 2,929 1,498 294 250 63 (1,128) 8,853
\n
Operating assets 45,633
\n
(1)
\n
46,647 38,661
\n
(2)
\n
4,197
\n
(3)
\n
14,861 1,276
\n
(4)
\n
(600) 150,675
\n
Trade payables 9,595 3,220 4,813 483 1,261 119 (1,428) 18,063
\n
Non-current and current contract
\n
liabilities
\n
4,188 3,351 35 443 - 1 (54) 7,964
\n
Sundry provisions 3,008 3,458 2,378 69 97 32 629 9,671
\n
Other 4,323 3,144 4,480 637 1,893 66 1,011 15,554
\n
Operating liabilities 21,114
\n
(5)
\n
13,173 11,706
\n
(6)
\n
1,632
\n
(7)
\n
3,251 218
\n
(8)
\n
158 51,252
\n
(1) Of which \u20ac251 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac307 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac4,125 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac553 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac64 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac76 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac961 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac52 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2021
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 27,335 23,075 18,671 3,440 10,853 1,948 150 85,472
\n
Intangible assets 2,313 16,071 11,414 772 557 179 730 32,036
\n
Non-current and current contract
\n
assets
\n
94 5 517 - 18 13 4 651
\n
Trade receivables 7,372 3,886 4,414 583 215 51 (429) 16,092
\n
Other 4,555 2,474 1,398 217 259 140 (947) 8,096
\n
Operating assets 41,669
\n
(1)
\n
45,511 36,414 5,012 11,902 2,331
\n
(2)
\n
(492)
\n
(3)
\n
142,347
\n
Trade payables 9,684 2,509 4,333 481 1,208 136 (1,367) 16,984
\n
Non-current and current contract
\n
liabilities
\n
4,109 3,109 30 438 - - (39) 7,647
\n
Sundry provisions 3,395 4,211 2,426 130 120 32 744 11,058
\n
Other 5,749 3,945 4,509 328 1,482 64 183 16,260
\n
Operating liabilities 22,937
\n
(4)
\n
13,774 11,298 1,377 2,810 232
\n
(5)
\n
(479)
\n
(6)
\n
51,949
\n
(1) Of which \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac999 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac136 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac6 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac22 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac57 million regarding units classified as held for sale or discontinued operations.
\n

\n\n

\n\n

\n\n
The following table reconciles segment assets and liabili-
\n
ties and the consolidated figures.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Total assets 219,618 206,940
\n
Equity-accounted investments 1,281 704
\n
Non-current financial derivative assets 3,970 2,772
\n
Other non-current financial assets 8,359 5,704
\n
Non-current tax assets included in \u201cOther non-current assets\u201d 1,674 2,286
\n
Other current financial assets 13,753 8,645
\n
Current financial derivative assets 14,830 22,791
\n
Cash and cash equivalents 11,041 8,858
\n
Deferred tax assets 10,925 11,034
\n
Tax assets 2,159 1,694
\n
Financial and tax assets of \u201cAssets held for sale\u201d 951 105
\n
Segment assets 150,675 142,347
\n
Total liabilities 177,536 164,598
\n
Long-term borrowings 68,191 54,500
\n
Non-current financial derivative liabilities 5,895 3,339
\n
Other non-current financial liabilities -120
\n
Short-term borrowings 18,392 13,306
\n
Current portion of long-term borrowings 2,835 4,031
\n
Other current financial liabilities 853 625
\n
Current financial derivative liabilities 16,141 24,607
\n
Deferred tax liabilities 9,542 9,259
\n
Income tax liabilities 1,623 712
\n
Other tax liabilities 1,047 1,274
\n
Financial and tax liabilities of \u201cLiabilities included in disposal groups held for sale\u201d 1,765 876
\n
Segment liabilities 51,252 51,949
\n

\n\n

\n\n

\n
Information on the consolidated income statement
\n\n

\n
Revenue
\n\n
11.a Revenue from sales and services \u2013 \u20ac135,653 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Sale of electricity 69,340 45,053 24,287 53.9%
\n
Transport of electricity 11,096 10,606 490 4.6%
\n
Fees from network operators 979 800 179 22.4%
\n
Transfers from institutional market operators 1,667 833 834 -
\n
Sale of gas 8,970 4,744 4,226 89.1%
\n
Transport of gas 80 599 (519) -86.6%
\n
Sale of fuel 5,605 1,791 3,814 -
\n
Fees for connection to electricity and gas networks 826 769 57 7.4%
\n
Construction contracts
\n
(1)
\n
1,672 1,268 404 31.9%
\n
Sale of environmental certificates 111 107 4 3.7%
\n
Sale of value-added services 1,384 1,092 292 26.7%
\n
Other sales and services 918 785 133 16.9%
\n
Total IFRS 15 revenue 102,648 68,447 34,201 50.0%
\n
Sale of commodities under contracts with physical settlement 37,247 24,314 12,933 53.2%
\n
Gain/(Loss) on the measurement of commodity sales contracts with physical
\n
settlement closed during the period
\n
(4,260) (10,893) 6,633 60.9%
\n
Other revenue 18 32 (14) -43.8%
\n
Total revenue from sales and services 135,653 81,900 53,753 65.6%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Revenue from the \u201cSale of electricity\u201d amounted to \u20ac69,340
\n
million, an increase of \u20ac24,287 million compared with the
\n
previous year (+53.9%). The increase mainly reflects higher
\n
sales volumes and prices, mainly in Italy (\u20ac14,852 million)
\n
and Spain (\u20ac8,076 million).
\n
\u201cTransfers from institutional market operators\u201d increased
\n
by \u20ac834 million compared with the previous year, mainly
\n
in Iberia due to an increase in costs incurred for the pur-
\n
chase of commodities used in thermal generation plants in
\n
the Canary Islands, taking account of the rise in prices on
\n
international markets.
\n
Revenue from the \u201cSale of gas\u201d in 2022 amounted to \u20ac8,970
\n
million (\u20ac4,744 million in 2021), an increase of \u20ac4,226 million
\n
compared with the previous year. The increase is mainly attrib-
\n
utable to higher sales volumes at higher average prices espe-
\n
cially in Spain (\u20ac2,253 million) and Italy (\u20ac1,781 million).
\n
Revenue from the \u201cSale of fuel\u201d increased by \u20ac3,814 million,
\n
especially by Enel Global Trading due to the rise in gas sales.
\n
The increase in the \u201cSale of commodities under contracts
\n
with physical settlement\u201d (\u20ac12,933 million) and of perfor-
\n
mance of the measurement of contracts settled in 2022
\n
(\u20ac6,633 million) mainly involve gas contracts.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Revenue from contracts with customers (IFRS 15) breaks
\n
down into \u201cpoint in time\u201d and \u201cover time\u201d revenue as indi-
\n
cated in the following tables.
\n
Millions of euro 2022
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
47,650 2,068 30,984 1,425 17,686 1,227 52 4 1,109 33 214 43 10 143 97,705 4,943
\n
2021
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
(1)
\n
29,187 1,178 19,707 402 16,525 245 46 2 805 17 194 26 - 113 66,464 1,983
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The following table shows the net results on contracts for
\n
the sale or purchase of commodities with physical settle-
\n
ment measured at fair value through profit or loss within
\n
the scope of IFRS 9.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro
\n
2022 2021 Change
\n
Fair value gain/(loss) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
Sales contracts
\n
Sale of electricity 5,436 4,368 1,068 24.5%
\n
Fair value gain/(loss) on closed contracts (795) (1,705) 910 53.4%
\n
Total electricity 4,641 2,663 1,978 74.3%
\n
Sale of gas 30,924 19,576 11,348 58.0%
\n
Fair value gain/(loss) on closed contracts (3,600) (9,335) 5,735 61.4%
\n
Total gas 27,324 10,241 17,083 -
\n
Sale of emissions allowances 875 366 509 -
\n
Fair value gain/(loss) on closed contracts 131 146 (15) -10.3%
\n
Total emissions allowances 1,006 512 494 96.5%
\n
Sale of guarantees of origin 12 4 8 -
\n
Fair value gain/(loss) on closed contracts 4 1 3 -
\n
Total guarantees of origin 16 5 11 -
\n
Total revenue 32,987 13,421 19,566 -
\n
Purchase contracts
\n
Purchase of electricity 6,161 3,677 2,484 67.6%
\n
Fair value gain/(loss) on closed contracts (200) (1,220) 1,020 83.6%
\n
Total electricity 5,961 2,457 3,504 -
\n
Purchase of gas 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on closed contracts (1,940) (8,057) 6,117 75.9%
\n
Total gas 31,152 11,894 19,258 -
\n
Purchase of emissions allowances 843 806 37 4.6%
\n
Fair value gain/(loss) on closed contracts 132 144 (12) -8.3%
\n
Total emissions allowances 975 950 25 2.6%
\n
Purchase of guarantees of origin 25 4 21 -
\n
Fair value gain/(loss) on closed contracts 3 1 2 -
\n
Total guarantees of origin 28 5 23 -
\n
Total costs 38,116 15,306 22,810 -
\n
Net revenue/(costs) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
(5,129) (1,885) (3,244) -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
Sales contracts
\n
Electricity (134) (1,606) 1,472 91.7%
\n
Gas 4,841 (16,285) 21,126 -
\n
Emissions allowances 490 (487) 977 -
\n
Guarantees of origin (15) (8) (7) -87.5%
\n
Tot al 5,182 (18,386) 23,568 -
\n
Purchase contracts
\n
Electricity (124) (2,169) 2,045 94.3%
\n
Gas 3,879 (13,801) 17,680 -
\n
Emissions allowances 627 (520) 1,147 -
\n
Guarantees of origin (72) 12 (84) -
\n
Tot al 4,310 (16,478) 20,788 -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
872 (1,908) 2,780 -
\n
Total net revenue/(costs) on contracts with physical settlement (within the scope of IFRS 9) (4,257) (3,793) (464) -12.2%
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The table below gives a breakdown of revenue from sales
\n
and services by geographical segment.
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Italy 57,859 33,304
\n
Europe
\n
Iberia 30,535 18,896
\n
France 3,086 970
\n
Switzerland 6,791 2,918
\n
Germany 1,676 1,085
\n
Austria 189 245
\n
Slovenia 146 195
\n
Romania 3-
\n
Greece 15 -
\n
Bulgaria --
\n
Belgium 834 522
\n
Czech Republic 321 435
\n
Hungary 712
\n
Russia -3
\n
Netherlands 38 96
\n
United Kingdom 11,841 3,736
\n
Other European countries 1,551 1,160
\n
Americas
\n
United States 779 601
\n
Canada 53 33
\n
Mexico 313 202
\n
Brazil 9,064 9,381
\n
Chile 4,434 3,151
\n
Peru 1,449 1,111
\n
Colombia 2,725 2,188
\n
Argentina 966 887
\n
Panama 177 150
\n
Costa Rica 17 14
\n
Guatemala 83 67
\n
Other
\n
Africa 132 114
\n
Asia 521 371
\n
Oceania 48 53
\n
Tot al 135,653 81,900
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Performance obligations
\n
The following table provides information about the Group\u2019s
\n
performance obligations arising from contracts with cus-
\n
tomers with reference to the main revenue streams only,
\n
with a summary of the specific judgments made and the
\n
related revenue recognition policies.
\n
For information on the use of estimates with revenue from
\n
contracts with customers, please see note 2.1 \u201cUse of esti-
\n
mates and management judgment\u201d.
\n
Type of product/
\n
service Nature and timing of satisfaction of performance obligation Accounting policies
\n
Sale of electricity
\n
produced by the
\n
Group
\n
In order to determine the nature of the promise contained in these
\n
contracts with customers for the sale of electricity, the Group carefully
\n
analyzes the facts and circumstances applicable to each contract.
\n
For the sale of electricity on power exchanges, the facts and
\n
circumstances (including the intrinsic characteristics of the commodity,
\n
contractual terms, information regarding infrastructure and other
\n
delivery mechanisms) generally indicate that the performance obligation
\n
is a service in which the customer simultaneously receives and
\n
consumes the benefits of the commodity as it is delivered. Thus, the
\n
Group identifies a performance obligation satisfied over time as part of
\n
a series of distinct goods/services (i.e., each unit of commodity) that
\n
are substantially the same and have the same pattern of transfer to the
\n
customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale of electricity
\n
on power exchanges, recognized over time, so
\n
as to recognize revenue in the amount to which
\n
it has a right to invoice the customer if that
\n
amount corresponds directly with the value to the
\n
customer of the performance completed to date,
\n
i.e., at the price defined in the market (without
\n
variable consideration).
\n
Network
\n
connection
\n
services
\n
The network connection fees received from customers for connecting
\n
them to the electricity/gas distribution networks require a specific
\n
Group assessment to take into consideration all terms and conditions of
\n
the connection arrangements.
\n
This assessment is intended to determine whether the contract includes
\n
other distinct goods or services, such as for example the right to obtain
\n
ongoing access to the infrastructure in order to receive the commodity
\n
or, when the connection fee is a \u201cnon-refundable up-front fee\u201d paid
\n
at or near contract inception, a material right that gives rise to a
\n
performance obligation.
\n
In particular, in some countries in which the Group operates, it has
\n
determined that the nature of the consideration received represents
\n
a \u201cnon-refundable up-front fee\u201d whose payment provides a material
\n
right to the customer. In order to determine if the period over which
\n
this material right should be recognized extends beyond the initial
\n
contractual period, the Group takes into consideration the applicable
\n
local legal and regulatory framework applicable to the contract and
\n
affecting the parties. In such cases, if there is an implied assignment
\n
of the material right and an obligation from the initial customer to
\n
the new customer, the Group recognizes the connection fee over a
\n
period beyond the relationship with the initial customer, considering
\n
the concession terms as the period during which the initial customer
\n
and any future customer can benefit from the ongoing access without
\n
paying an additional connection fee. As a consequence, the fee is
\n
recognized over the period for which the payment creates an obligation
\n
for the Group to make the lower prices available to future customers (i.e.,
\n
the period during which the customer is expected to benefit from the
\n
ongoing access service without having to pay an \u201cup-front fee\u201d upon
\n
renewal).
\n
Revenue from monetary and in-kind fees for
\n
connection to the electricity and gas distribution
\n
network is recognized on the basis of the
\n
satisfaction of the performance obligations
\n
included in the contract. The identification of
\n
distinct goods or services requires a careful
\n
analysis of the terms and conditions of the
\n
connection arrangements, which could vary
\n
from country to country based on the local
\n
context, regulations and law. In order to finalize
\n
this assessment, the Group considers not
\n
only the characteristics of the goods/services
\n
themselves (i.e., the good or service is capable of
\n
being distinct) but also the implied promises for
\n
which the customer has a valid expectation as it
\n
views those promises as part of the negotiated
\n
exchange, that is goods/services that the
\n
customer expects to receive and has paid for (i.e.,
\n
the promise to transfer the good or service to
\n
the customer is separately identifiable from other
\n
promises in the contract).
\n
Furthermore, the Group acts as an agent in some
\n
contracts for electricity/gas network connection
\n
services and other related activities, depending
\n
on local legal and regulatory framework. In such
\n
cases, it recognizes revenue on a net basis,
\n
corresponding to any fee or commission to which
\n
it expects to be entitled.
\n
Sale/transport of
\n
electricity/gas to
\n
end users
\n
An electricity/gas supply agreement signed with an end user includes
\n
a single performance obligation (sale and transport of the commodity)
\n
because the Group has determined that the contract does not provide
\n
distinct goods/services and the promise is satisfied by transferring
\n
control over the commodity to the customer when it is delivered at
\n
the point of delivery. In order to determine the nature of the promise
\n
included in such contracts, the Group carefully analyzes the facts and
\n
circumstances applicable to each contract and commodity.
\n
However, the Group considers that the performance obligation provided
\n
for in a repetitive service contract, such as a supply or transport contract
\n
for the provision of electricity/gas to end users, is typically satisfied over
\n
time (because the customer simultaneously receives and consumes the
\n
benefits of the commodity as it is delivered) as part of a series of distinct
\n
goods/services (i.e., each unit of commodity) that are substantially the
\n
same and have the same pattern of transfer to the customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale and transport of
\n
electricity/gas to end users, so as to recognize
\n
revenue in the amount to which it has a right to
\n
invoice the customer if that amount corresponds
\n
directly with the value to the customer of
\n
the performance completed to date, i.e., the
\n
quantities provided during the period, even if
\n
these have not yet been invoiced; this revenue is
\n
determined using estimates as well as periodic
\n
meter readings. Where applicable, this revenue
\n
is based on the rates and related restrictions
\n
established by law or by the Regulatory Authority
\n
for Energy, Networks and the Environment
\n
(ARERA) and analogous foreign authorities during
\n
the applicable period.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
Construction
\n
contracts
\n
The construction contracts typically include a performance obligation
\n
satisfied over time. For these contracts, the Group generally considers
\n
it appropriate to use an input method for measuring progress, except
\n
when a specific contract analysis suggests the use of an alternative
\n
method that better depicts the Group\u2019s performance obligation fulfilled
\n
at the reporting date.
\n
For construction contracts that include a
\n
performance obligation satisfied over time,
\n
the Group recognizes revenue over time by
\n
measuring progress toward the complete
\n
satisfaction of that performance obligation. The
\n
cost-to-cost method is generally considered the
\n
best method to depict the Group\u2019s performance
\n
obligation fulfilled at the reporting date.
\n
The amount due from customers under a
\n
construction contract is presented as a contract
\n
asset; the amount due to customers under a
\n
construction contract is presented as a contract
\n
liability.
\n
Concession
\n
service
\n
arrangements
\n
(within the scope
\n
of IFRIC 12)
\n
The Group, as concession holder, provides services for the construction/
\n
upgrade of the infrastructure used for the provision of public services
\n
and/or services for the operation and maintenance of the infrastructure
\n
itself for the period of the concession.
\n
For performance obligations related to infrastructure construction and
\n
improvement, please refer to the section \u201cConstruction contracts\u201d.
\n
As far as revenue from operating services is concerned, please refer
\n
to the sections \u201cSale of electricity produced by the Group\u201d and \u201cSale/
\n
transport of electricity/gas to end users\u201d.
\n
When the Group provides construction/upgrade
\n
services, it recognizes intangible assets and/or
\n
financial assets, depending on the characteristics
\n
of the service concession arrangement.
\n
The amounts received or receivable relating
\n
to both components are initially recognized as
\n
revenue from contracts with customers. For more
\n
details on revenue recognition, please refer to the
\n
section \u201cConstruction contracts\u201d.
\n
Furthermore, the component recognized in profit
\n
or loss deriving from the remeasurement at fair
\n
value of the financial assets in respect of service
\n
concession agreements for the distribution
\n
business in Brazil is also classified as revenue, in
\n
order to adequately reflect the business model in
\n
line with the related concession agreement.
\n
Revenue from management and maintenance
\n
activities is recognized as revenue from the
\n
sale of electricity on the market or to end users
\n
(please refer to sections \u201cSale of electricity
\n
produced by the Group\u201d and \u201cSale/transport of
\n
electricity/gas to end users\u201d, respectively).
\n

\n\n\n

\n\n
11.b Other income \u2013 \u20ac4,864 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Operating grants 28 33 (5) -15.2%
\n
Grants for environmental certificates 220 249 (29) -11.6%
\n
Capital grants (electricity and gas business) 28 26 2 7.7%
\n
Sundry reimbursements 314 300 14 4.7%
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
1,876 1,781 95 5.3%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
64 59 5 8.5%
\n
Service continuity bonuses 31 48 (17) -35.4%
\n
Other income 2,303 1,323 980 74.1%
\n
Tot al 4,864 3,819 1,045 27.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
\u201cGrants for environmental certificates\u201d came to \u20ac220 mil-
\n
lion, a decrease of \u20ac29 million compared with the previ-
\n
ous year, mainly reflecting the decrease in grants for white
\n
certificates obtained from distribution operations in Italy.
\n
This effect was partially offset by the increase in grants for
\n
guarantees of origin in Spain.
\n
Gains on the disposal of entities amounted to \u20ac1,876 mil-
\n
lion in 2022, mainly reflecting the recognition gains on the
\n
disposal by Enel X International of 1.1% of the investment
\n
in Ufinet (\u20ac220 million), the sale by Enel X Srl of financial
\n
companies to Mooney (\u20ac67 million), the sale of 50% of the
\n
investment held by Enel Grids in Gridspertise (\u20ac520 million)
\n
and the sale of Enel Chile\u2019s interest in Enel Transmisi\u00f3n Chile.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
In 2021 the item included the capital gain on the sale of
\n
Enel SpA\u2019s interest in Open Fiber (\u20ac1,763 million).
\n
\u201cOther income\u201d increased by \u20ac980 million, mainly due to
\n
the increase of income in Chile (\u20ac503 million) following a
\n
modification of the existing contractual agreement with
\n
Shell, in terms of volumes committed by the supplier, and
\n
the increase in Enel Green Power North America of income
\n
from tax partnership (\u20ac319 million).
\n
The following tables show a breakdown of total revenue by
\n
business line based on the approach used by management
\n
to monitor the Group\u2019s performance during the two years
\n
being compared.
\n
Millions of euro 2022
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 61,711 1,782 2,167 131,531 (28,883) 102,648
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
42,667 - - 26 - - 42,693 (5,446) 37,247
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts with physical
\n
settlement closed during
\n
the period
\n
(4,240) - - (20) - - (4,260) - (4,260)
\n
Other revenue - 6 13 - 1 21 41 (23) 18
\n
Total revenue from sales
\n
and services
\n
75,581 7,869 20,867 61,717 1,783 2,188 170,005 (34,352) 135,653
\n
Other income 754 1,298 2,165 435 426 47 5,125 (261) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Millions of euro 2021
\n
(1)
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 16,673 8,533 19,681 36,933 1,277 2,189 85,286 (16,839) 68,447
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
26,691 - - 14 - - 26,705 (2,391) 24,314
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts
\n
(10,895) - - 1 - - (10,894) 1 (10,893)
\n
Other revenue 5 6 15 - 3 31 60 (28) 32
\n
Total revenue from sales
\n
and services
\n
32,474 8,539 19,696 36,948 1,280 2,220 101,157 (19,257) 81,900
\n
Other income 129 633 546 451 148 1,792 3,699 120 3,819
\n
TOTAL REVENUE 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Costs
\n
12.a Electricity, gas and fuel \u2013 \u20ac96,896 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Electricity 47,155 28,624 18,531 64.7%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 6,161 3,677 2,484 67.6%
\n
Gas 47,930 26,614 21,316 80.1%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on contracts for purchase of electricity and gas with
\n
physical settlement closed during the period
\n
(2,140) (9,277) 7,137 76.9%
\n
Nuclear fuel 111 107 4 3.7%
\n
Other fuels 3,840 1,634 2,206 -
\n
Total 96,896 47,702 49,194 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Costs for the purchase of \u201cElectricity\u201d mainly increased
\n
due to a rise in volumes purchased in an environment of
\n
increasing average prices compared with the previous
\n
year, mainly attributable to Italy (\u20ac15,396 million) and Spain
\n
(\u20ac3,563 million).
\n
The increase in costs for the purchase of \u201cGas\u201d mainly re-
\n
flects the increase in quantities handled, mainly due to a
\n
rise in generation, as well as the increase in the cost of
\n
purchasing gas from third parties.
\n
The gain/(loss) from the fair value measurement of closed
\n
contracts with physical settlement showed an increase of
\n
\u20ac7,137 million compared with the previous year, of which
\n
\u20ac6,117 million attributable to gas and \u20ac1,020 million to
\n
electricity.
\n
The increase in \u201cOther fuels\u201d is mainly attributable to the
\n
increase in the volume of generation and the rise in com-
\n
modity prices.
\n
12.b Services and other materials \u2013 \u20ac20,228 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wheeling 8,247 8,921 (674) -7.6%
\n
Maintenance and repairs 1,067 1,364 (297) -21.8%
\n
Telephone and postal costs 181 177 4 2.3%
\n
Communication services 117 123 (6) -4.9%
\n
IT services 872 959 (87) -9.1%
\n
Leases and rentals 503 126 377 -
\n
Other services 5,707 4,160 1,547 37.2%
\n
Purchase of environmental certificates 963 1,256 (293) -23.3%
\n
- of which relating to purchases from contracts with physical delivery (IFRS 9) 868 810 58 7.2%
\n
Fair value gain/(loss) on contracts for purchase of environmental certificates
\n
with physical settlement closed during the period
\n
135 145 (10) -6.9%
\n
Change in inventories of environmental certificates 97 32 65 -
\n
Other materials 2,533 2,041 492 24.1%
\n
Tot al 20,228 19,240 988 5.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n
Costs for services and other materials amounted to
\n
\u20ac20,228 million in 2022, an increase of \u20ac988 million com-
\n
pared with 2021. This change essentially reflected:
\n
\u2022 an increase in costs for leases and rentals, mainly re-
\n
flecting the closure, in 2021, of a dispute in Spain, which
\n
permitted the reversal of provisions previously recog-
\n
nized in the amount of about \u20ac300 million;
\n
\u2022 an increase of \u20ac1,547 million in \u201cOther services\u201d, es-
\n
sentially reflecting the increase in costs for services
\n
connected with the electricity and gas business (\u20ac720
\n
million), those related to concessions in Brazil (\u20ac281 mil-
\n
lion), those related to the value-added services business
\n
(\u20ac119 million) and expenses for professional and techni-
\n
cal services (\u20ac156 million);
\n
\u2022 an increase in \u201cOther materials\u201d mainly attributable to
\n
higher procurement costs of raw materials and higher
\n
production volumes;
\n
\u2022 a decline in costs for wheeling, mainly in Italy and Spain,
\n
attributable to a decline in the average price applied,
\n
partially offset by an increase of those in Latin America
\n
due to the increase in traded volumes;
\n
\u2022 lower provisions for costs connected with the conver-
\n
sion of plants in Italy for the purposes of the energy tran-
\n
sition;
\n
\u2022 a decrease in costs for systems assistance, computer
\n
maintenance and IT development, mainly in Italy.
\n\n
12.c Personnel expenses \u2013 \u20ac4,570 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wages and salaries 3,442 3,122 320 10.2%
\n
Social security contributions 924 844 80 9.5%
\n
Italian post-employment benefits 107 104 3 2.9%
\n
Post-employment and other long-term benefits 73 86 (13) -15.1%
\n
Early retirement incentives (20) 10 (30) -
\n
Early retirement incentives connected with restructuring agreements (151) 795 (946) -
\n
Other costs 195 179 16 8.9%
\n
Tot al 4,570 5,140 (570) -11.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Personnel expenses in 2022 amounted to \u20ac4,570 million, a
\n
decrease of \u20ac570 million.
\n
The Group\u2019s workforce decreased by 1,155 employees,
\n
mainly reflecting the positive balance between new hires
\n
and terminations (1,998 employees), more than offset by
\n
changes in the consolidation scope (-3,153 employees),
\n
essentially attributable to:
\n
\u2022 the acquisition of Enel Hydro Appennino Centrale Srl in
\n
Italy;
\n
\u2022 the acquisition of Melita Italia Srl in Italy;
\n
\u2022 the sale of PayTipper SpA in Italy;
\n
\u2022 the sale of CityPoste Payment SpA in Italy;
\n
\u2022 the sale of PayTipper Network Srl in Italy;
\n
\u2022 the sale of FlagPay Srl in Italy;
\n
\u2022 the sale of Gridspertise Srl in Italy;
\n
\u2022 the sale of Central Geradora Termel\u00e9trica Fortaleza SA,
\n
Celg Distribui\u00e7\u00e3o SA - Celg-D and Gridspertise Latam SA
\n
in Brazil;
\n
\u2022 the sale of PJSC Enel Russia and subsidiaries in Russia;
\n
\u2022 the sale of Enel Transmisi\u00f3n SA in Chile.
\n
The increase in \u201cWages and salaries\u201d substantially reflects
\n
the cost incurred as a result of new hiring at companies in
\n
Italy, the United States, Brazil, Spain and Argentina.
\n
The \u20ac13 million decrease in in \u201cPost-employment and oth-
\n
er long-term benefits\u201d is mainly attributable to Spain.
\n
The decrease in \u201cEarly retirement incentives connected
\n
with restructuring agreements\u201d is mainly attributable to an
\n
increase in costs in Italy in 2021 as a result of the signing
\n
of a new framework agreement in application of Article 4,
\n
paragraphs 1-7-ter, of Law 92/2012, for which provisions
\n
of \u20ac557 million were recognized for restructuring and dig-
\n
italization. In 2022 the provision was adjusted according to
\n
the developments of the period and changes underlying
\n
the actuarial assumptions.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
The table below shows the average number of employees
\n
by category, along with a comparison with the previous
\n
year, and the headcount as of December 31, 2022.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
2022 2021 at Dec. 31, 2022
\n
Senior managers 1,389 1,386 1,366
\n
Middle managers 12,528 11,797 12,645
\n
Office staff 35,676 35,449 34,634
\n
Blue collar 16,883 17,344 16,479
\n
Tot al 66,476 65,976 65,124
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n

\n\n\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013
\n
\u20ac1,278 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Impairment losses on trade receivables 1,375 1,285 90 7.0%
\n
Impairment losses on other financial assets 169 93 76 81.7%
\n
Total impairment losses on trade receivables and other financial assets 1,544 1,378 166 12.0%
\n
Impairment gains on trade receivables (265) (202) (63) -31.2%
\n
Impairment gains on other financial assets (1) (1) - -
\n
Total impairment gains on trade receivables and other financial assets (266) (203) (63) -31.0%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,278 1,175 103 8.8%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The item, equal to \u20ac1,278 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
increased by a total of \u20ac90 million, essentially reflecting
\n
the effect of the increase in trade receivables which led to
\n
an increase in the provision for bad debts in order to guar-
\n
antee adequate coverage of the new receivable.
\n

\n\n\n

\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac7,447 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Property, plant and equipment 4,472 4,259 213 5.0%
\n
Investment property 2 3 (1) -33.3%
\n
Intangible assets 1,612 1,330 282 21.2%
\n
Other impairment losses 1,414 2,917 (1,503) -51.5%
\n
Other reversals of impairment losses (53) (2) (51) -
\n
Tot al 7,447 8,507 (1,060) -12.5%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The decrease in \u201cDepreciation, amortization and other im-
\n
pairment losses\u201d in 2022 essentially reflected:
\n
\u2022 the effect of impairment losses recognized in 2021
\n
on certain plants or CGUs in Italy (\u20ac989 million), Spain
\n
(\u20ac1,488 million), Mexico (\u20ac155 million), Chile (\u20ac32 million)
\n
and Australia (\u20ac30 million);
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
\u2022 the effect of the impairment losses recognized in 2021 in
\n
Costa Rica (\u20ac126 million) on the hydroelectric plant op-
\n
erated under a concession arrangement by PH Chucas
\n
.
\n
These effects were partially offset by:
\n
\u2022 an increase in depreciation and amortization in Ita-
\n
ly due to an acceleration of the depreciation rates for
\n
first-generation electronic meters (1G) in order to reflect
\n
the planned installation schedule for 2G meters provided
\n
for in the Open Meter plan;
\n
\u2022 the depreciation of tangible assets due to new invest-
\n
ments made in recent years in the renewable energy
\n
sector in South America, North America and Spain;
\n
\u2022 the value adjustments of the net assets of Enel Gener-
\n
aci\u00f3n Costanera SA (\u20ac174 million) and Central Dock Sud
\n
SA (\u20ac116 million) in Argentina, and Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (\u20ac827 million) and CGT Fortaleza in Brazil (\u20ac73
\n
million).
\n

\n\n

\n\n\n

\n\n
12.f Other operating costs \u2013 \u20ac4,685 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
System charges - emissions allowances 2,216 41 2,175 -
\n
System charges - energy efficiency certificates 182 239 (57) -23.8%
\n
System charges - purchases of green certificates - - - -
\n
System charges - guarantees of origin 112 26 86 -
\n
Losses on disposal of property, plant and equipment, and intangible assets 166 75 91 -
\n
Taxes and duties 1,107 1,099 8 0.7%
\n
Other 902 488 414 84.8%
\n
Tot al 4,685 1,968 2,717 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Other operating costs increased by \u20ac2,717 million com-
\n
pared with the previous year, mainly reflecting:
\n
\u2022 the increase in environmental compliance charges in It-
\n
aly and Spain (\u20ac2,178 million) reflecting the increase in
\n
the price of CO
\n
2
\n
and of thermal generation mainly attrib-
\n
utable to the need to compensate for low water levels
\n
during the period;
\n
\u2022 the capital losses recognized for the sale of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac208 million) and CGT
\n
Fortaleza in Brazil (\u20ac135 million).
\n

\n\n

\n\n
12.g Capitalized costs \u2013 \u20ac(3,415) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Personnel (1,184) (998) (186) -18.6%
\n
Materials (1,258) (1,079) (179) -16.6%
\n
Other (973) (964) (9) -0.9%
\n
Tot al (3,415) (3,041) (374) -12.3%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Capitalized costs increased by \u20ac374 million, mainly reflect-
\n
ing:
\n
\u2022 greater investment in renewable plants in Italy, Spain and
\n
North America;
\n
\u2022 greater investment in distribution lines in Latin America;
\n
\u2022 greater investment in the distribution sector in Italy, for
\n
an increase in new customer connections and an in-
\n
crease in investment in service quality (e-grid and DSO
\n
4.0 projects).
\n

\n\n

\n\n

\n\n

\n

\n\n
13. Net results from commodity contracts \u2013 \u20ac2,365 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Commodity derivatives:
\n
- income from settled derivatives 23,124 11,456 11,668 -
\n
- expense from settled derivatives 18,929 9,331 9,598 -
\n
Net income/(expense) from settled commodity derivatives: 4,195 2,125 2,070 97.4%
\n
- income from outstanding derivatives (2,479) 4,572 (7,051) -
\n
- expense from outstanding derivatives 223 2,266 (2,043) -90.2%
\n
Net income/(expense) from outstanding commodity derivatives (2,702) 2,306 (5,008) -
\n
Outstanding contracts for energy commodities with physical settlement:
\n
- results from outstanding contracts to sell energy commodities with
\n
physical settlement
\n
5,182 (18,386) 23,568 -
\n
- results from outstanding contracts to purchase energy commodities with
\n
physical settlement
\n
(4,310) 16,478 (20,788) -
\n
Net results from outstanding contracts for energy commodities with
\n
physical settlement
\n
872 (1,908) 2,780 -
\n
NET RESULTS FROM COMMODITY CONTRACTS 2,365 2,523 (158) -6.3%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Net results from commodity contracts showed net income
\n
of \u20ac2,365 million in 2022 (net income of \u20ac2,523 million in
\n
2021), and break down as follows:
\n
\u2022 net income from commodity derivatives totaling \u20ac1,493
\n
million (net income of \u20ac4,431 million in 2021), including
\n
derivatives designated as cash flow hedges and de-
\n
rivatives measured at fair value through profit or loss.
\n
More specifically, net income from derivatives settled in
\n
the period amounted to \u20ac4,195 million (net income of
\n
\u20ac2,125 million in 2021) and net expense from the fair
\n
value measurement of outstanding derivatives came to
\n
\u20ac2,702 million (net income of \u20ac2,306 million in 2021);
\n
\u2022 net income from the fair value measurement through
\n
profit or loss of energy commodity contracts with phys-
\n
ical settlement still outstanding at the reporting date
\n
amounting to \u20ac872 million (net expense of \u20ac1,908 mil-
\n
lion in 2021).
\n
For more information on derivatives, please see note 51
\n
\u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n

\n\n

\n\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(296) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 1,442 2,097 (655) -31.2%
\n
- income from derivatives at fair value through profit or loss 1,676 620 1,056 -
\n
Total income 3,118 2,717 401 14.8%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,744) (599) (1,145) -
\n
- expense from derivatives at fair value through profit or loss (1,670) (657) (1,013) -
\n
Total expense (3,414) (1,256) (2,158) -
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (296) 1,461 (1,757) -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n\n
In 2022, net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac296 million (net income of
\n
\u20ac1,461 million in 2021) and break down as follows:
\n
\u2022 net expense from derivatives designated as hedging deriv-
\n
atives in the amount of \u20ac302 million (net income of \u20ac1,498
\n
million in 2021) mainly in regard of cash flow hedges;
\n
\u2022 net income from derivatives at fair value through profit
\n
or loss in the amount of \u20ac6 million (net expense of \u20ac37
\n
million in 2021).
\n
The net balances recognized in 2022 and 2021 on both
\n
hedging derivatives and those at fair value through profit or
\n
loss mainly referred to the hedging of exchange rate risk.
\n
For more information on derivatives, see note 51 \u201cDeriva-
\n
tives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n\n

\n\n

\n
15. Net other financial income/(expense) \u2013 \u20ac(2,160) million
\n
Other financial income
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest income from financial assets
\n
(current and non-current):
\n
- interest income at effective rate on non-current securities and financial assets 158 117 41 35.0%
\n
- interest income at effective rate on current financial investments 201 80 121 -
\n
Total interest income at the effective interest rate 359 197 162 82.2%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
--- -
\n
Exchange gains 2,289 1,212 1,077 88.9%
\n
Income on equity investments 1 6 (5) -83.3%
\n
Income from hyperinflation 1,739 824 915 -
\n
Other income 781 447 334 74.7%
\n
TOTAL OTHER FINANCIAL INCOME 5,169 2,686 2,483 92.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial income amounted to \u20ac5,169 million, an in-
\n
crease of \u20ac2,483 million compared with the previous year.
\n
The increase mainly reflects the following factors:
\n
\u2022 an increase in income from exchange gains (\u20ac1,077 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac728
\n
million) and Enel Am\u00e9ricas (\u20ac222 million);
\n
\u2022 an increase in income from hyperinflation (\u20ac915 million),
\n
recognized by the Argentine companies as a result of
\n
the application of IAS 29 on financial reporting in hyper-
\n
inflationary economies; for more information, see note
\n
4 of these consolidated financial statements at 31 De-
\n
cember, 2022;
\n
\u2022 an increase in interest income at the effective rate (\u20ac162
\n
million), mainly relating to short-term financial invest-
\n
ments;
\n
\u2022 an increase in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value hedge
\n
relationships (\u20ac123 million).
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n
Other financial expense
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest expense on financial debt
\n
(current and non-current):
\n
- interest on bank borrowings 509 322 187 58.1%
\n
- interest expense on bonds 1,884 1,877 7 0.4%
\n
- interest expense on other borrowings 235 134 101 75.4%
\n
Total interest expense 2,628 2,333 295 12.6%
\n
Financial expense on debt management transactions - 702 (702) -
\n
Exchange losses 2,179 2,551 (372) -14.6%
\n
Adjustment to post-employment and other employee benefits 145 105 40 38.1%
\n
Adjustment to other provisions 201 126 75 59.5%
\n
Expense from equity investments ----
\n
Expense from hyperinflation 1,449 804 645 80.2%
\n
Other expenses 727 270 457 -
\n
TOTAL OTHER FINANCIAL EXPENSE 7,329 6,891 438 6.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial expense amounted to \u20ac7,329 million, an
\n
overall increase of \u20ac438 million compared with 2021, es-
\n
sentially reflecting the following factors:
\n
\u2022 an increase in expense from hyperinflation of \u20ac645 mil-
\n
lion, recognized by the Argentine companies as a result
\n
of the application of IAS 29 on financial reporting in hy-
\n
perinflationary economies; for more information, see
\n
note 4 of these consolidated financial statements at 31
\n
December 2022;
\n
\u2022 an increase in interest expense of \u20ac295 million, mainly
\n
attributable to the increase in interest rates due to the
\n
restrictive monetary policies implemented to face grow-
\n
ing inflationary pressures;
\n
\u2022 an increase in other expenses, in the amount of \u20ac63 mil-
\n
lion, in Argentina, mainly attributable to the increase in
\n
financial expense in respect of CAMMESA (\u20ac65 million),
\n
in Brazil, for higher costs deriving from the PIS/COFINS
\n
dispute, as well as \u20ac43 million at Enel Produzione for
\n
greater financial expense connected with the impair-
\n
ment loss on the receivable in respect of the sale of Slo-
\n
vak Power Holding.
\n
These effects were substantially offset by the reduction in
\n
financial expense associated with the recognition of ex-
\n
pense on debt management operations (\u20ac702 million) in
\n
2021.
\n

\n\n

\n\n

\n\n

\n\n\n

\n\n

\n\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac4 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share of profit of associates 145 624 (479) -76.8%
\n
Share of loss of associates (141) (53) (88) -
\n
Tot al 4 571 (567) -99.3%
\n
The share of profit/(loss) of equity-accounted investments
\n
in 2022 came to \u20ac4 million, a decrease of \u20ac567 million
\n
compared with the previous year.
\n
The change was essentially due to a decrease in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac587 million), heavily penalized by the sharp rise in
\n
electricity prices on the spot market, slightly offset by the
\n
increase in the share of profit/(loss) of the Spanish compa-
\n
nies (\u20ac20 million) and Rusenergosbyt (\u20ac19 million).
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
17. Income taxes \u2013 \u20ac3,523 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Current taxes 3,025 2,007 1,018 50.7%
\n
Adjustments for income taxes relating to prior years (233) 145 (378) -
\n
Total current taxes 2,792 2,152 640 29.7%
\n
Deferred tax expense 342 304 38 12.5%
\n
Deferred tax income 389 (836) 1,225 -
\n
TOTAL 3,523 1,620 1,903 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The tax rate for 2022 came to 40%, compared with 30% in
\n
2021. The increase essentially reflects the following factors:
\n
\u2022 the change in the tax impact of impairment losses and
\n
gains and losses on mergers and acquisitions in the pe-
\n
riod compared with the previous year;
\n
\u2022 higher costs incurred in Italy for the extraordinary tax fund-
\n
ing program to shield users from higher energy costs envis-
\n
aged under Law 51/2022 (about \u20ac121 million) and the soli-
\n
darity tax provided for by Law 197/2022 (about \u20ac599 million);
\n
\u2022 the effect of foreign tax rates exceeding the theoretical
\n
Italian rate;
\n
\u2022 a decrease in the tax credit to eliminate dual taxation of
\n
dividends at Enel Iberia (\u20ac60 million);
\n
\u2022 the tax effect of the application of hyperinflation ac-
\n
counting in Argentina (\u20ac30 million).
\n
These adverse factors were partly offset by:
\n
\u2022 the tax impact of the disposal of the interest in Ufinet, Grid-
\n
spertise and Mooney (\u20ac190 million);
\n
\u2022 the tax impact of the regime di Patent Box in Italy (\u20ac65 mil-
\n
lion);
\n
\u2022 deferred tax assets recognized on the carve-out of Enel
\n
X Way in North America (\u20ac60 million).
\n
For more information on changes in deferred tax assets
\n
and liabilities, see note 25.
\n
The following table provides a reconciliation of the theo-
\n
retical tax rate and the effective tax rate.
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Pre-tax profit 8,741 5,378
\n
Theoretical taxes 2,098 24% 1,291 24%
\n
Change in tax effect on impairment losses, capital gains and negative goodwill 399 (229)
\n
Net effect on deferred taxation recognized with timing mismatch - 70
\n
Tax reforms in Argentina and Colombia - 166
\n
Adjustment of tax credit of Enel Iberia - 211
\n
Preferential tax treatment of Open Fiber capital gain - (401)
\n
Preferential tax treatment of Ufinet, Gridspertise and Mooney capital gain (190) -
\n
Deferred tax assets recognized on the carve-out of Enel X Way (60) -
\n
Patent Box in Italy (65) -
\n
Deferred tax assets not recognized on tax losses - 75
\n
Sundry tax effects of hyperinflation accounting in Argentina 30 49
\n
Tax effect for non-deductible Matimba capital loss 20 -
\n
Reversal of tax credit for Astrid operation - 25
\n
Tax effect of provisions for non-deductible risks in Spain 30 -
\n
IRAP 260 276
\n
Extraordinary energy cost tax 121 -
\n
Solidarity tax 599 -
\n
Other differences, effect of different tax rates abroad compared with the
\n
theoretical rate in Italy, and other minor items
\n
281 81
\n
Effect of restatement of comparative figures of discontinued operations - 6
\n
Tot al 3,523 1,620
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n
18. Basic and diluted earnings per share
\n\n
Both of these indicators are calculated on the basis of the
\n
average number of ordinary shares for the year, equal to
\n
10,166,679,946, adjusted by the average number of trea-
\n
sury shares held.
\n

\n\n
The number of treasury shares, with a par value of \u20ac1
\n
each, held at December 31, 2022 was equal to 7,153,795
\n
(4,889,152 at December 31, 2021).
\n
Millions of euro
\n
2022 2021
\n
Profit for the year attributable to owners of the Parent (basic) 1,682 3,189
\n
of which from:
\n
- continuing operations 3,637 3,097
\n
- discontinued operations (1,955) 92
\n
Effect of preference rights on dividends (e.g., preference shares) - -
\n
Dividends on equity instruments (e.g., hybrid bonds) (123) (71)
\n
Other --
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 1,559 3,118
\n
of which from:
\n
- continuing operations 3,514 3,026
\n
- discontinued operations (1,955) 92
\n
Number of shares (units)
\n
Number of ordinary shares issued at 1 January 10,166,679,946 10,166,679,946
\n
Effect of treasury shares held (6,287,027) (4,111,452)
\n
Effect of share options exercised 145,119 -
\n
Other --
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 1,559 3,118
\n
Effect of dilution:
\n
- interest on convertible bonds --
\n
- other --
\n
Profit for the year attributable to ordinary owners of the Parent (diluted) 1,559 3,118
\n
of which:
\n
- continuing operations 3,514 3,026
\n
- discontinued operations (1,955) 92
\n
Number of shares (units)
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Effect of conversion of convertible notes - -
\n
Other --
\n
Weighted average number of ordinary shares outstanding (total) for diluted
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Basic earnings per share
\n
Basic earnings per share 0.15 0.31
\n
Basic earnings per share from continuing operations 0.35 0.30
\n
Basic earnings per share from discontinued operations (0.20) 0.01
\n
Diluted earnings per share
\n
Diluted earnings per share 0.15 0.31
\n
Diluted earnings per share from continuing operations 0.35 0.30
\n
Diluted earnings per share from discontinued operations (0.20) 0.01
\n

\n\n

\n\n
\n
Information on the statement of consolidated financial
\n
position
\n\n
19. Property, plant and equipment \u2013 \u20ac88,521 million
\n
The breakdown of and changes in property, plant and
\n
equipment for 2022 is given below.
\n
Millions of euro Land Buildings
\n
Plant and
\n
machinery
\n
Industrial and
\n
commercial
\n
equipment
\n
Other
\n
assets
\n
Leased
\n
assets
\n
Leasehold
\n
improvements
\n
Assets under
\n
construction
\n
and advances Tot al
\n
Cost net of accumulated
\n
impairment losses
\n
643 11,115 163,443 547 1,551 3,722 482 11,819 193,322
\n
Accumulated depreciation - 5,650 100,069 396 1,188 1,093 354 - 108,750
\n
Balance at Dec. 31, 2021 643 5,465 63,374 151 363 2,629 128 11,819 84,572
\n
Capital expenditure 3 43 2,125 32 115 - 7 8,905 11,230
\n
Assets entering service 27 804 5,078 7 22 27 49 (6,014) -
\n
Exchange differences (2) 163 322 1 (20) 86 1 133 684
\n
Change in the
\n
consolidation scope
\n
4 46 700 - 2 (9) - (122) 621
\n
Disposals (1) (12) (89) (1) (8) (96) - (63) (270)
\n
Depreciation - (215) (3,893) (24) (90) (336) (43) - (4,601)
\n
Impairment losses 1 - (153) - (1) - - (49) (202)
\n
Impairment gains (1) - 47 - - - - - 46
\n
Other changes 1 23 714 2 38 552 (3) 345 1,672
\n
Reclassifications from/to
\n
assets held for sale
\n
(46) (430) (3,540) (5) (129) (91) - (990) (5,231)
\n
Total changes (14) 422 1,311 12 (71) 133 11 2,145 3,949
\n
Cost net of accumulated
\n
impairment losses
\n
629 11,606 165,370 572 1,439 4,021 547 13,964 198,148
\n
Accumulated depreciation - 5,719 100,685 409 1,147 1,259 408 - 109,627
\n
Balance at Dec. 31, 2022 629 5,887 64,685 163 292 2,762 139 13,964 88,521
\n
Plant and machinery included assets to be relinquished free
\n
of charge with a carrying amount of \u20ac8,409 million (\u20ac7,946
\n
million at December 31, 2021), largely regarding power plants
\n
in Iberia and Latin America amounting to \u20ac3,456 million
\n
(\u20ac3,672 million at December 31, 2021), and the electricity dis-
\n
tribution grid in Latin America totaling \u20ac4,228 million (\u20ac3,506
\n
million at December 31, 2021).
\n
For more information on \u201cLeased assets\u201d, please see note 21
\n
below.
\n
The types of capital expenditure made during 2022 are sum-
\n
marized below by class of asset. These expenditures, totaling
\n
\u20ac13,329 million, increased by \u20ac1,128 million on 2021, increas-
\n
es that were particularly concentrated in solar power plants.
\n
Millions of euro
\n
2022 2021 Change
\n
Power plants:
\n
- thermal 661 550 111 20.2%
\n
- hydroelectric 435 402 33 8.2%
\n
- geothermal 121 120 1 0.8%
\n
- nuclear 134 157 (23) -14.6%
\n
- alternative energy sources 5,189 4,947 242 4.9%
\n
Total power plants 6,540 6,176 364 5.9%
\n
Electricity distribution grids
\n
(1)
\n
4,483 4,389 94 2.1%
\n
Enel X (e-City, e-Industries, e-Home) 373 285 88 30.9%
\n
Enel X Way (e-Mobility) 113 82 31 37.8%
\n
Retail customers 721 643 78 12.1%
\n
Other 1,099 626 473 75.6%
\n
TOTAL
\n
(2)
\n
13,329 12,201 1,128 9.2%
\n
(1) The figure for 2022 does not include \u20ac1,174 million in respect of infrastructure investments within the scope of IFRIC 12 (\u20ac907 million in 2021).
\n
(2) The figure for 2022 includes \u20ac156 million regarding units classified as held for sale (\u20ac111 million in 2021).
\n
\n\n
\n\n
\n\n
The Enel Group, in line with the Paris Agreement on CO
\n
2
\n
emissions reductions and guided by energy efficiency and
\n
energy transition objectives, has invested above all in gen-
\n
eration plants that exploit alternative energy sources. Cap-
\n
ital expenditure on generation plants mainly regard solar
\n
plants in the United States, Italy, Spain, Colombia, Peru,
\n
Chile, Brazil, South Africa and Australia.
\n
In order to respond to ever more variable climate develop-
\n
ments and, therefore, enhance the resilience of grids, the
\n
Group continued to invest in the distribution business line
\n
(\u20ac4,483 million). The \u20ac94 million increase is mainly attribut-
\n
able to greater investments in Italy, Brazil and Peru, mainly
\n
for corrective maintenance and grid reliability.
\n
Capital expenditure of Enel X increased mainly in Italy, in
\n
the e-City and e-Home businesses, in North America and
\n
Australia, reflecting higher industrial capex of the Battery
\n
Energy Storage business for the implementation of new
\n
projects, in Brazil due to higher expenditure in the Smart
\n
Lighting, e-Home and Distributed Energy businesses
\n
(launch of new PV-Photovoltaic projects), in Peru in the
\n
Public Lighting business, in Colombia with the launch of
\n
new projects in the Distributed Energy business (PV-Pho-
\n
tovoltaic) and in Spain, in the e-Home business.
\n
The growth of capital expenditure of Enel X Way refers to
\n
deployment of new charging points for electric mobility
\n
mainly in Spain.
\n
The change in \u201cOther\u201d mainly includes investments in the
\n
period in Battery Energy Storage Systems (BESS) in Italy
\n
and North America.
\n
Exchange gains amounted to \u20ac684 million.
\n
The \u201cChange in the consolidation scope\u201d in 2022 mainly
\n
refers to the acquisition of ERG Hydro Srl (now merged in
\n
Enel Produzione) in Italy and the sale of Thar Surya 1 Private
\n
Limited in India.
\n
\u201cImpairment losses\u201d amounted to \u20ac202 million and are
\n
mainly attributable to the value adjustment of the Spanish
\n
generation plants of Baleares, Canarias, Ceuta Melilla and
\n
Terminal Portuario de Los Barrios, and in Colombia to So-
\n
ciedad Portuaria Central Cartagena SA, controlled by Enel
\n
Colombia, which will terminate commercial operations
\n
from November 2023. For that reason, at December 31,
\n
2022, the carrying amount of \u201cPlant and machinery\u201d was
\n
written down.
\n
This item was also affected by impairment losses on Enel
\n
Produzione\u2019s assets of coal-fired power plants in Torreval-
\n
daliga Nord, Fusina and Brindisi Sud.
\n
\u201cReclassifications from/to assets held for sale\u201d refer mainly
\n
to all the assets of the Romanian, Greek companies and of
\n
Enel Russia, which was sold during the 4th Quarter of 2022.
\n
It also refers to the reclassification to assets held for sale
\n
of Enel Generaci\u00f3n Costanera SA and Central Dock Sud SA
\n
in Argentina, 3SUN Srl in Italy, Avikiran Solar India Private
\n
Limited in India and Bungala in Australia.
\n
\u201cOther changes\u201d include the provision for plant retiring and
\n
site restoration costs in the amount of a negative \u20ac302
\n
million, mainly in Spain and North America, new leases of
\n
\u20ac585 million, impairment losses on the property, plant and
\n
equipment of the Argentine companies operating in a hy-
\n
perinflationary economy in the amount of \u20ac1,081 million
\n
and the effect of capitalizing interest on loans specifical-
\n
ly dedicated to capital expenditure on property, plant and
\n
equipment of \u20ac260 million (\u20ac182 million in 2021) breaking
\n
down as follows.
\n
Millions of euro
\n
2022 Rate % 2021 Rate % Change
\n
EGP North America 83 0.5% 17 0.2% 66 -
\n
EGP M\u00e9xico 14 7.0% 10 4.3% 4 40.0%
\n
EGP South Africa 22 6.3% 61 6.3% (39) -63.9%
\n
Enel Am\u00e9ricas Group 50 3.2% 23 3.7% 27 -
\n
Enel Chile Group 91 6.1% 80 7.0% 11 13.8%
\n
Endesa Group 5 1.4% 4 1.5% 1 25.0%
\n
Enel Russia Group - 18 8.5% (18) -
\n
EGP India Group 7 9.9% 8 8.3% (1) -12.5%
\n
EGP Australia Group - 1 0.2% (1) -
\n
Enel Produzione 1 2.1% 2 2.1% (1) -50.0%
\n
C&C Uno Energy Srl 1 3.1% - 1 -
\n
Nuove Energie 21.6% 10.5% 1 -
\n
Enel Green Power Italia 6 3.6% 5 3.3% 1 20.0%
\n
Enel Finance International - 12 1.8% (12) -
\n
Total
\n
(1)
\n
282 242 40 16.5%
\n
(1) The total for 2022 also includes \u20ac22 million pertaining to assets held for sale (the total for 2021 includes -\u20ac5 million in capitalized financial expense in respect
\n
of intangible assets, \u20ac4 million in other non-current assets and \u20ac61 million pertaining to assets held for sale).
\n
\n\n
\n\n

\n

\n

\n\n
At December 31, 2022, contractual commitments to pur-
\n
chase property, plant and equipment amounted to \u20ac2,926
\n
million.
\n

\n\n\n
20. Infrastructure within the scope of \u201cIFRIC 12 - Service concession arrangements\u201d
\n
Service concession arrangements, which are recognized
\n
in accordance with IFRIC 12, regard certain infrastructure
\n
serving concessions for electricity distribution in Brazil and
\n
Costa Rica.
\n
The following table summarizes the salient details of those
\n
concessions.
\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
Amount
\n
recognized
\n
among
\n
contract
\n
assets at
\n
Dec. 31,
\n
2022
\n
Amount
\n
recognized
\n
among
\n
financial
\n
assets at
\n
Dec. 31,
\n
2022
\n
Amount
\n
recognized
\n
among
\n
intangible
\n
assets at
\n
Dec. 31,
\n
2022
\n
Enel Distribui\u00e7\u00e3o
\n
Rio de Janeiro
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1996-2026 4 years Yes 116 1,138 453
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 6 years Yes 86 876 459
\n
Enel Green
\n
Power Mour\u00e3o
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 24 years No - 5 -
\n
Enel Green
\n
Power
\n
Paranapanema
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 24 years No - 26 -
\n
Enel Green
\n
Power Volta
\n
Grande
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2017-2047 25 years No - 276 -
\n
Enel Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 6 years Yes 290 1,318 544
\n
PH Chucas
\n
Costa Rican
\n
Electricity
\n
Institute
\n
Hydroelectric
\n
plant
\n
Costa
\n
Rica
\n
2012-2031 9 years No - 103 44
\n
Total 492 3,742 1,500
\n
The assets classified under financial assets are measured
\n
at fair value at the end of the concessions. For more infor-
\n
mation, see note 52 \u201cAssets and liabilities measured at fair
\n
value\u201d.
\n

\n\n\n
21. Leases
\n
The table below shows changes in right-of-use assets in
\n
2022.
\n
Millions of euro Leased land
\n
Leased
\n
buildings Leased plants
\n
Other leased
\n
assets To ta l
\n
Total at Dec. 31, 2021 1,147 517 441 524 2,629
\n
Increases 289 172 (1) 138 598
\n
Exchange differences 63 6 11 6 86
\n
Depreciation (48) (120) (36) (132) (336)
\n
Other changes (139) (62) 9 (23) (215)
\n
Total at Dec. 31, 2022 1,312 513 424 513 2,762
\n

\n\n

\n\n

\n

\n\n
Lease liabilities and changes during the year are shown in
\n
the table below.
\n
Millions of euro
\n
Total at Dec. 31, 2021 2,547
\n
Increases 445
\n
Payments (310)
\n
Other changes (10)
\n
Total at Dec. 31, 2022 2,672
\n
of which medium to long term 2,409
\n
of which short term 263
\n
Millions of euro
\n
2022
\n
Depreciation of right-of-use assets 327
\n
Interest expense on lease liabilities 96
\n
Expense relating to short-term leases (included in costs for services and other materials) 59
\n
Expense relating to leases of low-value assets (included in costs for services and other materials) -
\n
Variable lease payments (included in costs for services and other materials) 32
\n
Tot al 514
\n

\n\n\n
22. Investment property \u2013 \u20ac94 million
\n
Millions of euro
\n
Cost net of accumulated impairment losses 129
\n
Accumulated depreciation 38
\n
Balance at Dec. 31, 2021 91
\n
Exchange differences 1
\n
Depreciation (2)
\n
Impairment losses -
\n
Other changes 4
\n
Total changes 3
\n
Cost net of accumulated impairment losses 116
\n
Accumulated depreciation 22
\n
Balance at Dec. 31, 2022 94
\n
Investment property at December 31, 2022 amounted to
\n
\u20ac94 million, an increase of \u20ac3 million on 2021.
\n
The Group\u2019s investment property consists of properties in
\n
Italy, Spain, Brazil and Chile, which are free of restrictions
\n
on their sale or the remittance of income and proceeds of
\n
disposal. In addition, the Group has no contractual obliga-
\n
tions to purchase, construct or develop investment prop-
\n
erty or for repairs, maintenance or enhancements.
\n
The change in 2021 was mainly due to impairment losses
\n
recognized on a number of assets in Spain and accumu-
\n
lated depreciation.
\n
For more information on the valuation of investment prop-
\n
erty, see notes 52 \u201cAssets and liabilities measured at fair
\n
value\u201d, and 52.2 \u201cAssets not measured at fair value in the
\n
statement of financial position\u201d.
\n

\n\n

\n\n

\n\n

\n\n
23. Intangible assets \u2013 \u20ac17,520 million
\n
A breakdown of and changes in intangible assets for 2022
\n
are shown below.
\n
Millions of euro
\n
Development
\n
expenditure
\n
Industrial
\n
patents &
\n
intellectual
\n
property
\n
rights
\n
Concessions,
\n
licenses,
\n
trademarks
\n
and similar
\n
rights
\n
Service
\n
concession
\n
arrangements Other
\n
Leasehold
\n
improvements
\n
Assets under
\n
development
\n
and
\n
advances
\n
Contract
\n
costs To t a l
\n
Cost net of accumulated
\n
impairment losses
\n
43 3,512 12,842 5,781 5,092 - 1,760 2,063 31,093
\n
Accumulated amortization 23 2,771 1,721 3,683 3,708 - - 1,117 13,023
\n
Balance at Dec. 31, 2021 20 741 11,121 2,098 1,384 - 1,760 946 18,070
\n
Capital expenditure 49 82 151 - 131 - 784 746 1,943
\n
Assets entering service 19 263 14 - 396 - (694) 2 -
\n
Exchange differences - (7) 250 234 14 - (3) - 488
\n
Change in the
\n
consolidation scope
\n
-1171---2-174
\n
Disposals - (1) - (15) (1) - (50) - (67)
\n
Amortization (4) (326) (216) (381) (356) - - (375) (1,658)
\n
Impairment losses - - (1) - (6) - (6) - (13)
\n
Impairment gains - - - - - - - - -
\n
Other changes 3 (23) 10 481 44 - 42 11 568
\n
Reclassifications from/to
\n
assets held for sale
\n
(8) (67) (705) (917) (174) - (88) (26) (1,985)
\n
Total changes 59 (78) (326) (598) 48 - (13) 358 (550)
\n
Cost net of accumulated
\n
impairment losses
\n
101 3,697 12,646 5,261 5,279 - 1,747 2,831 31,562
\n
Accumulated amortization 22 3,034 1,851 3,761 3,847 - - 1,527 14,042
\n
Balance at Dec. 31, 2022 79 663 10,795 1,500 1,432 - 1,747 1,304 17,520
\n
Enel\u2019s intellectual property (IP) portfolio comprises a set of
\n
critical information for sustainable growth. The Open In-
\n
novability
\n
\u00ae
\n
ecosystem generates innovation through the
\n
creation and sharing of internal and external solutions that
\n
give life to a stream of inventions that are protected and
\n
monetized with the support of intellectual property pro-
\n
tection mechanisms.
\n
At December 31, 2022 the Group had applied for 883
\n
patents for industrial inventions, in 163 patent families; of
\n
these, 711 have been granted and 172 are pending. The
\n
portfolio ensures protection in all the markets in which the
\n
Group is present. Enel\u2019s portfolio also includes 23 utility
\n
models and 194 design registrations. Together with pat-
\n
ents, utility models and designs, IP rights also include in-
\n
dustrial secrets of both a technical and commercial nature
\n
which are constantly codified and maintained in line with
\n
the provisions of the Trade Secrets Management proce-
\n
dure. The Group also owns 2,027 trademarks, of which
\n
1,642 have already been registered with 385 applications
\n
pending.
\n
Enel has consolidated the processes for managing the
\n
generation and exploitation of intellectual property rights
\n
within the Intellectual Property Management and Trade Se-
\n
crets Management organizational procedures. Both pro-
\n
cedures look at human capital as an essential element in
\n
the creation of IP and seek to encourage employee partic-
\n
ipation in the inventive process, emphasizing the strategic
\n
importance of all inventions.
\n
During 2022, the activity of coding and protection of in-
\n
tellectual property continued in all global business lines.
\n
More specifically:
\n
\u2022 Enel X Global Retail focused its activity on strategic plat-
\n
forms, coding copyrights on the Big Data Platform, a
\n
container of strategic data for all Enel X and X Custom-
\n
er business units, and global management system for
\n
Enel X customers. With regard to the circular economy,
\n
Enel X has protected its circularity schemes under copy-
\n
right law together with the related scores and operating
\n
mechanisms. In the field of telemedicine, a multiple de-
\n
sign has been registered in the European Union for the
\n
graphic interfaces of the \u201cSmart Axistance eWell\u201d app,
\n
which offers users a complete wellness package.
\n
\u2022 Enel Green Power and Thermal Generation report the
\n
following developments for the year:
\n
\u2013 in the photovoltaic sector, (i) a patent application for
\n
an industrial invention and a design application for
\n
a solution that automates the process of installing
\n
photovoltaic panels in the field, reducing installation
\n
times and costs and increasing operator safety; (ii) a
\n
patent application jointly owned with the Commissar-
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n
iat \u00e0 l\u2019\u00c9nergie Atomique et aux \u00c9nergies Alternatives
\n
(CEA) concerning a system for optimizing the removal
\n
and automatic insertion of the wafer bar holder of the
\n
cassette used to process wafers in fume cupboards.
\n
Furthermore, the generation and protection of the
\n
technological know-how necessary for the Gigafac-
\n
tory project continues at the 3SUN factory, mainly in
\n
the form of trade secrets;
\n
\u2013 in hydroelectric generation, a patent application for a
\n
utility model for a robotic solution that facilitates plant
\n
control, allowing the inspection of difficult-to-access
\n
locations, such as hydroelectric spirals, distributor
\n
vanes or small-diameter hydroelectric pipelines.
\n
\u2022 Enel Grids filed two patent applications for inventions in
\n
2022: one in the field of asset recognition and anomaly
\n
detection for grids and grid events (Project ODIN) and
\n
the other in the field of safety devices for workers work-
\n
ing at height. We also note (i) the registration of a design
\n
for a new sustainable road cab, which will be implement-
\n
ed using recycled materials to reduce the environmental
\n
impact and (ii) the filing of a patent application for a utility
\n
model in the safety field, consisting of a method for the
\n
delimitation of road construction sites. Also during the
\n
year, Gridspertise consolidated its IP portfolio by filing a
\n
patent application relating to the Quantum Edge - Qed
\n
\u00ae
\n
device, which exploits edge computing to digitalize the
\n
physical components of secondary substations, reduc-
\n
es installation, training and operating and maintenance
\n
costs and increases network reliability.
\n
\u2022 Global e-Mobility has protected the JuiceBox DC and
\n
JuiceBox 4.0 smart home charging devices respectively
\n
using: (i) an international design registered in the Euro-
\n
pean Union, the United Kingdom and the United States
\n
and (ii) an international design registered in Canada,
\n
Mexico and the United States. Intellectual property pro-
\n
tection for electric vehicle charging stations has also
\n
been extended to the registration in the European Union
\n
and in the United States of the designs of the JuiceMedia
\n
2.0 and JuiceMod products.
\n
\u2022 Enel Global Services filed a patent application in Italy for
\n
an industrial invention on the innovation management
\n
method, also protected as the trademark ENEL OOPS\u2026!
\n
INNOVATION
\n
\u00ae
\n
. This method is based on the improvement
\n
of industrial processes using Open Innovability
\n
\u00ae
\n
tools.
\n
More generally, the Group continues to invest resourc-
\n
es in the development of solutions with a high IP density,
\n
which is mainly expressed in the forms of copyright pro-
\n
tection and trade secrets for databases and forecasting
\n
algorithms for the electricity and gas markets, advanced
\n
quantitative models that use scenario data to evaluate the
\n
impact of climate change on specific assets/production
\n
activities. In particular, this activity includes development
\n
models designed to: (i) characterize the ability of an as-
\n
set to \u201cresist\u201d the possible effects of climate change; (ii)
\n
quantify the probability that an event or a combination of
\n
climate events will damage a plant; and (iii) provide an index
\n
of \u201cweakness\u201d for the asset, including in distributed form,
\n
with a specific technical approach to prioritize actions/
\n
fields for improvement.
\n\n
The following table reports service concession arrange-
\n
ments that do not fall within the scope of IFRIC 12 and had
\n
a balance as at December 31, 2022.
\n

\n\n\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2022
\n
Initial fair
\n
value
\n
Endesa Distribuci\u00f3n
\n
El\u00e9ctrica
\n
-
\n
Electricity
\n
distribution
\n
Spain Indefinite Indefinite - 5,678 5,673
\n
Enel Colombia (formerly
\n
Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,047 1,839
\n
Enel Distribuci\u00f3n Chile
\n
(formerly Chilectra)
\n
Republic of
\n
Chile
\n
Electricity
\n
distribution
\n
Chile Indefinite Indefinite - 1,331 1,667
\n
Enel Distribuci\u00f3n Per\u00fa
\n
(formerly Empresa de
\n
Distribuci\u00f3n El\u00e9ctrica de
\n
Lima Norte)
\n
Republic of
\n
Peru
\n
Electricity
\n
distribution
\n
Peru Indefinite Indefinite - 584 548
\n
Assets with an indefinite useful life amounted to \u20ac8,640
\n
million (\u20ac8,633 million at December 31, 2021) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,678 million), Colombia (\u20ac1,047 million), Chile
\n
(\u20ac1,331 million) and Peru (\u20ac584 million), for which there
\n
was no statutory or currently predictable expiration date.
\n
On the basis of the forecasts developed, cash flows for
\n
each CGU, with which the various concessions are asso-
\n
ciated, were sufficient to recover the carrying amount.
\n
The change during the year was essentially attributable to
\n
changes in exchange rates. For more information on ser-
\n
vice concession arrangements, see note 20.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
The change in the consolidation scope for 2022 mainly re-
\n
flected the acquisition by Enel Produzione of ERG Hydro Srl
\n
(now merged in Enel Produzione) in Italy, with an increase
\n
in the value of hydroelectric concessions of \u20ac170 million.
\n
Impairment losses amounted to \u20ac13 million in 2022, and
\n
mainly regarded projects for assets under development
\n
that management has decided to abandon. For more in-
\n
formation, see note 12.e.
\n
\u201cOther changes\u201d mainly reported the design costs connect-
\n
ed with the acquisition of a number of Brazilian vehicle com-
\n
panies and impairment losses on intangible assets of Argen-
\n
tine companies operating in a hyperinflationary economy.
\n

\n\n

\n\n\n

\n\n
24. Goodwill \u2013 \u20ac13,742 million
\n
Millions of euro at Dec. 31, 2021
\n
Change
\n
in
\n
consol.
\n
scope
\n
Exchange
\n
differences
\n
Impairment
\n
losses
\n
Offsetting
\n
cost with
\n
accum.
\n
impairment
\n
losses
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes
\n
at Dec. 31, 2022
\n
Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount
\n
Iberian
\n
Peninsula
\n
11,177 (2,392) 8,785 - - - - - 11,177 (2,392) 8,785
\n
Chile 1,209 - 1,209 - 42 - - (61) (42) 1,148 - 1,148
\n
Argentina 275 (253) 22 - (1) - - - - 274 (253) 21
\n
Peru 566 - 566 - 4 - - - 1 571 - 571
\n
Colombia 527 - 527 - (9) - - - - 518 - 518
\n
Brazil 1,303 - 1,303 - 95 - - (85) - 1,313 - 1,313
\n
Central
\n
America
\n
25 - 25 - 2 - - - (1) 26 - 26
\n
Mexico 18 (18) - - - - - - - - - -
\n
Enel Green
\n
Power North
\n
America
\n
70 - 70 - - - - - - 70 - 70
\n
Enel X North
\n
America
\n
199-199-13-- -(70)142-142
\n
Enel X
\n
Way North
\n
America
\n
------- 7070-70
\n
Enel X Asia
\n
Pacific
\n
84 - 84 - - - - - - 84 - 84
\n
Enel X Rest
\n
of Europe
\n
(1)
\n
46 (3) 43 - - - - - - 43 - 43
\n
Enel X Italy - - - - - - - - - - - -
\n
Market Italy
\n
(2)
\n
580 - 580 1 - - - - - 581 - 581
\n
Enel Green
\n
Power Italy
\n
21 - 21 - - - - - - 21 - 21
\n
Enel
\n
Produzione
\n
Italy
\n
- - - 349 - - - - - 349 - 349
\n
Romania 400 (13) 387 17 1 - - (404) (1) - - -
\n
Total 16,500 (2,679) 13,821 367 147 - - (550) (43) 16,387 (2,645) 13,742
\n
(1) Includes Viva Labs.
\n
(2) Includes Enel Energia.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Goodwill matrix at Dec. 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other To ta l
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 581 - - 581
\n
Enel Produzione Italy - 349 - - - - 349
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 2 19 - - - 21
\n
Brazil - 478 835 - - - 1,313
\n
Chile - 996 152 - - - 1,148
\n
Colombia - 295 223 - - - 518
\n
Peru 44 207 320 - - - 571
\n
Central America - 26 - - - - 26
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----142-142
\n
Enel X Way North
\n
America
\n
-----7070
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,634 7,337 2,388 269 70 13,742
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n
Goodwill matrix at Dec. 31, 2021
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other Tot al
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 580 - - 580
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 3 19 - - - 22
\n
Brazil - 423 880 - - - 1,303
\n
Chile - 996 213 - - - 1,209
\n
Colombia - 304 223 - - - 527
\n
Peru 44 202 320 - - - 566
\n
Central America - 25 - - - - 25
\n
Romania - - 330 57 - - 387
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----199-199
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,234 7,773 2,444 326 - 13,821
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The decrease of \u20ac79 million in goodwill was mainly attrib-
\n
utable to \u201creclassifications from/to assets classified as held
\n
for sale\u201d (-\u20ac550 million), regarding Romania (-\u20ac404 million)
\n
for classification as discontinued operations, Brazil (-\u20ac85
\n
million) and Chile (-\u20ac61 million) for reclassification as assets
\n
held for sale of Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s)
\n
and Enel Transmisi\u00f3n Chile, respectively (which were sold in
\n
2022). The negative effect was partially offset by the increase
\n
in the consolidation scope mainly reflecting the acquisition
\n
of Enel Hydro Appennino Centrale Srl (\u20ac349 million) and \u201cEx-
\n
change differences\u201d (a positive \u20ac147 million) mainly regarding
\n
Brazil, Chile and the United States.
\n
The criteria used to identify the cash generating units (CGUs)
\n
are based on revenue separation, which is considered the
\n
main criterion in view of the nature of our business, taking
\n
due account of the operational rules and regulations of the
\n
markets in which they operate and the corporate organi-
\n
zation. For the purposes of impairment testing of goodwill,
\n
the CGUs are grouped on the basis of expected synergies,
\n
consistent with management\u2019s strategic and operational vi-
\n
sion, within the operating segments identified for segment
\n
reporting purposes.
\n
Note also that in 2022 the existing CGUs underwent exten-
\n
sive analysis to assess the possible presence of significant
\n
changes pursuant to IAS 36, paragraph 72.
\n
This analysis led to the modification of the existing CGUs
\n
only for Enel X Way, a new global business established from
\n
the spin-off of electric mobility operations from Enel X.
\n
In particular, the new Enel X North America CGU was iden-
\n
tified.
\n
The recoverable amount of the goodwill recognized was es-
\n
timated by calculating the value in use of the CGUs or groups
\n
of CGUs using discounted cash flow models, which involve
\n
estimating expected future cash flows and applying an ap-
\n
propriate discount rate, selected on the basis of market in-
\n
puts such as risk-free rates, betas and market-risk premi-
\n
ums.
\n
Cash flows were determined on the basis of the best infor-
\n
mation available at the time of the estimate, taking account
\n
of the specific risks of individual CGU or groups of CGUs, and
\n
drawn:
\n
\u2022 for the explicit period, from the Business Plan approved
\n
by the Board of Directors of the Parent on November 21,
\n
2022, containing forecasts for volumes, revenue, operat-
\n
ing costs, capital expenditure, industrial and commercial
\n
organization and developments in the main macroeco-
\n
nomic variables (inflation, nominal interest rates and ex-
\n
change rates) and commodity prices. The explicit period
\n
of cash flows considered in impairment testing was three
\n
years;
\n
\u2022 for subsequent years, from assumptions concerning long-
\n
term developments in the main variables that determine
\n
cash flows, the average residual useful life of assets or the
\n
duration of the concessions.
\n
More specifically, the terminal value is calculated based on
\n
the specific characteristics of the businesses related to the
\n
various CGUs or groups of CGUs subject to impairment test-
\n
ing:
\n
\u2022 perpetuity, for the businesses of large-hydro (LH) power
\n
generation and of distribution, in which the licenses and
\n
public concessions are of a long-term nature and are eas-
\n
ily renewable; as well as for the Enel X and Enel X Way busi-
\n
nesses, as they feature the development of specific know-
\n
how that is sustainable over the long term;
\n
\u2022 annuity, for CGUs or groups of CGUs that are predomi-
\n
nantly characterized by retail business, for which the re-
\n
sidual life is, therefore, essentially correlated with the av-
\n
erage duration of the customer relationships; as well as
\n
for businesses of conventional thermal power generation
\n
(Generation and Trading). This method is also used for the
\n
renewable energy (Enel Green Power) businesses to take
\n
account of: (i) the value resulting from the remaining useful
\n
lives of the plants; and (ii) the residual value, in the event of
\n
plant decommissioning, associated with licensing rights,
\n
the competitiveness of the production facilities (in terms
\n
of natural resources), and network interconnectivity.
\n
The nominal growth rate (g-rate) is equal to the long-term
\n
rate of growth in electricity and/or inflation (depending on
\n
the country and business involved) and in any case no high-
\n
er than the average long-term growth rate of the reference
\n
market.
\n
The Group therefore confirmed its strategic direction based
\n
on the trends associated with the energy transition. The use
\n
of capital has been focused on:
\n
\u2022 decarbonization through the gradual development of
\n
generation assets that use renewable sources and the
\n
simultaneous exit from coal and gas-fired electricity pro-
\n
duction (by 2040);
\n
\u2022 electrification of energy consumption, with the incentive
\n
of new products and services for end users and the simul-
\n
taneous gradual exit from gas sales to end users (by 2040);
\n
\u2022 digitization and upgrading of distribution networks, to
\n
cope with the energy transition under way and guarantee
\n
quality of service to customers.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope 1 GHG
\n
emission
\n
intensity
\n
related
\n
to power
\n
generation
\n
Electricity
\n
generation
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n
(2)
\n
Short term
\n
(2025)
\n
130 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Gradual phase out of coal-fired capacity in
\n
2023-2025 (percentage weight of coal capacity
\n
out of total consolidated capacity reduced from
\n
about 7% in 2022 to below 0.5% in 2025).
\n
\u2022 Invest \u20ac15 billion to accelerate the development
\n
of renewable energy by installing 17 GW of new
\n
renewables capacity (13 GW of which at the
\n
consolidated level) and 4 GW in BESS in 2023-
\n
2025, reaching 75 GW of renewables capacity
\n
(including 4 GW of BESS) by 2025.
\n
Medium
\n
term (2030)
\n
72 gCO
\n
2eq
\n
/kWh
\n
(-80% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, implementing a Group-
\n
wide investment plan that will remain at the
\n
annual levels of the 2023-2025 plan, reaching
\n
a managed capacity of over 130 GW by 2030,
\n
thereby bringing total generation capacity to be
\n
made up of around 85% renewables.
\n
\u2022 Exit from coal-fired generation, which is
\n
expected to take place by 2027 globally.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n

\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Exit from the business of thermal electricity
\n
generation, achieving a 100% renewable energy
\n
mix.
\n
\u2022 No use of carbon-removal technologies.
\n
Scope 1
\n
and 3 GHG
\n
emission
\n
intensity
\n
related to
\n
integrated
\n
power
\n
Sale
\n
of electricity
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n

\n
73.4%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Short term
\n
(2025)
\n
135 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Increase the percentage of renewable energy
\n
sold to customers, while increasing Group\u2019s
\n
renewables production.
\n
\u2022 Increase the share of fixed-price energy
\n
sales covered by carbon-free sources in core
\n
countries from around 70% in 2022 to about
\n
90% by 2025, while increasing volumes of
\n
electricity sold at a fixed price from about 185
\n
TWh in 2022 to around 200 TWh by 2025.
\n
Medium
\n
term (2030)
\n
73 gCO
\n
2eq
\n
/kWh
\n
(-78% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Increase the share of renewable energy sold to
\n
customers by increasing the Group\u2019s renewables
\n
generation, reaching a managed capacity of
\n
over 130 GW by 2030, thereby bringing total
\n
generation capacity to be made up of around
\n
85% renewables.
\n
\u2022 Continue the strategy of balancing supply and
\n
demand and increase the share of electricity
\n
sold at a fixed price covered by carbon-free
\n
generation.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 By 2040, reach 100% of the energy sales
\n
covered by renewables.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope
\n
3 GHG
\n
emissions
\n
related
\n
to sale of
\n
natural gas
\n
on end-user
\n
market
\n
Sale of gas to
\n
end users
\n
100%
\n
of Scope 3 GHG
\n
emissions -
\n
category 11 (Use
\n
of sold products)
\n
Short term
\n
(2025)
\n
20.9 MtCO
\n
2eq
\n
n/a
\n
(4)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 20% by 2025.
\n
\u2022 Promote services to customers that enable
\n
electrification: increase in behind-the-meter
\n
storage capacity from around 99 MW in 2022 to
\n
about 352 MW by 2025; increase in the capacity
\n
of photovoltaic panels installed at end users
\n
from around 100 MW in 2022 to roughly 300
\n
MW by 2025; and increase in demand response
\n
capacity from around 8.4 GW in 2022 to about
\n
12.4 GW by 2025.
\n
\u2022 Reduce the volumes of gas sold to customers
\n
from around 10.2 bcm in 2022 to about 4.3 bcm
\n
by 2025.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), reducing
\n
customers of the retail gas business from
\n
around 6.5 million in 2022 to roughly 4.4 million
\n
by 2025.
\n
Medium
\n
term (2030)
\n
11.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 30% by 2030.
\n
\u2022 Continue with the short-term strategic actions,
\n
while continuing to promote services to
\n
customers that enable the electrification of
\n
consumption and reaching a demand response
\n
capacity of over 20 GW by 2030.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), continuing to
\n
reduce the volumes of gas sold to around 3 bcm
\n
by 2030.
\n
Long term
\n
(2040)
\n
0 MtCO
\n
2eq
\n

\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Aim to achieve sale of 100% renewable energy
\n
to end users by 2040.
\n
\u2022 Exit from the sale of gas to retail customers by
\n
2040.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Additional
\n
emissions
\n
Scopes
\n
1-2-3
\n
\u2022 Electricity
\n
distribution
\n
(Scopes 1
\n
and 2)
\n
\u2022 Management
\n
of vehicle fleet,
\n
buildings and
\n
other assets
\n
(Scopes 1
\n
and 2)
\n
\u2022 Supply chain
\n
management
\n
(Scope 3)
\n
\u2022 Purchasing of
\n
fuels (Scope 3)
\n
0.4%
\n
of Scope 1 GHG
\n
emissions
\n
100%
\n
of Scope 2 GHG
\n
emissions
\n
28.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 1
\n
(Purchase of
\n
goods and
\n
services) for the
\n
2030 target and
\n
43% for the 2040
\n
target
\n
(5)
\n
26.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Medium
\n
term (2030)
\n
10.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Invest a total of \u20ac15 billion in grids over the
\n
period 2023-2025, of which 11% to increase
\n
digitalization and 47% to improve grid resilience
\n
and quality, thereby helping to reduce grid
\n
losses and related greenhouse gas emissions.
\n
Replace existing distribution network
\n
infrastructure components with SF
\n
6
\n
-free
\n
solutions.
\n
\u2022 Electrify fleet and buildings by 2030.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Phase out coal-fired generation by 2027,
\n
mitigating all GHG emissions related to coal
\n
supply.
\n
Long term
\n
(2040)
\n
<2.5 MtCO
\n
2eq
\n

\n
(-90% compared
\n
to 2017 base
\n
year)
\n
Net-zero
\n
emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Promote grid digitalization and replace existing
\n
distribution network infrastructure components
\n
with SF
\n
6
\n
-free solutions.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Zero out emissions associated with gas
\n
extraction, as the Group will have completely
\n
exited both the gas-fired generation of
\n
electricity and the sale of gas to end users.
\n
(1) Percentages based on total GHG emissions in 2022.
\n
(2) Excludes marginal Scope 1 GHG emissions not directly related to the combustion of fossil fuels in electricity generation at thermal plants, which accounted
\n
for 1.4% of total Scope 1 emissions in 2022. In any event, GHG emissions covered by all of the above targets are equal, on the whole, to 98.7% of total Scope
\n
1 and 2 emissions in 2022, and therefore exceed the threshold of 95% required under the Science Based Target initiative.
\n
(3) The target is in line with the path to 1.5 \u00b0C set by the SBTi for the electrical services industry (Sectoral Decarbonization Approach, or SDA), although it could
\n
not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date.
\n
(4) The target could not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date. In
\n
addition, the SBTi has not defined a Sectoral Decarbonization Approach for these types of emissions, so the ambition level cannot be verified.
\n
(5) Two different percentage limits have been set for the target for Scope 3 GHG emissions by the supply chain, as allowed under the SBTi approach, which
\n
required coverage of at least 67% of Scope 3 emissions for the 2030 target, and at least 90% for the 2040 target.
\n
Total coverage of Scopes 1-2-3
\n
emissions in 2022
\n
\u2022 98.6% of Scope 1 GHG emissions (2025, 2030 and 2040 targets)
\n
\u2022 100% of Scope 2 GHG emissions (2030 and 2040 targets)
\n
\u2022 87% (2030 target) and 90% (2040 target) of Scope 3 GHG emissions
\n
(5)
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Regarding the assumptions for commodity price develop-
\n
ments, the use of Paris reference scenarios is confirmed.
\n
More specifically, the price of CO
\n
2
\n
is assumed to rise rapidly
\n
through 2030, driven by the gradual reduction in the sup-
\n
ply of allowances in the face of growing demand, while coal
\n
prices are projected to stabilize due to falling demand. Gas
\n
price tensions are expected to ease in the coming years in
\n
light of a realignment between supply and demand at the
\n
global level. Finally, the price of oil is expected to stabilize,
\n
with peak demand coming around 2030.
\n
Note also that the Group has used sensitivity analyses to
\n
take account of the impacts of climate change in the long
\n
term. More specifically:
\n
\u2022 we consider a long-term growth rate in the estimation of
\n
the terminal value that is in line with the change in elec-
\n
tricity demand over the 2026-2050 period, based on the
\n
specific features of the businesses concerned, adopting
\n
certain assumptions concerning the increase in tempera-
\n
ture due to climate change and trends connected with
\n
the energy transition;
\n
\u2022 we consider changes in the hydroelectric, wind and pho-
\n
tovoltaic generation levels of our portfolio assets, asso-
\n
ciated with each projection of underlying climate and
\n
weather variables (for example, temperature, irradiance,
\n
wind speed and precipitation);
\n
\u2022 we assume that the Group will incur the costs provisioned
\n
for decommissioning fossil fuel generation plants in line
\n
with the goal of zero direct (Scope 1) and indirect emis-
\n
sions from retail activities (Scope 3).
\n
In order to verify the robustness of the value in use of the
\n
CGUs, sensitivity analyses were conducted for the main val-
\n
ue drivers, in particular WACC, the long-term growth rate.
\n
In these circumstances as well, the results were consistent
\n
with the evidence described above, finding that the value of
\n
all the CGUs analyzed exceeded the carrying amount, thus
\n
ensuring the full recoverability of their carrying amount in
\n
the consolidated financial statements of the Enel Group at
\n
December 31, 2022.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The table below reports the composition of the main
\n
goodwill values for the companies within each CGU, along
\n
with the discount rates applied and the time horizon over
\n
which the expected cash flows have been discounted.
\n
Millions of euro
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Iberian Peninsula 8,785 2.47% 6.10% 3 years
\n
Perpetuity/25
\n
years EGP/13
\n
years G&T
\n
8,785 1.64% 3.93% 3 years
\n
Perpetuity/25
\n
years EGP/14
\n
years G&T
\n
Chile 1,148 2.00% 8.45% 3 years
\n
Perpetuity/26
\n
years EGP/5
\n
years G&T
\n
1,209 2.02% 6.58% 3 years
\n
Perpetuity/25
\n
years EGP/6
\n
years G&T
\n
Argentina 21 45.70% 71.78% 3 years Perpetuity 22 24.11% 46.75% 3 years
\n
Perpetuity/8
\n
years G&T
\n
Peru 571 2.25% 8.75% 3 years
\n
Perpetuity/25
\n
years EGP/8
\n
years G&T
\n
566 2.31% 6.64% 3 years
\n
Perpetuity/23
\n
years EGP/9
\n
years G&T
\n
Colombia 518 3.20% 11.79% 3 years
\n
Perpetuity/26
\n
years EGP/15
\n
years G&T
\n
527 3.11% 8.82% 3 years
\n
Perpetuity/28
\n
years EGP/16
\n
years G&T
\n
Brazil 1,313 3.58% 11.22% 3 years
\n
Perpetuity/25
\n
years EGP
\n
1,303 3.30% 9.09% 3 years
\n
Perpetuity/26
\n
years EGP/7
\n
years G&T
\n
Central America 26 2.02% 9.66% 3 years 18 years 25 2.03% 7.85% 3 years 19 years
\n
Enel Green Power North
\n
America
\n
70 2.02% 6.48% 3 years 25 years 70 2.03% 5.01% 3 years 26 years
\n
Enel X North America 142 2.02% 9.71% 3 years Perpetuity 199 2.03% 7.62% 3 years Perpetuity
\n
Enel X Way North America 70 2.02% 11.53% 3 years Perpetuity n.a. n.a. n.a. n.a. n.a.
\n
Enel X Asia Pacific 84 2.02% 10.39% 3 years Perpetuity 84 2.03% 8.81% 3 years Perpetuity
\n
Enel X Rest of Europe 43 1.62% 8.82% 3 years Perpetuity 43 1.70% 8.24% 3 years Perpetuity
\n
Enel Green Power Italy 21 1.62% 6.39% 3 years
\n
Perpetuity/24
\n
years
\n
21 1.52% 4.94% 3 years
\n
Perpetuity/23
\n
years
\n
Market Italy 581 2.38% 10.88% 3 years 15 years 580 1.48% 9.14% 3 years 15 years
\n
Enel Produzione Italy 349 1.64% 7.70% 3 years
\n
Perpetuity/15
\n
years
\n
n.a. n.a. n.a. n.a. n.a.
\n
Romania n.a. n.a. n.a. n.a. n.a. 387 2.06% 7.56% 3 years
\n
Perpetuity/25
\n
years
\n
CGUs with no recognized
\n
goodwill but that underwent
\n
impairment testing given the
\n
presence of the indicators
\n
provided for in IAS 36
\n
Iberia - NPT (Non-Peninsular
\n
Territories)
\n
n.a. n.a. n.a. n.a. n.a. - - 3.42% 5 years 5 years
\n
Australia n.a. n.a. n.a. n.a. n.a. - 0.91% 5.50% 3 years 25 years
\n
Mexico n.a. n.a. n.a. n.a. n.a. - 3.36% 8.77% 3 years 24 years
\n
(1) Perpetual growth rate for cash flows after the explicit forecast period.
\n
(2) Pre-tax WACC calculated using the iterative method: the discount rate that ensures that the value in use calculated with pre-tax cash flows is equal to that
\n
calculated with post-tax cash flows discounted with the post-tax WACC.
\n
(3) The terminal value has been estimated on the basis of a perpetuity or an annuity with a rising yield for the years indicated in the column (G&T = Generation
\n
& Trading, EGP = Enel Green Power, LH = Large Hydro).
\n

\n\n

\n\n

\n\n

\n\n
25. Deferred tax assets and liabilities \u2013 \u20ac10,925 million and \u20ac9,542 million
\n
The following tables detail changes in deferred tax assets
\n
and liabilities by type of timing difference and calculated
\n
based on the tax rates established by applicable regula-
\n
tions, as well as the amount of deferred tax assets offset-
\n
table, where permitted, with deferred tax liabilities.
\n
Millions of euro
\n
Increase/
\n
(Decrease)
\n
taken to
\n
profit or loss
\n
Increase/
\n
(Decrease)
\n
taken to
\n
equity
\n
Change in the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
Reclassifications
\n
of assets held
\n
for sale
\n
at Dec. 31, 2021
\n
at Dec. 31, 2022
\n
Deferred tax assets:
\n
- differences in the
\n
carrying amount of
\n
intangible assets,
\n
property, plant and
\n
equipment
\n
2,469 (90) 1 5 12 (10) (74) 2,313
\n
- accruals to provisions
\n
for risks and charges
\n
and impairment
\n
losses with deferred
\n
deductibility
\n
2,035 13 - 10 45 (19) (128) 1,956
\n
- tax loss carried
\n
forward
\n
785 158 - - 46 3 (206) 786
\n
- measurement of
\n
financial instruments
\n
2,248 91 522 4 2 67 (20) 2,914
\n
- employee benefits 871 (70) (78) - 45 40 (10) 798
\n
- other items 2,626 (464) 6 1 (7) 136 (140) 2,158
\n
Total 11,034 (362) 451 20 143 217 (578) 10,925
\n
Deferred tax liabilities:
\n
- differences on non-
\n
current and financial
\n
assets
\n
5,538 148 2 110 (97) 273 (255) 5,719
\n
- measurement of
\n
financial instruments
\n
1,527 28 (159) - 2 110 (2) 1,506
\n
- other items 2,194 188 6 (3) 38 78 (184) 2,317
\n
Total 9,259 364 (151) 107 (57) 461 (441) 9,542
\n
Non-offsettable
\n
deferred tax assets
\n
6,194
\n
Non-offsettable
\n
deferred tax liabilities
\n
4,612
\n
Excess net deferred
\n
tax liabilities after any
\n
offsetting
\n
199
\n
Deferred tax assets recognized at December 31, 2022, as the
\n
recovery of such assets is considered reasonably certain, to-
\n
taled \u20ac10,925 million (\u20ac11,034 million at December 31, 2021).
\n
Deferred tax assets decreased by \u20ac109 million during the
\n
year, essentially due to:
\n
\u2022 the reversal of deferred tax assets by Enel Iberia, the par-
\n
ent company of the tax consolidation group in Spain;
\n
\u2022 reversals of deferred tax assets on the differences in
\n
the value of non-current assets mainly in Italy and Latin
\n
America;
\n
\u2022 the reclassification of deferred tax assets relating to
\n
companies classified as available for sale and discontin-
\n
ued operations in the period.
\n
These factors were partly offset by the effect of deferred
\n
tax assets connected with developments in the fair value
\n
of cash flow hedge derivatives, the impact of exchange
\n
differences in Latin America and deferred tax assets rec-
\n
ognized following the corporate reorganization of the new
\n
e-Mobility Business Line in North America and Spain.
\n

\n\n

\n\n

\n

\n\n
Note that deferred tax assets have not been assessed on
\n
tax losses carried forward and for the year (\u20ac1,129 million)
\n
in the amount of \u20ac352 million because, as based on cur-
\n
rent estimates of future taxable income, their recoverabili-
\n
ty is not considered probable.
\n
Deferred tax liabilities amounted to \u20ac9,542 million at De-
\n
cember 31, 2022 (\u20ac9,259 million at December 31, 2021).
\n
They essentially include the determination of the tax ef-
\n
fects of the adjustments to assets acquired as part of the
\n
final allocation of the cost of acquisitions made in the
\n
various years and the deferred taxation in respect of the
\n
differences between depreciation charged for tax purpos-
\n
es, including accelerated depreciation, and depreciation
\n
based on the estimated useful lives of assets.
\n
Deferred tax liabilities increased by a total of \u20ac283 million,
\n
due, in particular, to:
\n
\u2022 the impact of tax reforms and hyperinflation in Argen-
\n
tina;
\n
\u2022 the tax effect of the allocation of the goodwill on the
\n
merger of Enel Hydro Appennino Centrale Srl.
\n
These effects were partially offset by the effect of deferred
\n
tax assets connected with developments in the fair value
\n
of cash flow hedge derivatives, the impact of exchange
\n
differences in Latin America and the reclassification of
\n
deferred tax liabilities relating to companies classified as
\n
available for sale and discontinued operations during the
\n
year.
\n

\n\n\n

\n\n

\n\n
26. Equity-accounted investments - \u20ac1,281 million
\n
The following table shows changes in the main investments
\n
in joint ventures and associated companies accounted for
\n
using the equity method.
\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl - - - 299 - - - 299 50.0%
\n
Mooney Group SpA - - (17) 305 - - (69) 219 50.0%
\n
Slovak Power Holding - 50.0% (65) - - - 155 90 50.0%
\n
Zacapa Topco S\u00e0rl 114 20.6% 1 (114) - - (1) - -
\n
Matimba project
\n
companies
\n
- - (3) 108 - - 3 108 50.0%
\n
Kino project companies 21 20.0% (18) - - - 13 16 20.0%
\n
Tejo Energia Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica
\n
12 43.8% - - (7) - - 5 43.8%
\n
Ewiva Srl 22 50.0% (2) - - - - 20 50.0%
\n
Drift Sand Wind Project 40 50.0% 2 - - - 3 45 50.0%
\n
Front Mar\u00edtim del Bes\u00f2s 33 61.4% (2) - - - - 31 61.4%
\n
Rusenergosbyt 51 49.5% 64 - (11) - (13) 91 49.5%
\n
Energie Electrique de
\n
Tahaddart
\n
18 32.0% 2 - (2) - (7) 11 32.0%
\n
PowerCrop - 50.0% 16 - - - (2) 14 50.0%
\n
Total joint ventures 311 (22) 598 (20) - 82 949
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Associates
\n
CESI 59 42.7% (3) - - - 2 58 42.7%
\n
Elecgas SA 15 50.0% 7 - (15) - 23 30 50.0%
\n
GNL Chile SA 6 33.3% 7 - - - 1 14 33.3%
\n
Energ\u00edas Especiales del
\n
Bierzo
\n
4 50.0% 3 - (2) - 7 12 50.0%
\n
Tecnatom 27 45.0% - - - (27) - - -
\n
Gorona del Viento El
\n
Hierro SA
\n
13 23.2% 1 - (1) - - 13 23.2%
\n
Suministradora El\u00e9ctrica
\n
de C\u00e1diz
\n
10 33.5% 4 - (5) - - 9 33.5%
\n
Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas
\n
8 37.5 % 3 - (3) - (1) 7 37.5 %
\n
Cogenio Srl 12 20.0% (1) - (4) - 2 9 20.0%
\n
Avikiran Surya India - - - 28 - - (1) 27 51.0%
\n
Sociedad de Inversiones
\n
K Cuatro SpA
\n
- - - (30) - - 30 - -
\n
Enel X AMPCI Ebus Chile
\n
SpA
\n
4 20.0% - (5) - - 1 - -
\n
EGPNA Renewable
\n
Energy Partners
\n
121 20.0% 5 (59) - - 10 77 10.0%
\n
Rocky Caney Holding 50 20.0% 5 (30) - - (3) 22 10.0%
\n
Other 64 (5) (12) (7) - 14 54
\n
Total associates 393 26 (108) (37) (27) 85 332
\n
TOTAL 704 4 490 (57) (27) 167 1,281
\n
The increase in equity-accounted investments in 2022
\n
mainly reflected:
\n
\u2022 the positive impact of changes in the consolidation
\n
scope, mainly regarding:
\n
- the acquisition of a stake in Mooney; more specifical-
\n
ly, with the closing of the transaction between Enel
\n
X Srl and Banca 5 both companies have acquired a
\n
50% stake in Mooney putting it under the joint control
\n
of both parties. Subsequently, all the activities related
\n
to Enel X\u2019s financial service business in Italy, marketed
\n
under the brand Enel X Pay, were sold to Mooney, cre-
\n
ating a European-based fintech company;
\n
- the recognition of the interest in Gridspertise Srl fol-
\n
lowing the disposal of a 50% stake in the company,
\n
previously wholly owned, to the international private
\n
equity fund CVC Capital Partners Fund VIII (CVC);
\n
- the recognition of the interest in the joint venture
\n
holding the companies of the Matimba project, previ-
\n
ously controlled by the Enel Group;
\n
- the recognition of the interest in the previously con-
\n
trolled Indian company Avikiran Surya India Private
\n
Limited;
\n
- the reclassification of the investment in Zacapa Top-
\n
co (\u20ac114 million) under \u201cInvestments in other entities\u201d,
\n
following the sale by Enel X International of 1.1% of
\n
the interest in Ufinet. Following the transaction, Enel X
\n
International retains an indirect stake of 19.5% in the
\n
share capital of Ufinet;
\n
- the sale by Enel X Chile SpA of the entire stake held in
\n
the associates Sociedad de Inversiones K Cuatro SpA
\n
and Enel X AMPCI Ebus Chile SpA;
\n
- the sale of 50% of the stakes held in EGPNA Renew-
\n
able Energy Partners and in Rocky Caney Holding
\n
(which, following the transaction, go from 20% to
\n
10%);
\n
\u2022 the profits attributable to the Group of equity-account-
\n
ed companies (\u20ac4 million), mainly accounted for by the
\n
profit contributed by Rusenergosbyt, PowerCrop and
\n
Spanish companies;
\n
\u2022 changes in the OCI reserves mainly relating to Slovak
\n
Power Holding, following the positive developments in
\n
the fair value of cash flow hedge derivatives, and the
\n
Spanish companies.
\n
These positive effects were mainly offset by:
\n
\u2022 dividends distributed in the period in the amount of \u20ac57
\n
million, mainly by Rusenergosbyt and certain Spanish
\n
companies;
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
\u2022 the reclassification of the investment in Tecnatom (\u20ac27
\n
million) as held for sale.
\n
The following tables provide a summary of financial infor-
\n
mation for the main joint ventures and associates of the
\n
Group not classified as held for sale in accordance with
\n
IFRS 5.
\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2022 2021 2022 2021 2022 2021
\n
Joint ventures
\n
Slovak Power Holding 5,184 3,417 (320) 190 (223) 137
\n
Gridspertise Srl 334 - 12 - 8 -
\n
Rusenergosbyt 2,919 2,288 170 112 137 90
\n
Matimba project
\n
companies
\n
34 - (22) - (15) -
\n
Mooney Group SpA 224 - (33) - (33) -
\n
Ewiva Srl - - (4) - (4) -
\n
Associates
\n
CESI 155 140 (4) (7) (1) (8)
\n
Elecgas SA 26 25 20 15 14 11
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
27. Derivatives
\n
Millions of euro Non-current Current
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Derivative financial assets 3,970 2,772 14,830 22,791
\n
Derivative financial liabilities 5,895 3,339 16,141 24,607
\n
For more information on derivatives classified as non-cur-
\n
rent financial assets, please see note 51 for hedging deriv-
\n
atives and trading derivatives.
\n

\n\n\n

\n

\n
28. Current/Non-current contract assets/(liabilities)
\n\n
Millions of euro Non-current Current
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Contract assets 508 530 106 121
\n
Contract liabilities 5,747 6,214 1,775 1,433
\n

\n\n\n
Non-current assets deriving from contracts with custom-
\n
ers (contract assets) refer mainly to assets under develop-
\n
ment resulting from public-to-private service concession
\n
arrangements recognized in accordance with IFRIC 12 and
\n
which have an expiration of beyond 12 months (\u20ac492 mil-
\n
lion). These cases arise when the concession holder has
\n
not yet obtained full right to recognize the asset from the
\n
grantor, in that there remains a contractual obligation to
\n
ensure that the asset is completed and can be remuner-
\n
ated through rates. The figure at December 31, 2022 in-
\n
cludes investments for the year in the amount of \u20ac1,174
\n
million.
\n

\n\n
Current contract assets mainly concern construction con-
\n
tracts in progress (\u20ac80 million to be invoiced, payments
\n
on which are subject to the fulfillment of a performance
\n
obligation).
\n
The value at December 31, 2022 of non-current contract
\n
liabilities is mainly attributable to distribution operations in
\n
Italy (\u20ac3,127 million) and Spain (\u20ac2,620 million) as a result of
\n
the accounting treatment of revenue from connections of
\n
new customers, which are deferred over the average dura-
\n
tion of the associated contracts.
\n
Current contract liabilities include the contractual liabilities
\n
related to revenue from connections to the electricity grid
\n
expiring within 12 months in the amount of \u20ac1,234 million,
\n
mainly recognized in Italy and Spain, as well as liabilities for
\n
construction contracts in progress (\u20ac509 million).
\n
As required under IFRS 15, the following table reports the
\n
reversal to profit or loss of contract liabilities by time band.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Within 1 year 1,775 1,433
\n
Within 2 years 516 498
\n
Within 3 years 517 480
\n
Within 4 years 516 479
\n
Within 5 years 515 477
\n
More than 5 years 3,683 4,280
\n
Tot al 7,5 2 2 7, 6 4 7
\n

\n\n

\n\n

\n\n

\n

\n

\n
29. Other non-current financial assets - \u20ac8,359 million
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Equity investments in other companies measured at fair value 366 72 294 -
\n
Financial assets and securities included in net financial debt (see note 29.1) 4,213 2,692 1,521 56.5%
\n
Service concession arrangements 3,732 2,890 842 29.1%
\n
Non-current financial prepayments 48 50 (2) -4.0%
\n
Tot al 8,359 5,704 2,655 46.5%
\n
\n\n

\n\n\n
\u201cOther non-current financial assets\u201d increased by \u20ac2,655
\n
million mainly reflecting:
\n
\u2022 the increase in financial assets included in net financial
\n
debt, as detailed in note 29.1;
\n
\u2022 the increase in financial assets in respect of service con-
\n
cession arrangements, mainly in Brazil;
\n
\u2022 the recognition of the investment in Zacapa Topco, fol-
\n
lowing the sale by Enel X International of a 1.1% share
\n
in Ufinet which resulted in the loss of joint control over
\n
Zacapa Topco.
\n

\n

\n\n
The following is a breakdown of equity investments in oth-
\n
er companies measured at fair value.
\n
Millions of euro
\n
at Dec. 31,
\n
2022 % held
\n
at Dec. 31,
\n
2021 % held Change
\n
Empresa Propietaria de la Red SA 7 11.1% 5 11.1% 2
\n
European Energy Exchange AG 22 2.4% 13 2.4% 9
\n
Athonet Srl 7 16.0% 7 16.0% -
\n
Korea Line Corporation 1 0.3% 1 0.3% -
\n
Hubject GmbH 11 12.5% 10 12.5% 1
\n
Termoel\u00e9ctrica Jos\u00e9 de San Mart\u00edn SA 11 4.2% 11 4.2% -
\n
Termoel\u00e9ctrica Manuel Belgrano SA 9 4.7% 12 4.7% (3)
\n
Zacapa Topco S\u00e0rl 288 19.5% - - 288
\n
Other 10 13 (3)
\n
Tot al 366 72 294
\n
29.1 Other non-current financial assets included in net financial debt \u2013 \u20ac4,213 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Securities 447 403 44 10.9%
\n
Other financial assets 3,766 2,289 1,477 64.5%
\n
Tot al 4,213 2,692 1,521 56.5%
\n
\u201cSecurities\u201d are represented by financial instruments in
\n
which the Dutch insurance companies invest a portion of
\n
their liquidity. The increase in \u201cOther financial assets\u201d is
\n
mainly attributable to an increase in financial assets for se-
\n
curity deposits.
\n

\n\n

\n\n

\n

\n\n
30. Other current financial assets \u2013 \u20ac13,753 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Current financial assets included in net financial debt (see note 30.1) 13,501 8,467 5,034 59.5%
\n
Other 252 178 74 41.6%
\n
Tot al 13,753 8,645 5,108 59.1%
\n
\u201cOther current financial assets\u201d increased by \u20ac5,108 mil-
\n
lion, mainly reflecting the increase in current financial as-
\n
sets included in net financial debt, as detailed in note 30.1.
\n
30.1 Other current financial assets included in net financial debt \u2013 \u20ac13,501 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Current portion of long-term financial assets 2,838 1,538 1,300 84.5%
\n
Securities at FVTPL - 1 (1) -
\n
Securities at FVOCI 78 87 (9) -10.3%
\n
Financial assets and cash collateral 8,319 6,485 1,834 28.3%
\n
Other 2,266 356 1,910 -
\n
Tot al 13,501 8,467 5,034 59.5%
\n
The increase in the item is mainly attributable to:
\n
\u2022 \u20ac1,300 million in respect of an increase in the current
\n
portion of long-term financial assets, which essentially
\n
reflects the increase in financial assets relating to the
\n
deficit of the Spanish electricity system;
\n
\u2022 \u20ac1,834 million in respect of an increase in cash collateral
\n
paid to counterparties for derivatives transactions;
\n
\u2022 an increase in \u201cOther\u201d, mainly reflecting the increase in
\n
short-term financial assets of Enel X Italia in respect of
\n
the assignment of tax credits for building renovations
\n
under the \u201ceco-sisma bonus\u201d program (\u20ac557 million) and
\n
the increase in financial assets in Brazil (\u20ac1,210 million)
\n
essentially relating to the sale of Celg Distribui\u00e7\u00e3o SA -
\n
Celg-D (Enel Goi\u00e1s).
\n

\n\n\n

\n\n

\n
31. Other non-current assets \u2013 \u20ac2,486 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 282 242 40 16.5%
\n
Net assets of personnel programs 8 - 8 -
\n
Other 2,196 3,026 (830) -27.4%
\n
Tot al 2,486 3,268 (782) -23.9%
\n

\n\n
Amounts due from institutional market operators in-
\n
creased by \u20ac40 million, mainly in Spain as a result of the
\n
remuneration of distribution operations.
\n
Other assets at December 31, 2022 included tax assets in
\n
the amount of \u20ac1,674 million (\u20ac2,286 million at December
\n
31, 2021) and security deposits in the amount of \u20ac301 mil-
\n
lion (\u20ac340 million at the end of 2021).
\n
The change for the year mainly reflected the decline in tax
\n
assets previously recognized in Brazil, connected with the
\n
PIS/COFINS dispute in the amount of \u20ac253 million, and a
\n
decrease in assets connected with the sale of a number
\n
of Brazilian companies in the amount of \u20ac976 million, only
\n
partially offset by positive exchange rate developments in
\n
the amount of \u20ac543 million.
\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n

\n

\n
32. Other current assets \u2013 \u20ac4,314 million
\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 1,033 2,205 (1,172) -53.2%
\n
Advances to suppliers 332 326 6 1.8%
\n
Amounts due from employees 30 29 1 3.4%
\n
Amounts due from others 1,056 1,071 (15) -1.4%
\n
Sundry tax assets 1,598 1,164 434 37.3%
\n
Current accrued income and prepayments 265 207 58 28.0%
\n
Tot al 4,314 5,002 (688) -13.8%
\n

\n\n

\n\n
Amounts due from institutional market operators main-
\n
ly include amounts due in respect of the Italian system in
\n
the amount of \u20ac617 million (\u20ac1,519 million at December
\n
31, 2021) and the Spanish system in the amount of \u20ac388
\n
million (\u20ac667 million at December 31, 2021). The decrease
\n
was essentially attributable to the decrease in amounts re-
\n
ceivable in Italy in respect of the Energy and Environmental
\n
Services Fund, mainly held by e-distribuzione (\u20ac429 mil-
\n
lion) and Servizio Elettrico Nazionale (\u20ac106 million), primar-
\n
ily connected with equalization mechanisms.
\n\n
The increase of \u20ac434 million in sundry tax assets is mainly
\n
attributable to an increase in credits for indirect taxes and
\n
duties in Italy (\u20ac216 million), Latin America (\u20ac100 million)
\n
and in the parent company Enel SpA (\u20ac282 million), partially
\n
offset by a decline in such items in Spain (\u20ac115 million) and
\n
North America (\u20ac93 million).
\n

\n\n

\n\n

\n\n\n
33. Inventories \u2013 \u20ac4,853 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Raw and ancillary materials, and consumables:
\n
- fuels 2,396 1,023 1,373 -
\n
- materials, equipment and other inventories 2,155 1,793 362 20.2%
\n
Tot al 4,551 2,816 1,735 61.6%
\n
Environmental certificates:
\n
- CO
\n
2
\n
emissions allowances 152 139 13 9.4%
\n
- green certificates - 3 (3) -
\n
- energy efficiency certificates 6 16 (10) -62.5%
\n
Tot al 158 158--
\n
Buildings held for sale 47 49 (2) -4.1%
\n
Payments on account 97 86 11 12.8%
\n
TOTAL 4,853 3,109 1,744 56.1%
\n
Raw and ancillary materials, and consumables consist of
\n
materials and equipment used to operate, maintain, and
\n
construct power plants and distribution networks, as well
\n
as fuel inventories to cover the Group\u2019s requirements for
\n
generation and trading activities.
\n
The overall increase in inventories in 2022 (\u20ac1,744 million) is
\n
mainly attributable to an increase in inventories of fuel and
\n
materials, devices and other inventories recorded above all
\n
in Italy (\u20ac1,221 million), Spain (\u20ac506 million) and Latin Amer-
\n
ica (\u20ac69 million), notably gas inventories to meet the needs
\n
of the Group plants and an increase in stocks of low- and
\n
medium-voltage materials, partially offset by the decrease
\n
in inventories in Russia and Romania (\u20ac100 million).
\n

\n\n

\n\n

\n

\n\n
34. Trade receivables \u2013 \u20ac16,605 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Customers:
\n
- electricity sales and transport 10,216 10,111 105 1.0%
\n
- distribution and sale of gas 3,026 2,658 368 13.8%
\n
- other assets 3,118 3,158 (40) -1.3%
\n
Total trade receivables due from customers 16,360 15,927 433 2.7%
\n
Trade receivables due from associates and joint ventures 245 149 96 64.4%
\n
TOTAL 16,605 16,076 529 3.3%
\n
Trade receivables due from customers are recognized net
\n
of loss allowances, which totaled \u20ac3,783 million at the end
\n
of the year, compared with a balance of \u20ac3,663 million at
\n
the end of the previous year.
\n
Specifically, the increase in 2022, totaling \u20ac529 million,
\n
mainly recognized in Spain (\u20ac530 million) and Latin Amer-
\n
ica (\u20ac554 million), was partially offset by the decrease rec-
\n
ognized in Italy (\u20ac106 million) and Romania (\u20ac500 million),
\n
which, in line with the provisions of \u201cIFRS 5 - Non-current
\n
assets held for sale and discontinued operations\u201d, was
\n
classified as held for sale.
\n
The change in the period is attributable to receivables for
\n
electricity and gas sales and transport recognized in the
\n
year, as well as the increase in allocations net of releases in
\n
respect of bad debt provisions in Italy and Latin America.
\n
For more information on trade receivables, see note 48
\n
\u201cFinancial instruments by category\u201d.
\n

\n\n\n
35. Cash and cash equivalents \u2013 \u20ac11,041 million
\n
Cash and cash equivalents, detailed in the following table,
\n
increased by \u20ac2,183 million due to proceeds from the sale
\n
in December 2022 of Enel Transmisi\u00f3n Chile, Gridspertise
\n
and Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Bank and postal deposits 8,968 8,118 850 10.5%
\n
Cash and cash equivalents on hand 35 8 27 -
\n
Other investments of liquidity 2,038 732 1,306 -
\n
Tot al 11,041 8,858 2,183 24.6%
\n

\n\n

\n\n

\n\n

\n\n
36. Assets and liabilities included in disposal groups classified as held for sale \u2013 \u20ac6,149
\n
million and \u20ac3,360 million
\n
Changes in assets held for sale in 2022 break down as fol-
\n
lows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-
\n
current assets
\n
Disposals and
\n
change in
\n
consolidation
\n
scope Impairment
\n
Exchange
\n
differences Investments
\n
Other
\n
changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Property, plant and equipment 899 5,231 (1,848) (1,102) 18 47 59 3,304
\n
Intangible assets 144 1,985 (1,136) (797) 23 17 98 334
\n
Goodwill 1 550 (62) (488) (42) - 41 -
\n
Deferred tax assets 16 578 (408) - - - 25 211
\n
Equity-accounted investments 4 27 (2) (1) - - (1) 27
\n
Non-current contract assets - 227 (233) - (2) 84 (76) -
\n
Other non-current assets 40 750 (639) - - - (26) 125
\n
Non-current financial assets - 208 (144) - (12) - 86 138
\n
Current financial assets and
\n
securities
\n
- 113 (65) - - - (5) 43
\n
Other current financial assets - 75 - - 8 - (74) 9
\n
Cash and cash equivalents 44 587 (287) - (4) - 85 425
\n
Inventories, trade receivables
\n
and other current assets
\n
94 2,353 (1,054) - (8) - 148 1,533
\n
Total 1,242 12,684 (5,878) (2,388) (19) 148 360 6,149
\n
Developments in liabilities break down as follows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-current
\n
liabilities
\n
Disposals and
\n
change in
\n
consolidation
\n
scope
\n
Exchange
\n
differences Other changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Long-term borrowings 782 1,160 (1,259) 33 59 775
\n
Provisions for risks and charges,
\n
non-current portion
\n
10 272 (242) 1 (8) 33
\n
Deferred tax liabilities 46 441 (207) - (40) 240
\n
Post-employment and other
\n
employee benefits
\n
-65(42)--23
\n
Non-current financial liabilities 40 123 (5) (10) (79) 69
\n
Non-current contract liabilities - 447 (5) (2) 2 442
\n
Other non-current liabilities 5 649 (597) (3) 125 179
\n
Short-term borrowings 2 651 (17) (9) 15 642
\n
Long-term borrowings, current
\n
portion
\n
- 137 (1,328) (29) 1,238 18
\n
Provisions for risks and charges,
\n
current portion
\n
-47(14) - -33
\n
Other current financial liabilities 6 28 (57) (1) 36 12
\n
Trade payables and other
\n
current liabilities
\n
71 1,663 (828) 4 (16) 894
\n
Total 962 5,683 (4,601) (16) 1,332 3,360
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The item essentially includes assets measured at the lower
\n
of cost, understood as their net carrying amount, and the
\n
estimated realizable value, which, due to management de-
\n
cisions, meet the requirements of \u201cIFRS 5 - Non-current
\n
assets held for sale and discontinued operations\u201d for their
\n
classification in this item.
\n
The balances of assets and liabilities held for sale and
\n
discontinued operations at December 31, 2022 came to,
\n
respectively, \u20ac6,149 million and \u20ac3,360 million and mainly
\n
refer to:
\n
\u2022 Romania: on December 14, 2022, Enel SpA announced
\n
that it had entered into an Exclusivity Agreement with
\n
Greek company Public Power Corporation SA (PPC) in
\n
relation to the potential disposal of all the equity stakes
\n
held by Enel Group in Romania. The value of the net as-
\n
sets held in Romania was thus adjusted to the expected
\n
sale price, with the recognition of an impairment loss of
\n
about \u20ac696 million, and the same were classified as \u201cdis-
\n
continued operations\u201d;
\n
\u2022 Enel Green Power Hellas: the parent company Enel Green
\n
Power has started a process aimed at finding an investor
\n
interested in a partnership for the management and de-
\n
velopment of the renewable energy business in Greece.
\n
The status of negotiations suggests that the sale is high-
\n
ly probable as at December 31, 2022. Accordingly, the
\n
requirements established by \u201cIFRS 5 - Non-current as-
\n
sets held for sale and discontinued operations\u201d for the
\n
classification of Greek assets as \u201cdiscontinued opera-
\n
tions\u201d have been met;
\n
\u2022 Enel Green Power Australia: considering the status of
\n
negotiations, the two subholding companies held in
\n
Australia and their subsidiaries have been reclassified
\n
under non-current assets held for sale and discontin-
\n
ued operations, in accordance with IFRS 5, with the aim
\n
of reaching an agreement with third parties within the
\n
Stewardship business model in the next 12 months;
\n
\u2022 Central Dock Sud and Enel Generaci\u00f3n Costanera in Ar-
\n
gentina: the Enel Group, through its subsidiary Enel Ar-
\n
gentina, started negotiations for the sale of the Group\u2019s
\n
75.7% stake in the thermal generation company Enel
\n
Generaci\u00f3n Costanera. Negotiations also covered the
\n
sale of the Group\u2019s 41.2% stake in the thermal genera-
\n
tion company Central Dock Sud. The net assets of the
\n
interests were classified as available for sale and their
\n
value was adjusted to the expected sale price (\u20ac97 mil-
\n
lion), with the recognition of an impairment loss of about
\n
\u20ac290 million. The transaction was finalized in the 1st
\n
Quarter of 2023;
\n
\u2022 Avikiran Solar India Private Limited in India: following the
\n
agreements signed for the partial sale to a new share-
\n
holder, the investment satisfies the requirements of
\n
\u201cIFRS 5 - Non-current assets held for sale and discon-
\n
tinued operations\u201d, for classification of the net assets as
\n
available for sale. The disposal is expected to be finalized
\n
in the 1st Half of 2023;
\n
\u2022 3SUN in Italy: based on the negotiation process for the
\n
sale of a 50% stake in the share capital of 3SUN Srl, its
\n
net assets were reclassified at December 31, 2022 as
\n
non-current assets held for sale and discontinued oper-
\n
ations, in line with IFRS 5.
\n
Assets previously classified as held for sale disposed of in
\n
2022 include:
\n
\u2022 renewable companies in South Africa sold in the 1st Half
\n
of 2022;
\n
\u2022 CGT Fortaleza in Brazil and companies belonging to the
\n
financial sector of Enel X in Italy sold in the 3rd Quarter;
\n
\u2022 the interest held by Enel SpA in Enel Russia sold in Octo-
\n
ber 2022, thus completing the disposal of all electricity
\n
generation assets in Russia. For more information on the
\n
economic effects of the transaction, please refer to the
\n
paragraph \u201cDiscontinued operations\u201d;
\n
\u2022 the subsidiary Enel Chile SA completed the sale of the
\n
entire investment, equal to 99.09% of the share capi-
\n
tal, held in the Chilean electricity transmission company
\n
Enel Transmisi\u00f3n Chile SA, while the subsidiary Enel Bra-
\n
sil SA finalized the sale of the entire interest held in the
\n
Brazilian power distribution company Celg Distribui\u00e7\u00e3o
\n
SA - Celg-D in December 2022.
\n
For more information on the financial effects of the above
\n
transactions, please refer to the note \u201cBusiness combina-
\n
tions\u201d.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n
37. Equity \u2013 \u20ac42,082 million
\n
37.1 Equity attributable to owners of the Parent \u2013 \u20ac28,657 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share capital 10,167 10,167 -
\n
Treasury share reserve (47) (36) (11)
\n
Other reserves 2,740 1,721 1,019
\n
Share premium reserve 7,496 7,496 -
\n
Reserve for equity instruments - perpetual hybrid bonds 5,567 5,567 -
\n
Legal reserve 2,034 2,034 -
\n
Other reserves 2,332 2,313 19
\n
Translation reserve (5,912) (8,125) 2,213
\n
Hedging reserve (3,553) (2,268) (1,285)
\n
Hedging costs reserve (81) (39) (42)
\n
Reserve from measurement of financial instruments at FVOCI (22) 10 (32)
\n
Reserve from equity-accounted investments (476) (721) 245
\n
Actuarial reserve (1,063) (1,325) 262
\n
Reserve from disposal of equity interests without loss of control (2,390) (2,378) (12)
\n
Reserve from acquisitions of non-controlling interests (1,192) (843) (349)
\n
Retained earnings 15,797 17,801 (2,004)
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n\n
Share capital \u2013 \u20ac10,167 million
\n
At December 31, 2022, the fully subscribed and paid-up
\n
share capital of Enel SpA totaled \u20ac10,166,679,946, rep-
\n
resented by the same number of ordinary shares with a
\n
par value of \u20ac1.00 each. Enel SpA\u2019s share capital was un-
\n
changed compared with the amount reported at Decem-
\n
ber 31, 2021.
\n
At December 31, 2022, based on the shareholders register
\n
and the notices submitted to CONSOB and received by the
\n
Parent pursuant to Article 120 of Legislative Decree 58 of
\n
February 24, 1998, as well as other available information,
\n
shareholders with interests of greater than 3% in the Par-
\n
ent\u2019s share capital were the Ministry for the Economy and
\n
Finance (with a 23.585% stake) and BlackRock Inc. (with a
\n
5.114% stake held for asset management purposes).
\n

\n\n\n
Treasury share reserve - \u20ac(47) million
\n
At December 31, 2022, treasury shares are represented by
\n
7,153,795 ordinary shares of Enel SpA with a par value of
\n
\u20ac1.00 each (4,889,152 at December 31, 2021), purchased
\n
through an authorized intermediary for a total of \u20ac47 mil-
\n
lion.
\n

\n\n\n
Other reserves - \u20ac2,740 million
\n
Share premium reserve - \u20ac7,496 million
\n
Pursuant to Article 2431 of the Italian Civil Code, the share
\n
premium reserve contains, in the case of the issue of
\n
shares at a price above par, the difference between the is-
\n
sue price of the shares and their par value, including those
\n
resulting from conversion from bonds. The reserve, which
\n
is a capital reserve, may not be distributed until the legal
\n
reserve has reached the threshold established under Arti-
\n
cle 2430 of the Italian Civil Code.
\n
Reserve for equity instruments - perpetual hybrid bonds
\n
- \u20ac5,567 million
\n
This reserve reports the nominal value, net of transaction
\n
costs, of the non-convertible subordinated perpetual hy-
\n
brid bonds denominated in euros for international inves-
\n
tors.
\n
In 2022, the Group paid \u20ac123 million in coupons to holders
\n
of perpetual hybrid bonds.
\n
Legal reserve - \u20ac2,034 million
\n
The legal reserve is formed of the part of profits that, pur-
\n
suant to Article 2430 of the Italian Civil Code, cannot be
\n
distributed as dividends.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Other reserves - \u20ac2,332 million
\n
These include \u20ac2,215 million related to the remaining por-
\n
tion of the adjustments carried out when Enel was trans-
\n
formed from a public entity to a joint-stock company.
\n
Pursuant to Article 47 of the Consolidated Income Tax
\n
Code (Testo Unico Imposte sul Reddito, or \u201cTUIR\u201d), this
\n
amount does not constitute taxable income when distrib-
\n
uted.
\n
Translation reserve - \u20ac(5,912) million
\n
The increase for the year, of \u20ac2,213 million, was mainly due
\n
to the change in the consolidation scope connected with
\n
the sale of PJSC Enel Russia, Central Geradora Termel\u00e9trica
\n
Fortaleza and Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s),
\n
and the net appreciation of the functional currencies used
\n
by the foreign subsidiaries, mainly in Latin America and the
\n
United States, against the Group presentation currency
\n
(the euro).
\n
Hedging reserve - \u20ac(3,553) million
\n
This includes the net expense recognized in equity from
\n
the measurement of cash flow hedge derivatives. The
\n
change in 2022 is mainly attributable to developments in
\n
commodity prices.
\n
Hedging costs reserve - \u20ac(81) million
\n
In application of IFRS 9, this reserve includes the fair val-
\n
ue gains and losses on currency basis points and forward
\n
points. The change in 2022 is mainly attributable to devel-
\n
opments in commodity prices.
\n
Reserve from measurement of financial instruments at
\n
FVOCI - \u20ac(22) million
\n
This includes net unrealized fair value losses on financial
\n
assets.
\n
Reserve from equity-accounted investments - \u20ac(476)
\n
million
\n
The reserve reports the share of comprehensive income to
\n
be recognized directly in equity of equity-accounted in-
\n
vestees. The change in 2022 is mainly attributable to the
\n
change in the hedging reserve of Slovak Power Holding.
\n
Actuarial reserve - \u20ac(1,063) million
\n
This reserve includes actuarial gains and losses in respect
\n
of employee benefit liabilities, net of tax effects.
\n
Reserve from disposal of equity interests without loss of
\n
control - \u20ac(2,390) million
\n
This item mainly reports:
\n
\u2022 the gain posted on the public offering of Enel Green
\n
Power shares, net of expenses associated with the dis-
\n
posal and the related taxation;
\n
\u2022 the sale of non-controlling interests recognized as a re-
\n
sult of the Enersis (now Enel Am\u00e9ricas and Enel Chile)
\n
capital increase;
\n
\u2022 the capital loss, net of expenses associated with the dis-
\n
posal and the related taxation, from the public offering
\n
of 21.92% of Endesa;
\n
\u2022 the disposal to third parties of the non-controlling inter-
\n
est in Enel Green Power North America Renewable Ener-
\n
gy Partners;
\n
\u2022 the effects of the merger into Enel Am\u00e9ricas of Endesa
\n
Am\u00e9ricas and Chilectra Am\u00e9ricas.
\n
The change in the reserve in 2022 is associated with the
\n
sale of the 49% stake held by Enel Green Power Canada in
\n
Pincher Creek LP and Riverview LP.
\n
Reserve from acquisitions of non-controlling interests -
\n
\u20ac(1,192) million
\n
This reserve mainly includes the surplus of acquisition
\n
prices with respect to the carrying amount of the equi-
\n
ty acquired following the acquisition from third parties of
\n
further interests in companies already controlled in Latin
\n
America.
\n
The change for the year (-\u20ac349 million) mainly reflects the
\n
effects of the merger between Emgesa SA ESP (acquir-
\n
ing entity), Codensa SA ESP, Enel Green Power Colombia
\n
SAS ESP and ESSA 2 (merged entities), following which the
\n
Group\u2019s interest in Emgesa SA ESP (now Enel Colombia
\n
SA ESP) increased from 39.89% to 47.18%, and the sale by
\n
Endesa X Servicios SLU to Enel X Way Srl of 51% of Endesa
\n
X Way SL increasing the interest held by the Group in the
\n
latter from 70.11% to 85.35%.
\n

\n

\n\n
Retained earnings - \u20ac15,797 million
\n
This reserve reports earnings from previous years that
\n
have not been distributed or allocated to other reserves.
\n
The table below shows the changes in gains and losses
\n
recognized directly in other comprehensive income, in-
\n
cluding non-controlling interests, with specific reporting
\n
of the related tax effects.
\n

\n\n

\n\n

\n\n

\n
Millions of euro
\n
at Dec. 31, 2021 Change
\n
at Dec. 31, 2022
\n
Tot al
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests
\n
Gains/
\n
(Losses)
\n
recognized
\n
in equity
\n
during the
\n
year
\n
Released
\n
to profit
\n
or loss Taxes Total
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests Tot al
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests
\n
Translation
\n
reserve
\n
(11,790) (6,303) (5,487) 890 - - 890 879 11 (10,900) (5,424) (5,476)
\n
Hedging reserve (2,961) (2,280) (681) (3,605) 1,323 587 (1,695) (1,293) (402) (4,656) (3,573) (1,083)
\n
Hedging costs
\n
reserve
\n
(49) (39) (10) (40) (31) 9 (62) (52) (10) (111) (91) (20)
\n
Reserve from
\n
measurement
\n
of financial
\n
instruments at
\n
FVOCI
\n
11 12 (1) (51) - 7 (44) (44) - (33) (32) (1)
\n
Share of OCI
\n
of equity-
\n
accounted
\n
associates
\n
(820) (825) 5 256 - (22) 234 224 10 (586) (601) 15
\n
Reserve from
\n
measurement
\n
of equity
\n
investments
\n
in other
\n
companies
\n
(32) (32) - 13 - - 13 13 - (19) (19) -
\n
Actuarial reserve (1,798) (1,265) (533) 403 - (79) 324 249 75 (1,474) (1,016) (458)
\n
Total gains/
\n
(losses)
\n
recognized in
\n
equity
\n
(17,439) (10,732) (6,707) (2,134) 1,292 502 (340) (24) (316) (17,779) (10,756) (7,023)
\n\n
37.2 Dividends
\n
Amount distributed
\n
(millions of euro) Dividend per share (euro)
\n
Dividends distributed in 2021
\n
Dividends for 2020 3,638 0.358
\n
Interim dividends for 2021
\n
(1)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2021 3,638 0.358
\n
Dividends distributed in 2021
\n
Dividends for 2022 3,861 0.380
\n
Interim dividends for 2022
\n
(2)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2022 3,861 0.380
\n
(1) Approved by the Board of Directors on November 4, 2021 and paid as from January 26, 2022 (interim dividend of \u20ac0.19 per share for a total of \u20ac1,932 million).
\n
(2) Approved by the Board of Directors on November 3, 2022 and paid as from January 25, 2023 (interim dividend of \u20ac0.20 per share for a total of \u20ac2,033 million).
\n
Dividends distributed are shown net of amounts due to
\n
treasury shares at the respective \u201crecord dates\u201d. These
\n
shares were waived for collection and allocated to \u201cre-
\n
tained earnings\u201d.
\n
The dividend for 2022 is equal to \u20ac0.40 per share, for a
\n
total of \u20ac4,067 million (of which \u20ac0.20 per share for a total
\n
of \u20ac2,033 million already paid as an interim dividend). It will
\n
be proposed to the Shareholders\u2019 Meeting of May 10, 2023
\n
at single call.
\n
These consolidated financial statements do not take ac-
\n
count of the effects of the distribution to shareholders of
\n
the dividend for 2022, except for the liability in respect
\n
of shareholders for the interim dividend for 2022, which
\n
was approved by the Board of Directors on November 3,
\n
2022 for a potential maximum of \u20ac2,033 million, and paid
\n
as from January 25, 2023 net of the portion pertaining to
\n
the 7,153,795 treasury shares held as at the record date of
\n
January 24, 2023.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n

\n
In 2022, the Group also paid \u20ac123 million in coupons to
\n
holders of perpetual hybrid bonds.
\n\n
Capital management
\n
The Group\u2019s objectives for managing capital comprise
\n
safeguarding the business as a going concern, creating
\n
value for stakeholders and supporting the development of
\n
the Group. In particular, the Group seeks to maintain an ad-
\n
equate capitalization that enables it to achieve a satisfac-
\n
tory return for shareholders and ensure access to external
\n
sources of financing, in part by maintaining an adequate
\n
rating.
\n
In this context, the Group manages its capital structure
\n
and adjusts that structure when changes in economic
\n
conditions so require. There were no substantive changes
\n
in objectives, policies or processes in 2022.
\n
To this end, the Group constantly monitors developments
\n
in the level of its debt in relation to equity. The situation at
\n
December 31, 2022 and 2021 is summarized in the follow-
\n
ing table.
\n

\n

\n\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Non-current financial debt 68,191 54,620 13,571
\n
Net current financial position (3,315) 24 (3,339)
\n
Non-current financial assets and long-term securities (4,213) (2,692) (1,521)
\n
Net exchange rate derivatives associated with borrowings
\n
(1)
\n
(595) (259) (336)
\n
Net financial debt
\n
(1)
\n
60,068 51,693 8,375
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n
Non-controlling interests 13,425 12,689 736
\n
Equity 42,082 42,342 (260)
\n
Debt/equity ratio 1.43 1.22 0.21
\n
(1) In order to improve the reporting of net financial debt, so as to take account of exchange risk hedging, in its determination the Group has decided to include
\n
the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on borrowings. Accordingly, in order to improve
\n
the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021.
\n
The increase in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in net financial debt, mainly reflecting the funding require-
\n
ments of investments in the year, the payment of divi-
\n
dends, and the acquisition of ERG Hydro.
\n
See note 47 for a breakdown of the individual items in the
\n
table.
\n

\n\n

\n\n\n

\n\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,425 million
\n
The following table presents the composition of non-con-
\n
trolling interests by geographical area.
\n
Millions of euro Non-controlling interests
\n
Profit for the year attributable to non-
\n
controlling interests
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Italy 1 1 - -
\n
Iberia 5,321 5,238 713 193
\n
Latin America 7,422 6,511 857 467
\n
Europe 328 635 (342) 5
\n
North America 218 151 10 6
\n
Africa, Asia and Oceania 135 153 - (3)
\n
Total 13,425 12,689 1,238 668
\n
The change in non-controlling interests mainly reflects the
\n
appreciation of the functional currencies of the foreign
\n
subsidiaries against the euro (especially in Latin America),
\n
the results for the period, the effect of the corporate trans-
\n
action in Colombia and the impact of hyperinflation. These
\n
effects were partly offset by the dividends distributed and
\n
the value adjustment of cash flow hedge instruments.
\n
The financial disclosure requirements of IFRS 12 for sub-
\n
sidiaries with significant non-controlling interests are re-
\n
ported below.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n\n

\n\n
Millions of
\n
euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
29,600 28,959 5,430 4,711 35,030 33,670
\n
Enel Chile
\n
10,985 9,887 1,541 (642) 12,526 9,245
\n
Endesa
\n
45,018 43,217 11,166 3,853 56,184 47,070
\n
Millions of
\n
euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable to
\n
owners of the Parent
\n
Non-controlling
\n
interests
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
11,534 11,320 6,208 6,073 17,742 17,393 17,288 16,277 12,136 11,556 5,152 4,721
\n
Enel Chile
\n
4,113 3,356 2,460 1,178 6,573 4,534 5,953 4,711 3,683 2,921 2,270 1,790
\n
Endesa
\n
18,414 15,196 17,372 11,449 35,786 26,645 20,398 20,425 15,083 15,187 5,315 5,238
\n
Millions of
\n
euro Total revenue Pre-tax profit
\n
Profit from continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable to non-
\n
controlling interests
\n
2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
14,696 13,581 1,015 1,516 221 757 (90) 337 311 420
\n
Enel Chile
\n
6,450 3,114 1,971 128 1,458 104 913 57 545 47
\n
Endesa
\n
32,714 20,217 3,055 769 2,244 589 1,534 396 710 193
\n

\n\n

\n\n

\n\n

\n\n\n
38. Borrowings
\n
Millions of euro Non-current Current
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Long-term borrowings 68,191 54,500 2,835 4,031
\n
Short-term borrowings - - 18,392 13,306
\n
Tot al 68,191 54,500 21,227 17,337
\n
For more information on the nature of borrowings, see
\n
note 48 \u201cFinancial instruments by category\u201d.
\n

\n\n

\n\n

\n\n
39. Employee benefits \u2013 \u20ac2,202 million
\n
The Group provides its employees with a variety of bene-
\n
fits, including deferred compensation benefits, additional
\n
months\u2019 pay for having reached age limits or eligibility for
\n
old-age pension, loyalty bonuses for achievement of se-
\n
niority milestones, supplemental retirement and health-
\n
care plans, residential electricity discounts and similar
\n
benefits. More specifically:
\n
\u2022 for Italy, the item \u201cPension benefits\u201d regards estimated
\n
accruals made to cover benefits due under the supple-
\n
mental retirement schemes of retired executives and the
\n
benefits due to personnel under law or contract at the
\n
time the employment relationship is terminated. For the
\n
foreign companies, the item refers to post-employment
\n
benefits, of which the most material regard the pension
\n
benefit schemes of Endesa in Spain, which break down
\n
into three types that differ on the basis of employee se-
\n
niority and company. In general, under the framework
\n
agreement of October 25, 2000, employees participate
\n
in a specific defined contribution pension plan and, in
\n
cases of disability or death of employees in service, a de-
\n
fined benefit plan which is covered by appropriate insur-
\n
ance policies. In addition, the group has two other lim-
\n
ited-enrollment plans (i) for current and retired Endesa
\n
employees covered by the electricity industry collective
\n
bargaining agreement prior to the changes introduced
\n
with the framework agreement noted earlier and (ii) for
\n
employees of the Catalan companies merged in the past
\n
(Fecsa/Enher/HidroEmpord\u00e0). Both are defined benefit
\n
plans and benefits are fully ensured, with the exception
\n
of the former plan for benefits in the event of the death
\n
of a retired employee. Finally, the Brazilian companies
\n
have also established defined benefit plans;
\n
\u2022 the item \u201cElectricity discount\u201d comprises benefits re-
\n
garding electricity supply associated in particular with
\n
foreign companies;
\n
\u2022 the item \u201cHealth insurance\u201d refers to benefits for current
\n
or retired employees covering medical expenses;
\n
\u2022 the item \u201cOther benefits\u201d mainly regards the loyalty bo-
\n
nus, which is adopted in various countries and for Italy
\n
is represented by the estimated liability for the benefit
\n
entitling employees covered by the electricity workers
\n
national collective bargaining agreement to a bonus for
\n
achievement of seniority milestones (25th and 35th year
\n
of service). It also includes other incentive plans, which
\n
provide for the award to certain Company managers of a
\n
monetary bonus subject to specified conditions.
\n
The following table reports changes in the defined benefit
\n
obligation for post-employment and other long-term em-
\n
ployee benefits at December 31, 2022, and December 31,
\n
2021, respectively, as well as a reconciliation of that obliga-
\n
tion with the actuarial liability.
\n

\n\n

\n\n

\n\n
Millions of euro 2022 2021
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Total
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Total
\n
CHANGES IN ACTUARIAL
\n
OBLIGATION
\n
Change in actuarial obligation
\n
previous year
\n
Actuarial obligation at the
\n
start of the year
\n
4,240 410 206 190 5,046 4,408 403 217 222 5,250
\n
Current service cost 13 1 5 13 32 17 2 4 28 51
\n
Interest expense 320 7 8 5 340 214 3 7 3 227
\n
Actuarial (gains)/losses arising
\n
from changes in demographic
\n
assumptions
\n
- - - - - 192 - (6) - 186
\n
Actuarial (gains)/losses arising
\n
from changes in financial
\n
assumptions
\n
(533) (93) (38) (18) (682) (664) (14) 6 (1) (673)
\n
Experience adjustments 119 (80) 8 1 48 452 31 (9) - 474
\n
Past service cost (3) - - - (3) (17) - - (3) (20)
\n
(Gains)/Losses arising from
\n
settlements
\n
(163) - - - (163) (4) - - - (4)
\n
Exchange differences 335 - 6 (1) 340 14 (1) (1) - 12
\n
Employer contributions - - - - - - - - - -
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (470) (15) (13) (44) (542) (379) (15) (12) (58) (464)
\n
Other changes - - - (6) (6) 7 1 - (1) 7
\n
Reclassification to assets 8 - - - 8 - - - - -
\n
Liabilities included in disposal
\n
groups classified as held for
\n
sale
\n
(101) (6) (20) (22) (149) - - - - -
\n
Actuarial obligation at year-
\n
end (A)
\n
3,765 224 162 118 4,269 4,240 410 206 190 5,046
\n
CHANGES IN PLAN ASSETS
\n
Fair value of plan assets at the
\n
start of the year
\n
2,348 - - - 2,348 2,299 - - - 2,299
\n
Interest income 193 - - - 193 121 - - - 121
\n
Expected return on plan assets
\n
excluding amounts included in
\n
interest income
\n
(184) - - - (184) 38 - - - 38
\n
Exchange differences 213 - - - 213 17 - - - 17
\n
Employer contributions 286 15 13 22 336 252 15 12 28 307
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (470) (15) (13) (22) (520) (379) (15) (12) (28) (434)
\n
Other payments (163) - - - (163) - - - - -
\n
Changes in the consolidation
\n
scope
\n
(99) - - - (99) - - - - -
\n
Fair value of plan assets at
\n
year-end (B)
\n
2,124 - - - 2,124 2,348 - - - 2,348
\n
EFFECT OF ASSET CEILING
\n
Asset ceiling at the start of
\n
the year
\n
26 - - - 26 13 - - - 13
\n
Interest income 2 - - - 2 1 - - - 1
\n
Changes in asset ceiling 27 - - - 27 12 - - - 12
\n
Exchange differences 2 - - - 2 - - - - -
\n
Changes in the consolidation
\n
scope
\n
----- -----
\n
Asset ceiling at year-end (C) 57 - - - 57 26 - - - 26
\n
Net liability in statement of
\n
financial position (A-B+C)
\n
1,698 224 162
\n
118 2,202 1,918 410 206 190 2,724
\n

\n\n

\n\n

\n\n
The liability recognized came to \u20ac2,202 million, a decrease
\n
of \u20ac522 million on 2021. Change in 2022 reflects the re-
\n
classification as held for sale of the actuarial liabilities of
\n
Enel Generaci\u00f3n Costanera SA and Central Dock Sud SA
\n
in Argentina, 3SUN Srl in Italy, all the companies in Roma-
\n
nia and Greece and PJSC Enel Russia and its subsidiaries,
\n
the latter sold in the last quarter of 2022. Furthermore, the
\n
actuarial measurement of a plan of Asociaci\u00f3n Nuclear As-
\n
c\u00f3-Vandell\u00f3s II AIE in Spain showed a surplus with respect
\n
to the obligation assumed by the company, and was thus
\n
reclassified in a specific asset item of the balance sheet.
\n
Millions of euro
\n
2022 2021
\n
(Gains)/Losses taken to profit or loss
\n
Service cost and past service cost 22 9
\n
Net interest expense 149 107
\n
(Gains)/Losses arising from settlements - (4)
\n
Actuarial (gains)/losses on other long-term benefits 722
\n
Other changes (20) 1
\n
Tot al 158 135
\n
Millions of euro
\n
2022 2021
\n
Change in (gains)/losses in OCI
\n
Expected return on plan assets excluding amounts included in interest income 184 (38)
\n
Actuarial (gains)/losses on defined benefit plans (614) (13)
\n
Changes in asset ceiling excluding amounts included in interest income 27 12
\n
Other changes - (1)
\n
Tot al (403) (40)
\n
The change in the cost recognized in profit or loss was
\n
equal to \u20ac23 million. The impact on the income statement
\n
is, therefore, greater but essentially in line with 2021.
\n
The liability recognized in the statement of financial posi-
\n
tion at the end of the year is reported net of the fair value
\n
of plan assets, amounting to \u20ac2,124 million at December
\n
31, 2022. Those assets, which are entirely in Spain and Bra-
\n
zil, break down as follows:
\n
2022 2021
\n
Investments quoted in active markets
\n
Equity instruments 10% 8%
\n
Fixed-income securities 66% 54%
\n
Investment property 3% 3%
\n
Other 21% -
\n
Unquoted investments
\n
Assets held by insurance undertakings --
\n
Other - 35%
\n
Tot al 100% 100%
\n
The main actuarial assumptions used to calculate the lia-
\n
bilities in respect of employee benefits and the plan assets,
\n
which are consistent with those used the previous year, are
\n
set out in the following table.
\n

\n\n

\n\n

\n\n
Italy Iberia Latin America
\n
Other
\n
countries Italy Iberia Latin America
\n
Other
\n
countries
\n
2022 2021
\n
Discount rate
\n
3.60%-
\n
3.70%
\n
3.57%-3.77% 5.40%-10.40% 3.75%-7.65%
\n
0.00%-
\n
0.80%
\n
0.00%-1.16% 5.60%-9.67%
\n
0.80%-
\n
8.40%
\n
Inflation rate 2.30% 2.78% 3.00%-8.00%
\n
2.40%-
\n
3.50%
\n
1.50% 2.20% 3.00% -8.00%
\n
1.50%-
\n
4.01%
\n
Rate of wage
\n
increases
\n
2.30%-
\n
4.30%
\n
2.78% 3.80%-8.49%
\n
3.00%
\n
-10.00%
\n
0.80%-
\n
1.80%
\n
2.20% 3.80%-8.00%
\n
2.50%-
\n
10.00%
\n
Rate of increase in
\n
healthcare costs
\n
3.30% 4.98% 7.12%-10.00% - 2.50% 4.40% 7.12%-8.00% -
\n
Expected rate of
\n
return on plan assets
\n
- 3.76%-3.77% 10.40% 7.40% - 0.57% 9.30% -9.46% -
\n
The following table reports the outcome of a sensitivity
\n
analysis that demonstrates the effects on the defined ben-
\n
efit obligation of changes reasonably possible at the end
\n
of the year in the actuarial assumptions used in estimating
\n
the obligation.
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Pension benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance Other benefits
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Decrease of 0.5%
\n
in discount rate
\n
185 2 6 (17) 225 27 11 -
\n
Increase of 0.5% in
\n
discount rate
\n
(118) (22) (9) (23) (184) (30) (14) (10)
\n
Increase of 0.5% in
\n
inflation rate
\n
16 (11) (8) (21) 2 (4) (2) (6)
\n
Decrease of 0.5%
\n
in inflation rate
\n
37 (10) 6 (16) 28 (2) 9 (2)
\n
Increase of 0.5% in
\n
remuneration
\n
29 (10) (2) (17) 14 (3) (2) -
\n
Increase of 0.5% in
\n
pensions currently
\n
being paid
\n
28 (10) (2) (20) 14 (3) (2) (5)
\n
Increase of 1% in
\n
healthcare costs
\n
- - (147) - - - 20 1
\n
Increase of 1 year
\n
in life expectancy
\n
of active and
\n
retired employees
\n
55 (9) 5 (17) 98 (3) 14 (5)
\n
The sensitivity analysis used an approach that extrapolates
\n
the effect on the defined benefit obligation of reasonable
\n
changes in an individual actuarial assumption, leaving the
\n
other assumptions unchanged.
\n
The contributions expected to be paid into defined benefit
\n
plans in the subsequent year amount to \u20ac221 million.
\n
The following table reports expected benefit payments in
\n
the coming years for defined benefit plans.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Within 1 year 427 392
\n
In 1-2 years 397 364
\n
In 2-5 years 1,124 1,077
\n
More than 5 years 1,826 1,714
\n
Expected payments are increasing in general. This is main-
\n
ly due to Brazil and Argentina.
\n

\n\n

\n\n

\n\n
40. Provisions for risks and charges \u2013 \u20ac7,380 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Non-current Current Total Non-current Current Total
\n
Provision for litigation, risks and other charges:
\n
- nuclear decommissioning 581 - 581 666 - 666
\n
- site retirement, removal and restoration 2,686 247 2,933 3,066 203 3,269
\n
- litigation 652 51 703 790 44 834
\n
- environmental certificates - 292 292 - 32 32
\n
- taxes and duties 313 26 339 267 28 295
\n
- other 803 316 1,119 821 347 1,168
\n
Total 5,035 932 5,967 5,610 654 6,264
\n
Provision for early retirement incentives and other
\n
restructuring plans
\n
231 192 423 435 293 728
\n
Provision for restructuring programs connected with
\n
the energy transition
\n
789 201 990 1,152 179 1,331
\n
TOTAL 6,055 1,325 7,380 7,197 1,126 8,323
\n
Millions of euro Accrual Reversal Utilization
\n
Discoun-
\n
ting
\n
Provisions
\n
for site reti-
\n
rement and
\n
restoration
\n
Change in
\n
consolida-
\n
tion scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
Reclassifications
\n
of liabilities
\n
included in
\n
disposal groups
\n
held for sale
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Provision for litigation,
\n
risks and other charges:
\n
- nuclear
\n
decommissioning
\n
666 - - - 8 (93) - - - - 581
\n
- site retirement, removal
\n
and restoration
\n
3,269 201 (135) (167) (12) (207) (2) 16 (1) (29) 2,933
\n
- litigation 834 239 (123) (162) 59 - - 42 35 (221) 703
\n
- environmental
\n
certificates
\n
32 345 (24) (8) - - - - (35) (18) 292
\n
- taxes and duties 295 45 (30) (10) 8 - 8 10 13 - 339
\n
- other 1,168 375 (79) (309) 11 (2) 39 (3) (38) (43) 1,119
\n
Total 6,264 1,205 (391) (656) 74 (302) 45 65 (26) (311) 5,967
\n
Provision for early
\n
retirement incentives
\n
and other restructuring
\n
plans
\n
728 4 (32) (244) (26) - - - (4) (3) 423
\n
Provision for
\n
restructuring programs
\n
connected with the
\n
energy transition
\n
1,331 51 (177) (157) (51) - - 2 (4) (5) 990
\n
TOTAL 8,323 1,260 (600) (1,057) (3) (302) 45 67 (34) (319) 7,380
\n
Nuclear decommissioning provision
\n
At December 31, 2022 the provision reflected solely the
\n
costs that would be incurred at the time of decommis-
\n
sioning of nuclear plants by Enresa, a Spanish public entity
\n
responsible for such activities in accordance with Royal
\n
Decree 1349/2003 and Law 24/2005. In general, the costs
\n
are quantified on the basis of a standard contract between
\n
Enresa and the electricity companies approved by the
\n
Ministry for the Economy in September 2001, which reg-
\n
ulates the retirement and closing of nuclear power plants.
\n
The time horizon envisaged, three years, corresponds to
\n
the period from the termination of power generation to
\n
the transfer of plant management to Enresa (so-called
\n
post-operational costs) and takes account, among the
\n
various assumptions used to estimate the amount, of the
\n
quantity of unused nuclear fuel expected at the date of
\n
closure of each of the Spanish nuclear plants on the basis
\n
of the provisions of the concession agreement.
\n
Site retirement, removal and restoration
\n
provision
\n
This provision represents the present value of the esti-
\n
mated cost for the retirement and removal of non-nuclear
\n
plants where there is a legal or constructive obligation to
\n
do so. The provision mainly regarded the Endesa Group
\n
and Enel Produzione. The change in the provision in 2022
\n

\n\n

\n\n

\n\n

\n
was mainly linked to the redetermination of the future re-
\n
tirement costs of certain plants in Iberia and North America
\n
as well as the uses and releases of provisions set aside in
\n
previous years to deal with the decarbonization process.
\n
The following table summarizes the temporal breakdown
\n
of payments connected with the site retirement, removal
\n
and restoration provision.
\n
Millions of euro
\n
Payments by time bracket
\n
(nominal value) Discounted amount
\n
Within 1 year 248 247
\n
In 1-5 years 1,221 1,134
\n
More than 5 years 2,275 1,552
\n
Tot al 3,744 2,933
\n
Litigation provision
\n
The litigation provision covers contingent liabilities in re-
\n
spect of pending litigation and other disputes. It includes
\n
an estimate of the potential liability relating to disputes
\n
that arose during the year, as well as revised estimates of
\n
the potential costs associated with disputes initiated in
\n
prior years, based on the indications of internal and exter-
\n
nal consultants. The balance for litigation mainly regards
\n
the companies in Latin America (\u20ac395 million), Spain (\u20ac169
\n
million) and Italy (\u20ac127 million).
\n
The decrease compared with the previous year, equal to
\n
\u20ac131 million, mainly reflects the decrease in the provision
\n
in Brazil following the deconsolidation of Celg-D.
\n
Provision for environmental certificates
\n
The provision for environmental certificates covers costs in
\n
respect of shortfalls in the environmental certificates need
\n
for compliance with national or supranational environ-
\n
mental protection requirements and mainly regards Iberia
\n
(Endesa Energ\u00eda and Endesa Generaci\u00f3n SA).
\n
Provision for taxes and duties
\n
The provision for taxes and duties covers the estimated
\n
liability deriving from tax disputes concerning direct and
\n
indirect taxes.
\n
The balance of the provision also includes the provision for
\n
current and potential disputes concerning local proper-
\n
ty tax (whether the Imposta Comunale sugli Immobili (ICI)
\n
or the Imposta Municipale Unica (IMU)) in Italy. In Italy, the
\n
Group has taken due account of developments in land
\n
registry regulations (which with effect from January 1, 2016
\n
excluded machinery, devices, equipment and other plant
\n
specific to a production process from the calculation of
\n
the imputed rent for buildings classified in land registry
\n
group D, which includes generation plants) in estimating
\n
the liability for such taxes, both for the purposes of quan-
\n
tifying the probable risk associated with pending litigation
\n
and generating a reasonable valuation of probable future
\n
charges on positions that have not yet been assessed by
\n
the Revenue Agency and municipalities.
\n\n
Other provisions
\n
Other provisions cover various risks and charges, mainly
\n
in connection with regulatory disputes and disputes with
\n
local authorities regarding various duties and fees or other
\n
charges.
\n
The decrease of \u20ac49 million in other provisions is mainly
\n
attributable to Enel Global Trading for uses of provisions
\n
for insurance compensation.
\n

\n\n
Provision for early retirement incentives and
\n
other restructuring plans
\n
The provision for early retirement incentives and other
\n
restructuring plans includes the estimated charges relat-
\n
ed to binding agreements for the voluntary termination
\n
of employment contracts in response to organizational
\n
needs. The reduction of \u20ac305 million for the year main-
\n
ly reflects uses of provisions for incentives established in
\n
previous period in Spain (Acuerdo de Salida Voluntaria) and
\n
Italy to cover the early termination of employment for cer-
\n
tain employees.
\n
Provision for restructuring programs
\n
connected with the energy transition
\n
Enel, in its role as a leader of the energy transition, has
\n
placed decarbonization and growth of renewables around
\n
the world at the center of its strategy.
\n
In this context, Enel has begun restructuring the activities
\n
associated with the energy transition process, which in-
\n
volves thermal generation plants in all the geographical ar-
\n
eas in which the Group operates. The consequent revision
\n
of processes and operating models will require changes in
\n
the roles and skills of employees, which the Group intends
\n
to implement with highly sustainable plans based on re-
\n
deployment programs, with major upskilling and reskilling
\n
plans and voluntary individual early retirement agreements.
\n
The energy transition is also based on the progressive and
\n
expansive development of digital tools, as digitization is
\n
essential to responding to multiple external forces and
\n
making informed and well-considered decisions at every
\n
level within the Group.
\n

\n\n

\n\n

\n

\n

\n

\n\n
A provision was therefore established in 2020 for restruc-
\n
turing programs, which at December 31, 2022 amounted
\n
to \u20ac990 million, which is mainly attributable to Spain and
\n
Italy, and represents the estimated costs that the Group
\n
will incur following the acceleration of the energy transi-
\n
tion, for all direct and indirect activities related to the re-
\n
view of processes and operating models and the roles and
\n
skills of employees.
\n

\n\n\n
41. Other non-current financial liabilities \u2013 \u20ac - million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Other non-current financial liabilities - 120 (120) -
\n
Tot al - 120 (120) -
\n
The change in \u201cOther non-current financial liabilities\u201d came
\n
to \u20ac120 million and regards the decrease in the non-cur-
\n
rent portion of liabilities in respect of the Spanish electrical
\n
system deficit, which were included in net financial debt.
\n

\n\n\n

\n\n

\n\n

\n
42. Other non-current liabilities \u2013 \u20ac4,246 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued operating expenses and deferred income 347 498 (151) -30.3%
\n
Other items 3,899 4,027 (128) -3.2%
\n
Tot al 4,246 4,525 (279) -6.2%
\n

\n\n
The change in \u201cOther items\u201d reflected the decrease of \u20ac45
\n
million in \u201cOther tax liabilities beyond 12 months\u201d, as well as
\n
the decrease of \u20ac351 million in \u201cOther liabilities\u201d relating to
\n
the outcome of the PIS/COFINS dispute in Brazil (already
\n
discussed under \u201cOther non-current assets\u201d), only partially
\n
offset by the increase of \u20ac323 million in \u201cLiabilities for tax
\n
partnerships\u201d in North America.
\n

\n\n

\n\n

\n\n\n

\n\n

\n\n

\n
43. Other current liabilities \u2013 \u20ac11,713 million
\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n\n

\n\n
The change in \u201cOther current liabilities\u201d mainly reflects:
\n
\u2022 the decrease in \u201cAmounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, with the decrease
\n
in amounts due to the Energy and Environmental Ser-
\n
vices Fund, determined by the update of rate in force for
\n
2022 with the Regulatory Authority for Energy, Networks
\n
and Environment (ARERA) Resolutions no. 35/2022,
\n
141/2022, 295/2022 and 462/2022, which complete-
\n
ly zeroed system charges rates for all types of users as
\n
from January 1, 2022;
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n\n

\n\n

\n\n
\u2022 the decrease in \u201cOther tax liabilities\u201d, mainly attributable
\n
to Italy following the start in 2021 of the Group settlement
\n
mechanism for VAT obligations by the Parent, Enel SpA;
\n

\n\n
\u2022 the decrease in \u201cOther liabilities\u201d, mainly attributable to
\n
Italy in respect of expired derivatives on energy com-
\n
modities.
\n

\n\n

\n\n

\n\n\n
44. Trade payables \u2013 \u20ac17,641 million
\n
The item amounted to \u20ac17,641 million (\u20ac16,959 million at
\n
December 31, 2021) and includes payables in respect of
\n
electricity supplies, fuel, materials, equipment associated
\n
with tenders, and other services.
\n
More specifically, trade payables falling due in less than 12
\n
months amounted to \u20ac17,605 million (\u20ac16,865 million at
\n
December 31, 2021), while those falling due in more than
\n
12 months amounted to \u20ac36 million (\u20ac94 million at De-
\n
cember 31, 2021).
\n

\n\n\n
45. Other current financial liabilities \u2013 \u20ac853 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued financial expense and deferred financial income 710 539 171 31.7%
\n
Other items 143 86 57 66.3%
\n
Tot al 853 625 228 36.5%
\n
The increase in other current financial liabilities is mainly
\n
attributable to the increase of \u20ac171 million in accrued fi-
\n
nancial expense and deferred financial income, as a result
\n
of higher accrued expenses on bond issues.
\n
Other items mainly regard liabilities for accrued interest.
\n

\n\n

\n\n
\n
Information on the consolidated statement of cash flows
\n\n
46. Cash flows
\n
Millions of euro
\n
2022 2021 Change
\n
Cash and cash equivalents at the beginning of the year
\n
(1)
\n
8,990 6,002 2,988
\n
Cash flows from operating activities
\n
(2)
\n
8,674 9,915 (1,241)
\n
of which discontinued operations (391) 280
\n
Cash flows from/(used in) investing activities (13,626) (10,875) (2,751)
\n
of which discontinued operations (351) (453)
\n
Cash flows from financing activities
\n
(2)
\n
7,369 3,931 3,438
\n
of which discontinued operations 656 118
\n
Impact of exchange rate fluctuations on cash and cash equivalents 136 17 119
\n
Cash and cash equivalents at the end of the year
\n
(3)
\n
11,543 8,990 2,553
\n
(1) Of which cash and cash equivalents equal to \u20ac8,315 million at January 1, 2022 (\u20ac5,266 million at January 1, 2021), short-term securities equal to \u20ac88 million
\n
at January 1, 2022 (\u20ac67 million at January 1, 2021) and cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of \u20ac44 million at January
\n
1, 2022 (\u20ac29 million at January 1, 2021) and cash and cash equivalents pertaining to \u201cdiscontinued operations\u201d equal to \u20ac543 million at January 1, 2022 (\u20ac640
\n
million at January 1, 2021).
\n
(2) In order to improve presentation, for comparative purposes only, realized financial income and expense connected solely with loans in currencies have been reclas-
\n
sified under a new item \u201cCollections/(Payments) associated with derivatives connected with borrowings\u201d in the section on cash flows from financing activities.
\n
(3) Of which cash and cash equivalents equal to \u20ac11,041 million at December 31, 2022 (\u20ac8,315 million at December 31, 2021), short-term securities equal to
\n
\u20ac78 million at December 31, 2022 (\u20ac88 million at December 31, 2021) and cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of
\n
\u20ac98 million at December 31, 2022 (\u20ac44 million at December 31, 2021) and to \u201cdiscontinued operations\u201d equal to \u20ac326 million at December 31, 2022 (\u20ac543
\n
million at December 31, 2021).
\n
Cash flows from operating activities in 2022 was a posi-
\n
tive \u20ac8,674 million, a decrease of \u20ac1,241 million on 2021,
\n
mainly attributable to increased cash requirements con-
\n
nected with changes in net working capital.
\n
Cash flows used in investing activities in 2022 came to
\n
\u20ac13,626 million, from \u20ac10,875 million in 2021.
\n
More specifically, investments in property, plant and equip-
\n
ment, intangibles, property investment and contract assets
\n
came to \u20ac14,503 million (including \u20ac156 million classified
\n
as available for sale), an increase on 2021.
\n
Investments in companies or business units, net of cash
\n
and cash equivalents acquired, amount to \u20ac1,275 million
\n
and mainly refer to the acquisition by Enel Produzione SpA
\n
of 100% of ERG Hydro Srl (now Enel Hydro Appennino Cen-
\n
trale Srl), for \u20ac1,196 million net of cash and cash equiva-
\n
lents acquired of \u20ac69 million.
\n
Disposals of businesses or business units, net of cash and
\n
cash equivalents sold, amount to \u20ac2,032 million and mainly
\n
refer to:
\n
\u2022 the sale by EGP SpA to Al Rayyan Holding LLC (controlled
\n
by the Qatar Investment Authority) of a 50% interest in
\n
EGP Matimba NewCo 1 Srl, indirect owner of six projects
\n
in South Africa (for \u20ac102 million net of cash and cash
\n
equivalents sold of \u20ac6 million);
\n
\u2022 the sale by Enel X Germany of the entire interest held in
\n
Cremzow KG and Cremzow Verwaltungs (for \u20ac8 million
\n
net of cash and cash equivalents sold of \u20ac4 million);
\n
\u2022 the sale by Enel Brasil SA of the entire interest held in
\n
CGTF - Central Geradora Termel\u00e9trica Fortaleza SA (for
\n
\u20ac29 million net of cash and cash equivalents sold of \u20ac60
\n
million);
\n
\u2022 the sale of the entire interest held in Enel SpA in PJSC
\n
Enel Russia, equal to 56.43% of the share capital of the
\n
latter, to PJSC Lukoil and Closed Combined Mutual In-
\n
vestment Fund \u201cGazprombank-Frezia\u201d (for \u20ac20 million
\n
net of cash and cash equivalents sold of \u20ac117 million);
\n
\u2022 the sale of the entire interest held by Enel Chile SA in
\n
Chilean power transmission company Enel Transmisi\u00f3n
\n
Chile SA, to Sociedad Transmisora Metropolitana SpA,
\n
controlled by Inversiones Grupo Saesa Ltda, for a total
\n
consideration of \u20ac1,342 million;
\n
\u2022 the sale of a 50% quota in its wholly-owned subsidiary
\n
Gridspertise Srl, to the international private equity fund
\n
CVC Capital Partners Fund VIII, for \u20ac272 million net of
\n
cash and cash equivalents sold of \u20ac27 million;
\n
\u2022 the sale of the entire interest held by Enel Am\u00e9ricas in
\n
the Brazilian electricity distribution company Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), equal to 99.9% of the
\n
share capital of the latter, to Equatorial Participa\u00e7\u00f5es e
\n
Investimentos SA, controlled by Equatorial Energia SA,
\n
for a total consideration of \u20ac259 million net of cash and
\n
cash equivalents sold of \u20ac10 million.
\n
Cash flows from/(used in) other investing activities in 2022
\n
came to 120 million and mainly reflects:
\n
\n\n
\n\n

\n

\n\n
\u2022 the sale of a 1.1% interest held by Enel X International in
\n
Ufinet, for \u20ac73 million;
\n
\u2022 the sale by Enel Kansas LLC of a 50% interest held in
\n
Rocky Caney Holdings LLC and EGPNA Renewable Ener-
\n
gy Partners for \u20ac94 million;
\n
\u2022 the acquisition of 50% of the share capital of Mooney for
\n
\u20ac225 million;
\n
\u2022 the sale by Enel Green Power Canada Inc. of a 49% in-
\n
terest held in Pincher Creek LP and Riverview LP for \u20ac56
\n
million;
\n
\u2022 minor disposals mainly in Italy, Iberia, North America and
\n
Latin America.
\n
Cash flows from financing activities came to a total \u20ac7,369
\n
million, from \u20ac3,931 million used in 2021, mainly reflecting:
\n
\u2022 the net increase as the balance between repayments,
\n
new borrowings and other changes in financial payables
\n
for \u20ac12,420 million;
\n
\u2022 distribution of dividends in the amount of \u20ac4,901 mil-
\n
lion, plus \u20ac123 million paid to holders of perpetual hybrid
\n
bonds;
\n
\u2022 capital increases in subsidiaries with non-controlling in-
\n
terests for \u20ac12 million, particularly in Australia.
\n
In 2022, cash flows used in investing activities in the
\n
amount of \u20ac13,626 million fully absorbed the cash flows
\n
from operating activities for \u20ac8,674 million, with the dif-
\n
ference coming from financing activities in the amount of
\n
\u20ac7,369 million. The difference is reflected in an increase
\n
in cash and cash equivalents at December 31, 2022 to
\n
\u20ac11,543 million, from \u20ac8,990 million at the end of 2021.
\n
The change was also affected by effects associated with
\n
the positive developments in the exchange rates of local
\n
currencies against the euro, in the amount of \u20ac136 million.
\n

\n\n\n
47. Net financial position and long-term financial assets and securities
\n
\u2013 \u20ac60,068 million
\n
The following table shows the net financial position and
\n
long-term financial assets and securities on the basis of
\n
the items on the statement of consolidated financial po-
\n
sition.
\n
Millions of euro
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Change
\n
Long-term borrowings 38 68,191 54,500 13,691 25.1%
\n
Other non-current financial borrowings
\n
(1)
\n
41 - 120 (120) -
\n
Short-term borrowings 38 18,392 13,306 5,086 38.2%
\n
Other current financial borrowings
\n
(2)
\n
-12(12) -
\n
Current portion of long-term borrowings 38 2,835 4,031 (1,196) -29.7%
\n
Other non-current financial assets included in net financial debt 29.1 (4,213) (2,692) (1,521) -56.5%
\n
Other current financial assets included in net financial debt 30.1 (13,501) (8,467) (5,034) -59.5%
\n
Cash and cash equivalents 35 (11,041) (8,858) (2,183) -24.6%
\n
Net exchange rate derivatives associated with borrowings
\n
(3)
\n
(595) (259) (336) -
\n
Tot al
\n
(3)
\n
60,068 51,693 8,375 16.2%
\n
(1) The item \u201cOther non-current financial borrowings\u201d is represented by \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(2) The item \u201cOther current financial borrowings\u201d is included under \u201cOther current financial liabilities\u201d in the statement of financial position.
\n
(3) In order to improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\n
The financial position is reported in compliance with Guide-
\n
line 39, issued on March 4, 2021 by ESMA and applicable
\n
as from May 5, 2021, and with warning notice no. 5/2021
\n
issued by CONSOB on April 29, 2021, which replaced the
\n
references to the CESR Recommendations and the ref-
\n
erences in Communication no. DEM/6064293 of July 28,
\n
2006 regarding the net financial position.
\n
The net financial debt of the Enel Group at December 31,
\n
2022 and December 31, 2021 is reconciled with net finan-
\n
cial debt as provided for in the presentation methods of
\n
the Enel Group.
\n

\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Liquidity
\n
Cash and cash equivalents on hand 35 8 27 -
\n
Bank and post office deposits 8,968 8,118 850 10.5%
\n
Liquid assets 9,003 8,126 877 10.8%
\n
Cash equivalents 2,038 732 1,306 -
\n
Securities 78 88 (10) -11.4%
\n
Short-term loan assets 10,585 6,841 3,744 54.7%
\n
Current portion of long-term loan assets 2,838 1,538 1,300 84.5%
\n
Other current financial assets 13,501 8,467 5,034 59.5%
\n
Liquidity 24,542 17,325 7,217 41.7%
\n
Current financial debt
\n
Bank debt (1,320) (1,329) 9 0.7%
\n
Commercial paper (13,838) (10,708) (3,130) -29.2%
\n
Other short-term borrowings
\n
(1)
\n
(3,234) (1,281) (1,953) -
\n
Current financial debt (including debt instruments) (18,392) (13,318) (5,074) -38.1%
\n
Current portion of long-term bank borrowings (890) (989) 99 10.0%
\n
Bonds issued (current portion) (1,612) (2,700) 1,088 40.3%
\n
Other borrowings (current portion) (333) (342) 9 2.6%
\n
Non-current financial debt (current portion) (2,835) (4,031) 1,196 29.7%
\n
Current financial debt (21,227) (17,349) (3,878) -22.4%
\n
Net current financial debt 3,315 (24) 3,339 -
\n
Non-current financial debt
\n
Bank borrowings (15,261) (12,579) (2,682) -21.3%
\n
Other borrowings
\n
(2)
\n
(2,851) (2,942) 91 3.1%
\n
Non-current financial debt (excluding current portion and debt
\n
instruments)
\n
(18,112) (15,521) (2,591) -16.7%
\n
Bonds (50,079) (39,099) (10,980) -28.1%
\n
Trade payables and other non-interest-bearing non-current liabilities with
\n
a significant financing component
\n
----
\n
Non-current financial position (68,191) (54,620) (13,571) -24.8%
\n
Financial assets in respect of \u201cAssets classified as held for sale\u201d 543 85 458 -
\n
Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
(1,435) (784) (651) -83.0%
\n
Net financial position as per CONSOB instructions (65,768) (55,343) (10,425) -18.8%
\n
Long-term financial receivables and securities 4,213 2,692 1,521 56.5%
\n
Net exchange rate derivatives associated with borrowings
\n
(3)
\n
595 259 336 -
\n
( - ) Financial assets in respect of \u201cAssets classified as held for sale\u201c (543) (85) (458) -
\n
( - ) Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
1,435 784 651 83.0%
\n
NET FINANCIAL DEBT
\n
(3)
\n
(60,068) (51,693) (8,375) -16.2%
\n
(1) Includes current financial borrowings included in \u201cOther current financial liabilities\u201d in the statement of financial position.
\n
(2) Includes other non-current financial borrowings presented under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(3) In order to improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\n

\n\n

\n\n

\n

\n\n
The net position as per CONSOB instructions does not
\n
include derivatives designated as hedges for hedge ac-
\n
counting purposes or entered into for trading purposes as
\n
they are used for hedging.
\n
At December 31, 2022, those financial assets and liabili-
\n
ties are reported separately in the statement of financial
\n
position under the following items: \u201cNon-current financial
\n
derivative assets\u201d in the amount of \u20ac3,970 million (\u20ac2,772
\n
million at December 31, 2021), \u201cCurrent financial derivative
\n
assets\u201d in the amount of \u20ac14,830 million (\u20ac22,791 million
\n
at December 31, 2021), \u201cNon-current financial derivative
\n
liabilities\u201d in the amount of \u20ac5,895 million (\u20ac3,339 million
\n
at December 31, 2021), and \u201cCurrent financial derivative li-
\n
abilities\u201d in the amount of \u20ac16,141 million (\u20ac24,607 million
\n
at December 31, 2021).
\n
Furthermore, for the purpose of better representing the
\n
Enel Group\u2019s net financial debt, it includes the fair value of
\n
the cross currency swaps entered into to hedge foreign
\n
currency loans to external counterparties. For more infor-
\n
mation on the classification of such derivatives, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n
Financial instruments
\n\n

\n
48. Financial instruments by category
\n
This note provides disclosures necessary for users to
\n
assess the significance of financial instruments for the
\n
Group\u2019s financial position and performance.
\n\n
48.1 Financial assets by category
\n
The following table reports the carrying amount for each
\n
category of financial asset provided for under IFRS 9, bro-
\n
ken down into current and non-current financial assets,
\n
showing hedging derivatives and derivatives measured at
\n
fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Financial assets at amortized cost 48.1.1 5,731 4,092 40,057 34,671
\n
Financial assets at FVOCI 48.1.2 901 706 279 144
\n
Financial assets at fair value through profit or loss
\n
Derivative financial assets at FVTPL 48.1.3 473 277 12,075 19,664
\n
Other financial assets at FVTPL 48.1.3 3,442 2,662 1,049 141
\n
Total financial assets at fair value through profit or loss 3,915 2,939 13,124 19,805
\n
Derivative financial assets designated as hedging instruments
\n
Fair value hedge derivatives 48.1.4 37 61 - -
\n
Cash flow hedge derivatives 48.1.4 3,460 2,434 2,755 3,127
\n
Total derivative financial assets designated as hedging instruments 3,497 2,495 2,755 3,127
\n
TOTAL 14,044 10,232 56,215 57,747
\n
For more information on the recognition and classification
\n
of current and non-current derivative assets, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n
For more information on fair value measurement, see note
\n
52 \u201cAssets and liabilities measured at fair value\u201d.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n
48.1.1 Financial assets measured at amortized cost
\n
The following table reports financial assets measured at
\n
amortized cost by nature, broken down into current and
\n
non-current financial assets.
\n\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Cash and cash equivalents - - 35 10,169 8,759
\n
Trade receivables 34 1,388 1,301 34 15,217 14,775
\n
Current portion of long-term loan assets - - 30.1 2,838 1,538
\n
Cash collateral - - 30.1 8,319 6,485
\n
Other financial assets 29.1 3,766 2,289 30.1 2,090 315
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 295 260 29 12 64
\n
Other financial assets at amortized cost 282 242 1,412 2,735
\n
Tot al 5,731 4,092 40,057 34,671
\n

\n\n
Impairment of financial assets at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac45,788 million at December 31, 2022 (\u20ac38,763 million at
\n
December 31, 2021) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,087 million at De-
\n
cember 31, 2022 (\u20ac4,051 million at the end of the previous
\n
year).
\n
The Group mainly has the following types of financial as-
\n
sets measured at amortized cost subject to impairment
\n
testing:
\n
\u2022 cash and cash equivalents;
\n
\u2022 trade receivables and contract assets;
\n
\u2022 loan assets;
\n
\u2022 other financial assets.
\n
While cash and cash equivalents are also subject to the
\n
impairment requirements of IFRS 9, the identified impair-
\n
ment loss was immaterial.
\n\n
The expected credit loss (ECL) \u2013 determined using proba-
\n
bility of default (PD), loss given default (LGD) and exposure
\n
at default (EAD) \u2013 is the difference between all contractual
\n
cash flows that are due in accordance with the contract
\n
and all cash flows that are expected to be received (i.e., all
\n
shortfalls) discounted at the original effective interest rate
\n
(EIR).
\n
For calculating ECL, the Group applies two different ap-
\n
proaches:
\n
\u2022 the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receivables.
\n
This approach, based on an assessment of any signif-
\n
icant increase in credit risk since initial recognition, is
\n
performed comparing the PD at origination with PD at
\n
the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss al-
\n
lowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e., staging):
\n
\u2013 12-month ECL, for financial assets for which there has
\n
not been a significant increase in credit risk since ini-
\n
tial recognition;
\n
\u2013 lifetime ECL, for financial assets for which there has
\n
been a significant increase in credit risk or which are
\n
credit impaired (i.e., defaulted based on past due in-
\n
formation);
\n
\u2022 the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a significant
\n
financing component, based on lifetime ECL without
\n
tracking changes in credit risk.
\n
A forward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
future events and macroeconomic developments that
\n
could impact the risk associated with the portfolio or fi-
\n
nancial instrument.
\n
Depending on the nature of the financial assets and the
\n
credit risk information available, the assessment of the in-
\n
crease in credit risk can be performed on:
\n
\u2022 an individual basis, if the receivables are individually sig-
\n
nificant and for all receivables which have been individ-
\n
ually identified for impairment based on reasonable and
\n
supportable information;
\n
\u2022 a collective basis, if no reasonable and supportable in-
\n
formation is available without undue cost or effort to
\n
measure expected credit losses on an individual instru-
\n
ment basis.
\n
When there is no reasonable expectation of recovering a
\n
financial asset in its entirety or a portion thereof, the gross
\n
carrying amount of the financial asset shall be reduced.
\n
A write-off represents a derecognition event (e.g., the right
\n
to cash flows is legally or contractually extinguished, trans-
\n
ferred or expired).
\n

\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports expected credit losses on fi-
\n
nancial assets measured at amortized cost on the basis of
\n
the general simplified approach.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Gross amount
\n
Expected
\n
credit loss
\n
allowance Total Gross amount
\n
Expected
\n
credit loss
\n
allowance Total
\n
Cash and cash equivalents 10,169 - 10,169 8,759 - 8,759
\n
Trade receivables 20,388 3,783 16,605 19,739 3,663 16,076
\n
Loan assets 17,261 248 17,013 10,861 234 10,627
\n
Other financial assets at amortized cost 2,057 56 2,001 3,455 154 3,301
\n
Total 49,875 4,087 45,788 42,814 4,051 38,763
\n
To measure expected losses, the Group assesses trade re-
\n
ceivables and contract assets with the simplified approach,
\n
both on an individual basis (e.g., government entities, au-
\n
thorities, financial counterparties, wholesale sellers, traders
\n
and large companies, etc.) and a collective basis (e.g., retail
\n
customers).
\n
In the case of individual assessments, PD is generally ob-
\n
tained from external providers.
\n
Otherwise, in the case of collective assessments, trade re-
\n
ceivables are grouped on the basis of their shared credit risk
\n
characteristics and information on past due positions, con-
\n
sidering a specific definition of default.
\n
Based on each business and local regulatory framework, as
\n
well as differences between customer portfolios, including
\n
their default and recovery rates (comprising expectations
\n
for recovery beyond 90 days):
\n
\u2022 the Group mainly defines a defaulted position as one that
\n
is 180 days past due. Accordingly, beyond this time lim-
\n
it, trade receivables are presumed to be credit impaired);
\n
and
\n
\u2022 specific clusters are defined on the basis of specific mar-
\n
kets, business and risk characteristics.
\n
Contract assets substantially have the same risk character-
\n
istics as trade receivables for the same types of contracts.
\n
In order to measure the ECL for trade receivables on a col-
\n
lective basis, as well as for contract assets, the Group uses
\n
the following assumptions regarding the ECL parameters:
\n
\u2022 PD, assumed equal to the average default rate, is calculat-
\n
ed by cluster and considering historical data from at least
\n
24 months;
\n
\u2022 LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022 EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices is-
\n
sued but not past due and invoices to be issued.
\n
Despite the deterioration in the collection status of certain
\n
customer segments, which was taken into consideration in
\n
determining impairment of trade receivables, the Group\u2019s
\n
portfolio has so far demonstrated resilience to the mac-
\n
roeconomic context and the current price scenario. This
\n
reflects the expansion of digital collection channels and a
\n
solid diversification of commercial customers.
\n
The following table reports changes in the allowance for ex-
\n
pected credit losses on loan assets in accordance with the
\n
general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 65 143
\n
Accruals -9
\n
Uses --
\n
Reversals to profit or loss (25) (9)
\n
Other changes 25 26
\n
Closing balance at Dec. 31, 2021 65 169
\n
Opening balance at Jan. 1, 2022 65 169
\n
Accruals 22 5
\n
Uses --
\n
Reversals to profit or loss - (11)
\n
Other changes (58) 56
\n
Closing balance at Dec. 31, 2022 29 219
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
The following table reports changes in the allowance for
\n
expected credit losses on trade receivables in accordance
\n
with the simplified approach.
\n
Millions of euro
\n
Opening balance at Jan. 1, 2021 3,287
\n
Accruals 1,285
\n
Uses 709
\n
Reversals to profit or loss (202)
\n
Other changes (1,416)
\n
Closing balance at Dec. 31, 2021 3,663
\n
Opening balance at Jan. 1, 2022 3,663
\n
Accruals 1,375
\n
Uses (766)
\n
Reversals to profit or loss (265)
\n
Other changes (224)
\n
Closing balance at Dec. 31, 2022 3,783
\n
The following table reports changes in the allowance for
\n
expected credit losses on other financial assets at amor-
\n
tized cost in accordance with the simplified approach.
\n
Millions of euro ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 129
\n
Accruals 94
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (68)
\n
Closing balance at Dec. 31, 2021 154
\n
Opening balance at Jan. 1, 2022 154
\n
Accruals 180
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (277)
\n
Closing balance at Dec. 31, 2022 56
\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\n\n\n
48.1.2 Financial assets at fair value through other
\n
comprehensive income
\n
The following table shows financial assets at fair value
\n
through other comprehensive income by nature, broken
\n
down into current and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Investments in other companies at FVOCI 29 360
\n
40 --
\n
Securities 29.1 447 403 30.1 78 87
\n
Receivables and other financial assets at FVOCI 94
\n
263 201 57
\n
Tot al 901 706 279 144
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
Changes in financial assets at FVOCI
\n
Investments in other companies
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 40 -
\n
Purchases 2-
\n
Sales -
\n
-
\n
Changes in fair value through OCI --
\n
Other changes (2)
\n
-
\n
Closing balance at Dec. 31, 2021 40 -
\n
Opening balance at Jan. 1, 2022 40
\n
-
\n
Purchases 149 -
\n
Sales -
\n
-
\n
Changes in fair value through OCI 11 -
\n
Other changes 160
\n
-
\n
Closing balance at Dec. 31, 2022 360 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 551 102
\n
Purchases 165 -
\n
Sales (87)
\n
-
\n
Changes in fair value through OCI 2-
\n
Reclassifications (85) 85
\n
Other changes 120
\n
(43)
\n
Closing balance at Dec. 31, 2021 666 144
\n
Opening balance at Jan. 1, 2022 666
\n
144
\n
Purchases 225 -
\n
Sales (41)
\n
(14)
\n
Changes in fair value through OCI (38) -
\n
Reclassifications (102) 102
\n
Other changes (168)
\n
47
\n
Closing balance at Dec. 31, 2022 541 279
\n

\n\n\n

\n\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n

\n\n

\n\n
48.1.4 Derivative financial assets designated as hedging
\n
instruments
\n
For more information on derivative financial assets, please
\n
see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
48.2 Financial liabilities by category
\n
The following table shows the carrying amount for each
\n
category of financial liability provided for under IFRS 9,
\n
broken down into current and non-current financial lia-
\n
bilities, showing hedging derivatives and derivatives mea-
\n
sured at fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Financial liabilities measured at amortized cost 48.2.1 68,432 54,914 45,697
\n
42,330
\n
Financial liabilities at fair value through profit or loss
\n
Derivative financial liabilities at FVTPL 48.4 588 169 11,642
\n
19,696
\n
Total financial liabilities at fair value through profit or loss 588 169 11,642 19,696
\n
Derivative financial liabilities designated as hedging instruments
\n
Fair value hedge derivatives 48.4 191 5 - -
\n
Cash flow hedge derivatives 48.4 5,116 3,165 4,499
\n
4,911
\n
Total derivative financial liabilities designated as hedging
\n
instruments
\n
5,307 3,170 4,499 4,911
\n
TOTAL 73,158 58,253 63,007
\n
66,937
\n
For more information on fair value measurement, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\n
48.2.1 Financial liabilities measured at amortized cost
\n
The following table shows financial liabilities at amortized
\n
cost by nature, broken down into current and non-current
\n
financial liabilities.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Long-term borrowings 48.3 68,191 54,500 48.3 2,835 4,031
\n
Short-term borrowings - - 48.3 18,392 13,306
\n
Trade payables 44 36 94 44 17,605 16,865
\n
Other financial liabilities 205
\n
320 6,865 8,128
\n
Tot al 68,432
\n
54,914 45,697 42,330
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
48.3 Borrowings
\n
48.3.1 Long-term borrowings (including the portion
\n
falling due within 12 months) \u2013 \u20ac71,026 million
\n
The following table reports the nominal value, carrying
\n
amount, and fair value of long-term borrowings including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
(1)
\n
Millions of euro
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Changes
\n
in carrying
\n
amount
\n
2022-
\n
2021
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Bonds:
\n
- listed, fixed rate 30,355 29,892 978 28,914 27,468 27,857 27,413 2,119 25,294 30,279 2,479
\n
- listed, floating rate 2,569 2,547 537 2,010 2,473 2,574 2,557 434 2,123 2,545 (10)
\n
- unlisted, fixed rate 18,959 18,727 - 18,727 17,249 11,293 11,207 50 11,157 12,670 7,520
\n
- unlisted, floating rate 525 525 97 428 600 622 622 97 525 728
\n
(97)
\n
Total bonds 52,408 51,691 1,612 50,079 47,790 42,346 41,799 2,700 39,099 46,222 9,892
\n
Bank borrowings:
\n
- fixed rate 3,367 3,273 211 3,062 3,021 2,414 2,405 238 2,167 2,298 868
\n
- floating rate 12,884 12,848 677 12,171 12,570 10,139 10,109 751 9,358 10,037
\n
2,739
\n
- use of revolving credit
\n
lines
\n
30 30 2 28 26 1,054 1,054 - 1,054 1,054
\n
(1,024)
\n
Total bank borrowings 16,281 16,151 890 15,261 15,617 13,607 13,568 989 12,579 13,389 2,583
\n
Leases:
\n
- fixed rate 2,630 2,630 251 2,379 2,630 2,477 2,477 242 2,235 2,477 153
\n
- floating rate 42 42 10 32 42 70 70 17 53 70
\n
(28)
\n
Total leases 2,672 2,672 261 2,411 2,672 2,547 2,547 259 2,288 2,547 125
\n
Other non-bank
\n
borrowings:
\n
- fixed rate 504 504 70 434 504 571 595 69 526 569 (91)
\n
- floating rate 8 8 2 6 12 34 22 14 8 25
\n
(14)
\n
Total other non-bank
\n
borrowings
\n
512 512 72 440 516 605 617 83 534 594
\n
(105)
\n
Total fixed-rate
\n
borrowings
\n
55,815 55,026 1,510 53,516 50,872 44,612 44,097 2,718 41,379 48,293
\n
10,929
\n
Total floating-rate
\n
borrowings
\n
16,058 16,000 1,325 14,675 15,723 14,493 14,434 1,313 13,121 14,459 1,566
\n
TOTAL 71,873 71,026 2,835 68,191 66,595 59,105 58,531 4,031 54,500 62,752
\n
12,495
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position that
\n
are included in long-term financial debt.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports long-term financial debt by
\n
currency and interest rate.
\n
Long-term financial debt by currency and interest rate
\n
(1)
\n
Millions of euro
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Euro 34,993 35,383 32,041 32,387 1.9% 2.1% 1.6% 1.9%
\n
US dollar 26,930 27,209 17,518 17,629 4.8% 5.1% 4.2% 4.3%
\n
Pound sterling 4,470 4,610 3,901 3,976 4.6% 4.8% 5.0% 5.2%
\n
Colombian peso 1,310 1,310 1,341 1,341 10.3% 10.3% 6.5% 6.5%
\n
Brazilian real 1,899 1,926 1,720 1,753 10.0% 10.2% 8.8% 8.9%
\n
Swiss franc 359 360 343 344 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 526 531 423 428 5.1% 5.2% 5.2% 5.2%
\n
Peruvian sol 429 429 415 415 5.3% 5.3% 5.2% 5.2%
\n
Russian ruble - - 427 427 6.8% 7.3%
\n
Other currencies 110 115 402 405
\n
Total non-euro currencies 36,033 36,490 26,490 26,718
\n
TOTAL 71,026 71,873 58,531 59,105
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
Long-term financial debt denominated in currencies other
\n
than the euro increased by \u20ac9,543 million, largely attrib-
\n
utable to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term debt
\n
(1)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope
\n
New
\n
borrowings Other changes
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Bonds 42,346 (2,788) (37) 12,390 - 497 52,408
\n
Borrowings 16,759 (6,571) (1,016)
\n
10,009 -28419,465
\n
- of which leases 2,547 (310) (88) 445 -782,672
\n
Total financial debt 59,105 (9,359) (1,053) 22,399 - 781 71,873
\n
(1) Does not include changes in the nominal value of other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the
\n
statement of financial position.
\n
The nominal value of long-term debt amounted to \u20ac71,873
\n
million at December 31, 2022, an increase of \u20ac12,768 mil-
\n
lion compared with December 31, 2021. The increase in
\n
debt reflected new borrowing of \u20ac22,399 million and ex-
\n
change losses of \u20ac781 million, only partially offset by re-
\n
payments of \u20ac9,359 million and the deconsolidation of
\n
debt of various companies, in particular that resulting from
\n
the sale of the equity investment in Enel Russia, equal to
\n
\u20ac1,053 million.
\n
Repayments in 2022 involved bonds in the amount of
\n
\u20ac2,788 million and loans in the amount of \u20ac6,571 million.
\n
Specifically, repayments of bonds in 2022 included:
\n
\u2022 \u20ac50 million in respect of a fixed-rate bond issued by Enel
\n
Finance International, maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
\u2022 270,000 million Colombian pesos (equivalent to \u20ac52
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2022;
\n
\u2022 \u20ac1,949 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in September 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in September
\n
2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in November 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in December
\n
2022.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022 \u20ac5,250 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022 \u20ac264 million in respect of Endesa loans, of which \u20ac132
\n
million in sustainable loans;
\n
\u2022 \u20ac504 million in respect of sustainable loans of Group\u2019s
\n
Italian companies;
\n
\u2022 the equivalent of \u20ac354 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2022 involved \u20ac12,390 million in bonds
\n
and \u20ac10,009 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2022 and translated into euros
\n
at the exchange rate prevailing at December 31, 2022.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of
\n
euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance International 17.01.2022 1,250 EUR 0.25% Fixed rate 17.11.2025
\n
Enel Finance International 17.01.2022 750 EUR 0.88% Fixed rate 17.01.2031
\n
Enel Finance International 17.01.2022 750 EUR 1.25% Fixed rate 17.01.2035
\n
Enel Finance International 11.04.2022 845 GBP 2.88% Fixed rate 11.04.2029
\n
Enel Finance International 15.06.2022 703 USD 4.25% Fixed rate 15.06.2025
\n
Enel Finance International 15.06.2022 703 USD 4.63% Fixed rate 15.06.2027
\n
Enel Finance International 15.06.2022 937 USD 5.00% Fixed rate 15.06.2032
\n
Enel Finance International 15.06.2022 937 USD 5.50% Fixed rate 15.06.2052
\n
Enel Finance International 09.09.2022 1,000 EUR 3.88% Fixed rate 09.03.2029
\n
Enel Finance International 14.10.2022 703 USD 6.80% Fixed rate 14.10.2025
\n
Enel Finance International 14.10.2022 1,171 USD 7.50% Fixed rate 14.10.2032
\n
Enel Finance International 14.10.2022 937 USD 7.75% Fixed rate 14.10.2052
\n
Enel Finance America 14.10.2022 937 USD 7.10% Fixed rate 14.10.2027
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 12.05.2022 142 BRL IPCA + 6.14% Floating rate 15.04.2032
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 30.05.2022 106 BRL IPCA + 6.21% Floating rate 17.05.2032
\n
Total bonds 11,871
\n
Bank borrowings
\n
Enel SpA 07.03.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 14.09.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 30.09.2022 350 EUR Euribor + 0.45% Floating rate 26.07.2025
\n
Enel SpA 30.09.2022 648 EUR Euribor + 0.40% Floating rate 12.05.2025
\n
Enel SpA 30.09.2022 1,852 EUR Euribor + 0.40% Floating rate 05.03.2026
\n
Enel SpA 30.09.2022 1,000 EUR Euribor + 0.52% Floating rate 02.10.2024
\n
e-distibuzione 05.08.2022 300 EUR Euribor + 0.473% Floating rate 05.08.2037
\n
Enel Italia 29.07.2022 60 EUR Euribor 6M + 0.462% Floating rate 29.07.2037
\n
Enel Finance America 06.10.2022 403 USD USD SOFR 6M CMP + 1.22% Floating rate 15.05.2034
\n
Enel Finance America 03.11.2022 187 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 13.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 21.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Endesa 17.01.2022 300 EUR Euribor 6M + 0.53% Floating rate 20.12.2033
\n
Endesa 25.03.2022 400 EUR Euribor 3M + 0.72% Floating rate 31.07.2024
\n
Endesa 28.03.2022 250 EUR Euribor 6M + 0.368% Floating rate 30.03.2037
\n
Endesa 30.03.2022 50 EUR Euribor 6M + 0.45% Floating rate 31.07.2024
\n
Endesa 31.03.2022 250 EUR Euribor 3M + 0.85% Floating rate 31.07.2024
\n
Endesa 31.03.2022 275 EUR Euribor 3M + 1.20% Floating rate 31.07.2024
\n
Endesa 31.03.2022 75 EUR 1.405% Fixed rate 01.04.2027
\n
Endesa 08.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 29.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 10.05.2022 100 EUR Euribor 3M + 0.65% Floating rate 31.07.2024
\n
Endesa 25.05.2022 500 EUR 1.895% Fixed rate 13.05.2027
\n
Endesa 19.10.2022 200 EUR Euribor 3M + 1.30% Floating rate 31.07.2024
\n
Endesa 18.11.2022 250 EUR Euribor 6M + 0.582% Floating rate 18.11.2037
\n
Enel Colombia 05.04.2022 93 COP COP IBR 3M + 2.05% Floating rate 05.04.2028
\n
Enel Colombia 28.07.2022 79 COP COP IBR 3M + 1.6% Floating rate 28.07.2028
\n
Enel Colombia 30.11.2022 70 COP COP IBR 3M + 2.98% Floating rate 30.11.2029
\n
Enel Distribuci\u00f3n Per\u00fa 04.04.2022 52 PEN 6.96% Fixed rate 19.03.2025
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 24.03.2022 51 USD USD SOFR CMP + 0.91% Floating rate 21.03.2025
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 01.09.2022 88 USD 3.61% Fixed rate 01.09.2037
\n
Total bank borrowings 8,665
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports the impact on gross long-term
\n
debt of hedges to mitigate currency risk.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
(1)
\n
Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Euro 34,993 35,383 49.2% 23,473 58,856 81.9% 32,041 32,387 54.8% 16,657 49,044 83.0%
\n
US dollar 26,930 27,209 37.9% (19,741) 7,468 10.4% 17,518 17,629 29.8% (13,423) 4,206 7.1%
\n
Pound sterling 4,470 4,610 6.4% (4,610) - - 3,901 3,976 6.7% (3,976) - -
\n
Colombian peso 1,310 1,310 1.8% - 1,310 1.8% 1,341 1,341 2.3% - 1,341 2.3%
\n
Brazilian real 1,899 1,926 2.7% 1,187 3,113 4.4% 1,720 1,753 3.0% 1,028 2,781 4.7%
\n
Swiss franc 359 360 0.5% (360) - - 343 344 0.6% (344) - -
\n
Chilean peso/UF 526 531 0.7% - 531 0.7% 423 428 0.7% - 428 0.7%
\n
Peruvian sol 429 429 0.6% - 429 0.6% 415 415 0.7% - 415 0.7%
\n
Russian ruble - - - - - - 427 427 0.7% - 427 0.7%
\n
Other currencies 110 115 0.2% 51 166 0.2% 402 405 0.7% 58 463
\n
0.8%
\n
Total non-euro
\n
currencies 36,033 36,490 50.8% (23,473) 13,017 18.1% 26,490 26,718 45.2% (16,657) 10,061 17.0%
\n
TOTAL 71,026 71,873 100.0% - 71,873 100.0% 58,531 59,105 100.0% - 59,105
\n
100.0%
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
The amount of floating-rate debt that is not hedged
\n
against interest rate risk is the main risk factor that could
\n
adversely impact profit or loss (raising borrowing costs) in
\n
the event of an increase in market interest rates.
\n
Millions of euro 2022 2021
\n
Pre-hedge % Post-hedge
\n
% Pre-hedge % Post-hedge %
\n
Floating rate 34,450 38.2% 31,353 34.7% 27,811 38.4% 22,478 31.0%
\n
Fixed rate 55,815 61.8% 58,912 65.3% 44,612 61.6% 49,945 69.0%
\n
Total 90,265 90,265 72,423 72,423
\n
At December 31, 2022, 38.2% of long and medium-term
\n
financial debt was floating rate (38.4% at December 31,
\n
2021). Taking account of hedges of interest rates consid-
\n
ered effective pursuant to the IFRS-EU, 34.7% of long and
\n
medium-term net financial debt at December 31, 2022
\n
was exposed to interest rate risk (31% at December 31,
\n
2021). These figures are in line with the limits established in
\n
the risk management policy.
\n
The following table shows the impact of the IBOR reform
\n
on long-term financial debt for the main indices (for more
\n
details, please see the section \u201cReform of benchmarks for
\n
the determination of interest rates - IBOR reform\u201d in note
\n
51.1).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional amount Phase 1 Phase 2 Phase 1 Phase 2
\n
USD LIBOR/SOFR 1,310 - 888 -
\n
GBP LIBOR/SONIA ---
\n
-
\n
Tot al 1,310 - 888 -
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Long-term debt \u2013 Main covenants
\n
The Group\u2019s main long-term financial liabilities are gov-
\n
erned by covenants that are commonly adopted in inter-
\n
national business practice. They include in particular bond
\n
issues carried out within the framework of the Global/Euro
\n
Medium Term Notes program, issues of subordinated un-
\n
convertible hybrid bonds (so-called \u201chybrid bonds\u201d) and
\n
loans granted by banks and other financial institutions (in-
\n
cluding the European Investment Bank and Cassa Depositi
\n
e Prestiti SpA).
\n
The main covenants regarding bond issues carried out
\n
within the framework of the Global/Euro Medium Term
\n
Notes program of Enel and Enel Finance International NV
\n
(including the green bonds of Enel Finance International
\n
NV guaranteed by Enel SpA, which are used to finance the
\n
Group\u2019s so-called eligible green projects) and those re-
\n
garding bonds issued by Enel Finance International NV on
\n
the US market guaranteed by Enel SpA can be summarized
\n
as follows:
\n
\u2022 negative pledge clauses under which the issuer and the
\n
guarantor may not establish or maintain mortgages, liens
\n
or other encumbrances on all or part of their assets or
\n
revenue to secure certain financial liabilities, unless the
\n
same encumbrances are extended equally or pro rata to
\n
the bonds in question;
\n
\u2022 pari passu clauses, under which the bonds and the as-
\n
sociated security constitute a direct, unconditional and
\n
unsecured obligation of the issuer and the guarantor,
\n
are issued without preferential rights among them and
\n
have at least the same seniority as other present and fu-
\n
ture unsubordinated and unsecured bonds of the issuer
\n
and the guarantor;
\n
\u2022 cross-default clauses, under which the occurrence of
\n
a default event in respect of a specified financial liabil-
\n
ity (above a threshold level) of the issuer, the guarantor
\n
or, in some cases, \u201csignificant\u201d subsidiaries constitutes
\n
a default in respect of the liabilities in question, which
\n
become immediately repayable.
\n
Since 2019, Enel Finance International NV has issued a
\n
number of \u201csustainable\u201d bonds on the European market (as
\n
part of the Euro Medium Term Notes - EMTN bond issue
\n
program) and on the American market, both guaranteed
\n
by Enel SpA, linked to the achievement of a number of the
\n
Sustainable Development Goals (SDGs) of the United Na-
\n
tions that contain the same covenants as other bonds of
\n
the same type.
\n
In 2022, Enel Finance America LLC issued a \u201csustainable\u201d
\n
bond of the same type, guaranteed by Enel SpA, on the
\n
US market.
\n
The main covenants covering Enel\u2019s hybrid bonds, includ-
\n
ing the perpetual hybrid bond issues, which will only be
\n
repaid in the event of the dissolution or liquidation of the
\n
Company, can be summarized as follows:
\n
\u2022 subordination clauses, under which each hybrid bond is
\n
subordinate to all other bonds issued by the company
\n
and has the same seniority with all other hybrid financial
\n
instruments issued, being senior only to equity instru-
\n
ments;
\n
\u2022 prohibition on mergers with other companies, the sale
\n
or leasing of all or a substantial part of the company\u2019s
\n
assets to another company, unless the latter succeeds
\n
in all obligations of the issuer.
\n
The main covenants envisaged in the loan contracts
\n
of Enel and Enel Finance International NV and the other
\n
Group companies, including the sustainability-linked loan
\n
facility agreements obtained by Enel SpA, can be summa-
\n
rized as follows:
\n
\u2022 negative pledge clauses, under which the borrower and,
\n
in some cases, the guarantor are subject to limitations
\n
on the establishment of mortgages, liens or other en-
\n
cumbrances on all or part of their respective assets, with
\n
the exception of expressly permitted encumbrances;
\n
\u2022 disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their as-
\n
sets or operations, with the exception of expressly per-
\n
mitted disposals;
\n
\u2022 pari passu clauses, under which the payment undertak-
\n
ings of the borrower have the same seniority as its other
\n
unsecured and unsubordinated payment obligations;
\n
\u2022 change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required to
\n
renegotiate the terms and conditions of the financing or
\n
make compulsory early repayment of the loans granted;
\n
\u2022 rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022 cross-default clauses, under which the occurrence of a
\n
default event in respect of a specified financial liability
\n
(above a threshold level) of the issuer or, in some cas-
\n
es, the guarantor constitutes a default in respect of the
\n
liabilities in question, which become immediately repay-
\n
able.
\n
Some loan contracts entered into by Enel SpA, including as
\n
guarantor, provide for some additional covenants, such as:
\n
\u2022 the commitment to use the loan exclusively to hedge
\n
collateral for trading activities on the energy markets;
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending
\n
bank can request the cancellation of its financial com-
\n
mitment undertaken by it and the early payment of the
\n
sums disbursed if it has suffered ascertained harm to its
\n
own reputation or that of other persons as a result of
\n
substantial breach of certain regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure com-
\n
pliance with certain environmental and social regulations
\n
and standards.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
In some cases, the covenants are also binding for the sig-
\n
nificant companies or subsidiaries of the obligated parties.
\n
All the borrowings considered specify \u201cevents of default\u201d
\n
typical of international business practice, such as, for ex-
\n
ample, insolvency, bankruptcy proceedings or the entity
\n
ceases trading.
\n
In addition, the guarantees issued by Enel in the interest
\n
of e-distribuzione SpA for certain loans to e-distribuzi-
\n
one SpA from Cassa Depositi e Prestiti SpA require that
\n
at the end of each six-month measurement period Enel\u2019s
\n
net consolidated financial debt shall not exceed 4.5 times
\n
annual consolidated EBITDA.
\n
Finally, the debt of Endesa SA, Enel Am\u00e9ricas SA, Enel Chile
\n
SA and the other Spanish and Latin American subsidiaries
\n
(notably Enel Generaci\u00f3n Chile SA) contains covenants and
\n
events of default typical of international business practice.
\n
48.3.2 Short-term borrowings \u2013 \u20ac18,392 million
\n
At December 31, 2022 short-term borrowings totaled
\n
\u20ac18,392 million, an increase of \u20ac5,086 million compared
\n
with December 31, 2021, and break down as follows:
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Short-term bank borrowings 1,320 1,329 (9)
\n
Commercial paper 13,838 10,708 3,130
\n
Cash collateral and other financing on derivatives 1,513 918 595
\n
Other short-term borrowings
\n
(1)
\n
1,721 351 1,370
\n
Short-term borrowings 18,392 13,306 5,086
\n
(1) Does not include other current borrowings included in \u201cOther current financial liabilities\u201d.
\n
Commercial paper liabilities totaling \u20ac13,838 million con-
\n
cerned issues by Enel Finance International, Endesa and
\n
Enel Finance America.
\n
The main commercial paper programs include:
\n
\u2022 \u20ac8,000 million of Enel Finance International, an increase
\n
from \u20ac6,000 million in 2021;
\n
\u2022 \u20ac5,000 million of Endesa, an increase from \u20ac4,000 mil-
\n
lion in 2021;
\n
\u2022 $5,000 million (equivalent to \u20ac4,414 million at December
\n
31, 2022), of Enel Finance America.
\n
At December 31, 2022, the whole amount of commercial
\n
paper issues, equal to \u20ac13,838 million, was linked to sus-
\n
tainability objectives.
\n

\n\n

\n\n
48.4 Derivative financial liabilities
\n
For more information on derivative financial liabilities,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n

\n\n
48.5 Net gain/(loss)
\n
The following table shows net gains and losses by category
\n
of financial instruments, excluding derivatives.
\n
Millions of euro 2022 2021
\n
(1)
\n
Net gain/(loss)
\n
Of which
\n
impairment
\n
(loss)/gain Net gain/(loss)
\n
Of which
\n
impairment
\n
(loss)/gain
\n
Financial assets at amortized cost (1,242) (1,305) (883) (1,151)
\n
Financial assets at FVOCI
\n
Equity investments at FVOCI - - - -
\n
Other financial assets at FVOCI (4) - 15 -
\n
Total financial assets at FVOCI (4) - 15 -
\n
Financial assets at FVTPL
\n
Financial assets at FVTPL 9 - 3 -
\n
Financial assets designated upon initial recognition (fair value option) - - - -
\n
Total financial assets at FVTPL 9 - 3 -
\n
Financial liabilities measured at amortized cost (2,357) - (4,310) -
\n
Financial liabilities at FVTPL
\n
Financial liabilities held for trading - - - -
\n
Financial liabilities designated upon initial recognition (fair value option) - - - -
\n
Total financial liabilities at FVTPL - - - -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of revenue connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements of
\n
IFRS 5 for their classification as discontinued operations have been met.
\n
For more details on net gains and losses on derivatives,
\n
please see note 14 \u201cNet financial income/(expense) from
\n
derivatives\u201d.
\n

\n\n\n
49. Risk management
\n
Financial risk management governance and
\n
objectives
\n
As part of its operations, the Enel Group is exposed to a va-
\n
riety of financial risks, notably interest rate risk, commodity
\n
risk, currency risk, credit and counterparty risk and liquidity
\n
risk.
\n
Enel\u2019s primary objective is to mitigate financial risks appro-
\n
priately so that they do not give rise to unexpected chang-
\n
es in results.
\n
The following sections detail the above financial risks.
\n
There were no changes in the sources of exposure to such
\n
risks compared with the previous year.
\n
Interest rate risk
\n
Interest rate risk derives primarily from the use of financial
\n
instruments and manifests itself as unexpected changes
\n
in charges on financial liabilities, if indexed to floating rates
\n
and/or exposed to the uncertainty of financial terms and
\n
conditions in negotiating new debt instruments, or as an
\n
unexpected change in the value of financial instruments
\n
measured at fair value (such as fixed-rate debt).
\n
The main financial liabilities held by the Group include
\n
bonds, bank borrowings, borrowings from other lenders,
\n
commercial paper, derivatives, cash deposits received to
\n
secure commercial or derivative contracts (guarantees,
\n
cash collateral).
\n
The Enel Group mainly manages interest rate risk through
\n
the definition of an optimal financial structure, with the
\n
dual goal of stabilizing borrowing costs and containing the
\n
cost of funds.
\n
This goal is pursued through the diversification of the port-
\n
folio of financial liabilities by contract type, maturity and
\n
interest rate, and modifying the risk profile of specific ex-
\n
posures using OTC derivatives, mainly interest rate swaps
\n
and interest rate options. The term of such derivatives
\n
does not exceed the maturity of the underlying financial li-
\n
ability, so that any change in the fair value and/or expected
\n
cash flows of such contracts is offset by a corresponding
\n
change in the fair value and/or cash flows of the hedged
\n
position.
\n
Proxy hedging techniques can be used in a number of re-
\n
sidual circumstances, when the hedging instruments for
\n

\n\n

\n\n

\n\n

\n
the risk factors are not available on the market or are not
\n
sufficiently liquid.
\n
Using interest rate swaps, the Enel Group agrees with the
\n
counterparty to periodically exchange floating-rate in-
\n
terest flows with fixed-rate flows, both calculated on the
\n
same notional principal amount.
\n
The following table reports the notional amount of interest
\n
rate derivatives at December 31, 2022 and December 31,
\n
2021 broken down by type of contract.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Floating-to-fixed interest rate swaps 5,836
\n
7, 7 00
\n
Fixed-to-floating interest rate swaps 1,401 722
\n
Fixed-to-fixed interest rate swaps --
\n
Floating-to-floating interest rate swaps 618 391
\n
Interest rate options -50
\n
Tot al 7,855
\n
8,863
\n
For more details on interest rate derivatives, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n
Interest rate risk sensitivity analysis
\n
Enel analyzes the sensitivity of its exposure by estimating
\n
the effects of a change in interest rates on the portfolio of
\n
financial instruments.
\n
More specifically, sensitivity analysis measures the po-
\n
tential impact on profit or loss and on equity of market
\n
scenarios that would cause a change in the fair value of
\n
derivatives or in the financial expense associated with un-
\n
hedged gross debt.
\n
These market scenarios are obtained by simulating parallel
\n
increases and decreases in the yield curve as at the re-
\n
porting date.
\n
There were no changes introduced in the methods and as-
\n
sumptions used in the sensitivity analysis compared with
\n
the previous year.
\n
With all other variables held constant, the Group\u2019s pre-tax
\n
profit would be affected by a change in the level of interest
\n
rates as follows:
\n
Millions of euro 2022
\n
Pre-tax impact on profit or loss Pre-tax impact on equity
\n
Basis
\n
points Increase Decrease Increase
\n
Decrease
\n
Change in financial expense on gross long-term floating-rate
\n
debt after hedging
\n
25 32
\n
(32) --
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
25 25
\n
(25) --
\n
Change in the fair value of derivatives designated as hedging
\n
instruments
\n
Cash flow hedges 25 - - 29 (29)
\n
Fair value hedges 25 - - (9)
\n
9
\n
At December 31, 2022, 22.3% (24.5% at December 31,
\n
2021) of the nominal value of gross long-term financial
\n
debt was floating rate. Taking account of effective cash
\n
flow hedges of interest rate risk (in accordance with the
\n
provisions of the IFRS-EU), 82.0% of the nominal value of
\n
gross long-term financial debt was hedged at December
\n
31, 2022 (84.5% at December 31, 2021).
\n\n
Currency risk
\n
Currency risk mainly manifests itself as unexpected
\n
changes in the financial statement items associated with
\n
transactions denominated in a currency other than the
\n
presentation currency. The Group\u2019s consolidated financial
\n
statements are also exposed to translation risk as a result
\n
of the conversion of the financial statements of foreign
\n
subsidiaries, which are denominated in local currencies,
\n
into euros as the Group\u2019s presentation currency.
\n
The Group\u2019s exposure to currency risk is connected with
\n
the purchase or sale of fuels and power, investments (cash
\n
flows for capitalized costs), dividends and the purchase or
\n
sale of equity investments, commercial transactions and
\n
financial assets and liabilities.
\n
The Group policies for managing currency risk provide for
\n
the mitigation of the effects on profit or loss of changes
\n
in the level of exchange rates, with the exception of the
\n
translation effects connected with consolidation.
\n

\n

\n\n

\n\n

\n\n

\n\n

\n\n
In order to minimize the exposure to currency risk, Enel im-
\n
plements diversified revenue and cost sources geograph-
\n
ically, and uses indexing mechanisms in commercial con-
\n
tracts. Enel also uses various types of derivative, typically
\n
on the OTC market.
\n
The derivatives in the Group\u2019s portfolio of financial instru-
\n
ments include cross currency interest rate swaps, currency
\n
forwards and currency swaps. The term of such contracts
\n
does not exceed the maturity of the underlying instru-
\n
ment, so that any change in the fair value and/or expected
\n
cash flows of such instruments offsets the corresponding
\n
change in the fair value and/or cash flows of the hedged
\n
position.
\n
Cross currency interest rate swaps are used to transform a
\n
long-term financial liability denominated in currency other
\n
than the presentation currency into an equivalent liability in
\n
the presentation currency.
\n
Currency forwards are contracts in which the counter-
\n
parties agree to exchange principal amounts denominat-
\n
ed in different currencies at a specified future date and
\n
exchange rate (the strike). Such contracts may call for the
\n
actual exchange of the two principal amounts (deliverable
\n
forwards) or payment of the difference generated by dif-
\n
ferences between the strike exchange rate and the prevail-
\n
ing exchange rate at maturity (non-deliverable forwards). In
\n
the latter case, the strike rate and/or the spot rate can be
\n
determined as averages of the rates observed in a given
\n
period.
\n
Currency swaps are contracts in which the counterparties
\n
enter into two transactions of the opposite sign at differ-
\n
ent future dates (normally one spot, the other forward) that
\n
provide for the exchange of principal denominated in dif-
\n
ferent currencies.
\n
The following table reports the notional amount of trans-
\n
actions outstanding at December 31, 2022 and December
\n
31, 2021, broken down by type of hedged item.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Cross currency interest rate swaps (CCIRSs) hedging debt denominated in currencies other than the euro 28,444 21,123
\n
Currency forwards hedging currency risk on commodities 8,392 6,183
\n
Currency forwards/CCIRSs hedging future cash flows in currencies other than the euro 5,333 5,034
\n
Other currency forwards 1,497 926
\n
Tot al 43,666 33,266
\n
More specifically, these include:
\n
\u2022 CCIRSs with a notional amount of \u20ac28,444 million to
\n
hedge the currency risk on debt denominated in cur-
\n
rencies other than the euro (\u20ac21,123 million at Decem-
\n
ber 31, 2021);
\n
\u2022 currency forwards and cross currency swaps with a to-
\n
tal notional amount of \u20ac13,725 million used to hedge
\n
the currency risk associated with purchases of natu-
\n
ral gas and fuel and expected cash flows in currencies
\n
other than the euro (\u20ac11,217 million at December 31,
\n
2021); changes in the notional amount during the year
\n
were affected by a greater exposure to exchange rate
\n
risk, in particular towards the US dollar, following the in-
\n
crease in natural gas prices and the increase in the use
\n
of coal for electricity generation;
\n
\u2022 other currency forwards, which include OTC derivatives
\n
transactions carried out to mitigate currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of in-
\n
vestment goods in the renewables and infrastructure
\n
and networks sectors (new generation digital meters),
\n
on operating costs for the supply of cloud services and
\n
on revenue from the sale of renewable energy. During
\n
2022, hedged items included exposures to fluctuations
\n
in the euro/Chinese renminbi exchange rate deriving
\n
from investments in BESS (Battery Energy Storage Sys-
\n
tem) projects.
\n
At December 31, 2022, 51% (45% at December 31, 2021)
\n
of Group long-term debt was denominated in currencies
\n
other than the euro.
\n
Taking account of hedges of currency risk, the percent-
\n
age of debt not hedged against that risk amounted to
\n
18% at December 31, 2022 (17% at December 31, 2021).
\n
Currency risk sensitivity analysis
\n
The Group analyzes the sensitivity of its exposure by es-
\n
timating the effects of a change in exchange rates on the
\n
portfolio of financial instruments.
\n
More specifically, sensitivity analysis measures the po-
\n
tential impact on profit or loss and equity of market
\n
scenarios that would cause a change in the fair value of
\n
derivatives or in the financial expense associated with un-
\n
hedged gross medium/long-term debt.
\n
These scenarios are obtained by simulating the apprecia-
\n
tion/depreciation of the euro against all of the currencies
\n
compared with the value observed as at the reporting
\n
date.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
There were no changes in the methods or assumptions
\n
used in the sensitivity analysis compared with the previ-
\n
ous year.
\n
With all other variables held constant, the pre-tax profit
\n
would be affected by changes in exchange rates as fol-
\n
lows.
\n
Millions of euro 2022
\n
Pre-tax impact
\n
on profit or loss Pre-tax impact on equity
\n
Exchange
\n
rate EUR appr. EUR depr. EUR appr.
\n
EUR depr.
\n
Change after hedging in financial expense on gross long-term
\n
debt denominated in currencies other than the euro
\n
10% ----
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
10% 880
\n
(1,073) --
\n
Change in the fair value of derivatives designated as hedging
\n
instruments
\n
Cash flow hedges 10% - - (3,434) 4,193
\n
Fair value hedges 10% (40) 49 - -
\n

\n\n\n
Commodity price risk
\n
The risk of fluctuations in the price of energy commodities
\n
such as electricity, gas, oil, CO
\n
2
\n
, and raw materials such as
\n
minerals and metals is generated by the volatility of pric-
\n
es and structural correlations between them, which cre-
\n
ate uncertainty in the margin on purchases and sales of
\n
electricity and fuels and materials at variable prices (e.g.,
\n
indexed bilateral contracts, transactions on the spot mar-
\n
ket, etc.).
\n
The exposures on indexed contracts are quantified by
\n
breaking down the contracts that generate exposure into
\n
the underlying risk factors.
\n
To contain the effects of fluctuations and stabilize margins,
\n
in accordance with the policies and operating limits deter-
\n
mined by the Group\u2019s governance and leaving an appropri-
\n
ate margin of flexibility to seize any short-term opportuni-
\n
ties that may present themselves, Enel develops and plans
\n
strategies that impact the various phases of the industrial
\n
process linked to the production and sale of electricity and
\n
gas (such as forward procurement and long-term com-
\n
mercial agreements), as well as risk mitigation plans and
\n
techniques using derivative contracts (hedging).
\n
As regards electricity sold by the Group, Enel mainly uses
\n
fixed-price contracts in the form of bilateral physical con-
\n
tracts (PPAs) and financial contracts (e.g., contracts for dif-
\n
ferences, VPP contracts, etc.) in which differences are paid
\n
to the counterparty if the market electricity price exceeds
\n
the strike price and to Enel in the opposite case. The resid-
\n
ual exposure in respect of the sale of energy on the spot
\n
market not hedged with such contracts is aggregated by
\n
uniform risk factors that can be managed with hedging
\n
transactions on the market. Proxy hedging techniques
\n
can be used for the industrial portfolios when the hedg-
\n
ing instruments for the specific risk factors generating
\n
the exposure are not available on the market or are not
\n
sufficiently liquid. In addition, Enel uses portfolio hedging
\n
techniques to assess opportunities for netting intercom-
\n
pany exposures.
\n
The Group mainly uses plain vanilla derivatives for hedging
\n
(more specifically, forwards, swaps, options on commodi-
\n
ties, futures, contracts for differences).
\n
Some of these products can be indexed to a variety of un-
\n
derlyings (coal, gas, oil, CO
\n
2
\n
, different geographical areas,
\n
etc.) and the approaches can be assessed and adapted to
\n
specific needs.
\n
Enel also engages in proprietary trading in order to main-
\n
tain a presence in the Group\u2019s reference energy com-
\n
modity markets. These operations consist in taking on
\n
exposures in energy commodities (oil products, gas, coal,
\n
CO
\n
2
\n
certificates and electricity) using financial derivatives
\n
and physical contracts traded on regulated and over-the-
\n
counter markets, optimizing profits through transactions
\n
carried out on the basis of expected market developments.
\n
The following table reports the notional amount of out-
\n
standing transactions at December 31, 2022 and Decem-
\n
ber 31, 2021, broken down by type of instrument.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Forward and futures contracts 114,128 90,273
\n
Swaps 11,271 12,122
\n
Options 504 1,076
\n
Embedded --
\n
Tot al 125,903 103,471
\n
For more details, please see note 51 \u201cDerivatives and hedge
\n
accounting\u201d.
\n
Commodity price risk sensitivity analysis
\n
The following table presents the results of the analysis of
\n
sensitivity to a reasonably possible change in the com-
\n
modity prices underlying the valuation model used in the
\n
scenario at the same date, with all other variables held
\n
constant.
\n
The impact on pre-tax profit of shifts of +15% and -15% in
\n
the price curve for the main commodities that make up
\n
the fuel scenario and the basket of formulas used in the
\n
contracts is mainly attributable to the change in the price
\n
of electricity, gas and petroleum products and, to a lesser
\n
extent, of CO
\n
2
\n
. The impact on equity of the same shifts in
\n
the price curve is primarily due to changes in the price of
\n
electricity, petroleum products and, to a lesser extent, CO
\n
2
\n
.
\n
The Group\u2019s exposure to changes in the prices of other
\n
commodities is not material.
\n
Millions of euro 2022
\n
Pre-tax impact on profit or loss Pre-tax impact on equity
\n
Commodity price Increase Decrease Increase Decrease
\n
Change in the fair value of trading derivatives on
\n
commodities
\n
20% (165) 169 - -
\n
Change in the fair value of derivatives on commodities
\n
designated as hedging instruments
\n
20% (17) 22 (273) 243
\n

\n\n\n
Credit and counterparty risk
\n
The Group\u2019s commercial, commodity and financial trans-
\n
actions expose it to credit risk, i.e., the possibility that a
\n
deterioration in the creditworthiness of a counterparty or
\n
the failure to discharge contractual payment obligations
\n
could lead to the interruption of incoming cash flows and
\n
an increase in collection costs (settlement risk), as well as
\n
lower revenue flows due to the replacement of the original
\n
transactions with similar transactions negotiated on unfa-
\n
vorable market conditions (replacement risk). Other risks
\n
include the reputational and financial risks associated with
\n
significant exposures to a single counterparty or groups of
\n
related customers, or to counterparties operating in the
\n
same sector or in the same geographical area.
\n
Accordingly, the exposure to credit and counterparty risk is
\n
attributable to the following types of transactions:
\n
\u2022 the sale and distribution of electricity and gas in free and
\n
regulated markets and the supply of goods and services
\n
(trade receivables in respect of non-Group debtors);
\n
\u2022 trading activities that involve the physical exchange of
\n
assets or transactions in financial instruments (the com-
\n
modity portfolio);
\n
\u2022 trading in derivatives, bank deposits and, more generally,
\n
financial instruments (the financial portfolio).
\n
In order to minimize credit and counterparty risk, cred-
\n
it exposures are managed at the region/country/global
\n
business line level by different units, thereby ensuring the
\n
necessary segregation of risk management and control
\n
activities. Monitoring the consolidated exposure is carried
\n
out by Enel SpA.
\n
In addition, at the Group level the policy provides for the
\n
use of uniform criteria \u2013 in all the main regions/countries/
\n
global business lines and at the consolidated level \u2013 in mea-
\n
suring commercial credit exposures in order to promptly
\n
identify any deterioration in the quality of outstanding re-
\n
ceivables and any mitigation actions to be taken.
\n
The policy for managing credit and counterparty risk asso-
\n
ciated with commercial activities provides for a preliminary
\n
assessment of the creditworthiness of counterparties and
\n
the adoption of mitigation instruments, such as obtaining
\n
collateral or unsecured guarantees.
\n
In addition, the Group undertakes transactions to factor
\n
receivables without recourse, which results in the com-
\n
plete derecognition of the corresponding assets involved
\n
in the factoring, as the risks and rewards associated with
\n
them have been transferred.
\n
Finally, with regard to financial and commodity transac-
\n
tions, risk mitigation is pursued with a uniform system for
\n
assessing counterparties at the Group level, including im-
\n

\n\n

\n\n

\n\n

\n\n

\n\n
plementation at the level of regions/countries/global busi-
\n
ness lines, as well as with the adoption of specific stan-
\n
dardized contractual frameworks that contain risk mitiga-
\n
tion clauses (e.g., netting arrangements) and possibly the
\n
exchange of cash collateral.
\n
Despite the deterioration in the collection status of some
\n
customer segments, which was taken into account in the
\n
assessment of the impairment of trade receivables, to
\n
date the Group portfolio has displayed resilience to the
\n
current macroeconomic context and price scenario. This
\n
reflects the strengthening of digital collection channels
\n
and a sound diversification of the customer base.
\n
Loan assets
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Staging
\n
Basis for
\n
recognition of
\n
expected credit loss
\n
allowance
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance Carrying amount
\n
Performing 12-month ECL 1.2% 16,918 205 16,713
\n
Underperforming Lifetime ECL 4.1% 266 11 255
\n
Non-performing Lifetime ECL 12.6% 254 32
\n
222
\n
Tot al 17,438 248 17,190
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Contract assets, trade receivables and other financial assets: individual measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 79 - 79
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,560 41 5,519
\n
Trade receivables past due:
\n
- 1-30 days 1.0% 477 5 472
\n
- 31-60 days 1.3% 75 1 74
\n
- 61-90 days 2.8% 36 1 35
\n
- 91-120 days 7.1% 28 2 26
\n
- 121-150 days 12.5% 24 3 21
\n
- 151-180 days 5.9% 51 3 48
\n
- more than 180 days (credit impaired) 80.8% 1,629 1,317 312
\n
Total trade receivables 7,880 1,373 6,507
\n
Other financial assets
\n
Other financial assets not past due 2.2% 1,401 31 1,370
\n
Other financial assets past due:
\n
- 1-30 days - 35 - 35
\n
- 31-60 days - 219 - 219
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 2 - 2
\n
- more than 180 days (credit impaired) 16.3% 147 24 123
\n
Total other financial assets 1,804 55 1,749
\n
TOTAL 9,763 1,428 8,335
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 110 - 110
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,339 39 5,300
\n
Trade receivables past due:
\n
- 1-30 days 1.2% 489 6 483
\n
- 31-60 days 3.4% 89 3 86
\n
- 61-90 days 10.2% 59 6 53
\n
- 91-120 days 50.0% 34 17 17
\n
- 121-150 days 31.6% 19 6 13
\n
- 151-180 days 26.9% 26 7 19
\n
- more than 180 days (credit impaired) 77.1% 1,813 1,397 416
\n
Total trade receivables 7,868 1,481 6,387
\n
Other financial assets
\n
Other financial assets not past due 1.9% 1,712 32 1,680
\n
Other financial assets past due:
\n
- 1-30 days - 352 - 352
\n
- 31-60 days - 244 - 244
\n
- 61-90 days - - - -
\n
- 91-120 days - 2 - 2
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) 13.9% 332 46 286
\n
Total other financial assets 2,642 78 2,564
\n
TOTAL 10,620 1,559 9,061
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Contract assets, trade receivables and other financial assets: collective measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 4.3% 46 2 44
\n
Trade receivables
\n
Trade receivables not past due 2.4% 7,698 187 7,511
\n
Trade receivables past due:
\n
- 1-30 days 2.6% 535 14 521
\n
- 31-60 days 42.3% 123 52 71
\n
- 61-90 days 24.0% 275 66 209
\n
- 91-120 days 29.0% 186 54 132
\n
- 121-150 days 35.6% 146 52 94
\n
- 151-180 days 45.0% 129 58 71
\n
- more than 180 days (credit impaired) 56.4% 3,416 1,927 1,489
\n
Total trade receivables 12,508 2,410 10,098
\n
Other financial assets
\n
Other financial assets not past due - 251 - 251
\n
Other financial assets past due:
\n
- 1-30 days 50.0% 2 1 1
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) - - - -
\n
Total other financial assets 253 1 252
\n
TOTAL 12,807 2,413 10,394
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 11.5% 26 2 24
\n
Trade receivables
\n
Trade receivables not past due 1.7% 4,603 77 4,526
\n
Trade receivables past due:
\n
- 1-30 days 2.8% 3,321 94 3,227
\n
- 31-60 days 9.9% 272 27 245
\n
- 61-90 days 15.3% 183 28 155
\n
- 91-120 days 26.1% 111 29 82
\n
- 121-150 days 32.4% 111 36 75
\n
- 151-180 days 33.3% 90 30 60
\n
- more than 180 days (credit impaired) 58.5% 3,180 1,861 1,319
\n
Total trade receivables 11,871 2,182 9,689
\n
Other financial assets
\n
Other financial assets not past due - 804 76 728
\n
Other financial assets past due:
\n
- 1-30 days - 7 - 7
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 1 - 1
\n
- more than 180 days (credit impaired) - 1 - 1
\n
Total other financial assets 813 76 737
\n
TOTAL 12,710 2,260 10,450
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Liquidity risk
\n
Liquidity risk manifests itself as uncertainty about the
\n
Group\u2019s ability to discharge its obligations associated with
\n
financial liabilities that are settled by delivering cash or an-
\n
other financial asset.
\n
Enel manages liquidity risk by implementing measures to
\n
ensure an appropriate level of liquid financial resources,
\n
minimizing the associated opportunity cost and maintain-
\n
ing a balanced debt structure in terms of its maturity pro-
\n
file and funding sources.
\n
In the short term, liquidity risk is mitigated by maintaining
\n
an appropriate level of unconditionally available resources,
\n
including liquidity on hand and short-term deposits, avail-
\n
able committed credit lines and a portfolio of highly liquid
\n
assets.
\n
In the long term, liquidity risk is mitigated by maintaining a
\n
balanced maturity profile for our debt, access to a range of
\n
sources of funding on different markets, in different cur-
\n
rencies and with diverse counterparties.
\n
The mitigation of liquidity risk enables the Group to main-
\n
tain a credit rating that ensures access to the capital mar-
\n
ket and limits the cost of funds, with a positive impact on
\n
its financial position and performance.
\n
The Group holds the following undrawn lines of credit and
\n
commercial paper programs.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Committed credit lines 355 19,122 438 14,822
\n
Uncommitted credit lines 980 - 888 -
\n
Commercial paper 3,847 - 3,709 -
\n
Tot al 5,182 19,122 5,035 14,822
\n
Maturity analysis
\n
The table below summarizes the maturity profile of the
\n
Group\u2019s long-term debt.
\n
Millions of euro
\n
At Dec. 31, 2022 Maturing in
\n
Less than 3
\n
months
\n
From 3
\n
months to 1
\n
year 2024 2025 2026 2027 Beyond
\n
Bonds:
\n
- listed, fixed rate 54 924 4,674 3,421 3,848 3,738 13,233
\n
- listed, floating rate 237 300 391 304 225 199 891
\n
- unlisted, fixed rate - - 1,403 1,395 1,163 2,529 12,237
\n
- unlisted, floating rate - 97 97 97 97 97 40
\n
Total bonds 291 1,321 6,565 5,217 5,333 6,563 26,401
\n
Bank borrowings:
\n
- fixed rate 73 138 928 288 406 692 748
\n
- floating rate 120 557 3,144 1,196 2,399 944 4,488
\n
- use of revolving credit lines - 2 - 26 2 - -
\n
Total bank borrowings 193 697 4,072 1,510 2,807 1,636 5,236
\n
Leases:
\n
- fixed rate 67 184 219 200 172 144 1,644
\n
- floating rate 1 9 10 11 6 1 4
\n
Total leases 68 193 229 211 178 145 1,648
\n
Other non-bank borrowings:
\n
- fixed rate 18 52 61 56 60 56 201
\n
- floating rate - 2 - 6---
\n
Total other non-bank borrowings 18 54 61 62 60 56 201
\n
TOTAL 570 2,265 10,927 7,000 8,378 8,400 33,486
\n

\n\n

\n\n

\n\n

\n

\n

\n\n
Commitments to purchase commodities
\n
In conducting its business, the Enel Group has entered into
\n
contracts to purchase specified quantities of commodities
\n
at a certain future date for its own use, which qualify for
\n
the own use exemption provided for under IFRS 9.
\n
The following table reports the undiscounted cash flows
\n
associated with outstanding commitments at December
\n
31, 2022.
\n
Millions of euro
\n
at Dec. 31, 2022 2022-2025 2026-2030 2031-2035 Beyond
\n
Commitments to purchase commodities:
\n
- electricity 64,878 18,777 17,752 10,913 17,436
\n
- fuels 96,996 11,842 59,697 13,466 11,991
\n
Total 161,874 30,619 77,449 24,379
\n
29,427
\n

\n\n\n
50. Offsetting financial assets and financial liabilities
\n
At December 31, 2022, the Group did not hold offset po-
\n
sitions in assets and liabilities, as it is not the Enel Group\u2019s
\n
policy to settle financial assets and liabilities on a net basis.
\n

\n\n\n
51. Derivatives and hedge accounting
\n
The following tables show the notional amount and the fair
\n
value of derivative financial assets and derivative financial
\n
liabilities eligible for hedge accounting or measured at
\n
FVTPL, classified on the basis of the type of hedge rela-
\n
tionship and the hedged risk, broken down into current
\n
and non-current instruments.
\n
The notional amount of a derivative contract is the amount
\n
on the basis of which cash flows are exchanged. This
\n
amount can be expressed as a value or a quantity (for ex-
\n
ample tons, converted into euros by multiplying the no-
\n
tional amount by the agreed price). Amounts denominated
\n
in currencies other than the euro are translated at the offi-
\n
cial closing exchange rates provided by the World Markets
\n
Refinitiv (WMR) Company.
\n
Millions of euro Non-current Current
\n
Notional Fair value Notional Fair value
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
DERIVATIVE ASSETS
\n
Fair value hedge derivatives:
\n
- on interest rates 1541392219----
\n
- on exchange rates 99 672 15 42 - - -
\n
-
\n
- of which associated with borrowings 70 672 14 42----
\n
Total 2538113761----
\n
Cash flow hedge derivatives:
\n
- on interest rates 4,949404336199---
\n
- on exchange rates 16,955 14,980 1,854 1,356 4,053 2,690 389
\n
104
\n
- of which associated with borrowings 15,402 13,130 1,786 1,303 1,244 77 236 14
\n
- on commodities 4,321 2,693 1,270 1,059 7,416 3,469 2,366 3,023
\n
Total 26,225 18,077 3,460 2,434 11,478 6,159 2,755 3,127
\n
Trading derivatives:
\n
- on interest rates -----50-1
\n
- on exchange rates 19 26 1 - 3,640 2,154 74 23
\n
- on commodities 1,774 1,147 472 277 49,253 48,304 12,001
\n
19,640
\n
Total 1,793 1,173 473 277 52,893 50,508 12,075 19,664
\n
TOTAL DERIVATIVE ASSETS 28,271 20,061 3,970 2,772 64,371 56,667 14,830
\n
22,791
\n

\n\n

\n\n

\n\n

\n
Millions of euro Non-current Current
\n
Notional Fair value Notional Fair value
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
DERIVATIVE LIABILITIES
\n
Fair value hedge derivatives:
\n
- on interest rates 1,603660925----
\n
- on exchange rates 813 - 99 - 185 - - -
\n
- of which associated with borrowings 750 - 91-----
\n
Total 2,4166601915185---
\n
Cash flow hedge derivatives:
\n
- on interest rates 890 6,807 59 620 150 653 1 9
\n
- on exchange rates 11,956 7,224 1,640 1,244 3,798 1,892 176 49
\n
- of which associated with borrowings 8,388 5,034 1,348 1,099 67 21 2 1
\n
- on commodities 6,403 3,312 3,417 1,301 9,556 2,067 4,322 4,853
\n
Total 19,249 17,343 5,116 3,165 13,504 4,612 4,499 4,911
\n
Trading derivatives:
\n
- on interest rates ----1001502373
\n
- on exchange rates 52 73 1 2 2,096 3,555 34 60
\n
- on commodities 1,281 884 587 167 45,899 41,595 11,585 19,563
\n
Total 1,333 957 588 169 48,095 45,300 11,642 19,696
\n
TOTAL DERIVATIVE LIABILITIES 22,998 18,960 5,895 3,339 61,784 49,912 16,141 24,607
\n
Exchange rate derivatives associated with borrowings re-
\n
fer to the fair value and notional amount of cross currency
\n
swaps entered into to hedge foreign currency loans to third
\n
parties; the net fair value of these derivatives is included in
\n
the representation of the Group\u2019s net financial debt.
\n\n
51.1 Derivatives designated as hedging
\n
instruments
\n
Derivatives are initially recognized at fair value, on the trade
\n
date of the contract, and are subsequently re-measured at
\n
their fair value. The method of recognizing the resulting
\n
gain or loss depends on whether the derivative is desig-
\n
nated as a hedging instrument, and if so, the nature of the
\n
item being hedged.
\n
Hedge accounting is applied to derivatives entered into in
\n
order to reduce risks such as interest rate risk, currency
\n
risk, commodity price risk (including Virtual PPAs) and net
\n
investments in foreign operations when all the criteria pro-
\n
vided by IFRS 9 are met.
\n
At the inception of the transaction, the Group docu-
\n
ments the relationship between hedging instruments and
\n
hedged items, as well as its risk management objectives
\n
and strategy. The Group also documents its assessment,
\n
both at hedge inception and on an ongoing basis, of
\n
whether hedging instruments are highly effective in offset-
\n
ting changes in fair values or cash flows of hedged items.
\n
For cash flow hedges of forecast transactions designat-
\n
ed as hedged items, the Group assesses and documents
\n
that they are highly probable and present an exposure to
\n
changes in cash flows that affect profit or loss.
\n
Depending on the nature of the risk exposure, the Group
\n
designates derivatives as either:
\n
\u2022 fair value hedges;
\n
\u2022 cash flow hedges.
\n
For more details about the nature and the extent of risks
\n
arising from financial instruments to which the Group is
\n
exposed, please see note 49 \u201cRisk management\u201d.
\n
To be effective a hedge relationship shall meet all of the
\n
following criteria:
\n
\u2022 existence of an economic relationship between hedging
\n
instrument and hedged item;
\n
\u2022 the effect of credit risk does not dominate the value
\n
changes resulting from the economic relationship;
\n
\u2022 the hedge ratio defined at initial designation shall be
\n
equal to the one used for risk management purposes
\n
(i.e., same quantity of the hedged item that the entity
\n
actually hedges and the quantity of the hedging instru-
\n
ment that the entity actually uses to hedge the quantity
\n
of the hedged item).
\n
Based on the IFRS 9 requirements, the existence of an
\n
economic relationship is evaluated by the Group through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n
\u2022 if the underlying risk of the hedging instrument and the
\n
hedged item is the same, the existence of an economic
\n
relationship will be provided through a qualitative anal-
\n
ysis;
\n
\u2022 on the other hand, if the underling risk of the hedging
\n
instrument and the hedged item is not the same, the
\n
existence of the economic relationship will be demon-
\n
strated through a quantitative method in addition to a
\n
qualitative analysis of the nature of the economic rela-
\n
tionship (i.e., linear regression).
\n
In order to demonstrate that the behavior of the hedging
\n
instrument is in line with those of the hedged item, differ-
\n
ent scenarios will be analyzed.
\n
For hedging of commodity price risk, the existence of an
\n
economic relationship is deduced from a ranking matrix
\n
that defines, for each possible risk component, a set of all
\n
standard derivatives available in the market whose ranking
\n
is based on their effectiveness in hedging the considered
\n
risk.
\n
In order to evaluate the credit risk effects, the Group con-
\n
siders the existence of risk mitigating measures (collateral,
\n
mutual break-up clauses, netting agreements, etc.).
\n
The Group has established a hedge ratio of 1:1 for all the
\n
hedge relationships (including commodity price risk hedg-
\n
ing) as the underlying risk of the hedging derivative is
\n
identical to the hedged risk, in order to minimize hedging
\n
ineffectiveness.
\n
The hedge ineffectiveness will be evaluated through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument match and there are no other sources of inef-
\n
fectiveness including the credit risk adjustment on the
\n
hedging derivative, the hedge relationship will be con-
\n
sidered fully effective on the basis of a qualitative as-
\n
sessment;
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument do not match or there is at least one source of
\n
ineffectiveness, the hedge ineffectiveness will be quan-
\n
tified applying the dollar offset cumulative method with
\n
hypothetical derivative. This method compares changes
\n
in fair value of the hedging instrument and the hypo-
\n
thetical derivative between the reporting date and the
\n
inception date.
\n
The main causes of hedge ineffectiveness can be the fol-
\n
lowing:
\n
\u2022 basis differences (i.e., the fair value or cash flows of the
\n
hedged item depend on a variable that is different from
\n
the variable that causes the fair value or cash flows of
\n
the hedging instrument to change);
\n
\u2022 timing differences (i.e., the hedged item and hedging in-
\n
strument occur or are settled at different dates);
\n
\u2022 quantity or notional amount differences (i.e., the hedged
\n
item and hedging instrument are based on different
\n
quantities or notional amounts);
\n
\u2022 other risks (i.e., changes in the fair value or cash flows of
\n
a derivative hedging instrument or hedged item relate to
\n
risks other than the specific risk being hedged);
\n
\u2022 credit risk (i.e., the counterparty credit risk differently im-
\n
pact the changes in the fair value of the hedging instru-
\n
ments and hedged items).
\n
The macroeconomic context became particularly unstable
\n
in 2022, due to the conflict between Russia and Ukraine,
\n
impacting raw material supply chains and causing high
\n
price volatility, especially in the energy sector. In this con-
\n
text, the commodity risk was managed effectively and did
\n
not have a significant impact on the soundness of hedging
\n
relationships, also thanks to the solidity of the integrated
\n
portfolio models used in the main European areas in which
\n
the Group operates and the geographical diversification of
\n
our sources of supply. Even credit risk was essentially un-
\n
affected, as the Group\u2019s main trading counterparties have
\n
a high credit rating or are adequately secured by bank or
\n
insurance guarantees.
\n
The conflict and the difficult macroeconomic conditions
\n
had only a limited impact on the management of interest
\n
rate and exchange rate risk, being insufficient to direct-
\n
ly and significantly influence the valuation of derivative
\n
instruments and the outcome of effectiveness checks of
\n
hedges. The volatility that buffeted financial markets was
\n
offset by risk mitigation actions using derivative financial
\n
instruments.
\n
Fair value hedges
\n
Fair value hedges are used to protect the Group against
\n
exposures to changes in the fair value of assets, liabilities
\n
or firm commitment attributable to a particular risk that
\n
could affect profit or loss.
\n
Changes in the fair value of derivatives that qualify and are
\n
designated as hedging instruments are recognized in the
\n
income statement, together with changes in the fair value
\n
of the hedged item that are attributable to the hedged risk.
\n
If the hedge no longer meets the criteria for hedge ac-
\n
counting, the adjustment to the carrying amount of a
\n
hedged item for which the effective interest rate method
\n
is used is amortized to profit or loss over the period to ma-
\n
turity.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n
Cash flow hedges
\n
Cash flow hedges are applied in order to hedge the Group
\n
exposure to changes in future cash flows that are attribut-
\n
able to a particular risk associated with a recognized asset
\n
or liability or a highly probable transaction that could affect
\n
profit or loss.
\n
The effective portion of changes in the fair value of deriv-
\n
atives that are designated and qualify as cash flow hedges
\n
is recognized in other comprehensive income. The gain or
\n
loss relating to the ineffective portion is recognized imme-
\n
diately in the income statement.
\n
Amounts accumulated in equity are reclassified to profit
\n
or loss in the periods when the hedged item affects profit
\n
or loss (for example, when the hedged forecast sale takes
\n
place).
\n
If the hedged item results in the recognition of a non-fi-
\n
nancial asset (i.e., property, plant and equipment or inven-
\n
tories, etc.) or a non-financial liability, or a hedged forecast
\n
transaction for a non-financial asset or a non-financial
\n
liability becomes a firm commitment for which fair value
\n
hedge accounting is applied, the amount accumulated in
\n
equity (i.e., hedging reserve) shall be removed and included
\n
in the initial amount (cost or other carrying amount) of the
\n
asset or the liability hedged (i.e., \u201cbasis adjustment\u201d).
\n
When a hedging instrument expires or is sold, or when a
\n
hedge no longer meets the criteria for hedge accounting,
\n
any cumulative gain or loss existing in equity at that time
\n
remains in equity and is recognized when the forecast
\n
transaction is ultimately recognized in the income state-
\n
ment. When a forecast transaction is no longer expected
\n
to occur, the cumulative gain or loss that was reported in
\n
equity is immediately transferred to the income statement.
\n
For hedge relationships using forwards as a hedging in-
\n
strument, where only the change in the value of the spot
\n
element is designated as the hedging instrument, ac-
\n
counting for the forward element (profit or loss vs OCI) is
\n
defined case by case. This approach is actually applied by
\n
the Group for hedging of currency risk on renewables as-
\n
sets.
\n
Conversely, for hedge relationships using cross currency
\n
interest rate swaps as hedging instruments, the Group
\n
separates foreign currency basis spread, in designating
\n
the hedging derivative, and present them in other com-
\n
prehensive income (OCI) as hedging costs.
\n
With specific regard to cash flow hedges of commodity
\n
risk, in order to improve their consistency with the risk
\n
management strategy, the Enel Group applies a dynamic
\n
hedge accounting approach based on specific liquidity re-
\n
quirements (the so-called liquidity-based approach).
\n
This approach requires the designation of hedges through
\n
the use of the most liquid derivatives available on the mar-
\n
ket and replacing them with others that are more effective
\n
in covering the risk in question.
\n
Consistent with the risk management strategy, the liquid-
\n
ity-based approach allows the roll-over of a derivative by
\n
replacing it with a new derivative, not only in the event of
\n
expiry but also during the hedge relationship, if and only
\n
if the new derivative meets both of the following require-
\n
ments:
\n
\u2022 it represents a best proxy of the old derivative in terms
\n
of ranking;
\n
\u2022 it meets specific liquidity requirements.
\n
Satisfaction of these requirements is verified quarterly.
\n
At the roll-over date, the hedge relationship is not discon-
\n
tinued. Accordingly, starting from that date, changes in the
\n
effective fair value of the new derivative will be recognized
\n
in equity (the hedging reserve), while changes in the fair
\n
value of the old derivative are recognized through profit
\n
or loss.
\n\n
Reform of benchmarks for the determination of interest
\n
rates \u2013 IBOR reform
\n
Overview
\n
Interbank Offered Rates (\u201cIBORs\u201d) are benchmark rates at
\n
which banks can borrow funds on the interbank market on
\n
an unsecured basis for a given period ranging from over-
\n
night to 12 months, in a specific currency.
\n
In recent years there have been a number of cases of ma-
\n
nipulation of these rates by the banks contributing to their
\n
calculation. For this reason, regulators around the world
\n
have begun a sweeping reform of interest rate bench-
\n
marks that includes the replacement of some benchmarks
\n
with alternative risk-free rates (the IBOR reform).
\n
The Group\u2019s main exposure is based on Euribor and USD
\n
LIBOR.
\n
Euribor is still considered compliant with the European
\n
Benchmarks Regulation (BMR) and this permits market
\n
participants to continue to use it for both existing and new
\n
contracts.
\n
In line with the most recent guidance issued by the major
\n
regulatory bodies:
\n
\u2022 the 1-month, 3-month and 6-month USD LIBOR bench-
\n
marks will become unrepresentative after June 30, 2023
\n
and the alternative reference rate will be the Secured
\n
Overnight Financing Rate (SOFR);
\n
\u2022 the 1-month, 3-month and 6-month GBP LIBOR bench-
\n
marks will become unrepresentative after December 31,
\n
2021 and the alternative reference rate will be the Ster-
\n
ling Overnight Index Average (SONIA).
\n
As a result of the IBOR reform, a number of temporary ex-
\n
ceptions to the rules on hedge relationships have been al-
\n
lowed in implementation of the amendments to IFRS 9 is-
\n
sued in September 2019 (Phase 1) and August 2020 (Phase
\n
2) to address, respectively:
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
\u2022 pre-replacement issues that impact financial reporting
\n
in the period preceding the replacement of an existing
\n
interest rate benchmark with an alternative risk-free rate
\n
(Phase 1); and
\n
\u2022 post-replacement issues that could impact financial
\n
reporting when an existing interest rate benchmark is
\n
reformed or replaced and there is no longer any initial
\n
uncertainty, but hedge contracts and relationships still
\n
need to be updated to reflect the new benchmark rates
\n
(Phase 2).
\n
Impact of the IBOR reform on the Group
\n
In a context of uncertainty regarding the IBOR transition in
\n
the various countries, the Group has determined the over-
\n
all number and nominal value of the contracts impacted by
\n
the reform. In addition, a number of contractual amend-
\n
ments have already been implemented in contracts pre-
\n
viously indexed to GBP LIBOR in 2021 and others will be
\n
amended in 2023 on the basis of the evolution of the IBOR
\n
reform and market practice.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and USD LIBOR and is almost entirely
\n
hedged using financial derivatives.
\n
At the reporting date, the Group is planning to take no
\n
action with regard to Euribor since, as stated above, this
\n
benchmark has been comprehensively reformed to com-
\n
ply with the European Benchmarks Regulation. Despite the
\n
continuity with Euribor, replacement clauses may be re-
\n
quired and could therefore be implemented by the Group
\n
in the new contracts in accordance with the evolution of
\n
accepted market practice.
\n
During 2022, the Group obtained new US dollar loans in-
\n
dexed to SOFR. The main focus over the coming months
\n
will be how to change existing USD LIBOR to USD SOFR ex-
\n
posures and how to use the new, alternative risk-free rates
\n
for new financial transactions.
\n
The Group\u2019s derivative instruments are managed through
\n
contracts that are mainly based on framework agreements
\n
defined by the International Swaps and Derivatives Associ-
\n
ation (ISDA).
\n
The ISDA has revised its standardized contracts in light of
\n
the IBOR reform and amended the choices for floating rates
\n
within the 2006 ISDA definitions to include replacement
\n
clauses that would apply upon the permanent discontinu-
\n
ation of specific key benchmarks. These changes took ef-
\n
fect on January 25, 2021. Transactions represented in the
\n
2006 ISDA definitions carried out on January 25, 2021 or
\n
later include adjusted floating-rate options (e.g., the choice
\n
of floating rate with replacement clause), while transactions
\n
completed before that date (previous derivative contracts)
\n
continue to be based on the 2006 ISDA definitions.
\n
For this reason, the ISDA published an IBOR Fallback Pro-
\n
tocol to facilitate multilateral amendments to include the
\n
amended definitions.
\n
The Group is assessing whether to: (i) adopt that protocol
\n
in the light of its exposure and developments in the IBOR
\n
reform or (ii) adjust in advance any contracts impacted bi-
\n
laterally by the reform.
\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, USD LIBOR and
\n
SONIA.
\n
The Group has assessed the impact of uncertainty engen-
\n
dered by the IBOR reform on hedge relationships at De-
\n
cember 31, 2022 with reference to both hedging instru-
\n
ments and hedged items. Both the hedged items and the
\n
hedging instruments will change their parameterization
\n
from interbank market-based benchmarks (IBORs) to al-
\n
ternative risk-free rates (RFRs) as a result of the contrac-
\n
tual amendments that will take effect in the coming years.
\n
In particular, uncertainty remains as to how the replacement
\n
will take place with regard to both hedging instruments and
\n
hedged items indexed to USD LIBOR. The Group manages
\n
the uncertainty associated with these hedge relationships
\n
by continuing to apply the temporary exceptions provided
\n
for in the amendments to IFRS 9 issued in September 2019
\n
(Phase 1). It was therefore felt that the benchmark indices
\n
for determining the interest rates on which the cash flows
\n
of the hedged items or the hedging instruments are based
\n
would not change as a consequence of the IBOR reform.
\n
The exception was applied for the following hedge rela-
\n
tionship requirements:
\n
\u2022 determine if a forecast transaction is highly probable;
\n
\u2022 establish whether the future hedged cash flows will arise
\n
in a discontinued cash flow hedge relationship;
\n
\u2022 assess the economic relationship between the hedged
\n
item and the hedging instrument.
\n
The hedge relationships impacted may become ineffective
\n
attributable to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In any case,
\n
the Group will seek to implement the replacements at the
\n
same time.
\n
In addition, the Group changed the reference to GBP LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically equiv-
\n
alent, SONIA benchmark at the end of 2021. Consequently,
\n
the Group no longer applies the amendments to IFRS 9
\n
issued in September 2019 (Phase 1) to these hedge rela-
\n
tionships and, consequently, is applying the amendments
\n
to IFRS 9 issued in August 2020 (Phase 2), modifying the
\n
formal designation of the hedge relationship as required
\n
by the IBOR reform and without considering this event as a
\n
termination of the hedge relationship.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n\n
Furthermore, for cash flow hedge relationships, in modify-
\n
ing the description of the hedged item in the hedge rela-
\n
tionship, the amounts accumulated in the cash flow hedge
\n
reserve were considered on the basis of the alternative
\n
benchmark index in relation to which the future hedged
\n
cash flows are determined.
\n
The following table provides details of the notional amounts
\n
of the hedging instruments for which the amendments to
\n
IFRS 9 (both Phase 1 and Phase 2) were applied as at De-
\n
cember 31, 2022, broken down by the alternative bench-
\n
mark index used for determining the interest rate.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022
\n
Hedging instruments Phase 1 Phase 2
\n
USD LIBOR/SOFR 977 -
\n
GBP LIBOR/SONIA - 1,240
\n
Tot al 977
\n
1,240
\n

\n\n\n
Unamended contracts including those with specific
\n
replacement clauses
\n
The Group is monitoring the evolution of the transition
\n
from the old interest rate benchmarks to the new rates,
\n
reviewing the overall value of contracts that have not yet
\n
been indexed to the new benchmark rates and, among
\n
these, the value of contracts which already include specific
\n
replacement clauses. The Group considers a contract to
\n
have not yet incorporated an alternative benchmark rate
\n
when the interest rate of the contract is indexed to an in-
\n
terest rate benchmark still involved in the IBOR reform and,
\n
therefore, when uncertainties still exist as to how and when
\n
replacement with the new benchmark will take place.
\n

\n

\n\n
51.1.1 Hedge relationships by type of risk hedged
\n
Interest rate risk
\n
The following table shows the notional amount and the
\n
average interest rate of instruments hedging the interest
\n
rate risk on transactions outstanding at December 31,
\n
2022 and December 31, 2021, broken down by maturity.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Interest rate swaps
\n
Total notional amount 159 722 573 902 2,017 3,382 7,755
\n
Notional amount related to IRS in euro 159 623 573 682 1,558 2,724 6,319
\n
Average IRS rate in euro 4.41 2.24 1.91 2.20 1.84 1.61
\n
Notional amount related to IRS in US dollars - 47 - - 459 237 743
\n
Average IRS rate in US dollars 0.70 3.23 3.84
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the interest rate risk
\n
of transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument
\n
Hedged item
\n
Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Fair value hedges
\n
Interest rate swaps Floating-rate borrowings/bonds 20 (2) 518 13 (1) 241
\n
Interest rate swaps Fixed-rate borrowings/bonds 2 (90) 1,239 6 (4)
\n
558
\n
Cash flow hedges
\n
Interest rate swaps Floating-rate bonds 29 (44)
\n
1,190 - (167) 1,190
\n
Interest rate swaps Floating-rate loan assets - (9) 162 13 (1) 164
\n
Interest rate swaps Floating-rate borrowings 307 (7) 4,646 6 (461)
\n
6,510
\n
Tot al 358 (152) 7,755 38 (634) 8,663
\n
The following table shows the notional amount and the fair
\n
value of hedging derivatives on interest rate risk as at De-
\n
cember 31, 2022 and December 31, 2021 broken down by
\n
type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
Interest rate swaps 154 139 22 19 1,603 660 (92) (5)
\n
Total 154 139 22 19 1,603 660 (92) (5)
\n
Cash flow hedges
\n
Interest rate swaps 4,958 404 336 19 1,040 7,460 (60) (629)
\n
Total 4,958 404 336 19 1,040 7,460 (60) (629)
\n
TOTAL INTEREST RATE
\n
DERIVATIVES
\n
5,112 543 358 38 2,643 8,120 (152) (634)
\n
The notional amount of derivatives classified as hedging
\n
instruments at December 31, 2022 came to \u20ac7,755 million,
\n
with a corresponding positive fair value of \u20ac206 million.
\n
Compared with December 31, 2021, the notional amount
\n
decreased by \u20ac908 million, mainly reflecting:
\n
\u2022 the expiry of interest rate swaps amounting to \u20ac481 mil-
\n
lion;
\n
\u2022 the classification as assets held for sale of Australian
\n
companies holding interest rate financial derivatives in
\n
the amount of \u20ac340 million;
\n
\u2022 new interest rate swaps amounting to \u20ac1,174 million;
\n
\u2022 the reduction in the notional amount of amortizing inter-
\n
est rate swaps in the amount of \u20ac211 million.
\n
We also note the early closure of interest rate swaps for
\n
an amount of \u20ac1,050 million. The improvement in the fair
\n
value of \u20ac802 million mainly reflects developments in the
\n
yield curve.
\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss in respect of fair value hedge
\n
derivatives and the hedged item that are attributable to in-
\n
terest rate risk both in 2022 and the previous year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (84) (10)
\n
Hedged item 75 3
\n
Ineffective portion (9) (7)
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table shows the impact of fair value hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 1,757 (70) (70) 799 14 14
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds 1,152 (87) (81) 562 4 (8)
\n
Floating-rate borrowings/bonds 576 (16) (18) 262 (9) 12
\n
Total 1,728 (103) (99) 824 (5) 4
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on interest rate
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on interest
\n
rates
\n
Positive fair value 336 80 98 60 48 64 -
\n
Negative fair value (60) (15) (10) (10) (8) (24) -
\n
The following table shows the impact of cash flow hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 5,998 276 276 7,864 (610)
\n
(610)
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
bonds
\n
15 - (15) - - 167 - (167) - -
\n
Floating-rate
\n
loan assets
\n
9 - (9) - - (12) - 12 - -
\n
Floating-rate
\n
borrowings
\n
(327) (28) 326 - 2 417 (32) (417) - (6)
\n
Total (303) (28) 302 - 2 572 (32) (572) - (6)
\n\n
Currency risk
\n
The following table reports the maturity profile of the no-
\n
tional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRS)
\n
Total notional amount of CCIRS 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRS EUR/USD 1,171 2,290 2,107 1,171 1,615 11,529 19,883
\n
Average exchange rate EUR/USD 1.33 1.13 1.07 1.18 1.10 1.15
\n
Notional amount for CCIRS EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount for CCIRS EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 140 288 239 94 - - 761
\n
Average exchange rate USD/BRL 5.22 5.50 5.22 5.29
\n
Notional amount for CCIRS EUR/BRL 597 438 181 - 70 - 1,286
\n
Average exchange rate EUR/BRL 6.09 6.25 6.16 3.92
\n
Currency forwards
\n
Total notional amount of forwards 6,127 2,374 625 - - - 9,126
\n
Notional amount - currency forwards EUR/USD 4,713 2,345 625 - - - 7,683
\n
Average currency forward rate - EUR/USD 1.09 1.10 1.11
\n
Notional amount - currency forwards USD/BRL 333 -----333
\n
Average currency forward rate - USD/BRL 5.61
\n
Notional amount - currency forwards EUR/CNH 311 -----311
\n
Average currency forward rate - EUR/CNH 7.41
\n
Notional amount - currency forwards USD/CLP 199 20----219
\n
Average currency forward rate - USD/CLP 906.90 921.05
\n
Notional amount - currency forwards USD/COP 156 2----158
\n
Average currency forward rate - USD/COP 4,720.74 4,444.96
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026 Beyond Total
\n
At Dec. 31, 2021
\n
Cross currency interest rate swap (CCIRS)
\n
Total notional amount of CCIRS 258 1,574 4,638 1,002 1,153 12,814 21,439
\n
Notional amount for CCIRS EUR/USD - 1,104 2,158 661 1,104 8,632 13,659
\n
Average exchange rate EUR/USD 1.33 1.13 1.17 1.18 1.21
\n
Notional amount for CCIRS EUR/GBP - - 1,012 - - 3,678 4,690
\n
Average exchange rate EUR/GBP 0.88 0.82
\n
Notional amount for CCIRS EUR/CHF - - 218 - - 126 344
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 98 132 295 155 49 244 973
\n
Average exchange rate USD/BRL 4.81 5.22 5.55 5.29 5.39 3.57
\n
Notional amount for CCIRS EUR/BRL 160 339 402 79 - 77 1,057
\n
Average exchange rate EUR/BRL 6.41 6.44 6.25 6.71 3.92
\n
Currency forward
\n
Total notional amount of forwards 4,324 1,320 371 4 - - 6,019
\n
Notional amount - currency forwards EUR/USD 3,064 1,268 371 4 - - 4,707
\n
Average currency forward rate - EUR/USD 1.16 1.19 1.18 1.18
\n
Notional amount - currency forwards USD/BRL 311 -----311
\n
Average currency forward rate - USD/BRL 5.65
\n
Notional amount - currency forwards USD/COP 284-----284
\n
Average currency forward rate - USD/COP 3,963.3
\n
Notional amount - currency forwards USD/CLP 145-----145
\n
Average currency forward rate - USD/CLP 818.94
\n
Notional amount - currency forwards USD/CAD 107-----107
\n
Average currency forward rate - USD/CAD 1.24
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the currency risk of
\n
transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument Hedged item Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
15 (99) 1,097 12 - 595
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings in foreign
\n
currencies
\n
-- -30-77
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings/financial
\n
assets in foreign currencies
\n
95 (76) 1,061 88 (19) 953
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
4 (233) 2,445 43 (58) 2,553
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate bonds in foreign
\n
currencies
\n
60 - 414 37 - 344
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
1,864 (1,293) 23,381 1,159 (1,095) 16,601
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Future cash flows denominated in
\n
foreign currencies
\n
- (50) 335 - (75) 316
\n
Currency forwards
\n
Future cash flows denominated in
\n
foreign currencies
\n
9 (6) 326 7 (3) 378
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign currencies
\n
192 (135) 7,508 106 (36) 4,802
\n
Currency forwards
\n
Purchases of investment goods and
\n
other in foreign currencies
\n
19 (23) 1,292 20 (7) 839
\n
Tot al 2,258 (1,915) 37,859 1,502 (1,293) 27,458
\n
Cash flow hedges and fair value hedges include:
\n
\u2022 CCIRSs with a notional amount of \u20ac26,923 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac258 million;
\n
\u2022 CCIRSs with a notional amount of \u20ac1,810 million used to
\n
hedge the currency risk on floating-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac29 million;
\n
\u2022 currency forwards with a notional amount of \u20ac7,834
\n
million used to hedge the currency risk associated with
\n
purchases of natural gas, purchases of fuel and expect-
\n
ed cash flows in currencies other than the euro, with a
\n
total positive fair value of \u20ac60 million;
\n
\u2022 currency forwards with a notional amount of \u20ac1,292
\n
million and a negative fair value of \u20ac4 million, in respect
\n
of OTC transactions to mitigate the currency risk on ex-
\n
pected cash flows in currencies other than the presen-
\n
tation currency connected with the purchase of invest-
\n
ment goods in the renewables and infrastructure and
\n
networks sectors (new generation digital meters), on
\n
operating costs for the supply of cloud services and on
\n
revenue from the sale of renewable energy.
\n
The following table reports the notional amount and fair
\n
value of foreign exchange derivatives at December 31,
\n
2022 and December 31, 2021, broken down by type of
\n
hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
CCIRS 99 672 15 42 998 - (99) -
\n
Total 99 672 15 42 998 - (99) -
\n
Cash flow hedges
\n
Currency forwards 4,313 4,117 220 133 4,813 1,902 (164) (46)
\n
CCIRS 16,695 13,553 2,023 1,327 10,941 7,214 (1,652) (1,247)
\n
Total 21,008 17,670 2,243 1,460 15,754 9,116 (1,816) (1,293)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
21,107 18,342 2,258 1,502 16,752 9,116 (1,915) (1,293)
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The notional amount of CCIRS at December 31, 2022
\n
amounted to \u20ac28,733 million (\u20ac21,439 million at Decem-
\n
ber 31, 2021), an increase of \u20ac7,294 million. Cross curren-
\n
cy interest rate swaps with a total amount of \u20ac258 million
\n
expired, while new derivatives amounted to \u20ac7,500 million,
\n
of which \u20ac6,936 million in respect of bond issues denomi-
\n
nated in British pounds and US dollars in 2022. In addition,
\n
following the novation of a bond in US dollars from Enel
\n
Finance International to Enel Finance America, cross cur-
\n
rency interest rate swaps of \u20ac662 million were terminated
\n
early. The amount also reflects developments in the ex-
\n
change rate of the euro against the main other currencies
\n
and the effect of amortization, which caused their notional
\n
amount to increase by \u20ac714 million.
\n
The notional amount of currency forwards at December
\n
31, 2022 amounted to \u20ac9,126 million (\u20ac6,019 million at De-
\n
cember 31, 2021), an increase of \u20ac3,107 million. The expo-
\n
sure to currency risk, especially that associated with the US
\n
dollar, is mainly due to purchases of natural gas, purchases
\n
of fuel and cash flows in respect of investments. Changes
\n
in the notional amount are connected with a greater ex-
\n
posure to exchange rate risk, in particular towards the US
\n
dollar, resulting from the increase in natural gas prices and
\n
the recovery in the generation of electricity from coal.
\n

\n

\n\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss, reflecting changes in the fair
\n
value of fair value hedge derivatives and the hedged item
\n
that are attributable to currency risk for 2022 and the pre-
\n
vious year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (119) 9
\n
Hedged item 129 (8)
\n
Ineffective portion 10 1
\n
The following table shows the impact of fair value hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 1,097 (84) (87) 672 42 37
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds in foreign currencies 525 (109) 70 639 35
\n
(40)
\n
Floating-rate borrowings/bonds in foreign
\n
currencies
\n
449 (10) 13 - -
\n
-
\n
Total 974 (119) 83 639 35 (40)
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on currency
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 2,243 1,256 889 320 299 2,197
\n
-
\n
Negative fair value (1,816) (58) (53) (97) 7 (361) -
\n
The following table shows the impact of cash flow hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and at December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 27,636 371 433 20,767 80 82
\n
Currency forwards 9,126 56 56 6,019 87 89
\n
Total 36,762 427 489 26,786 167 171
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Other effects
\n
through
\n
profit or
\n
loss
\n
(1)
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
borrowings in foreign
\n
currencies
\n
(30) 30 - (11) - (69) 69 - -
\n
Fixed-rate
\n
borrowings in foreign
\n
currencies
\n
225 (225) (4) - - 15 (15) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(60) 60 - - - (37) 37 - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
(628) 509 (56) - 118 (66) 66 (2) -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with CCIRSs)
\n
50 (50) - - - 75 (75) - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(3) 3 - - - (2) 2 1 -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
(60) 59 (1) (1) - (72) 72 - -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
7 (7) 1 2 - (15) 15 (3) -
\n
Total (499) 379 (60) (10) 118 (171) 171 (4) -
\n
(1) The impact is connected with changes in spot rates between the date of inception of the CCRIS entered into to hedge bonds denominated in foreign cur-
\n
rencies and the actual disbursement of the loan.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Commodity price risk
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Commodity swaps
\n
Notional amount on electricity 653 164 143 139 132 333 1,564
\n
Average commodity swap price on power (\u20ac/MWh) 162.5 77.9 48.9 47.2 45.8 29.0
\n
Notional amount on coal/shipping 1,037 - - - - - 1,037
\n
Average commodity swap price on coal/shipping ($/t) 293.7-----
\n
Notional amount on gas 1,183 1,184 1,205 23 20 65 3,680
\n
Average commodity swap price on gas (\u20ac/MWh) 60.1 47.9 52.0 21.0 8.3 7.2
\n
Notional amount on oil 1,076 227 48---1,351
\n
Average commodity swap price on oil ($/bbl) 105.0 93.0 82.0---
\n
Commodity forwards/futures
\n
Notional amount on power 2,906 509 388 294 249 720 5,066
\n
Average commodity forward/future price on power (\u20ac/MWh) 148.1 35.2 17.4 17.8 15.8 15.6
\n
Notional amount on coal/shipping - - - ----
\n
Average commodity forward/future price on coal/shipping ($/ton) - -----
\n
Notional amount on gas 7,171 4,099 229 - - - 11,499
\n
Average commodity forward/future price on gas (\u20ac/MWh) 72.9 92.1 56.6---
\n
Notional amount on CO
\n
2
\n
1,63522650---1,911
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/ton) 81.3 94.9 94.0 - - -
\n
Notional amount on oil 1,263 58----1,321
\n
Average commodity forward/future price on oil ($/bbl) 81.7 73.9 - - - -
\n
Commodity options
\n
Notional amount on power 16 16 16 16 16 117 197
\n
Average commodity option price on power (\u20ac/MWh) 35.0 35.0 35.0 35.0 35.0 33.0
\n
Notional amount on gas -------
\n
Average commodity option price on gas (\u20ac/MWh) ------
\n
Notional amount on oil 70-----70
\n
Average commodity option price on oil ($/bbl) 133-----
\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026
\n
Beyond To ta l
\n
At Dec. 31, 2021
\n
Commodity swap
\n
Notional amount on power 124 164 168 149 146
\n
472 1,223
\n
Average commodity swap price on power (\u20ac/MWh) 51.8 53.7 47.5 46.6 46.0
\n
33.2
\n
Notional amount on gas 131 372 129 11 17 93 753
\n
Average commodity swap price on gas (\u20ac/MWh) 63.8 13.7 12.1 9.4 12.0 9.6
\n
Notional amount on oil 669 244 99 - -
\n
- 1,012
\n
Average commodity swap price on oil ($/bbl) 86.4 92.9 79.4 - -
\n
-
\n
Commodity forwards/futures
\n
Notional amount on power 319 637 302 288 248
\n
856 2,650
\n
Average commodity forward/future price on power (\u20ac/MWh) 29.7 43.3 20.0 19.7 18.7 16.6
\n
Notional amount on coal/shipping 14 - - - -
\n
- 14
\n
Average commodity forward/future price on coal/shipping ($/ton) 90.8----
\n
-
\n
Notional amount on gas 3,315 1,048 5 - - - 4,368
\n
Average commodity forward/future price on gas (\u20ac/MWh) 15.1 18.9 18.0---
\n
Notional amount on CO
\n
2
\n
47661----537
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/t) 46.1 38.4----
\n
Notional amount on oil 600 57 - - - - 657
\n
Average commodity forward/future price on oil ($/bbl) 37.7 51.6---
\n
-
\n
Commodity options
\n
Notional amount on power 10 21 21 21 21
\n
134 228
\n
Average commodity option price on power (\u20ac/MWh) 26.3 29.3 29.9 29.8 29.8
\n
32.6
\n
Notional amount on gas 99----- 99
\n
Average commodity option price gas (\u20ac/MWh) 50.5 - - - -
\n
-
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports the notional amount and fair
\n
value of instruments hedging commodity price risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021, broken down by type of commodity.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives
\n
Cash flow hedges
\n
Derivatives on power:
\n
- swaps 1,213 820 982 640 352 401 (498) (263)
\n
- forwards/futures 1,535 769 89 1,073 3,510 1,881 (898) (598)
\n
- options 218 229 36 49 - - (12) (18)
\n
Total derivatives on power 2,966 1,818 1,107 1,762 3,862 2,282 (1,408) (879)
\n
Derivatives on coal/shipping:
\n
- swaps 9 - 2 - 1,028 - (373) -
\n
- forwards/futures - 14 - 3 - - - -
\n
- options - - - -----
\n
Total derivatives on coal/shipping 9 14 2 3 1,028 - (373) -
\n
Derivatives on gas and oil:
\n
- swaps 2,302 669 666 69 2,729 1,095 (765) (99)
\n
- forwards/futures 4,734 3,094 1,714 2,557 8,085 1,932 (5,182) (5,150)
\n
- options 22 30 4 3 48 70 (4) (26)
\n
Total derivatives on gas and oil 7,058 3,793 2,384 2,629 10,862 3,097 (5,951) (5,275)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps --------
\n
- forwards/futures 1,704 537 143 410 207 - (7) -
\n
- options --------
\n
Total derivatives on CO
\n
2
\n
1,704 537 143 410 207 - (7) -
\n
TOTAL COMMODITY DERIVATIVES 11,737 6,162 3,636 4,804 15,959 5,379 (7,739) (6,154)
\n
The table reports the notional amount and fair value of de-
\n
rivatives hedging commodity price risk at December 31,
\n
2022 and at December 31, 2021, broken down by type of
\n
hedge.
\n
The positive fair value of cash flow hedge derivatives on
\n
commodities regards derivatives on gas and oil commod-
\n
ities in the amount of \u20ac2,384 million, derivatives on CO
\n
2
\n
\n
(\u20ac143 million), derivatives on power (\u20ac1,107 million) and, to
\n
a lesser extent, hedges of coal purchases requested by the
\n
generation companies in the amount of \u20ac2 million.
\n
The first category primarily regards hedges of fluctuations
\n
in the price of natural gas, for both purchases and sales,
\n
carried out for oil commodities and gas products.
\n
The CO
\n
2
\n
category mainly includes hedging transactions
\n
undertaken for Enel Group compliance purposes.
\n
The power category mainly includes medium/long-term
\n
hedging transactions, especially in Spain and North Amer-
\n
ica.
\n
Cash flow hedge derivatives on commodities included in
\n
liabilities regard derivatives on gas and oil commodities in
\n
the amount of \u20ac5,951 million (mainly for derivatives hedg-
\n
ing sales), derivatives on power in the amount of \u20ac1,408
\n
million and, to a lesser extent, derivatives on coal and CO
\n
2
\n
\n
in the amount of respectively \u20ac373 million and \u20ac7 million.
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on commodity
\n
price risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on commodities
\n
Positive fair value 3,838 2,438 829 160 101 93 217
\n
Negative fair value (7,941) (4,598) (2,116) (619) (180) (153) (275)
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table shows the impact of cash flow hedges
\n
of commodity price risk in the statement of financial posi-
\n
tion at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Power swaps 1,564 485 469 1,221 377 377
\n
Coal/shipping swaps 1,037 (371) (371) - - -
\n
Gas and oil swaps 5,031 (99) (98) 1,764 (30)
\n
(30)
\n
Power forwards/futures 5,045 (809) (938) 2,675 (223) (223)
\n
Coal/shipping forwards/futures - - - 14 3 3
\n
Gas and oil forwards/futures 12,820 (3,469) (3,673) 5,027 (2,592) (2,592)
\n
CO
\n
2
\n
forwards/futures 1,911 136 138 537 410 410
\n
Power options 218 24 24 204 7 7
\n
Gas and oil options 70 - - 99 (24)
\n
(24)
\n
Total 27,696 (4,103) (4,449) 11,541 (2,072) (2,072)
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Future transactions in power 602 (602) 15 (32) (297) 297 -
\n
(29)
\n
Future transactions in coal/shipping 371 (371) - - (3) 3 - -
\n
Future transactions in gas and oil 3,360 (3,360) - (232) 2,751 (2,751) - (2)
\n
Future transactions in CO
\n
2
\n
(133) 133 - - (410) 410 - -
\n
Total 4,200 (4,200) 15 (264) 2,041 (2,041) - (31)
\n
With regard to cash flow hedge derivatives on commodity
\n
prices, the entire commodities market continued to expe-
\n
rience major price swings in 2022. The greatest impact in
\n
terms of changes in the cash flow hedge reserve is attrib-
\n
utable to future transactions in gas, which of all commodi-
\n
ties was the one most affected by the high volatility.
\n
Finally, the ineffectiveness recognized in 2022 on future
\n
transactions in gas is mainly related to proxy hedging op-
\n
erations in Spain.
\n

\n\n

\n\n

\n\n

\n\n
51.2 Derivatives at fair value through profit or loss
\n
The following table shows the notional amount and the fair
\n
value of derivatives at FVTPL as at December 31, 2022 and
\n
December 31, 2021.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL
\n
on interest rates:
\n
- interest rate swaps - 50 - 1 100 100 (23) (71)
\n
- interest rate options -----50-(2)
\n
on exchange rates:
\n
- currency forwards 3,659 2,180 75 23 2,102 3,628 (34) (62)
\n
- CCIRS ----46-(1)-
\n
- on commodities
\n
Derivatives on power:
\n
- swaps 595 777 106 (78) 245 1,088 (180) (198)
\n
- forwards/futures 6,903 23,207 872 3,368 5,620 17,970 (908) (2,927)
\n
- options 7 3 15 78 140 113 (172) (16)
\n
Total derivatives on power 7,505 23,987 993 3,368 6,005 19,171 (1,260) (3,141)
\n
Derivatives on coal:
\n
- swaps - 35 - 4 - 133 - 23
\n
- forwards/futures 115 213 21 63 1,291 455 (9) (148)
\n
- options - -------
\n
Total derivatives on coal 115 248 21 67 1,291 588 (9) (125)
\n
Derivatives on gas and oil:
\n
- swaps 1,964 2,904 806 (1,049) 834 4,199 (550) 1,843
\n
- forwards/futures 40,669 19,001 10,456 16,706 38,651 16,755 (10,280) (17,374)
\n
- options 34 232 8 268 33 399 (22) (402)
\n
Total derivatives on gas and oil 42,667 22,137 11,270 15,925 39,518 21,353 (10,852) (15,933)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps --------
\n
- forwards/futures 725 3,079 115 557 361 1,366 (35) (530)
\n
- options 2 - 2 -----
\n
Total derivatives on CO
\n
2
\n
727 3,079 117 557 361 1,366 (35) (530)
\n
Derivatives on other:
\n
- swaps -----1-(1)
\n
- forwards/futures 13 - 72 - 5 - (16) -
\n
- options --------
\n
Total derivatives on other 13 - 72 - 5 1 (16) (1)
\n
Embedded derivatives --------
\n
TOTAL 54,686 51,681 12,548 19,941 49,428 46,257 (12,230) (19,865)
\n
At December 31, 2022 the notional amount of trading de-
\n
rivatives on interest rates came to \u20ac100 million. The neg-
\n
ative fair value of \u20ac23 million improved by \u20ac48 million on
\n
the previous year, mainly due to developments in the yield
\n
curve.
\n
At December 31, 2022, the notional amount of derivatives
\n
on exchange rates was \u20ac5,761 million. The overall decrease
\n
in their notional value of \u20ac47 million and the increase in
\n
the associated net fair value of \u20ac80 million mainly reflected
\n
normal operations and developments in exchange rates.
\n

\n\n

\n\n

\n

\n

\n\n
At December 31, 2022, the notional amount of derivatives
\n
on commodities came to \u20ac98,207 million. The fair value
\n
of trading derivatives on commodities classified as as-
\n
sets mainly reflects the market valuation of hedges of gas
\n
and oil amounting to \u20ac11,270 million, derivatives on power
\n
amounting to \u20ac993 million, derivatives on CO
\n
2
\n
amounting
\n
to \u20ac117 million and, to a lesser extent, derivatives on coal
\n
and other commodities totaling \u20ac21 million and \u20ac72 mil-
\n
lion, respectively.
\n
The fair value of trading derivatives on commodities
\n
classified as liabilities mainly regards hedges of gas and
\n
oil amounting to \u20ac10,852 million, derivatives on power
\n
amounting to \u20ac1,260 million and derivatives on CO
\n
2
\n
, coal
\n
and other commodities in the amount of \u20ac35 million, \u20ac9
\n
million and \u20ac16 million, respectively.
\n
These amounts include transactions managed within the
\n
trading portfolios and transactions that, although estab-
\n
lished for hedging purposes, did not meet the require-
\n
ments for hedge accounting.
\n
The \u201cother\u201d category includes hedges using carried out
\n
on guarantees of origin and green certificates, i.e., incen-
\n
tive mechanisms for the production of electricity from re-
\n
newable sources. In addition to commodity price risk, the
\n
Group companies have to manage the risk of fluctuations
\n
in the price of these certificates which were recently af-
\n
fected by greater market volatility compared with the past,
\n
due to the increasing market attention to environmental
\n
sustainability issues.
\n

\n\n\n

\n
Fair value measurement
\n\n
52. Assets and liabilities measured at
\n
fair value
\n
The Group determines fair value in accordance with IFRS
\n
13 whenever such measurement is required by the IFRS as
\n
a recognition or measurement criterion.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The best proxy of fair value is market price, i.e., the current
\n
publicly available price actually used on a liquid and active
\n
market.
\n
The fair value of assets and liabilities is classified in accor-
\n
dance with the three-level hierarchy described below, de-
\n
pending on the inputs and valuation techniques used in
\n
determining their fair value:
\n
\u2022 Level 1, where the fair value is determined on the basis
\n
of quoted prices (unadjusted) in active markets for iden-
\n
tical assets or liabilities that the entity can access at the
\n
measurement date;
\n
\u2022 Level 2, where the fair value is determined on the basis
\n
of inputs other than quoted prices included within Level
\n
1 that are observable for the asset or liability, either di-
\n
rectly (such as prices) or indirectly (derived from prices);
\n
\u2022 Level 3, where the fair value is determined on the basis
\n
of unobservable inputs.
\n
This note also provides detailed disclosures concerning
\n
the valuation techniques and inputs used to perform these
\n
measurements.
\n
To that end:
\n
\u2022 recurring fair value measurements of assets or liabilities
\n
are those required or permitted by the IFRS in the state-
\n
ment of financial position at the close of each period;
\n
\u2022 non-recurring fair value measurements are those re-
\n
quired or permitted by the IFRS in the statement of fi-
\n
nancial position in particular circumstances.
\n
For general information or specific disclosures on the ac-
\n
counting treatment of these circumstances, please see
\n
note 2 \u201cAccounting policies\u201d.
\n
52.1 Assets measured at fair value in the
\n
statement of financial position
\n
The following table shows, for each class of assets mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position, the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
of those assets are classified.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2022
\n
Equity investments in other
\n
companies at FVOCI
\n
29 360 14 43 303 - - - -
\n
Securities at FVOCI 29.1, 30.1 447 447 - - 78 78 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
94 - 94 - 201 - 201 -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 7--7 ----
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 3,436 - 3,436 - - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
8--8 176176--
\n
Other cash investments at
\n
FVTPL
\n
---- 87242-830
\n
Non-monetary grants in
\n
respect of environmental
\n
certificates
\n
16--16 ----
\n
Fair value hedge derivatives:
\n
- on interest rates 51 22 - 22 - - - - -
\n
- on exchange rates 51 15 - 15 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 336 - 336 - - - - -
\n
- on exchange rates 51 1,854 - 1,854 - 389 - 389 -
\n
- on commodities 51 1,270 314 300 656 2,366 496 1,597 273
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 74 - 74 -
\n
- on commodities 51 472 109 362 1 12,001 10,640 1,360 1
\n
Inventories measured at fair
\n
value
\n
51 15 15 - - 18 - 18 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n
The fair value of \u201cEquity investments in other companies
\n
at FVOCI\u201d is determined for listed companies on the basis
\n
of the quoted price at the close of the year, while that for
\n
unlisted companies is based on a reliable valuation of the
\n
relevant assets and liabilities.
\n\n
\u201cFinancial assets from service concession arrangements
\n
at FVTPL\u201d concern electricity distribution operations in
\n
Brazil, mainly by Enel Distribui\u00e7\u00e3o Rio de Janeiro, Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1, and Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, as well as
\n
the generation plant of PH Chucas in Costa Rica, and are
\n
accounted for in accordance with IFRIC 12.
\n

\n\n
Fair value was estimated as the net replacement cost
\n
based on the most recent rate information available and
\n
on the general price index for the Brazilian market.
\n
The current portion of \u201cLoan assets and other financial as-
\n
sets at FVTPL\u201d essentially regard investments of liquidity.
\n
Their fair value is determined using Level 1 as based on
\n
market inputs.
\n
Level 3 of the non-current portion of \u201cLoan assets and
\n
other financial assets at FVTPL\u201d reports the receivable
\n
in respect of the sale of Slovak Power Holding, which
\n
amounted to \u20ac8 million at December 31, 2022. Its fair value
\n
was determined using the contractual price formula. The
\n
current portion of \u201cLoan assets and other financial assets
\n
at FVTPL\u201d includes under Level 1 investments in securities
\n
and funds held mainly by Latin American companies.
\n
The current portion of \u201cOther cash investments at FVTPL\u201d
\n
at Level 3 mainly refers to the optimization of Enel SpA\u2019s
\n
excess cash holdings.
\n
The fair value of derivative contracts is determined us-
\n
ing the official prices for instruments traded on regulated
\n
markets. The fair value of instruments not listed on a reg-
\n
ulated market is determined using valuation methods ap-
\n
propriate for each type of financial instrument and market
\n
data as of the end of the reporting period (such as interest
\n
rates, exchange rates, volatility), discounting expected fu-
\n
ture cash flows on the basis of the market yield curve and
\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
translating amounts in currencies other than the euro us-
\n
ing exchange rates provided by the World Markets Refinitiv
\n
(WMR) Company.
\n
Derivatives on interest rates and exchange rates are all
\n
measured using Level 2 inputs.
\n
The fair value of derivatives on commodities is almost al-
\n
ways measured using Level 1 or Level 2 inputs, as the de-
\n
termination is based on market inputs as these contracts
\n
are entered into with exchange counterparties, leading
\n
sector operators or financial institutions.
\n
Marginal exceptions include certain derivatives relating to
\n
certain long-term financial contracts (virtual power pur-
\n
chase agreements, or VPPAs), for which internal measure-
\n
ment models were also used in part in order to measure
\n
these instruments over longer time horizons, given the illi-
\n
quidity of the underlying variables.
\n
In accordance with the IFRS, the Group assess credit risk,
\n
both of the counterparty (Credit Valuation Adjustment or
\n
CVA) and its own (Debit Valuation Adjustment or DVA), in
\n
order to adjust the fair value of financial instruments for
\n
the corresponding amount of counterparty risk where
\n
necessary. More specifically, the Group measures CVA/DVA
\n
using a Potential Future Exposure valuation technique for
\n
the net exposure of the position and subsequently allocat-
\n
ing the adjustment to the individual financial instruments
\n
that make up the overall portfolio. All of the inputs used in
\n
this technique are observable on the market.
\n
52.2 Assets not measured at fair value in the
\n
statement of financial position
\n
For each class of assets not measured at fair value on a
\n
recurring basis but whose fair value must be reported, the
\n
following table reports the fair value at the end of the year
\n
and the level in the fair value hierarchy into which the fair
\n
value measurements of those assets are classified.
\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Investment property 22 154 16 - 138 - - - -
\n
Inventories 33 - - - - 47 - - 47
\n
The table reports the fair value of investment property and
\n
inventories of real estate not used in the business in the
\n
amount of \u20ac154 million and \u20ac47 million respectively. The
\n
amounts were calculated with the assistance of apprais-
\n
als conducted by independent experts, who used different
\n
methods depending on the specific assets involved.
\n
52.3 Liabilities measured at fair value in the
\n
statement of financial position
\n
The following table reports for each class of liabilities mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
are classified.
\n
Millions of euro Non-current liabilities Current liabilities
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Fair value hedge derivatives:
\n
- on interest rates 51 92-92- ----
\n
- on exchange rates 51 99 - 99 - - - - -
\n
- on commodities 51 - - - - ----
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 59 - 59 - 1 - 1 -
\n
- on exchange rates 51 1,640 - 1,640 - 176 - 176 -
\n
- on commodities 51 3,417 1,722 1,551 144 4,322 3,049 1,250 23
\n
Trading derivatives:
\n
- on interest rates 51 ---- 23-23-
\n
- on exchange rates 51 1 - 1 - 34 - 34 -
\n
- on commodities 51 587 192 395 - 11,585 10,595 990 -
\n
Contingent consideration 46 - - 46 46 - 44 2
\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
Contingent consideration mainly regards a number of
\n
equity investments held by the Group in North America,
\n
whose fair value was determined on the basis of the con-
\n
tractual terms and conditions.
\n
52.4 Liabilities not measured at fair value in the
\n
statement of financial position
\n
For each class of liabilities not measured at fair value in the
\n
statement of financial position but whose fair value must
\n
be reported, the following table reports the fair value at the
\n
end of the period and the level in the fair value hierarchy
\n
into which the fair value measurements of those liabilities
\n
are classified.
\n
Millions of euro
\n
Notes Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022
\n
Bonds:
\n
- fixed rate 48.3.1 44,717 41,964 2,753 -
\n
- floating rate 48.3.1 3,073 62 3,011 -
\n
Bank borrowings:
\n
- fixed rate 48.3.1 3,021 - 3,021 -
\n
- floating rate 48.3.1 12,596 - 12,596 -
\n
Non-bank borrowings:
\n
- fixed rate 48.3.1 3,134 - 3,134 -
\n
- floating rate 48.3.1 54 - 54 -
\n
Tot al 66,595 42,026 24,569 -
\n
For listed debt instruments, the fair value is given by official
\n
prices. For unlisted instruments the fair value is determined
\n
using appropriate valuation techniques for each category
\n
of financial instrument and market data at the close of the
\n
year, including the credit spreads of Enel.
\n

\n\n

\n\n
Other information
\n\n
53. Share-based payments
\n
Starting in 2019, the Shareholders\u2019 Meeting of Enel SpA
\n
(\u201cEnel\u201d or the \u201cCompany\u201d) has each year approved the
\n
adoption of long-term share-based incentive plans for the
\n
management of Enel and/or its subsidiaries pursuant to
\n
Article 2359 of the Italian Civil Code. Each of the incen-
\n
tive plans approved (the 2019 Long-Term Incentive Plan,
\n
the 2020 Long-Term Incentive Plan, the 2021 Long-Term
\n
Incentive Plan, the 2022 Long-Term Incentive Plan; referred
\n
to hereinafter, respectively, the \u201c2019 LTI Plan\u201d, \u201c2020 LTI
\n
Plan\u201d, the 2021 LTI Plan\u201d, the \u201c2022 LTI Plan\u201d and, jointly, the
\n
\u201cPlans\u201d) provides for the grant of ordinary Company shares
\n
(\u201cShares\u201d) to the respective beneficiaries subject to the
\n
achievement of specific performance targets.
\n
Plan beneficiaries are the Chief Executive Officer/General
\n
Manager of Enel and Enel Group managers in the positions
\n
most directly responsible for company performance or
\n
considered to be of strategic interest. The Plans provide
\n
for the award to the beneficiaries of an incentive consist-
\n
ing of a monetary component and an equity component.
\n
This incentive \u2013 determined, at the time of the award, as
\n
a base value calculated in relation to the fixed remuner-
\n
ation of the individual beneficiary \u2013 may vary depending
\n
on the degree of achievement of each of the three-year
\n
performance targets by the Plans, ranging from zero up to
\n
a maximum of 280% or 180% of the base value in the case,
\n
respectively, of the Chief Executive Officer/General Man-
\n
ager or the other beneficiaries.
\n
The Plans establish that, of the total incentive effectively
\n
vested, the bonus will be fully paid in Shares in the amount
\n
of (i) up to 100% of the base value for the Chief Executive
\n
Officer/General Manager (up to 130% for the 2022 LTI Plan),
\n
and (ii) up to 50% of the base value for the other beneficia-
\n
ries (up to 65% for the 2022 LTI Plan).
\n
The actual award of the bonus under the Plans is subject
\n
to the achievement of specific performance targets during
\n
the three year performance period. If these targets are
\n
achieved, 30% of both the stock and cash components
\n
of the incentive will be paid in the first year following the
\n
end of the performance period and the remaining 70% will
\n
be paid in the second year following the end of the per-
\n

\n\n

\n\n

\n\n
\n
\n
\n

\n
formance period. The payment of a substantial portion
\n
of long-term variable remuneration (70% of the total) is
\n
therefore deferred to the second year following the end of
\n
the performance period of the individual Plans.
\n
The following table provides information on the 2019 LTI
\n
Plan, the 2020 LTI Plan, the 2021 LTI Plan, and the 2022 LTI
\n
Plan.
\n
For more information on the characteristics of the Plans,
\n
please see the information documents prepared pursuant
\n
to Article 84-bis of the CONSOB Regulation issued with
\n
Resolution no. 11971 of May 14, 1999 (the Issuers Regu-
\n
lation), which are available to the public in the section of
\n
Enel\u2019s website (www.enel.com) dedicated to the Sharehold-
\n
ers\u2019 Meetings held respectively on May 16, 2019, May 14,
\n
2020, May 20, 2021 and May 19, 2022.
\n
Grant date Performance period
\n
Verification of
\n
achievement of
\n
targets Payout
\n
2019 LTI Plan 12.11.2019
\n
(47)
\n
2019-2021 2022
\n
(48)
\n
2022-2023
\n
(49)
\n
2020 LTI Plan 17.09.2020
\n
(50)
\n
2020-2022 2023
\n
(51)
\n
2023-2024
\n
2021 LTI Plan 16.09.2021
\n
(52)
\n
2021-2023 2024
\n
(53)
\n
2024-2025
\n
2022 LTI Plan 21.09.2022
\n
(54)
\n
2022-2024 2025
\n
(55)
\n
2025-2026
\n
In implementation of the authorizations granted by the
\n
Shareholders\u2019 Meetings held on May 16, 2019, May 14, 2020,
\n
May 20, 2021 and May 19, 2022, in compliance with the
\n
associated terms and conditions, the Board of Directors
\n
approved \u2013 at is meetings of September 19, 2019, July 29,
\n
2020, June 17, 2021 and June 16, 2022 \u2013 the launch of share
\n
buyback programs to serve the 2019 LTI Plan, the 2020 LTI
\n
Plan, the 2021 LTI Plan and the 2022 LTI Plan, respectively.
\n
The number of Shares whose purchase was authorized by
\n
the Board of Directors for each Plan, the actual number of
\n
Shares purchased, the associated weighted average price
\n
and total value are shown below.
\n
(47) The date on which the Board of Directors approved the procedures and timing for granting the 2019 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of November 11, 2019).
\n
(48) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2021, the Board of Directors verified the level
\n
of achievement of the performance targets of the 2019 LTI Plan.
\n
(49) On September 5, 2022 the Company awarded part of the equity component of the bonus vested by the beneficiaries of the 2019 LTI Plan, in accordance
\n
with the Plan rules.
\n
(50) The date on which the Board of Directors approved the procedures and timing for granting the 2020 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of September 16, 2020).
\n
(51) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2022, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2020 LTI Plan.
\n
(52) The date on which the Board of Directors approved the procedures and timing for granting the 2021 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of June 9, 2021).
\n
(53) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2023, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2021 LTI Plan.
\n
(54) The date on which the Board of Directors approved the procedures and timing for granting the 2022 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of June 8, 2022).
\n
(55) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2024, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2022 LTI Plan.
\n

\n\n

\n\n

\n\n
Purchases authorized by the
\n
Board of Directors Actual purchases
\n
Number of shares Number of shares
\n
Weighted average price
\n
(euros per share) Total value (euros)
\n
2019 LTI Plan
\n
No more than 2,500,000
\n
for a maximum amount of
\n
\u20ac10,500,000 million
\n
1,549,152
\n
(56)
\n
6.7779 10,499,999
\n
2020 LTI Plan 1,720,000 1,720,000
\n
(57)
\n
7.4366 12,790,870
\n
2021 LTI Plan 1,620,000 1,620,000
\n
(58)
\n
7.8737 12,755,459
\n
2022 LTI Plan 2,700,000 2,700,000
\n
(59)
\n
5.1951 14,026,715
\n
As a result of the purchases made to support the 2019 LTI
\n
Plan, the 2020 LTI Plan, the 2021 LTI Plan and the 2022 LTI
\n
Plan, and taking into account the award on September 5,
\n
2022 of 435,357 shares to the beneficiaries of the 2019 LTI
\n
Plan, at December 31, 2022 Enel holds a total of 7,153,795
\n
treasury shares, equal to 0.07% of share capital.
\n
The following information concerns the equity instruments
\n
granted in 2019, 2020, 2021 and 2022.
\n
2022 2021
\n
Number of shares
\n
granted at the grant
\n
date
\n
Fair value per
\n
share at the
\n
grant date
\n
Number of
\n
shares potentially
\n
available for
\n
award
\n
Number of shares
\n
awarded
\n
Number of
\n
shares potentially
\n
available for
\n
award
\n
Number of shares
\n
awarded
\n
2019 LTI Plan 1,538,547 6.983 1,021,328 435,357
\n
(60)
\n
1,529,182 -
\n
2020 LTI Plan 1,638,775 7.380 1,631,951 - 1,638,775 -
\n
2021 LTI Plan 1,577,773 7.0010 1,577,773 - 1,577,773 -
\n
2022 LTI Plan 2,398,143 4.8495 2,395,323 - - -
\n
The fair value of those equity instruments is measured on
\n
the basis of the market price of Enel Shares at the grant
\n
date.
\n
(61)
\n
The cost of the equity component is determined on the
\n
basis of the fair value of the equity instruments granted
\n
and is recognized over the duration of the vesting period
\n
through an equity reserve.
\n
The total costs recognized by the Group through profit or
\n
loss amounted to \u20ac11 million in 2022 (\u20ac9 million in 2021).
\n
There have been no terminations or amendments involving
\n
the 2019 LTI Plan, the 2020 LTI Plan, the 2021 LTI Plan, or the
\n
2022 LTI Plan.
\n
(56) Shares purchased in the period between September 23 and December 2, 2019, equal to about 0.015% of share capital.
\n
(57) Shares purchased in the period between September 3 and October 28, 2020, equal to about 0.017% of share capital.
\n
(58) Shares purchased in the period between June 18 and July 21, 2021, equal to about 0.016% of share capital.
\n
(59) Shares purchased in the period between June 17 and July 20, 2022, equal to about 0.026% of share capital.
\n
(60) The table shows the number of shares awarded on September 5, 2022, to the beneficiaries of the 2019 LTI Plan, which make up the equity component of the
\n
bonus vested by the beneficiaries following the achievement of the performance objectives of the Plan. The disbursement of the remaining portion of the equity
\n
component of the bonus is deferred to 2023, in accordance with the terms and procedures of the rules of the 2019 LTI Plan.
\n
(61) For the 2019 LTI Plan, the grant date is November 12, 2019, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2019 LTI Plan to the beneficiaries.
\n
For the 2020 LTI Plan, the grant date is September 17, 2020, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2020 LTI Plan to the beneficiaries.
\n
For the 2021 LTI Plan, the grant date is September 16, 2021, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2021 LTI Plan to the beneficiaries.
\n
For the 2022 LTI Plan, the grant date is September 21, 2022, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2022 LTI Plan to the beneficiaries.
\n

\n\n

\n\n

\n\n
54. Related parties
\n
As an operator in the field of generation, distribution,
\n
transport and sale of electricity and the sale of natural gas,
\n
Enel carries out transactions with a number of companies
\n
directly or indirectly controlled by the Italian State, the
\n
Group\u2019s controlling shareholder.
\n
The table below summarizes the main types of transac-
\n
tions carried out with such counterparties.
\n
Related party Relationship Nature of main transactions
\n
Single Buyer
\n
Fully controlled (indirectly) by the Ministry for the
\n
Economy and Finance
\n
Purchase of electricity for the enhanced protection market
\n
Cassa Depositi e
\n
Prestiti Group
\n
Directly controlled by the Ministry for the Economy and
\n
Finance
\n
Sale of electricity on the Ancillary Services Market (Terna)
\n
Sale of electricity transport services (Eni Group)
\n
Purchase of transport, dispatching and metering services (Terna)
\n
Purchase of postal services (Poste Italiane)
\n
Purchase of fuels for generation plants and natural gas storage and
\n
distribution services (Eni Group)
\n
ESO - Energy
\n
Services Operator
\n
Fully controlled (directly) by the Ministry for the
\n
Economy and Finance
\n
Sale of subsidized electricity
\n
Payment of A3 component for renewable resource incentives
\n
EMO - Energy
\n
Markets Operator
\n
Fully controlled (indirectly) by the
\n
Ministry for the Economy and Finance
\n
Sale of electricity on the Power Exchange (EMO)
\n
Purchase of electricity on the Power Exchange for pumping and
\n
plant planning (EMO)
\n
Leonardo Group
\n
Directly controlled by the Ministry for the Economy and
\n
Finance
\n
Purchase of IT services and supply of goods
\n
In addition, the Group conducts essentially commercial
\n
transactions with associated companies or companies in
\n
which it holds non-controlling interests.
\n
Finally, Enel also maintains relationships with the pension
\n
funds FOPEN and FONDENEL, as well as Fondazione Enel
\n
and Enel Cuore, an Enel non-profit company devoted to
\n
providing social and healthcare assistance.
\n
All transactions with related parties were carried out on
\n
normal market terms and conditions, which in some cas-
\n
es are determined by the Regulatory Authority for Energy,
\n
Networks and the Environment.
\n

\n\n

\n\n

\n\n
Credit facility guaranteed by SACE - Disclosure
\n
obligations established by Article 13, paragraph
\n
3, letter c) (ii), of CONSOB Regulation on
\n
transactions with related parties
\n
In compliance with the disclosure obligations established
\n
under Article 13, paragraph 3, letter c) (ii), of CONSOB
\n
Regulation no. 17221 of March 12, 2010, as amended (the
\n
\u201cCONSOB Regulation\u201d), and Article 13.4, letter c) (ii), of the
\n
Enel Procedure for Transactions with Related Parties (the
\n
\u201cEnel Procedure\u201d), we hereby disclose that a transaction
\n
with related parties was carried out in 2022 which qualifies
\n
as a transaction of \u201cgreater importance\u201d having an ordinary
\n
nature and completed at market-equivalent or standard
\n
terms. More specifically, on December 23, 2022, Enel SpA
\n
signed with a pool of financial institutions \u2013 composed of
\n
Banco BPM SpA, BPER Banca SpA, Cassa Depositi e Pres-
\n
titi SpA, Intesa Sanpaolo SpA and UniCredit SpA \u2013 a loan
\n
agreement in the form of a revolving credit facility in the
\n
amount of \u20ac12 billion, of which up to 70% of the nominal
\n
amount is guaranteed by SACE SpA.
\n
This credit facility, and the related guarantee, is aimed
\n
at funding the collateral requirements of the Enel Group
\n
companies operating in Italy (specifically Enel Global Trad-
\n
ing SpA) for trading on energy markets and is part of the
\n
temporary measures to support the liquidity of companies,
\n
provided in the form of a guarantee, envisaged by Article
\n
15 of Decree Law 50 of May 17, 2022, ratified with Law 91 of
\n
July 15, 2022 (the so-called \u201cAid Decree Law\u201d), as amended.
\n
The overall transaction qualifies as a transaction with
\n
related parties due to the fact that Enel SpA, Cassa De-
\n
positi e Prestiti SpA and SACE SpA are companies under
\n
the common control of Italy\u2019s Ministry for the Economy
\n
and Finance. Taking into account the amounts indicated
\n
above (and, in particular, in consideration of the value of
\n
the guarantee), it qualifies as a related-party transaction
\n
of \u201cgreater importance\u201d. The transaction in question was
\n
completed applying the exemption pursuant to Article 13,
\n
paragraph 3, letter c), of the CONSOB Regulation and Ar-
\n
ticle 13.4, letter c), of the Enel Procedure, as an ordinary
\n
transaction completed at market-equivalent or standard
\n
terms.
\n
In particular, the transaction is connected with the ordi-
\n
nary exercise of \u201cfinance activity connected to the op-
\n
erations\u201d of the Group headed by Enel SpA, taking into
\n
account, inter alia, the object, recurrence and size of the
\n
same, as well as the nature of the counterparties. Further-
\n
more, the main terms and conditions applicable to it are
\n
governed by Article 15 of the Aid Decree Law. For the por-
\n
tion of the loan for which it is responsible, Cassa Depositi
\n
e Prestiti SpA applied to Enel SpA the same terms and
\n
conditions that are applied by the other banks.
\n
The following tables summarize transactions with relat-
\n
ed parties, associated companies and joint ventures out-
\n
standing at December 31, 2022 and December 31, 2021
\n
and carried out during the period.
\n

\n\n

\n\n

\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Income statement
\n
Revenue from sales and services - 7,949 87 4,497 196
\n
Other income - - - 389 -
\n
Other financial income - - - - -
\n
Electricity, gas and fuel purchases 6,379 16,817 2 4,266 3
\n
Costs for services and other materials - 220 2 3,258 73
\n
Other operating costs 10 147 - 420 3
\n
Net results from commodity contracts - - - 50 -
\n
Other financial expense 1 - 2 10 -
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Statement of financial position
\n
Other non-current financial assets - - - - -
\n
Trade receivables - 220 6 1,040 38
\n
Current financial derivative assets - - - - -
\n
Other current financial assets - - - 5 -
\n
Other current assets - - 30 58 2
\n
Long-term borrowings - - - 447 -
\n
Non-current contract liabilities - - - 9 8
\n
Non-current financial derivative liabilities - - - - -
\n
Short-term borrowings - - - - -
\n
Current portion of long-term borrowings - - - 89 -
\n
Trade payables 1,211 305 6 1,097 (1)
\n
Other current financial liabilities - - - - -
\n
Current contract liabilities - - - 23 20
\n
Other current liabilities - - - 3 23
\n
Other information
\n
Guarantees issued - 20 - 11 58
\n
Guarantees received - - - 134 36
\n
Commitments - - - 149 -
\n

\n\n

\n\n

\n\n
Total 2022
\n
Associates and joint
\n
ventures
\n
Overall total 2022
\n
Total in financial
\n
statements % of total
\n
12,729 210 12,939 135,653 9.5%
\n
389 - 389 4,864 8.0%
\n
- 154 154 3,430 4.5%
\n
27,467 413 27,880 96,896 28.8%
\n
3,553 247 3,800 20,228 18.8%
\n
580 1 581 4,685 12.4%
\n
50 - 50 2,365 2.1%
\n
13 21 34 5,880 0.6%
\n
Total at Dec. 31, 2022
\n
Associates and joint
\n
ventures
\n
Overall total
\n
at Dec. 31, 2022
\n
Total in financial
\n
statements % of total
\n
- 1,885 1,885 8,359 22.6%
\n
1,304 259 1,563 16,605 9.4%
\n
- 5 514,830 -
\n
5 99 104 13,753 0.8%
\n
90 63 153 4,314 3.5%
\n
447 327 774 68,191 1.1%
\n
17 - 17 5,747 0.3%
\n
- 9 9 5,895 0.2%
\n
- 14 14 18,392 0.1%
\n
89 21 110 2,835 3.9%
\n
2,618 192 2,810 17,641 15.9%
\n
- 1 18530.1%
\n
43 - 43 1,775 2.4%
\n
26 21 47 11,713 0.4%
\n
89 - 89
\n
170 - 170
\n
149 - 149
\n

\n\n

\n\n

\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Income statement
\n
Revenue from sales and services - 3,018 275 3,165 210
\n
Other income - - - 5 -
\n
Financial income - - - 15 -
\n
Electricity, gas and fuel purchases 4,613 6,363 - 2,572 -
\n
Costs for services and other materials - 75 3 2,874 57
\n
Other operating costs 6 198 - 13 1
\n
Results from commodity contracts - - - 13 -
\n
Other financial expense - - - 10 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Statement of financial position
\n
Other non-current financial assets -----
\n
Non-current financial derivative assets -----
\n
Other non-current assets - - - 119 -
\n
Trade receivables - 469 9 659 36
\n
Current financial derivative assets -----
\n
Other current financial assets ----1
\n
Other current assets - - 76 21 2
\n
Long-term borrowings - - - 536 -
\n
Non-current contract liabilities - - - 187 7
\n
Non-current financial derivative liabilities -----
\n
Short-term borrowings -----
\n
Current portion of long-term
\n
borrowings
\n
---89-
\n
Trade payables 1,903 641 1 1,466 12
\n
Current contract liabilities - - - 12 -
\n
Other current liabilities - - - 38 38
\n
Other information
\n
Guarantees issued - 40 - 11 59
\n
Guarantees received - - - 138 36
\n
Commitments - - - 401 -
\n

\n\n

\n\n

\n\n
Total 2021
\n
Associates and joint
\n
ventures Overall total 2021
\n
Total in financial
\n
statements
\n
(1)
\n
% of total
\n
6,668 342 7,010 81,900 8.6%
\n
5 1 6 3,819 0.2%
\n
15 123 138 1,862 7.4%
\n
13,548 278 13,826 47,702 29.0%
\n
3,009 143 3,152 19,240 16.4%
\n
218 - 218 1,968 11.1%
\n
13 11 24 2,523 1.0%
\n
10 22 32 6,087 0.5%
\n
Total
\n
at Dec. 31, 2021
\n
Associates and joint
\n
ventures
\n
Overall total
\n
at Dec. 31, 2021
\n
Total in financial
\n
statements % of total
\n
- 1,120 1,120 5,704 19.6%
\n
- 14 14 2,772 0.5%
\n
119 - 119 3,268 3.6%
\n
1,173 148 1,321 16,076 8.2%
\n
- 32 32 22,791 0.1%
\n
1 156 157 8,645 1.8%
\n
99 24 123 5,002 2.5%
\n
536 344 880 54,500 1.6%
\n
194 - 194 6,214 3.1%
\n
- 1 1 3,339 -
\n
- 6 6 13,306 -
\n
89 20 109 4,031 2.7%
\n
4,023 59 4,082 16,959 24.1%
\n
12 - 12 1,433 0.8%
\n
76 4 80 12,959 0.6%
\n
110 - 110
\n
174 - 174
\n
401 - 401
\n

\n\n

\n\n

\n\n
With regard to disclosures on the remuneration of direc-
\n
tors, members of the Board of Statutory Auditors and key
\n
management personnel, provided for under IAS 24, please
\n
see the following tables.
\n
Millions of euro
\n
2022 2021 Change
\n
Remuneration of members of the Board of Directors and Board of
\n
Statutory Auditors and the General Manager
\n
Short-term employee benefits 5 5 - -
\n
Other long-term benefits 1 1 - -
\n
Tot al 66--
\n
Millions of euro
\n
2022 2021 Change
\n
Remuneration of key management personnel
\n
Short-term employee benefits 13 13 - -
\n
Other long-term benefits 2 4 (2) -50%
\n
Tot al 15 17 (2) -11.8%
\n
In November 2010, the Board of Directors of Enel SpA ap-
\n
proved a procedure governing the approval and execution
\n
of transactions with related parties carried out by Enel SpA
\n
directly or through subsidiaries (the \u201cEnel Procedure\u201d). The
\n
procedure (available at https://www.enel.com/investors/
\n
bylaws-rules-and-policies/transactions-with-related-par-
\n
ties/) sets out rules designed to ensure the transparency
\n
and procedural and substantive propriety of transactions
\n
with related parties. It was adopted in implementation of
\n
the provisions of Article 2391-bis of the Italian Civil Code
\n
and the implementing regulations issued by CONSOB with
\n
Resolution no. 17221 of March 12, 2010, as amended (the
\n
\u201cCONSOB Regulation\u201d).
\n

\n\n

\n\n

\n\n
55. Government grants - Disclosure pursuant to Article 1,
\n
paragraphs 125-129, of Law 124/2017
\n
Pursuant to Article 1, paragraphs 125-129, of Law 124/2017
\n
as amended, the following provides information on grants
\n
received from Italian public agencies and bodies, as well
\n
as donations by Enel SpA and the fully consolidated sub-
\n
sidiaries to companies, individuals and public and private
\n
entities. The disclosure comprises: (i) grants received from
\n
Italian public entities/State entities; and (ii) donations
\n
made by Enel SpA and Group subsidiaries to public or pri-
\n
vate parties resident or established in Italy.
\n
The following disclosure includes payments in excess of
\n
\u20ac10,000 made by the same grantor/donor during 2022,
\n
even if made in multiple financial transactions. They are
\n
recognized on a cash basis.
\n
Pursuant to the provisions of Article 3-quater of Decree
\n
Law 135 of December 14, 2018, ratified with Law 12 of Feb-
\n
ruary 11, 2019, for grants received, please refer to the in-
\n
formation contained in the National Register of State Aid
\n
referred to in Article 52 of Law 234 of December 24, 2012.
\n
Grants received in millions of euro
\n
Financial
\n
institution/Grantor Beneficiary Amount Notes
\n
Anpal Enel Green Power
\n
Italia Srl
\n
(0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Green Power
\n
Italia Srl
\n
(0.05) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Invitalia MISE Enel Green Power
\n
Italia Srl
\n
(8.44) Return of instalment of grant under first progress statement of Development
\n
Contract 3SUN HJT, following abandonment of original project to expand the Catania
\n
facility
\n
Anpal Enel Green Power
\n
SpA
\n
(0.07) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Green Power
\n
SpA
\n
(0.05) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Thermal
\n
Generation Srl
\n
(0.06) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Thermal
\n
Generation Srl
\n
(0.02) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Grids (0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Grids (0.04) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global Trading
\n
SpA
\n
(0.005) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global Trading
\n
SpA
\n
(0.006) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Produzione
\n
SpA
\n
(0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Produzione
\n
SpA
\n
(0.03) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal e-distribuzione
\n
SpA
\n
(0.17) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n

\n\n

\n\n

\n\n
Grants received in millions of euro
\n
Financial
\n
institution/Grantor Beneficiary Amount Notes
\n
Anpal e-distribuzione
\n
SpA
\n
(0.10) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Regione Lazio Enel X Srl 0.07 Instalment of grant as balance for the Homix-Care project, funded under the ROP
\n
ERDF Lazio 2014-2020
\n
Anpal Enel X Srl (0.02) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel X Srl (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Sole Srl - Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Sole Srl (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Regione Sicilia Enel X Mobility Srl 2.03 Instalment of grant for Sicilia Smart Charging project, financed by the Region of Sicily
\n
through National Plan for Electric Vehicle Charging Infrastructure
\n
Anpal Servizio Elettrico
\n
Nazionale SpA
\n
(0.02) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Servizio Elettrico
\n
Nazionale SpA
\n
(0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Energia SpA (0.14) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Energia SpA (0.02) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Services Srl
\n
(0.06) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Services Srl
\n
(0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Italia SpA (0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Italia SpA (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
(7.413) Total
\n

\n\n

\n\n

\n\n
Grants made in millions of euro
\n
Grantor Beneficiary Amount Notes
\n
Enel SpA FGS Onlus 0.05 Donation to promote equal opportunities
\n
Enel SpA European University Institute 0.10 Donation for scientific research on European energy issues
\n
Enel SpA Fondazione Centro Studi Enel 0.10 Enel Foundation grant
\n
Enel SpA Earthrise Trust 0.01 Donation for rural development projects
\n
Enel SpA International Energy Agency 0.08 Donation for the study of the energy market
\n
Enel SpA Comunit\u00e0 Sant\u2019Egidio 0.04 Gadgets donation
\n
Enel SpA Associazione UISP Unione Italiana
\n
Sport per Tutti
\n
0.03 Gadgets donation
\n
Enel SpA Onlus CESIE 0.06 Gadgets donation
\n
Enel SpA Onlus Sport Senza Frontiere 0.02 Gadgets donation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.06 30% 1st tranche - project presentation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.06 30% 2nd tranche - digital content creation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.08 40% last tranche - conclusion
\n
Enel Produzione SpA Fondazione Centro Studi Enel 0.09 Enel Foundation \u2013 balance of 2021 grant
\n
Enel Produzione SpA Fondazione Centro Studi Enel 0.48 Enel Foundation \u2013 1st instalment of 2022 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.13 2nd instalment of Enel Cuore 2021 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.18 1st instalment of Enel Cuore 2022 grant
\n
Enel Produzione SpA Fondazione WWF Italia 0.01 Agreement Enel Produzione
\n
Enel Produzione SpA Associazione Le Colonne 0.03 Donation \u201cAccogliere ad Arte\u201d
\n
Enel Italia SpA Enel Cuore Onlus 0.15 2021 grant
\n
Enel Italia SpA Societ\u00e0 Coop, Greenwill 0.01 Modal donation \u201cAlleva la speranza Greenwill\u201d
\n
Enel Italia SpA Foglietti Enrico 0.01 Modal donation \u201cAlleva la speranza Foglietti Enrico\u201d
\n
Enel Italia SpA Feat Impresa Locale 0.02 1st instalment 2022 donation WE Feat arl
\n
Enel Italia SpA Help Code Italia 0.04 Enel Helpcode project \u201c\u00c8 viva la scuola labs\u201d
\n
Enel Italia SpA Fondazione Accademia Nazionale
\n
\u201cSanta Cecilia\u201d
\n
0.60 Modal donation 2022
\n
Enel Italia SpA Fondazione Teatro alla Scala 0.60 Donation 2022
\n
Enel Italia SpA Fondazione Teatro Maxxi 0.60 Modal donation 2022
\n
Enel Italia SpA Enel Cuore Onlus 0.02 Extraordinary contribution 2022
\n
Enel Italia SpA Fondazione Centro Studi Enel 0.05 Grants 2022
\n
Enel Italia SpA Help Code Italia 0.02 Payment for the start of energy courses
\n
Enel Italia SpA Moige - Movimento italiano genitori
\n
Onlus
\n
0.05 Donation to support the Young Ambassadors Campaign for digital citizenship
\n
to counter cyber risk, bulling and cyberbullying in all its forms - 2nd instalment
\n
and balance
\n
Enel Italia SpA Fondazione Centro Studi Enel 0.11 Balance of 2021 grant
\n
e-distribuzione SpA Enel Cuore Onlus 2.09 80% balance of 2021 grant
\n
e-distribuzione SpA Enel Cuore Onlus 0.47 20% instalment of 2022 grant
\n
e-distribuzione SpA Fondazione Centro Studi Enel 1.41 50% balance of 2021 grant
\n
e-distribuzione SpA Fondazione Centro Studi 1.28 50% instalment of 2022 grant
\n
Enel X Srl Enel Cuore Onlus 0.04 2022 grant
\n
Enel Green Power Italia Unione dei Comuni Montani Amiata
\n
Grossetana (Sarchioto - Borrello -
\n
Simoni Giorgio)
\n
0.04 Donation to the Union of Amiata Grossetana mountain municipalities as part
\n
of sustainability activities linked to the BG3 power station smart repowering
\n
project, for the \u201cNon Solo Neve\u201d and \u201cFondo per la Montagna\u201d projects
\n
developed by the beneficiary. The projects envisage the construction and
\n
redevelopment of a bike-pedestrian path with urban furniture and signage for
\n
the benefit of the area, also affecting municipalities with a geothermal vocation
\n
in an area where Enel Green Power has been operating for a long time
\n
Enel Energia SpA Confimprese 0.01 Association dues 2022 - 029/22
\n
Enel Energia SpA Anigas 0.10 Association dues 2022
\n
Enel Energia SpA Fondazione Centro Studi Enel 1.01 Balance 2021 grant
\n
Enel Energia SpA Enel Cuore Onlus 1.49 Balance 2021 grant
\n
Enel Energia SpA Enel Cuore Onlus 0.20 \u201cNel Cuore dello Spazio Enel\u201d project
\n
Enel Energia SpA Enel Cuore Onlus 0.33 20% instalment of 2022 grant
\n
Enel Energia SpA Fondazione Centro Studi Enel 0.90 50% instalment of 2022 grant
\n
Enel Energia SpA Associazione Milano & Partners 0.05 Association dues 2022
\n
Enel Energia SpA Assonime 0.02 Association dues 2022
\n
Enel Energia SpA Proxigas 0.10 Balance Proxigas
\n
Enel Energia SpA Enel Cuore Onlus 0.04 Association dues
\n
Enel Global Trading SpA Enel Cuore Onlus 0.14 Contribution aimed at supporting and developing projects of Enel Cuore Onlus
\n
Enel Global Trading SpA Fondazione Centro Studi Enel
\n
0.10 Contribution aimed at supporting and developing Research and Higher
\n
Education projects
\n
13.71 Total
\n

\n\n

\n\n

\n\n

\n\n
56. Contractual commitments and guarantees
\n
The commitments entered into by the Enel Group and the
\n
guarantees given to third parties are shown below.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Guarantees given:
\n
- sureties and other guarantees granted to third parties 4,296 4,937 (641)
\n
Commitments to suppliers for:
\n
- electricity purchases 64,878 71,244 (6,366)
\n
- fuel purchases 96,996 58,042 38,954
\n
- various supplies 2,449 1,631 818
\n
- tenders 6,165 4,668 1,497
\n
- other 6,889 6,187 702
\n
Tot al 177,377 141,772 35,605
\n
TOTAL 181,673 146,709 34,964
\n
Compared with December 31, 2021, the decrease of
\n
\u20ac6,366 million in commitments for \u201celectricity purchases\u201d
\n
is essentially attributable to companies in Latin America,
\n
in particular in Brazil, and mainly reflects the sale of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), partially offset by the
\n
increase in Chile, mainly attributable to new contracts and
\n
developments in commodity prices.
\n
The increase of \u20ac38,954 million in commitments for \u201cfuel
\n
purchases\u201d mainly regards gas supplies, especially in Italy
\n
and Spain, and reflected the increase in demand for natu-
\n
ral gas and in gas prices.
\n
For more details on the expiry of commitments and guar-
\n
antees, please see the section \u201cCommitments to purchase
\n
commodities\u201d in note 49.
\n

\n\n

\n\n

\n\n

\n\n
57. Contingent assets and liabilities
\n
The following reports the main contingent assets and lia-
\n
bilities at December 31, 2022, which are not recognized in
\n
the consolidated financial statements as they do not meet
\n
the requirements provided for in IAS 37.
\n
Brindisi Sud thermal generation plant - Ash
\n
dispute - Italy
\n
With regard to the criminal investigation initiated by the
\n
Public Prosecutor\u2019s Office of the Court of Lecce in 2017
\n
concerning the use of fly ash in the cement industry, the
\n
Brindisi Sud power plant was involved in a criminal inves-
\n
tigation involving accused individuals and Enel Produzione
\n
(EP) pursuant to Legislative Decree 231 of June 8, 2001,
\n
that resulted in the issue of a preventive seizure order that
\n
allowed operation of the plant as well as the seizure of EP
\n
assets and receivables up to an amount of about \u20ac500
\n
million. The seizures were subsequently revoked follow-
\n
ing the positive outcome of testing by the independent
\n
experts appointed by the investigating magistrate, which
\n
confirmed the non-hazardous nature of the ash, finding it
\n
suitable for use in the cement-making process, as well as
\n
the appropriateness of the operation of the plant. Subse-
\n
quently, a pre-trial hearing was conducted in 2021, follow-
\n
ing which the pre-trial hearing judge granted petitions to
\n
participate in the trial as civil plaintiff filed by the City of
\n
Brindisi, which quantified damages at about \u20ac27 million,
\n
requesting a provisional award of \u20ac8 million, and by the Re-
\n
gion of Puglia, which has not yet quantified the damages
\n
requested. The pre-trial hearing judge remanded all of the
\n
defendants before the Court of Brindisi. At the hearing of
\n
May 26, 2022, the court, in upholding the objection raised
\n
by EP that the preliminary hearing of October 22, 2021,
\n
held without the necessary presence of the parties, should
\n
be declared void, declared the hearing and the instrument
\n
ordering committal for trial void and submitted the trial
\n
documentation to the Court of Lecce for a new preliminary
\n
hearing. At the following hearing of October 7, 2022, which
\n
was held as summary judgement at the request of the
\n
defendant, the court issued its ruling acquitting all of the
\n
defendants of the charges because \u201cthe alleged offense
\n
did not occur\u201d. The ruling also acquitted EP as the admin-
\n
istrative offense alleged under the provisions of Legislative
\n
Decree 231/2001 had not occurred as there were no pred-
\n
icate offenses, in conformity with the position of the Public
\n
Prosecutor and the defense.
\n
Enel, Enel Energia and Servizio Elettrico
\n
Nazionale antitrust proceeding - Italy
\n
On May 11, 2017, the Competition Authority announced the
\n
beginning of proceedings for alleged abuse of a dominant
\n
position against Enel SpA (Enel), Enel Energia SpA (EE) and
\n
Servizio Elettrico Nazionale SpA (SEN). The proceeding was
\n
initiated on the basis of complaints filed by the Italian As-
\n
sociation of Energy Wholesalers and Traders (AIGET) and
\n
the company Green Network SpA (GN), as well as a number
\n
of complaints from individual consumers.
\n
On December 20, 2018 the Competition Authority issued
\n
its final ruling, with which it levied a fine of about \u20ac93 mil-
\n
lion on all three Group companies, for violation of Article
\n
102 of the Treaty on the Functioning of the European
\n
Union (TFEU).
\n
The main disputed conduct consisted in abuse of a domi-
\n
nant position by the three companies (to the benefit in par-
\n
ticular of EE) who allegedly used the privacy consent given
\n
by SEN consumers, to the detriment of competing traders.
\n
With regard to other allegations made with the measure to
\n
initiate the proceeding, concerning the organization and
\n
performance of sales activities at physical locations (Enel
\n
Points and Enel Point Partner Shops) and winback policies
\n
reported by GN, the Competition Authority reached the
\n
conclusion that the preliminary findings did not provide
\n
sufficient evidence of any abusive conduct on the part of
\n
Enel Group companies.
\n
The companies involved challenged the measures of the
\n
Competition Authority before the Lazio Regional Admin-
\n
istrative Court, which with a decision filed on October
\n
17, 2019 partially upheld the appeals filed by SEN and EE,
\n
shortening the period of abuse and requiring the Compe-
\n
tition Authority to recalculate the penalty in accordance
\n
with the criteria specified in the ruling. With a measure
\n
dated November 27, 2019, the Competition Authority set
\n
the recalculated penalty at \u20ac27,529,786.46.
\n
The rulings of the Regional Administrative Court were chal-
\n
lenged on appeal before the Council of State. With an or-
\n
der of July 20, 2020, the Council of State suspended the
\n
ruling and ordered that the issue be submitted for a pre-
\n
liminary ruling before the Court of Justice of the European
\n
Union (CJEU) pursuant to Article 267 of the TFEU, formulat-
\n
ing a number of questions aimed at clarifying the interpre-
\n
tation of the concept of \u201cabuse of a dominant position\u201d to
\n
be applied to the present case.
\n
With a ruling of May 12, 2022, the CJEU provided the re-
\n
quested interpretation and, subsequently, on December 1,
\n
2022, the Council of State, in application of the guidelines
\n
set out by the CJEU, fully voided the fine levied by the Com-
\n
petition Authority and, upholding the arguments present-
\n
ed by the companies, denied that any abuse of position
\n
had occurred.
\n
Hydroelectric concessions - Italy
\n
Italian regulations governing large-scale hydroelectric
\n
concessions were most recently modified by the \u201cSimplifi-
\n
cations Decree\u201d (Decree Law 135 of 2018 ratified with Law
\n
12 of February 11, 2019), which introduced a series of inno-
\n
vations regarding the granting of such concessions upon
\n
their expiry and the valorization of the assets and works
\n

\n\n

\n\n

\n\n
connected to them to be transferred to the new conces-
\n
sion holder. This legislation also introduced a number of
\n
changes in the matter of concession fees, establishing a
\n
fixed and variable component of fees, as well as an obli-
\n
gation to provide free power to public bodies (220 kWh
\n
of power for each kW of average nominal capacity of the
\n
facilities covered by the concession). In implementation
\n
of this national law and under specific enabling authori-
\n
ty, various regions (Lombardy, Piedmont, Emilia-Romagna,
\n
Friuli-Venezia Giulia, the Province of Trento, Calabria and
\n
Basilicata) enacted regional laws.
\n
In particular, the regions of Lombardy, Piedmont and Emil-
\n
ia-Romagna, in application of these new regulations, re-
\n
quested payment from Enel Green Power Italia and Enel
\n
Produzione of the dual-component fee and the monetiza-
\n
tion of the free power.
\n
Enel Green Power Italia and Enel Produzione challenged
\n
the first implementing acts issued under the individual re-
\n
gional laws and the subsequent payment notices of fees
\n
and the monetization of free electricity supplies before
\n
the Regional Administrative Court and Regional Water
\n
Resources Court (of Lombardy, Piedmont and Emilia-Ro-
\n
magna), asking that they be declared void and raising the
\n
question of constitutional illegitimacy of both the nation-
\n
al law and the regional laws. The Regional Administrative
\n
Court and then the Council of State, at the appeal stage,
\n
deferred their jurisdiction in favor of the Superior Public
\n
Water Resources Court, before which Enel Green Power
\n
Italia and Enel Produzione resumed the disputes, which are
\n
now at the preliminary stage.
\n
The companies initiated the proceedings by complaining
\n
that the regional implementing acts \u2013 as well as the re-
\n
gional legislation which they implement \u2013 were constitu-
\n
tionally illegitimate, first for violation of national legislation
\n
and various primary principles protected both by the Ital-
\n
ian Constitution and European law concerning legitimate
\n
expectations, property rights, reasonableness, private ini-
\n
tiative, and concessions, where:
\n
\u2022 they provide for retroactive application to valid large di-
\n
version concessions of the dual-component fee and the
\n
obligation to supply free power or its financial equiva-
\n
lent;
\n
\u2022 they order the monetization of the obligation to supply
\n
free energy, which is not envisaged in the national law.
\n
Furthermore, the introduction by the regions of these new
\n
obligations to pay the new dual-component fee (divided
\n
into a fixed component and a variable component) and
\n
to supply a certain annual quantity of electricity free of
\n
charge in the form of payment of the associated monetary
\n
value, which is also to be paid by the holders of valid con-
\n
cessions that have not yet expired, creates an unexpected
\n
and unreasonable financial imbalance in the concession
\n
relationships. This circumstance is in evident contrast with
\n
the principles of reasonableness, proportionality and le-
\n
gitimate expectation of concession fees, compliance with
\n
which is required by constitutional case law if, in the con-
\n
text of long-term relationships, pejorative modifications
\n
are introduced.
\n
Both the national law and the regional implementing leg-
\n
islation violate Community principles and constitutional
\n
principles such as property rights, the principle of legal
\n
certainty, and the freedom of enterprise. In particular, the
\n
rules do not expressly provide for the transfer of the busi-
\n
ness unit from the outgoing to the successor concession
\n
holder, and also establish inadequate criteria for the valo-
\n
rization of the works to be transferred, which threatens to
\n
create what is essentially a mechanism for expropriation, in
\n
violation of constitutional principles.
\n
Finally, the Council of Ministers had challenged a number
\n
of the regional implementing laws before the Constitu-
\n
tional Court, claiming the violation of various constitution-
\n
al principles. Enel Green Power Italia participated in the
\n
aforementioned proceedings (together with a number of
\n
trade associations and other sector operators) concerning
\n
constitutional legitimacy undertaken by the government
\n
against the Province of Trento and the Regions of Lom-
\n
bardy, Piedmont and Basilicata. The Council of Ministers
\n
subsequently withdrew the appeals as the complaints of
\n
illegitimacy they brought were resolved by subsequent
\n
regional laws. The Constitutional Court therefore extin-
\n
guished the proceedings, with the consequent cancel-
\n
lation of the related interventions by Enel Green Power
\n
Italia, despite the fact that the latter concerned different
\n
constitutionality issues than those raised by the Council of
\n
Ministers.
\n
Antitrust proceeding 12461 EE \u2013 Contract
\n
renewals
\n
On December 13, 2022, the Competition Authority notified
\n
Enel Energia SpA (\u201cCompany\u201d or \u201cEE\u201d) and six other com-
\n
panies (Hera, A2A, Acea, Eni Plenitude, Engie, Edison) that
\n
it had initiated a proceeding for unfair commercial prac-
\n
tices, contesting the violation of certain provisions of the
\n
Consumer Code and Article 3 of Decree Law 115 of August
\n
9, 2022 (the so-called \u201csecond Aid Decree\u201d) of August 10,
\n
2022, ratified with Law 142 of September 21, 2022. Simi-
\n
lar proceedings had previously been initiated against four
\n
other operators (Iren, Iberdrola, E.ON and Dolomiti).
\n
In particular, the Competition Authority, acting on the basis
\n
of reports received and without any preliminary investiga-
\n
tion, argued that EE had sent its customers, in the period
\n
from May to October 2022, notices of price changes that
\n
were allegedly generic and omissive to the extent that they
\n
did not specify the expiry date of the financial conditions
\n
subject to renewal and represented a unwarranted exer-
\n
cise of ius variandi in modification of the financial condi-
\n
tions of the supply relationship, in violation of the afore-
\n
mentioned Article 3 of the second Aid Decree.
\n
With the measure initiating the procedure, the Competi-
\n
tion Authority simultaneously prohibited on a precaution-
\n

\n\n

\n\n

\n\n
ary basis the sending of new price change notices and or-
\n
dered the correction of those already sent.
\n
All the operators subject to the order, including EE, chal-
\n
lenged the provision, which was based on the assumption
\n
that any price change had been prohibited to suppliers in
\n
the period indicated by the second Aid Decree (August 10
\n
- April 30).
\n
With an order of December 22, 2022, issued as part of
\n
the appeal filed by Iren, the Council of State distinguished
\n
contractual renewals (of expiring offers) from those cov-
\n
ered by ius variandi and excluded the applicability of Article
\n
3 of the decree law. This principle was also recognized by
\n
the Government, which, with the Milleproroghe Decree of
\n
December 29, 2022, established that Article 3 of the sec-
\n
ond Aid Decree shall not apply to the contractual clauses
\n
that allow an electricity and natural gas supply company
\n
to update the contractual financial conditions upon expiry
\n
of the same, in compliance with the contractual terms of
\n
notice and without prejudice to the right of withdrawal of
\n
the counterparty. The Milleproroghe Decree also extended
\n
the duration of the prohibition to June 30, 2023.
\n
Following the pronouncement of the Council of State and
\n
the aforementioned clarifying legislative intervention, the
\n
Competition Authority, with a new precautionary mea-
\n
sure of December 30, 2022, ordered the partial upholding
\n
of the original precautionary measure and confirmed the
\n
prohibition on changes or renewals of the financial con-
\n
ditions of expiring contracts for which the expiry date was
\n
not specifically identified or in any case predeterminable in
\n
the associated notice sent to the customer.
\n
EE filed an appeal for additional reasons, whose hearing,
\n
together with all the various appeals lodged by other oper-
\n
ators, took place on February 22, 2023 and the publication
\n
of the ruling is pending.
\n
BEG litigation - Italy, France, Luxembourg
\n
Following an arbitration proceeding initiated by BEG SpA
\n
(BEG) in Italy, Enelpower SpA (Enelpower) obtained a rul-
\n
ing in its favor in 2002, which was upheld by the Court of
\n
Cassation in 2010, which entirely rejected the petition for
\n
damages with regard to alleged breach by Enelpower of
\n
an agreement concerning the assessment of the possible
\n
construction of a hydroelectric power station in Albania.
\n
Subsequently, BEG, acting through its subsidiary Albania
\n
BEG Ambient Shpk (ABA), filed suit against Enelpower and
\n
Enel SpA (Enel) in Albania concerning the matter, obtain-
\n
ing a ruling from the District Court of Tirana on March 24,
\n
2009, upheld by the Albanian Court of Cassation, ordering
\n
Enelpower and Enel to pay tortious damages of about \u20ac25
\n
million for 2004 as well as an unspecified amount of tor-
\n
tious damages for subsequent years. Following the ruling,
\n
Albania BEG Ambient demanded payment of more than
\n
\u20ac430 million.
\n
On November 5, 2016, Enel and Enelpower filed a petition
\n
with the Albanian Court of Cassation, asking for the ruling
\n
issued by the District Court of Tirana on March 24, 2009 to
\n
be voided. The proceeding is still pending.
\n
With a ruling of the Court of Appeal of Rome of March
\n
7, 2022, the further proceedings undertaken by Enel and
\n
Enelpower before the Court of Rome were concluded,
\n
having sought recognition of BEG\u2019s liability for having cir-
\n
cumvented the arbitration award rendered in Italy in favor
\n
of Enelpower through the aforementioned initiatives un-
\n
dertaken by the subsidiary ABA. With the ruling, the Court
\n
of Appeal of Rome upheld the ruling of first instance ren-
\n
dered by the Court of Rome on June 16, 2015, which had
\n
denied the petition in the proceeding.
\n
On May 20, 2021, the European Court of Human Rights
\n
(ECHR) issued a ruling with which it decided the appeal
\n
brought by BEG against the Italian State for violation of
\n
Article 6.1 of the European Convention on Human Rights.
\n
With this decision, the Court denied BEG\u2019s request to re-
\n
open the above arbitration proceedings, and also rejected
\n
BEG\u2019s claim for pecuniary damages amounting to about
\n
\u20ac1.2 billion due to the absence of a causal link with the
\n
disputed conduct, granting it only \u20ac15,000.00 in non-pe-
\n
cuniary damages.
\n
Nonetheless, on December 29, 2021, BEG, with an action
\n
that the company and its legal counsel deemed unfound-
\n
ed and specious, also decided to sue the Italian State be-
\n
fore the Court of Milan, to demand, as a consequence of
\n
the ECHR ruling, damages for tortious liability in an amount
\n
of about \u20ac1.8 billion. In this case, BEG also involved Enel
\n
and Enelpower by way of a claim of joint and several liabili-
\n
ty. With an order of June 14, 2022, the Court of Milan, in ac-
\n
cepting the objection of territorial incompetence raised by
\n
the State Attorney, declared its incompetence to hear the
\n
dispute in favor of the Court of Rome, the court exclusively
\n
competent to hear the causes in which the Italian State is
\n
involved, ordering BEG to pay the costs of the proceed-
\n
ings in favor of the defendants. BEG did not resume the
\n
judgment before the Court of Rome within the legal term
\n
of 14 October 2022 and therefore the proceeding was ex-
\n
tinguished.
\n
A short time later, on November 3, 2022, BEG resubmitted
\n
the same claims for damages of the terminated proceed-
\n
ing, serving a new writ of summons before the Court of Mi-
\n
lan against the same defendants, with the exception of the
\n
Italian State, which BEG declared not to wishing to agree to
\n
this judgement. The first appearance hearing is set for May
\n
9, 2023. The company is preparing its defenses to proceed
\n
with the appearance in court in order to contest the claim,
\n
which is considered entirely specious and unfounded, like
\n
the previous similar initiative.
\n

\n\n

\n\n

\n\n
Proceedings undertaken by Albania BEG
\n
Ambient Shpk (ABA) to obtain enforcement
\n
of the ruling of the District Court of Tirana of
\n
March 24, 2009
\n
France
\n
In February 2012, ABA filed suit against Enel and Enelpow-
\n
er with the Tribunal de Grande Instance in Paris in order
\n
to render the ruling of the Albanian court enforceable in
\n
France. Enel SpA and Enelpower SpA challenged the suit.
\n
Following the beginning of the case before the Tribunal de
\n
Grande Instance, between 2012 and 2013 Enel France was
\n
served with a number of \u201cSaisie Conservatoire de Cr\u00e9anc-
\n
es\u201d (orders for the precautionary attachment of receiv-
\n
ables) in favor of ABA to conserve any receivables of Enel
\n
in respect of Enel France.
\n
On January 29, 2018, the Tribunal de Grande Instance is-
\n
sued a ruling in favor of Enel and Enelpower, denying ABA
\n
the recognition and enforcement of the Tirana court\u2019s rul-
\n
ing in France for lack of the requirements under French
\n
law for the purposes of granting exequatur. Among other
\n
issues, the Tribunal de Grande Instance ruled that: (i) the
\n
Albanian ruling conflicted with an existing decision (the
\n
arbitration ruling of 2002) and that (ii) the fact that BEG
\n
sought to obtain in Albania what it was not able to obtain in
\n
the Italian arbitration proceeding, resubmitting the same
\n
claim through ABA, represented fraud.
\n
Subsequently, with a ruling of May 4, 2021, the Paris Court
\n
of Appeal denied the appeal by ABA in full, fully upholding
\n
the non-compatibility of the Albanian ruling with the ar-
\n
bitration award of 2002 determined by the TGI, ordering
\n
it to reimburse Enel and Enelpower \u20ac200,000.00 each for
\n
legal costs.
\n
On June 21, 2021, ABA filed an appeal with the Cour de
\n
Cassation against the ruling of the Paris Court of Appeal.
\n
Enel and Enelpower have appeared in court and the hear-
\n
ing for the final discussion of the case is set for March 28,
\n
2023.
\n
Enel initiated a separate proceeding to obtain release of
\n
the precautionary attachments granted to ABA and which
\n
are no longer valid as a result of the appeal ruling. With
\n
an order of June 16, 2022, the Court of Paris ordered the
\n
release of the precautionary attachments while also order-
\n
ing ABA to pay Enel a total of about \u20ac146,000 in damages
\n
and legal costs. ABA challenged the aforementioned re-
\n
lease order, requesting its suspension as a precautionary
\n
measure. The request for precautionary suspension was
\n
rejected on November 23, 2022 and the appeal continues
\n
in the trial court. At the same time, Enel is taking the nec-
\n
essary actions for credit recovery.
\n
The Netherlands
\n
At the end of July 2014, ABA filed suit with the Court of Am-
\n
sterdam to render the ruling of the Albanian court enforce-
\n
able in the Netherlands.
\n
Following an initial ruling of June 29, 2016, in favor of ABA,
\n
in a ruling of July 17, 2018, the Amsterdam Court of Appeal
\n
upheld the appeal advanced by Enel and Enelpower, rul-
\n
ing that the Albanian judgment cannot be recognized and
\n
enforced in the Netherlands, as it was arbitrary and mani-
\n
festly unreasonable and therefore contrary to Dutch public
\n
order. Subsequently, the proceeding before the Court of
\n
Appeal continued with regard to the subordinate question
\n
raised by ABA with which it asked the Dutch court to rule
\n
on the merits of the dispute in Albania and in particular
\n
the alleged tortious liability of Enel and Enelpower in the
\n
failure to build the power plant in Albania. On December 3,
\n
2019, the Amsterdam Court of Appeal issued a definitive
\n
ruling in which it fully quashed the trial court judgment of
\n
June 29, 2016, rejecting any claim made by ABA, thereby
\n
confirming the denial of recognition and enforcement of
\n
the Albanian ruling in the Netherlands. The Court came to
\n
this conclusion after affirming its jurisdiction over ABA\u2019s
\n
subordinate claim and re-analyzing the merits of the case
\n
under Albanian law, finding no tortious liability on the part
\n
of Enel and Enelpower. As a result of the decision of the
\n
Court of Appeal, Enel and Enelpower are therefore not li-
\n
able to pay any amount to ABA, which was in fact ordered
\n
by the Court of Appeal to reimburse the companies for the
\n
losses incurred in illegitimate conservative seizures, to be
\n
quantified as part of a specific procedure, and the costs of
\n
the trial and appeal proceedings.
\n
On July 16, 2021 the Supreme Court completely rejected
\n
ABA\u2019s appeal of the rulings of the Court of Appeal, ordering
\n
it to reimburse court costs. The decision of the Court of
\n
Appeal has thus become final.
\n
Luxembourg
\n
In Luxembourg, again at the initiative of ABA, J.P. Morgan
\n
Bank Luxembourg SA was also served with an order for
\n
a number of precautionary seizures of any receivables of
\n
both Enel Group companies in respect of the bank.
\n
In parallel ABA filed a claim to obtain enforcement of the
\n
ruling of the Court of Tirana in Luxembourg. Owing to a
\n
number of procedural delays, the proceeding is still in the
\n
initial stages and no ruling has been issued.
\n
United States and Ireland
\n
In 2014, ABA had initiated two proceedings requesting ex-
\n
ecution of the Albanian sentence before the courts of the
\n
State of New York and Ireland, which both ruled in favor of
\n
Enel and Enelpower, respectively, on February 23 and Feb-
\n
ruary 26, 2018. Accordingly, there are no lawsuits pending
\n
in Ireland or New York State.
\n
Environmental incentives - Spain
\n
With the Decision of November 27, 2017 on the issue of
\n
environmental incentives for thermal power plants (the
\n
\u201cDecision\u201d), the European Commission reached the prelim-
\n
inary conclusion that the environmental incentive for coal
\n

\n\n

\n\n

\n\n
power plants provided for in Spain\u2019s Order ITC/3860/2007
\n
represents State aid pursuant to Article 107, paragraph 1,
\n
of the Treaty on the Functioning of the European Union
\n
(TFEU), expressing doubts about the compatibility of the
\n
incentive with the internal market while recognizing that
\n
the incentives are in line with the European Union\u2019s envi-
\n
ronmental policy. On March 2, 2018, the Commission\u2019s Di-
\n
rectorate-General for Competition has initiated a formal
\n
enquiry pursuant to Article 108, paragraph 2, of the TFEU,
\n
in order to establish whether the incentive in question con-
\n
stituted state aid compatible with the internal market. The
\n
formal enquiry pursuant to Article 108 of the TFUE is still
\n
open. On April 13, 2018, Endesa Generaci\u00f3n SA, acting as
\n
an interested third party, submitted comments contesting
\n
this interpretation. Subsequently, on September 8, 2021,
\n
the appeal of the decision lodged by Gas Natural (now
\n
Naturgy) with the General Court of the European Union
\n
was denied. The ruling was appealed by Naturgy and EDP
\n
Espa\u00f1a before the Court of Justice of the European Union
\n
(CJEU). Endesa Generaci\u00f3n has filed a request to partici-
\n
pate in the proceeding and, with an order of June 1, 2022,
\n
the CJUE allowed that participation. Endesa Generaci\u00f3n
\n
then filed its briefs in the proceedings initiated by Naturgy
\n
and EDP Espa\u00f1a on July 8 and 13, 2022, respectively.
\n
Social Bonus - Spain
\n
In relation to the various financing schemes for the Social
\n
Bonus adopted by the Spanish Government \u2013 in relation to
\n
which on December 21, 2021, the Tribunal Supremo had
\n
declared inapplicable the scheme envisaged in Article 45,
\n
paragraph 4 of Spain\u2019s Electricity Industry Law no. 24 of De-
\n
cember 26, 2013 (LSE) for incompatibility with Article 3.2 of
\n
Directive 2009/72/EC of the European Parliament, in line
\n
with the decision issued in this regard by the Court of Justice
\n
of the European Union (CJEU) on October 14, 2021 \u2013 with
\n
ruling no. 212/2022 of February 21, 2022 the Tribunal Su-
\n
premo also ruled on the appeals filed by Endesa SA, Endesa
\n
Energ\u00eda SAU and Energ\u00eda XXI Comercializadora de Referen-
\n
cia SLU (Endesa) and other companies in the energy sector
\n
against the third scheme for financing the Social Bonus, and
\n
for co-financing with government authorities of the supply
\n
to vulnerable consumers, envisaged under Article 45, para-
\n
graph 4 of LSE, Royal Decree Law 7/2016 of December 23
\n
and Royal Decree 897/2017 of October 6.
\n
With the ruling, the Tribunal Supremo, partially allowing the
\n
appeals, found that (i) the aforesaid regime was inapplicable;
\n
(ii) Articles 12 to 17 of Royal Decree 897/2017 of 6 October
\n
are inapplicable and void, and (iii) the appellants were en-
\n
titled to be compensated for the amounts paid to finance
\n
the Social Bonus and provide co-financing with government
\n
authorities, and to reimbursement of all costs incurred to
\n
fulfill the obligations set out in this mechanism, deducting
\n
any amounts transferred to customers, where applicable.
\n
In the absence of voluntary compliance by the authorities,
\n
on November 10, 2022 the companies filed a petition for
\n
enforcement of the ruling, requesting payment of the re-
\n
lated amounts; the proceeding is currently pending.
\n
\u201cEndesa I and II\u201d industrial relations
\n
dispute - Spain
\n
With effect from January 1, 2019, Endesa notified the work-
\n
ers and their union representatives that the 4th Collective
\n
Bargaining Agreement must be considered terminated
\n
under the terms of the \u201cframework guarantee contract\u201d
\n
and the \u201cagreement on the voluntary suspension or reso-
\n
lution of employment contracts in the period 2013-2018\u201d,
\n
applying from that date the provisions of general labor law,
\n
as well as the applicable legal criteria established in the
\n
matter. Yet, the interpretative differences between Endesa
\n
and the trade union representatives regarding the effects
\n
of the resolution of the 4th Collective Bargaining Agree-
\n
ment with regard, in particular, to the social benefits grant-
\n
ed to retired personnel, led to the initiation of a suit by the
\n
unions represented in the company. On March 26, 2019,
\n
the court of first instance issued a ruling in favor of Endesa,
\n
but the unions appealed against this decision before the
\n
Tribunal Supremo.
\n
On July 7, 2021, the Tribunal Supremo issued a definitive
\n
ruling denying the appeals lodged by the aforementioned
\n
unions against the ruling of the court of first instance, af-
\n
firming that social benefits (including those relating to
\n
electricity prices) originate exclusively in the collective bar-
\n
gaining agreements, both for employees currently in ser-
\n
vice and those who have retired, as well as for their family
\n
members, with the consequence that the termination of
\n
such agreements (as happened in the case of the 4th Col-
\n
lective Bargaining Agreement) produces the general con-
\n
tractual regulation of the conditions established therein
\n
for employees currently in service and. for those who have
\n
retired and their family members, the definitive extinction
\n
of all their rights, until new regulations (which came with
\n
the 5th Endesa Collective Bargaining Agreement).
\n
In parallel, numerous individual suits have been filed by staff
\n
and former employees who had agreed to participate in
\n
termination incentive agreements in order to obtain judi-
\n
cial confirmation that the termination of the 4th Endesa
\n
Collective Bargaining Agreement did not affect them. The
\n
majority of these proceedings, initially suspended pending
\n
the definition of the collective action pending before the
\n
Tribunal Supremo, were rolled together to incorporate the
\n
outcome of the ruling of the latter, that, regarding a \u201ccollec-
\n
tive dispute\u201d, would have the value of res judicata in respect
\n
of individual proceedings concerning the same issue.
\n
Meanwhile, on January 21, 2020, the arbitration award was
\n
issued on the arbitration submitted before the Servicio In-
\n
terconfederal de Mediaci\u00f3n y Arbitraje (SIMA) with a view
\n
to resolving the main issues concerning the 5th Endesa
\n
Collective Bargaining Agreement with the company. The
\n
award amended certain parts of the 5th Endesa Collective
\n
Bargaining Agreement, which was subsequently signed
\n

\n\n

\n\n

\n\n
by the social partners and entered force on January 23,
\n
2020. On the same date, Endesa also signed two further
\n
collective bargaining agreements (a \u201cframework guaran-
\n
tee contract\u201d and an \u201cagreement on voluntary measures to
\n
suspend or terminate employment contracts\u201d) with all the
\n
unions present in the company. On June 17, 2020, the 5th
\n
Endesa Collective Bargaining Agreement was published in
\n
the Spanish Official Journal (Bolet\u00edn Oficial del Estado), tak-
\n
ing full effect.
\n
On December 30, 2020, the Audiencia Nacional notified
\n
Endesa a new petition for a \u201ccollective dispute\u201d initiated by
\n
three trade unions with minority representation filed on De-
\n
cember 1, 2020, concerning the cancellation of some \u201cde-
\n
rogatory provisions\u201d of the 5th Endesa Collective Bargain-
\n
ing Agreement. The plaintiffs claim that the contested \u201cde-
\n
rogatory provisions\u201d would imply the illegitimate abolition
\n
of social benefits and economic rights of workers. Endesa
\n
considers these provisions to be fully legitimate, in line with
\n
the arguments made during proceeding concerning the re-
\n
duction of social benefits for retired personnel. With a ruling
\n
of November 15, 2021, the petitions of the plaintiff unions
\n
were rejected, with verification of the legitimacy of the 5th
\n
Endesa Collective Bargaining Agreement. The ruling was
\n
appealed by the trade unions before the Tribunal Supremo
\n
and the proceeding is currently under way.
\n
GNL Endesa Generaci\u00f3n SA arbitration
\n
proceeding - Spain
\n
In the course of an arbitration proceeding to review the
\n
price of a long-term supply contract for liquefied natural
\n
gas (LNG) initiated by Endesa Generaci\u00f3n SA, the defen-
\n
dant, an LNG production company, filed a counterclaim
\n
demanding payment of some $1 billion. The amount of the
\n
claim could be revised by the plaintiff depending on mar-
\n
ket developments in months up to the completion of arbi-
\n
tration proceeding, which is scheduled for the 2nd Quarter
\n
of 2023. The company believes that this counterclaim is
\n
unfounded and late and external legal counsel believes it is
\n
highly unlikely to be upheld.
\n
Furnas-Tractebel litigation - Brazil
\n
In 1998 the Brazilian company CIEN (now Enel CIEN) signed
\n
an agreement with Tractebel for the delivery of electricity
\n
from Argentina through its Argentina-Brazil interconnec-
\n
tion line. As a result of Argentine regulatory changes intro-
\n
duced as a consequence of the economic crisis in 2002,
\n
Enel CIEN was unable to make the electricity available to
\n
Tractebel.
\n
In October 2009, Tractebel sued Enel CIEN, which submit-
\n
ted its defense. Enel CIEN cited force majeure as a result
\n
of the Argentine crisis as the main argument in its de-
\n
fense. Out of court, Tractebel has indicated that it plans
\n
to acquire 30% of the interconnection line involved in the
\n
dispute. With a ruling of February 16, 2023, the court of
\n
first instance denied the grounds of the claim submitted
\n
by Tractebel against Enel CIEN. The time limit for appealing
\n
that ruling is currently pending. The amount involved in the
\n
dispute is estimated at about R$658 million (about \u20ac117
\n
million), plus damages to be quantified.
\n
For analogous reasons, in May 2010 Furnas had also filed
\n
suit against Enel CIEN for failure to deliver electricity, re-
\n
questing payment of about R$571.6 million (about \u20ac91
\n
million), in addition to unspecified damages, seeking to
\n
acquire ownership (in this case 70%) of the interconnec-
\n
tion line. The proceeding was decided in Enel CIEN\u2019s favor
\n
with a ruling of the Tribunal de Justi\u00e7a with a definitive
\n
ruling of October 18, 2019, which denied all of the claims
\n
of Furnas.
\n
Cibran litigation - Brazil
\n
Companhia Brasileira de Antibi\u00f3ticos (Cibran) has filed
\n
six suits against the Enel Group company Ampla Energia
\n
e Servi\u00e7os SA (today Enel Distribui\u00e7\u00e3o Rio de Janeiro) to
\n
obtain damages for alleged losses incurred as a result of
\n
the interruption of electricity service by the Brazilian dis-
\n
tribution company between 1987 and 2002, in addition
\n
to non-pecuniary damages. The Court ordered a unified
\n
technical appraisal for those cases, the findings of which
\n
were partly unfavorable to Enel Distribui\u00e7\u00e3o Rio de Janeiro.
\n
The latter challenged the findings, asking for a new study,
\n
which led to the denial of part of Cibran\u2019s petitions. Cibran
\n
subsequently challenged the findings of the new study, but
\n
without success.
\n
The first suit, filed in 1999 and regarding the years from
\n
1995 to 1999, was adjudicated with a ruling of the court of
\n
first instance against Enel Distribui\u00e7\u00e3o Rio de Janeiro. Enel
\n
Distribui\u00e7\u00e3o Rio de Janeiro appealed the ruling and the ap-
\n
peal was upheld by the Tribunal de Justi\u00e7a, which denied all
\n
of Cibran\u2019s claims. The ruling became definitive on August
\n
24, 2020.
\n
With regard to the second case, filed in 2006 and regarding
\n
the years from 1987 to 1994, on June 1, 2015, the courts is-
\n
sued a ruling ordering Enel Distribui\u00e7\u00e3o Rio de Janeiro to pay
\n
R$96,465,103 (about \u20ac23 million) plus interest in pecuniary
\n
damages and R$80,000 (about \u20ac19,000) in non-pecuniary
\n
damages. On July 8, 2015, Enel Distribui\u00e7\u00e3o Rio de Janeiro
\n
appealed the decision with the Tribunal de Justi\u00e7a of Rio de
\n
Janeiro, which on November 6, 2019 issued a ruling on merits
\n
granting Ampla\u2019s petition and denying all of Cibran\u2019s claims.
\n
On November 25, 2019, Cibran filed an appeal against the
\n
ruling of the Tribunal de Justi\u00e7a of Rio de Janeiro, which
\n
was preliminarily denied for formal reasons on September
\n
10, 2020. On January 29, 2021, Cibran appealed (agravo de
\n
instrumento) the decisions before the Superior Tribunal de
\n
Justi\u00e7a (STJ), which was denied on June 8, 2021. On June 22,
\n
2021, Cibran filed an appeal (agravo interno) with the STJ,
\n
which was denied on March 24, 2022. On April 19, 2022, Ci-
\n
bran filed another appeal (recurso extraordinario), which was
\n
denied with ruling of May 13, 2022, against which Cibran has
\n
appealed and the proceeding is pending.
\n

\n\n

\n\n

\n\n
A ruling from the court of first instance is still pending for
\n
the remaining four suits for the years 2001 and 2002. The
\n
value of all the disputes is estimated at about R$681 mil-
\n
lion (about \u20ac121 million).
\n
Coperva litigation - Brazil
\n
As part of the project to expand the grid in rural areas of
\n
Brazil, in 1982 Companhia Energ\u00e9tica do Cear\u00e1 SA (Coelce,
\n
today Enel Distribui\u00e7\u00e3o Cear\u00e1), then owned by the Brazil-
\n
ian government and now an Enel Group company, had en-
\n
tered into contracts for the use of the grids of a number
\n
of cooperatives established specifically to pursue the ex-
\n
pansion project. The contracts provided for the payment
\n
of a monthly fee by Enel Distribui\u00e7\u00e3o Cear\u00e1, which was also
\n
required to maintain the networks.
\n
Those contracts, between cooperatives established in
\n
special circumstances and the then public-sector compa-
\n
ny, do not specifically identify the grids governed by the
\n
agreements, which prompted a number of the coopera-
\n
tives to sue Enel Distribui\u00e7\u00e3o Cear\u00e1 asking for, among oth-
\n
er things, a revision of the fees agreed in the contracts.
\n
These proceedings include the suit filed by Cooperativa de
\n
Eletrifica\u00e7\u00e3o Rural do Vale do Acarau Ltda (Coperva) with a
\n
value of about R$427 million (about \u20ac75 million). Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1 was granted rulings in its favor from the
\n
trial court and the court of appeal, but Coperva filed a fur-
\n
ther appeal (embargo de declara\u00e7\u00e3o) based on procedural
\n
issues, which was also denied by the appeal court in a ruling
\n
of January 11, 2016. On February 3, 2016, Coperva lodged
\n
an extraordinary appeal before the Tribunal Superior de
\n
Justi\u00e7a (TSJ) against the appeal court ruling on the merits,
\n
which was granted on November 5, 2018 for the ruling is-
\n
sued in the previous appeal (embargo de declara\u00e7\u00e3o). On
\n
December 3, 2018, Enel Distribui\u00e7\u00e3o Cear\u00e1 filed an appeal
\n
(agravo interno) against this ruling of the TSJ. The proceed-
\n
ings are currently pending.
\n
ANEEL litigation - Brazil
\n
In 2014, Eletropaulo (today Enel Distribui\u00e7\u00e3o S\u00e3o Paulo) ini-
\n
tiated an action before the Brazilian federal courts seeking
\n
to void the administrative measure of the Ag\u00eancia Nacion-
\n
al de Energia El\u00e9trica (ANEEL, the national electricity agen-
\n
cy), which in 2012 retroactively introduced a negative coef-
\n
ficient to be applied in determining rates for the following
\n
regulatory period (2011-2015). With this provision, ANEEL
\n
ordered the restitution of the value of some compo-
\n
nents of the network previously included in rates because
\n
they were considered non-existent and denied Enel Dis-
\n
tribui\u00e7\u00e3o S\u00e3o Paulo\u2019s request to include additional compo-
\n
nents in rates. The administrative measure of ANEEL was
\n
challenged and on September 9, 2014 it was suspended
\n
on a precautionary basis. The first-instance proceeding
\n
is still in its preliminary stages and the value of the suit is
\n
about R$1.3 billion (about \u20ac241 million).
\n
Endicon \u2013 Brazil
\n
On October 17, 2021 Endicon (former Enel service provid-
\n
er in Brazil) filed a lawsuit against Enel Distribui\u00e7\u00e3o Rio de
\n
Janeiro and Enel Distribui\u00e7\u00e3o Cear\u00e1 in which it seeks total
\n
damages of approximately R$435 million (about \u20ac77 mil-
\n
lion) for pecuniary and non-pecuniary damages incurred
\n
in connection with certain events allegedly attributable to
\n
Group companies, which occurred during the execution
\n
of the contracts between the parties, and from the abu-
\n
sive exercise of contractual rights by the latter, which is al-
\n
leged to have produced a loss on the management of the
\n
contracts. On May 10, 2022, in upholding the appeals filed
\n
by the two Group companies, the precautionary measure
\n
that had been previously notified to the companies and
\n
immediately suspended was definitively revoked. It had re-
\n
quired them to (i) publicly announce the material facts of
\n
the dispute and (ii) record a contingency in the financial
\n
statements of the companies in relation to the dispute. In
\n
the meantime, on December 2, 2021, Enel Distribui\u00e7\u00e3o Rio
\n
de Janeiro and Enel Distribui\u00e7\u00e3o Cear\u00e1 presented their de-
\n
fenses in the proceedings on the merits, which continue in
\n
the first instance.
\n
Socrel \u2013 Brazil
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo has been sued by Servi\u00e7os de
\n
Eletricidade and Telecomunica\u00e7\u00f5es Ltda (Socrel) for dam-
\n
ages for losses caused by an alleged unlawful termination
\n
of contract by the Group company that involved a series of
\n
contracts between the parties, which would have caused
\n
Socrel\u2019s liquidity crisis. Following an expert report issued
\n
during the proceedings, Socrel\u2019s request was quantified at
\n
R$295 million (about \u20ac52 million). The proceeding is cur-
\n
rently pending before the court of first instance.
\n
Extraordinary 2022 rate revision (Cear\u00e1) \u2013
\n
Brazil
\n
On April 19, 2022, the Ag\u00eancia Nacional de Energia El\u00e9tri-
\n
ca (ANEEL) issued resolution no. 3.026/2022 with which
\n
it authorized an average 24.85% rate increase for 2022
\n
for the electricity distribution services performed by Enel
\n
Distribui\u00e7\u00e3o Cear\u00e1. Both private individuals and public
\n
institutions have challenged this resolution before the
\n
Federal Regional Court of the district of Cear\u00e1, for a to-
\n
tal of six proceedings requesting, on precautionary basis,
\n
the cancellation of the effects of the resolution and, on a
\n
permanent basis, the voidance of the resolution itself, ar-
\n
guing that the rate increase is illegitimate. In all proceed-
\n
ings, Enel Distribui\u00e7\u00e3o Cear\u00e1 has contested the petition-
\n
ers\u2019 claims, arguing the legitimacy of the rate adjustment.
\n
On June 21, 2022, the Federal Regional Court rejected the
\n
precautionary request and joindered the six proceedings
\n
in a single proceeding in consideration of fact that the
\n
relief sought and the cause of action are the same. On
\n
September 23, 2022, Enel Distribui\u00e7\u00e3o Cear\u00e1 also sub-
\n
mitted that, as a result of certain legislative measures,
\n

\n\n

\n\n

\n\n
the rate had been reduced following an extraordinary
\n
rate review and a reduction in taxes. The trial proceeding
\n
continues. The estimated value of the proceeding has not
\n
been determined.
\n
GasAtacama Chile \u2013 Chile
\n
In January 2020, the appeal proceeding was completed
\n
for the administrative fine levied in August 2016 by the
\n
Superintendencia de Electricidad y Combustibles (SEC)
\n
against GasAtacama Chile (now Enel Generaci\u00f3n Chile)
\n
concerning the information provided to the CDEC- SING
\n
(Centro de Despacho Econ\u00f3mico de Carga) in relation
\n
to the variables of the Technical Minimum and the Min-
\n
imum Operation Time at the Atacama power station.
\n
Upon completion of the proceeding, the amount of the
\n
fine was reduced from approximately $6 million to about
\n
$432,000 and the amount was paid by the company.
\n
In relation to the issue mentioned above, a number of op-
\n
erators of the Sistema Interconectado del Norte Grande
\n
(SING), including Aes Gener SA, El\u00e9ctrica Angamos SA and
\n
Engie Energ\u00eda Chile SA, sued GasAtacama Chile seeking
\n
damages of about \u20ac58 million (the former two) and about
\n
\u20ac150 million (the other operators). The aforementioned
\n
disputes have been partially combined into a single pro-
\n
ceeding and are currently pending (after the resumption of
\n
the proceeding following the lifting of the national emer-
\n
gency in response to the COVID-19 pandemic, the court
\n
served the provision that determines the substantial facts
\n
and issues of the trial, the preliminary investigation phase
\n
is completed and the proceeding continues its course).
\n
El Quimbo \u2013 Colombia
\n
A number of legal actions (\u201cacciones de grupo\u201d and \u201cac-
\n
ciones populares\u201d) brought by residents and fishermen in
\n
the affected area are pending with regard to the El Qui-
\n
mbo project for the construction by Emgesa (now Enel
\n
Colombia) of a 400 MW hydroelectric plant in the region
\n
of Huila (Colombia). More specifically, the first collective
\n
action, currently in the preliminary stage, was brought
\n
by around 1,140 residents of the municipality of Garz\u00f3n,
\n
who claim that the construction of the plant would re-
\n
duce their business revenue by 30%. A second action was
\n
brought, between August 2011 and December 2012, by
\n
residents and businesses/associations of five municipali-
\n
ties of Huila claiming damages related to the closing of a
\n
bridge (Paso El Colegio). With regard to acciones popu-
\n
lares, or class action lawsuits, in 2008 a suit was filed by a
\n
number of residents of the area demanding, among oth-
\n
er things, that the environmental permit be suspended.
\n
As part of this action, on September 11, 2020, the Huila
\n
Court issued a partially unfavorable ruling against Emge-
\n
sa, sentencing it to fulfill the obligations already provid-
\n
ed for in the environmental license. Both the Autoridad
\n
Nacional de Licencias Ambientales (ANLA) and Emgesa
\n
challenged this decision before the Council of State. On
\n
September 20, 2022, ANLA\u2019s appeal was denied because
\n
it had been filed late. The proceeding continues in rela-
\n
tion to Emgesa\u2019s appeal.
\n
Another acci\u00f3n popular was brought by a number of fish
\n
farming companies over the alleged impact that filling the
\n
Quimbo basin would have on fishing in the Betania basin
\n
downstream from Quimbo. After a number of precaution-
\n
ary rulings, on February 22, 2016, the Huila Court issued
\n
a ruling allowing generation to continue for six months.
\n
The court ordered Emgesa to prepare a technical design
\n
that would ensure compliance with oxygen level require-
\n
ments and to provide collateral of about 20,000,000,000
\n
Colombian pesos (about \u20ac5.5 million).
\n
The Huila Court subsequently extended the six-month
\n
time limit, and therefore, in the absence of contrary court
\n
rulings the Quimbo plant is continuing to generate elec-
\n
tricity as the oxygenation system installed by Emgesa has
\n
so far demonstrated that it can maintain the oxygen lev-
\n
els required by the court. On March 22, 2018, ANLA and
\n
CAM jointly presented the final report on the monitoring
\n
of water quality downstream of the dam of the El Quimbo
\n
hydroelectric plant. Both authorities confirmed the com-
\n
pliance of Emgesa with the oxygen level requirements.
\n
After the parties had filed briefs, on January 12, 2021, it
\n
was learned that the ruling of first instance of the Court
\n
of Huila had been issued (it was subsequently notified to
\n
the company on February 1, 2021). The ruling, while ac-
\n
knowledging that the oxygenation system implemented
\n
by Emgesa had mitigated the risks associated with the
\n
protection of fauna in the Bethany basin, imposed a se-
\n
ries of obligations on the environmental authorities in-
\n
volved, as well as on Emgesa itself. In particular, the lat-
\n
ter is required to implement a decontamination project
\n
to ensure that the water in the basin does not generate
\n
risks for the flora and fauna of the river, which will be sub-
\n
ject to verification by ANLA, and to make permanent the
\n
operation of the oxygenation system, adapting it to com-
\n
ply with the parameters established by ANLA. On March
\n
4, 2021, Emgesa challenged the appeal ruling before the
\n
Council of State.
\n
On December 31, 2021, the Council of State ruled that
\n
Emgesa\u2019s appeal was admissible. The proceeding is con-
\n
tinuing at the appeal level.
\n
Nivel de Tensi\u00f3n Uno proceedings - Colombia
\n
This dispute involves an \u201cacci\u00f3n de grupo\u201d brought by
\n
Centro M\u00e9dico de la Sabana hospital and other parties
\n
against Codensa (now Enel Colombia) seeking restitu-
\n
tion of allegedly excess rates. The action is based upon
\n
the alleged failure of Codensa to apply a subsidized rate
\n
that they claim the users should have paid as Tensi\u00f3n Uno
\n
category users (voltage of less than 1 kV) and owners of
\n
infrastructure, as established in Resolution no. 82/2002,
\n
as amended by Resolution no. 97/2008. The preliminary
\n
stage has been completed and a ruling is pending. The
\n

\n\n

\n\n

\n\n
estimated value of the proceeding is about 337 billion
\n
Colombian pesos (about \u20ac96 million).
\n
Chucas arbitration - Costa Rica
\n
PH Chucas SA (Chucas) is a special purpose entity estab-
\n
lished by Enel Green Power Costa Rica SA after it won a
\n
tender organized in 2007 by the Instituto Costarricense
\n
de Electricidad (ICE) for the construction of a 50 MW hy-
\n
droelectric plant and the sale of the power generated by
\n
the plant to ICE under a build, operate and transfer con-
\n
tract (BOT).
\n
On May 27, 2015, Chucas initiated an arbitration proceed-
\n
ing before the C\u00e1mara Costarricense-Norteamericana
\n
de Comercio (AMCHAM CICA) seeking reimbursement of
\n
the additional costs incurred to build the plant and as a
\n
result of the delays in completing the project as well as
\n
voidance of the fine levied by ICE for alleged delays in fi-
\n
nalizing the works. In a decision issued in November 2017,
\n
the arbitration board ruled in Chucas\u2019 favor, granting rec-
\n
ognition of the additional costs incurred in the amount
\n
of about $113 million (about \u20ac91 million) and legal costs
\n
and found that Chucas was not liable to pay the finds to
\n
ICE. ICE appealed the arbitration ruling before the Su-
\n
preme Court and on September 5, 2019 Chucas was no-
\n
tified of the ruling partially upholding ICE\u2019s appeal to void
\n
the arbitration ruling for a number of formal procedural
\n
reasons. On September 11, 2019, Chucas filed a \u201crecurso
\n
de aclaraci\u00f3n y adici\u00f3n\u201d with the same court and it was
\n
partially upheld on June 8, 2020. The Court\u2019s decision ex-
\n
panded on the ruling of September 5, 2019 with infor-
\n
mation concerning the admission of evidence deposited
\n
by Chucas without, however, modifying the decision con-
\n
cerning the voidance of the arbitration award.
\n
On July 14, 2020, Chucas filed a new request for arbitra-
\n
tion with the AMCHAM CICA for a preliminary estimated
\n
amount of about $240 million. On August 14, 2020, ICE
\n
filed its response, requesting the dismissal of the pro-
\n
ceeding for lack of jurisdiction on the part of the arbi-
\n
tration tribunal. The request for dismissal was denied by
\n
AMCHAM CICA. In parallel, ICE filed precautionary ap-
\n
peals to the Tribunal Contencioso Administrativo against
\n
Chucas and the AMCHAM CICA seeking to suspend the
\n
arbitration proceedings. While these appeals were pre-
\n
liminarily upheld, they were subsequently denied. In May
\n
2021, Chucas filed its arbitration request complete with
\n
preliminary demands, quantifying the value of its claim at
\n
about $362 million (about \u20ac305 million). In June 2021, ICE
\n
filed its defense, continuing to assert a lack of jurisdiction.
\n
ICE has not made a counterclaim. On August 4, 2021, the
\n
arbitration tribunal rejected ICE\u2019s claim of lack of juris-
\n
diction. The matter has subsequently been submitted for
\n
consideration to the first section of the Supreme Court
\n
and the arbitration proceedings was suspended.
\n
On May 12, 2022, with a measure that was notified to the
\n
company on July 28, 2022, the first section of the Supreme
\n
Court ruled that the arbitration tribunal was incompetent
\n
to hear the dispute. On August 8, 2022, Chucas filed an
\n
extraordinary appeal against this ruling, the overall reso-
\n
lution of which is expected for mid-2023. The arbitration
\n
proceeding is suspended.
\n
Kino arbitration - Mexico
\n
On September 16, 2020, Kino Contractor SA de Cv (Kino
\n
Contractor), Kino Facilities Manager SA de Cv (Kino Fa-
\n
cilities) and Enel SpA (Enel) were notified of a request for
\n
arbitration filed by Parque Solar Don Jos\u00e9 SA de Cv, Villan-
\n
ueva Solar SA de Cv and Parque Solar Villanueva Tres SA
\n
de Cv (together, \u201cProject Companies\u201d) in which the Proj-
\n
ect Companies alleged the violation (i) by Kino Contractor
\n
of certain provisions of the EPC Contract and (ii) by Kino
\n
Facilities of certain provisions of the Asset Management
\n
Agreement, both contracts concerning solar projects
\n
owned by the three companies filing for arbitration.
\n
Enel, which is the guarantor of the obligations assumed
\n
by Kino Contractor and Kino Facilities under the above
\n
contracts, has also been called into the arbitration pro-
\n
ceeding, but no specific claims have been filed against it.
\n
The Project Companies, in which Enel Green Power SpA is
\n
a non-controlling shareholder, are controlled by CDPQ In-
\n
fraestructura Participaci\u00f3n SA de Cv (which is controlled
\n
by Caisse de D\u00e9p\u00f4t et Placement du Qu\u00e9bec) and CKD
\n
Infraestructura M\u00e9xico SA de Cv. After the request for ar-
\n
bitration and the related response from the defendants,
\n
the parties exchanged further introductory briefs, in which
\n
the financial claim of the counterparties was updated to
\n
about $135 million, while Kino Facilities has not continued
\n
its counter-claim. The hearing was held in October 2022
\n
and the final phase is currently pending. The issuance of
\n
the arbitration award is expected by mid-2023.
\n
Allianz \u2013 North America
\n
On May 18, 2022, High Lonesome Wind Project LLC was
\n
sued in New York Superior Court by Allianz Risk Transfer
\n
Ltd for about $203 million concerning an alleged liability
\n
accrued by the company, as of February 2020, in con-
\n
nection with a Proxy Revenue Swap. The claim is being
\n
contested in its entirety. The proceedings are currently
\n
pending before the Southern District Court in New York.
\n
Gastalsa \u2013 Peru
\n
In 2011, Empresa de Gas de Talara SA (Gastalsa) filed a
\n
claim before the Civil Court of Talara requesting to revoke
\n
the measure that canceled the concession of natural gas
\n
granted to it in the Parinas district, the Province of Talara
\n
and the Department of Piura, and the consequent trans-
\n
fer of the gas pipeline owned by Enel Generaci\u00f3n Piura SA
\n
(EGPIURA) to Gastalsa itself.
\n
On January 6, 2022, the court partially upheld the Gastal-
\n
sa claim. In February 2022, EGPIURA learned of a precau-
\n
tionary measure issued by the Civil Court of Talara of the
\n

\n\n

\n\n

\n\n
Superior Court of Justice of Sullana (Juzgado Civil de Ta-
\n
lara de la Corte Superior de Justicia de Sullana) in favor of
\n
Gastalsa which orders the Direcci\u00f3n General de Hidrocar-
\n
buros del Ministerio de Energ\u00eda y Minas, the Organismo
\n
Superior de la Inversi\u00f3n en Energ\u00eda y Miner\u00eda (Osinergmin)
\n
and the Ministry of Energy to (i) restore the natural gas
\n
concession of the Parinas district, the Province of Talara
\n
and the Department of Piura in favor of Gastalsa; and (ii)
\n
proceed with the upgrade and transfer of the pipeline to
\n
Gastalsa. The above means that the economic value of
\n
the gas pipeline, currently owned by EGPIURA (which sup-
\n
plies natural gas to the Malacas thermal power station) is
\n
to be estimated for transfer to Gastalsa.
\n
On August 2, 2022, the Sala Civil de la Corte Superior
\n
de Justicia de Sullana ruled against Gastalsa in the sec-
\n
ond-level appeal, referring the case to the court of first
\n
instance for a new decision. As a result of that decision,
\n
on September 9, 2022, the precautionary measure issued
\n
earlier was revoked.
\n
In the meantime, in July 2022, the Constitutional Court
\n
had granted the petition of the system operator, an inter-
\n
ested third party, acknowledging that the original petition
\n
of Gastalsa had been filed after the time limit. On January
\n
24, 2023 the Constitutional Court also denied the appeal
\n
of that measure.
\n
Gab\u010d\u00edkovo litigation - Slovakia
\n
Slovensk\u00e9 elektr\u00e1rne (SE) is involved in a number of cas-
\n
es before the national courts concerning the 720 MW
\n
Gab\u010d\u00edkovo hydroelectric plant, which is administered by
\n
Vodohospod\u00e1rska V\u00fdsatavba \u0160t\u00e1tny Podnik (VV) and whose
\n
operation and maintenance, as part of the privatization of
\n
SE in 2006, had been entrusted to SE for a period of 30
\n
years under an operating agreement (the VEG Operating
\n
Agreement).
\n
Immediately after the closing of the privatization, the Pub-
\n
lic Procurement Office (PPO) filed suit with the Court of
\n
Bratislava seeking to void the VEG Operating Agreement
\n
on the basis of alleged violations of the regulations gov-
\n
erning public tenders, qualifying the contract as a service
\n
contract and as such governed by those regulations. In No-
\n
vember 2011 the trial court ruled in favor of SE, whereupon
\n
the PPO appealed the decision.
\n
In parallel with the PPO action, VV also filed a number of
\n
suits, asking in particular for the voidance of the VEG Op-
\n
erating Agreement. On December 12, 2014, VV withdrew
\n
unilaterally from the VEG Operating Agreement, notifying
\n
its termination on March 9, 2015, for breach of contract.
\n
On March 9, 2015, the decision of the appeals court over-
\n
turned the ruling of the trial court and voided the contract
\n
as part of the action pursued by the PPO. SE lodged an
\n
extraordinary appeal against that decision before the Su-
\n
preme Court. At a hearing of June 29, 2016, the Supreme
\n
Court denied the appeal and SE then appealed the ruling
\n
to the Constitutional Court, which denied the appeal on
\n
January 18, 2017.
\n
In addition, SE lodged a request for arbitration with the
\n
Vienna International Arbitral Centre (VIAC) under the VEG
\n
Indemnity Agreement. Under that accord, which had been
\n
signed as part of the privatization between the National
\n
Property Fund (now MH Manazment - MHM) of the Slovak
\n
Republic and SE, the latter was entitled to an indemnity in
\n
the event of the early termination of the VEG Operating
\n
Agreement for reasons not attributable to SE. On June 30,
\n
2017, the arbitration court issued its ruling denying the re-
\n
quest of SE.
\n
In parallel with this arbitration proceeding launched by SE,
\n
both VV and MHM filed two suits in the Slovakian courts to
\n
void the VEG Indemnity Agreement owing to the alleged
\n
connection of the latter with the VEG Operating Agree-
\n
ment. These proceedings were joindered and, on Septem-
\n
ber 27, 2017, the Court of Bratislava denied the request of
\n
the plaintiffs for procedural reasons. Both VV and MHM
\n
appealed that decision, and both the appeals were denied
\n
upholding the trial court decision in favor of SE. VV filed an
\n
extraordinary appeal (dovolanie) against that decision on
\n
March 9, 2020, with the Supreme Court, to which SE re-
\n
plied with a brief submitted on June 8, 2020. SE also filed an
\n
appeal before the Slovak Constitutional Court, which was
\n
denied on July 29, 2021. On March 24, 2021, the Supreme
\n
Court overturned the decision of the Bratislava Court of
\n
Appeal, referring the judgment to the latter court, and the
\n
proceeding is currently pending.
\n
At the local level, VV has also filed other suits against SE for
\n
alleged unjustified enrichment (estimated at about \u20ac360
\n
million plus interest) for the period from 2006 to 2015. SE
\n
filed counter-claims for all of the proceedings under way.
\n
Developments in those proceedings can be summarized
\n
as follows:
\n
\u2022 for 2006-2008, at the hearing of June 26, 2019, the
\n
Court of Bratislava rejected VV\u2019s main claim and, con-
\n
sequently, SE\u2019s counterclaim. The ruling in first instance
\n
was appealed by both parties before the Court of Ap-
\n
peal of Bratislava. As for the appeal proceedings (a) the
\n
proceedings relating to 2006 were completed with the
\n
decision of December 6, 2022, notified to SE on Feb-
\n
ruary 18, 2023, which upheld the ruling in first instance.
\n
SE is assessing which course of action to pursue; (b) the
\n
proceedings relating to the years 2007 and 2008 are still
\n
pending;
\n
\u2022 the proceedings relating to the years 2011, 2014 and
\n
2015 are all pending before the court of first instance
\n
and briefs have been exchanged between the parties. For
\n
proceedings relating to the years 2011 and 2014 hear-
\n
ings before the court of first instance were postponed
\n
to specified dates before being postponed to dates to
\n
be determined owing the pandemic. For the proceeding
\n
relating to 2015 the hearing before the court of first in-
\n
stance is scheduled for March 7, 2023;
\n
\u2022 the proceedings relating to the years 2009, 2010 and
\n

\n\n

\n\n

\n\n
2013 were completed in the court of first instance with
\n
ruling issued by the Court of Bratislava on, respectively,
\n
November 24, 15 and 22, 2022, rejecting both VV\u2019s claim
\n
and SE\u2019s counterclaim. Between December 2022 and
\n
January 2023 both SE and VV filed appeals against the
\n
rulings relating to the years 2010 and 2013, and on Jan-
\n
uary 19, 2023 SE also filed an appeal against the ruling
\n
relating to the year 2009;
\n
\u2022 as regards the proceeding relating to the year 2012, on
\n
February 2, 2023 SE was notified of the appeal ruling up-
\n
holding the ruling of first instance denying of both VV\u2019s
\n
claim and SE\u2019s counterclaim. SE is considering which
\n
course of action to pursue.
\n
Finally, in another proceeding VV asked for SE to return
\n
the fee for the transfer from SE to VV of the technology
\n
assets of the Gab\u010d\u00edkovo plant as part of the privatization,
\n
with a value of about \u20ac43 million plus interest. After issuing
\n
a preliminary decision on the case in which it noted the
\n
lack of standing of VV, on December 18, 2020, the Court
\n
of Bratislava issued a decision in favor of SE, rejecting VV\u2019s
\n
claims. On January 4, 2021, VV filed an appeal against that
\n
decision, and the proceeding is pending.
\n
Tax litigation in Brazil
\n
Withholding Tax \u2013 Ampla
\n
In 1998, Ampla Energia e Servi\u00e7os SA (Ampla) financed
\n
the acquisition of Coelce with the issue of bonds in the
\n
amount of $350 million (\u201cFixed Rate Notes\u201d - FRN) sub-
\n
scribed by its Panamanian subsidiary, which had been es-
\n
tablished to raise funds abroad. Under the special rules
\n
then in force, subject to maintaining the bond until 2008,
\n
the interest paid by Ampla to its subsidiary was not subject
\n
to withholding tax in Brazil.
\n
However, the financial crisis of 1998 forced the Panama-
\n
nian company to refinance itself with its Brazilian parent,
\n
which for that purpose obtained loans from local banks.
\n
The tax authorities considered this financing to be the
\n
equivalent of the early extinguishment of the bond, with
\n
the consequent loss of entitlement to the exemption from
\n
withholding tax.
\n
In December 2005, Ampla Energia e Servi\u00e7os carried out a
\n
spin-off that involved the transfer of the residual FRN debt
\n
and the associated rights and obligations to Ampla Inves-
\n
timentos e Servi\u00e7os SA.
\n
On November 6, 2012, the C\u00e2mara Superior de Recursos
\n
Fiscais (the highest level of administrative courts) issued
\n
a ruling against Ampla, for which the company promptly
\n
asked that body for clarifications. On October 15, 2013,
\n
Ampla was notified of the denial of the request for clari-
\n
fication (embargo de declara\u00e7\u00e3o), thereby upholding the
\n
previous adverse decision. The company provided security
\n
for the debt and on June 27, 2014 continued litigation be-
\n
fore the ordinary courts (Tribunal de Justi\u00e7a).
\n
In December 2017, the court appointed an expert to ex-
\n
amine the issue in greater detail in support of the future
\n
ruling. In September 2018, the expert submitted a report,
\n
requesting additional documentation.
\n
In December 2018, the company provided the additional
\n
documentation and is awaiting the court\u2019s assessment of
\n
the arguments and documents presented.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac246 million.
\n
PIS/COFINS/ICMS - Enel Distribui\u00e7\u00e3o S\u00e3o Paulo
\n
In March 2017, the Supremo Tribunal Federal of Brazil (STF)
\n
ruled on the calculation of the PIS and COFINS taxes, con-
\n
firming the argument that the ICMS - Imposto sobre Cir-
\n
cula\u00e7\u00e3o de Mercadorias e Servi\u00e7os (tax on the circular of
\n
goods and services) was not included in the calculation
\n
basis of the PIS and COFINS.
\n
In May 2021, the STF established that the ruling would have
\n
effect from the judgment of March 2017, except for taxpay-
\n
ers who had filed an appeal before that date.
\n
The Group\u2019s Brazilian companies affected by the STF ruling
\n
had already initiated legal action in their respective federal
\n
regional courts. Subsequently, the latter notified them of
\n
the final decision, recognizing the right to deduct the ICMS
\n
applied to their operations from the calculation basis of
\n
the PIS and COFINS. Since the excess payment of the PIS
\n
and COFINS taxes had been transferred to final customers,
\n
at the same time as the recognition of these recoverable
\n
taxes, a liability in respect of those customers was recog-
\n
nized in the same amount, net of any costs incurred or to
\n
be incurred in the legal proceedings. These liabilities rep-
\n
resent an obligation to reimburse the recovered taxes to
\n
final customers.
\n
In this regard, Enel Distribui\u00e7\u00e3o S\u00e3o Paulo initiated two
\n
proceedings that led to rulings in its favor. These regard-
\n
ed the periods from December 2003 to December 2014
\n
and from January 2015 onwards. With regard to the second
\n
proceeding, the Federal Union filed an action of rescission
\n
against the company, disputing the fact that part of the
\n
period in question (prior to March 2017) would be adversely
\n
impacted by the STF ruling of May 2021.
\n
In May 2022, the company challenged this action and will
\n
defend its actions through the various levels of the court
\n
system.
\n
The estimated amount involved in the proceeding at De-
\n
cember 31, 2022 was about \u20ac206 million.
\n
IRPJ/CSLL \u2013 Eletropaulo
\n
On October 5, 2021, Eletropaulo received an assessment
\n
notice from the Brazilian tax authorities contesting the de-
\n
ductibility for income tax purposes (Imposto sobre a Renda
\n
das Pessoas Jur\u00eddicas - IRPJ and Contribui\u00e7ao Social sobre o
\n
Lucro L\u00edquido - CSLL) of the amortization of the increased
\n
values generated by extraordinary corporate transactions
\n
carried out before the acquisition of the company by the
\n
Enel Group. The contested period runs from 2017 to 2019.
\n

\n\n

\n\n

\n\n
Considering its position sound, the company presented its
\n
defense at the first level of administrative adjudication.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac137 million.
\n
PIS \u2013 Eletropaulo
\n
In July 2000, Eletropaulo filed suit seeking a tax credit for
\n
PIS (Programa Integra\u00e7\u00e3o Social) paid in application of
\n
regulations (Decree Laws 2.445/1988 and 2.449/1988)
\n
that were subsequently declared unconstitutional by the
\n
Supremo Tribunal Federal (STF). In May 2012, the Superior
\n
Tribunal de Justi\u00e7a (STJ) issued a final ruling in favor of the
\n
company that recognized the right to the credit.
\n
In 2002, before the issue of that favorable final ruling, the
\n
company had offset its credit against other federal taxes.
\n
This behavior was contested by the federal tax authorities
\n
but the company, claiming it had acted correctly, chal-
\n
lenged in court the assessments issued by the federal tax
\n
authorities. Following defeat at the initial level of adjudica-
\n
tion, the company appealed.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac123 million.
\n
ICMS - Ampla, Coelce and Eletropaulo
\n
The States of Rio de Janeiro, Cear\u00e1 and S\u00e3o Paulo issued
\n
a number of tax assessments against Ampla Energia e
\n
Servi\u00e7os SA (for the years 1996-1999 and 2007-2017),
\n
Companhia Energ\u00e9tica do Cear\u00e1 (2003, 2004, 2006-2012,
\n
2015 and 2016) and Eletropaulo (2008-2021), challeng-
\n
ing the deduction of ICMS - Imposto sobre Circula\u00e7\u00e3o de
\n
Mercadorias e Servi\u00e7os (tax on the circular of goods and
\n
services) in relation to the purchase of certain non-current
\n
assets. The companies challenged the assessments, argu-
\n
ing that they correctly deducted the tax and asserting that
\n
the assets, the purchase of which generated the ICMS, are
\n
intended for use in their electricity distribution activities.
\n
The companies are continuing to defend their actions at
\n
the various levels of adjudication.
\n
The amount involved in the disputes totaled approximately
\n
\u20ac95 million at December 31, 2022.
\n
Withholding Tax - Endesa Brasil
\n
On November 4, 2014, the Brazilian tax authorities issued
\n
an assessment against Endesa Brasil SA (now Enel Brasil SA)
\n
alleging the failure to apply withholding tax to payments of
\n
allegedly higher dividends to non-resident recipients.
\n
More specifically, in 2009, Endesa Brasil, as a result of the
\n
first-time application of the IFRS, had derecognized good-
\n
will, recognizing the effects in equity, on the basis of the
\n
correct application of the accounting standards it had
\n
adopted. The Brazilian tax authorities, however, asserted
\n
\u2013 during an audit \u2013 that the accounting treatment was in-
\n
correct and that the effects of the derecognition should
\n
have been recognized through profit or loss. As a result,
\n
the corresponding amount (about \u20ac202 million) was re-
\n
classified as a payment of income to non-residents and,
\n
therefore, subject to withholding tax of 15%.
\n
It should be noted that the accounting treatment adopted by
\n
the company was agreed with the external auditor and also
\n
confirmed by a specific legal opinion issued by a local firm.
\n
Following unfavorable rulings from the administrative courts,
\n
the company is continuing to defend its actions in court and
\n
the appropriateness of the accounting treatment.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac69 million.
\n
ICMS \u2013 Coelce
\n
The State of Cear\u00e1 has filed various tax assessments
\n
against Companhia Energ\u00e9tica do Cear\u00e1 SA (Coelce) over
\n
the years (for tax periods from 2005 to 2014), contesting
\n
the determination of the deductible portion of the ICMS -
\n
Imposto sobre Circula\u00e7\u00e3o de Mercadorias e Servi\u00e7os (tax
\n
on the circular of goods and services) and in particular the
\n
method of calculation of the pro-rata deduction with ref-
\n
erence to the revenue deriving from the application of a
\n
special rate envisaged by the Brazilian government for the
\n
sale of electricity to low-income households (Baixa Renda).
\n
The company has appealed the individual assessments, ar-
\n
guing that the tax deduction was calculated correctly. The
\n
company is defending its actions in the various levels of
\n
jurisdiction.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac55 million.
\n
PIS \u2013 Eletropaulo
\n
In December 1995, the Brazilian government increased
\n
the rate of the federal PIS (Programa Integra\u00e7\u00e3o Social) tax
\n
from 0.50% to 0.65% with the issue of a provisional mea-
\n
sure (Executive Provisional Order).
\n
Subsequently, the provisional measure was re-issued five
\n
times before its definitive ratification into law in 1998. Un-
\n
der Brazilian legislation, an increase in the tax rate (or the
\n
establishment of a new tax) can only be ordered by law and
\n
take effect 90 days after its publication.
\n
Eletropaulo therefore filed suit arguing that an increase in
\n
the tax rate would only have been effective 90 days after
\n
the last Provisional Order, claiming that the effects of the
\n
first four provisional measures should be considered void
\n
(since they were never ratified into law). This dispute ended
\n
in April 2008 with recognition of the validity of the increase
\n
in the PIS rate starting from the first provisional measure.
\n
In May 2008, the Brazilian tax authorities filed a suit against
\n
Eletropaulo to request payment of taxes corresponding
\n
to the rate increase from March 1996 to December 1998.
\n
Eletropaulo has fought the request at the various levels of
\n
adjudication, arguing that the time limit for the issue of
\n
the notice of assessment had lapsed. In particular, since
\n
more than five years have passed since the taxable event
\n
(December 1995, the date of the first provisional measure)
\n
without issuing any formal instrument, the right of the tax
\n

\n\n

\n\n

\n\n
authorities to request the payment of additional taxes and
\n
the authority to undertake legal action to obtain payment
\n
have been challenged.
\n
In 2017, following the unfavorable decisions issued in pre-
\n
vious rulings, Eletropaulo filed an appeal in defense of its
\n
rights and its actions with the Superior Tribunal de Justi\u00e7a
\n
(STJ) and the Supremo Tribunal Federal (STF). The proceed-
\n
ings are still pending while the amounts subject to dispute
\n
have been covered by a bank guarantee.
\n
With regard to the request of the Office of the Attorney
\n
General of the Brazilian National Treasury Department to
\n
replace the bank guarantee with a deposit in court, the
\n
court of second instance granted the petition. The com-
\n
pany therefore replaced the bank guarantee with a cash
\n
deposit and filed a clarification motion against the related
\n
decision, which is currently awaiting a decision.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac45 million.
\n
FINSOCIAL \u2013 Eletropaulo
\n
Following a final ruling issued by the Federal Regional Court
\n
on September 11, 2011, Eletropaulo was recognized the
\n
right to compensation for certain FINSOCIAL credits (so-
\n
cial contributions) relating to sums paid from September
\n
1989 to March 1992.
\n
Despite the expiration of the relative statute of limitations,
\n
the Federal Tax Authority contested the determination of
\n
some credits and rejected the corresponding offsetting,
\n
issuing tax assessments that the company promptly chal-
\n
lenged in the administrative courts, defending the legiti-
\n
macy of its calculations and actions.
\n
After an unfavorable ruling at first instance, the company
\n
filed an appeal before the administrative court of second
\n
instance.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac43 million.
\n
Tax litigation in Spain
\n
Income tax - Enel Iberia, Endesa and subsidiaries
\n
In 2018, the Spanish tax authorities completed a general
\n
audit involving the companies of the Group participating
\n
in the Spanish tax consolidation mechanism. This audit,
\n
which began in 2016, involved corporate income tax, value
\n
added tax and withholding taxes (mainly for the years 2011
\n
to 2014).
\n
With reference to the main claims, the companies involved
\n
have challenged the related assessments at the first ad-
\n
ministrative level (Tribunal Econ\u00f3mico-Administrativo Cen-
\n
tral - TEAC), defending the correctness of their actions.
\n
On April 4, 2022, the TEAC rejected the appeal and the
\n
companies are continuing to defend their actions in court
\n
(Audiencia Nacional).
\n
With regard to the disputes concerning corporate income
\n
tax, the issues for which an unfavorable outcome is con-
\n
sidered possible amounted to about \u20ac133 million at De-
\n
cember 31, 2022:
\n
\u2022 Enel Iberia is defending the appropriateness of the crite-
\n
rion adopted for determining the deductibility of capital
\n
losses deriving from stock sales (around \u20ac88 million) and
\n
certain financial expense (around \u20ac15 million);
\n
\u2022 Endesa and its subsidiaries are mainly defending the ap-
\n
propriateness of the criteria adopted for the deductibil-
\n
ity of certain financial expense (about \u20ac24 million) and
\n
costs for decommissioning nuclear power plants (about
\n
\u20ac6 million).
\n
In 2021, the Spanish tax authorities concluded a new gen-
\n
eral audit for the years from 2015 to 2018. The companies
\n
involved challenged the related assessments at the first
\n
level of administrative adjudication (TEAC), arguing that
\n
they had acted correctly.
\n
In relation to the main dispute regarding corporate income
\n
tax, which concerned the deductibility of certain financial
\n
charges, the dispute for which an adverse outcome is consid-
\n
ered possible has a value of about \u20ac222 million at December
\n
31, 2022 (Enel Iberia \u20ac210 million and Endesa SA \u20ac12 million).
\n
Income tax - Enel Green Power Espa\u00f1a SL
\n
On June 7, 2017, the Spanish tax authorities issued a notice
\n
of assessment to Enel Green Power Espa\u00f1a SL, contesting
\n
the treatment of the merger of Enel Uni\u00f3n Fenosa Ren-
\n
ovables SA (\u201cEUFER\u201d) into Enel Green Power Espa\u00f1a SL in
\n
2011 as a tax neutral transaction, asserting that the trans-
\n
action had no valid economic reason.
\n
On July 6, 2017, the company appealed the assessment at
\n
the first administrative level (Tribunal Econ\u00f3mico-Adminis-
\n
trativo Central - TEAC), defending the appropriateness of
\n
the tax treatment applied to the merger. The company has
\n
provided the supporting documentation demonstrating
\n
the synergies achieved as a result of the merger in order
\n
to prove the existence of a valid economic reason for the
\n
transaction. On December 10, 2019, the TEAC denied the
\n
appeal and the company is continuing to defend its ac-
\n
tions in court (Audiencia Nacional).
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac100 million.
\n
Tax litigation in Italy
\n
Withholding Tax \u2013 Enel Servizio Elettrico Nazionale
\n
As a result of a tax audit initiated in March 2018 and fol-
\n
lowing a subsequent investigation conducted with ques-
\n
tionnaires submitted to the banks involved as assignees
\n
in certain transfers of receivables from Servizio Elettrico
\n
Nazionale SpA (SEN) in respect of mass market custom-
\n
ers under a framework agreement, on December 19, 2018,
\n
the Revenue Agency Regional Directorate of Lazio Large
\n
Taxpayers Office, notified the company of an assessment
\n
in respect of the alleged violation of withholding tax obli-
\n

\n\n

\n\n

\n

\n

\n\n
gations relating to the amounts paid to the banks as part
\n
of the aforementioned transfers in 2013.
\n
In particular, the dispute arises from an assessment by the
\n
Office that: (i) reclassified, for tax purposes only, the assign-
\n
ment of receivables as a financing transaction; (ii) asserted
\n
an alleged withholding obligation for the company com-
\n
mensurate with the cost of the transaction (as the difference
\n
between the nominal value of the assigned receivables and
\n
the transfer price), reconstructing the subsequent transac-
\n
tions involving the assigned receivables (further sales and/or
\n
securitizations with non-residents carried out by the banks),
\n
in which the company had no role.
\n
In the first stages of the proceeding, which arose following
\n
SEN\u2019s appeal of the assessment, the company\u2019s objections
\n
concerning the illegitimacy of the Office\u2019s reclassification
\n
of the transaction for tax purposes and, consequently, of
\n
the payment flows were not upheld, despite significant
\n
procedural violations in the assessment activity.
\n
In 2022, the conditions for a settlement arose, which the
\n
company decided to accept for the sole purpose of avoid-
\n
ing the continuation of the pending dispute concerning
\n
a matter characterized by interpretative uncertainty. This
\n
solution provides for an overall revision of the tax claim and
\n
the withdrawal of claims for subsequent years.
\n
The settlement involved the payment during the year by
\n
the company of about \u20ac45 million and the action was de-
\n
prived of purpose.
\n

\n\n\n
58. Future accounting standards
\n
The following provides a list of accounting standards,
\n
amendments and interpretations that will take effect for
\n
the Group after December 31, 2022.
\n
\u2022 \u201cAmendments to IAS 1 - Classification of Liabilities as
\n
Current or Non-current\u201d, issued in January 2020. The
\n
amendments regard the provisions of IAS 1 concern-
\n
ing the presentation of liabilities. More specifically, the
\n
changes clarify:
\n
\u2013 the criteria to adopt in classifying a liability as current
\n
or non-current, specifying the meaning of right of an
\n
entity to defer settlement and that that right must ex-
\n
ist at the end of the reporting period;
\n
\u2013 that the classification is unaffected by the intentions
\n
or expectations of management about when the en-
\n
tity will exercise its right to defer settlement of a lia-
\n
bility;
\n
\u2013 that the right to defer exists if and only if the entity
\n
satisfies the terms of the loan at the end of the re-
\n
porting period, even if the creditor does not verify
\n
compliance until later; and
\n
\u2013 that settlement regards the transfer to the counterpar-
\n
ty of cash, equity instruments, other assets or services.
\n
The amendments will take effect, subject to endorse-
\n
ment, for annual periods beginning on or after January
\n
1, 2024.
\n
(62)
\n
\u2022 \u201cAmendments to IAS 1 - Non-current Liabilities with Cov-
\n
enants\u201d, issued in October 2022. IAS 1 requires classifi-
\n
cation of liabilities as non-current only where an entity
\n
has a right to defer settlement in the 12 months following
\n
the reporting date. The amendments of the standard im-
\n
prove disclosure when the right to defer settlement of a
\n
liability for at least 12 months is subject to compliance
\n
with covenants and specify that the classification of the
\n
liability as current or non-current at the reporting date
\n
is not affected by covenants that must be complied with
\n
subsequent to the reporting date.
\n
The amendments will take effect, subject to endorsement,
\n
for annual periods beginning on or after January 1, 2024.
\n
\u2022 \u201cAmendments to IAS 1 and IFRS Practice Statement 2
\n
- Disclosure of Accounting Policies\u201d, issued in February
\n
2021. The amendments are intended to support entities
\n
in deciding which accounting policies to disclose in the
\n
financial statements. The amendments to IAS 1 require
\n
companies to disclose their material accounting policy
\n
information rather than their significant accounting pol-
\n
icies. A guide on how to apply the concept of materiality
\n
to disclosures on accounting policies is provided in the
\n
amendments to IFRS Practice Statement 2. The amend-
\n
ments will take effect for annual periods beginning on or
\n
after January 1, 2023.
\n
\u2022 \u201cAmendments to IAS 8 - Definition of Accounting Esti-
\n
mates\u201d, issued in February 2021. The amendments clar-
\n
ify how companies should distinguish changes in ac-
\n
counting policies from changes in accounting estimates.
\n
The definition of changes in accounting estimates has
\n
been replaced with a definition of accounting estimates
\n
as \u201cmonetary amounts in financial statements that are
\n
subject to measurement uncertainty\u201d. The amendments
\n
will take effect for annual periods beginning on or after
\n
January 1, 2023.
\n
\u2022 \u201cAmendments to IAS 12 - Income Taxes: Deferred Tax re-
\n
lated to Assets and Liabilities arising from a Single Trans-
\n
action\u201d, issued in May 2021. The amendments require
\n
entities to recognize deferred tax on transactions that at
\n
initial recognition give rise to equal taxable and deductible
\n
temporary differences. The amendments will take effect
\n
for annual periods beginning on or after January 1, 2023.
\n
\u2022 \u201cAmendments to IFRS 10 and IAS 28 \u2013 Sale or Contribu-
\n
tion of Assets between an Investor and its Associate or
\n
Joint Venture\u201d, issued in September 2014. The amend-
\n
ments clarify the accounting treatment for sales or con-
\n
tribution of assets between an investor and its associates
\n
or joint ventures. They confirm that the accounting treat-
\n

\n

\n\n\n
(62) In July 2020, an amendment was issued to postpone the date of entry into force from January 1, 2023 to January 1, 2024.
\n

\n\n

\n\n

\n

\n\n
ment depends on whether the assets sold or contributed
\n
to an associate or joint venture constitute a \u201cbusiness\u201d
\n
(as defined in IFRS 3). The IASB has deferred the effective
\n
date of these amendments indefinitely.
\n
\u2022 \u201cIFRS 17 \u2013 Insurance Contracts\u201d, issued in May 2017. The
\n
standard introduces different models for calculating the
\n
costs of insurance and reinsurance. The standard will take
\n
effect for annual periods beginning on or after January 1,
\n
2023. The Group has recalculated the impact of the first-
\n
time application of IFRS 17 at January 1, 2022 and the total
\n
impact at December 31, 2022 is estimated as a positive
\n
change of up to \u20ac30 million, mainly due to the discount-
\n
ing of reserves.
\n
\u2022 \u201cAmendments to IFRS 16 - Lease Liability in a Sale and
\n
Leaseback\u201d, issued in September 2022. The amendments
\n
require the seller-lessee to measure the right-of-use as-
\n
set arising from a sale and leaseback transaction in pro-
\n
portion to the previous carrying amount of the asset in-
\n
volved in the arrangement and in line with the retained
\n
right-of-use. Consequently, the seller-lessee will be al-
\n
lowed to recognize only the amount of any capital gain or
\n
loss relating to the rights transferred to the buyer-lessor.
\n
The amendments do not prescribe specific measurement
\n
requirements for liabilities deriving from a leaseback.
\n
However, they include examples that illustrate the initial
\n
and subsequent measurement of the liability by including
\n
variable payments that do not depend on an index or a
\n
rate. This representation is a departure from the general
\n
accounting model required by IFRS 16, in which variable
\n
payments that do not depend on an index or a rate are
\n
recognized through profit or loss in the period in which
\n
the event or condition that determines these payments
\n
occurs. In this regard, the seller-lessee will have to devel-
\n
op and apply an accounting policy to determine the lease
\n
payments such that any amount of retained right-of-use
\n
gain or loss is not recognized.
\n
The amendments will take effect, subject to endorse-
\n
ment, for annual periods beginning January 1, 2024. In
\n
conformity with \u201cIAS 8 - Accounting Policies, Changes in
\n
Accounting Estimates and Errors\u201d, retrospective applica-
\n
tion is permitted for sale and leaseback transactions en-
\n
tered into after the date of initial application of IFRS 16.
\n
The Group is assessing the potential impact of the future
\n
application of the new provisions.
\n

\n\n\n
59. Events after the reporting period
\n
Enel places new perpetual hybrid bonds for \u20ac1.75 billion
\n
to refinance some of its outstanding hybrid bonds
\n
On January 9, 2023, Enel SpA launched the issuance of
\n
non-convertible, subordinated, perpetual, hybrid bonds
\n
for institutional investors on the European market, de-
\n
nominated in euros for an aggregate principal amount of
\n
\u20ac1.75 billion (the \u201cNew Securities\u201d). At the same time, Enel
\n
also announced, through a separate notice, the launch of
\n
voluntary tender offers to repurchase for cash and sub-
\n
sequently cancel, for a total aggregate principal amount
\n
equal to the principal amount raised from the New Secu-
\n
rities, any-and-all of the \u20ac750 million equity-accounted
\n
perpetual hybrid bond with first call date in August 2023,
\n
as well as part of the outstanding $1,250 million hybrid
\n
bond due September 2073 with call date in September
\n
2023, subject to satisfaction of a number of conditions.
\n
Enel announces the results of the tender offer on the
\n
perpetual hybrid bond denominated in euros
\n
With the conclusion of the voluntary tender offer launched
\n
on January 9, 2023 and expired on January 16, 2023,
\n
on January 18, 2023 Enel announced that it will repur-
\n
chase for cash its outstanding perpetual hybrid bond
\n
denominated in euros for an aggregate nominal amount
\n
of \u20ac699,970,000.00. Taking into account the principal
\n
amount raised through the issue of new securities and
\n
the principal amount of securities purchased in connec-
\n
tion with the tender offer for the euro-denominated bond,
\n
the capped maximum acceptance amount (\u201cCapped Max-
\n
imum Amount\u201d) for the concurrent tender offer for its
\n
$1,250 million hybrid bond due September 2073 with call
\n
date in September 2023 has been removed.
\n
Enel announces the results of the tender offer on the
\n
perpetual hybrid bond denominated in euros
\n
As a consequence of the removal of the capped maximum
\n
acceptance amount (\u201cCapped Maximum Amount\u201d) on the
\n
dollar-denominated bond \u2013 as announced on January
\n
18, 2023 \u2013 Enel has accepted for purchase all of the of-
\n
fers validly tendered on the dollar-denominated bond by
\n
the Early Tender Deadline for a total nominal amount of
\n
$411,060,000.
\n
Enel launches a \u20ac1.5 billion sustainability-linked bond
\n
On February 14, 2023, Enel Finance International NV
\n
launched a dual-tranche sustainability-linked bond for in-
\n
stitutional investors for a total of \u20ac1.5 billion. The new issue
\n
envisages for the first time the use by Enel of multiple Key
\n
Performance Indicators (KPIs) per tranche. One tranche of
\n

\n\n

\n\n

\n

\n\n
the bond combines a KPI linked to the EU taxonomy with a
\n
KPI linked to the United Nations Sustainable Development
\n
Goals (SDGs). The other tranche of the bond is linked to
\n
two KPIs related to the Group\u2019s full decarbonization path,
\n
across direct and indirect greenhouse gas emission re-
\n
duction.
\n
Enel starts disposal process for assets in Argentina by
\n
selling thermal generation activities
\n
On February 17, 2023, the Enel Group, through its subsidi-
\n
ary Enel Argentina, signed and closed the deal for the sale
\n
to energy company Central Puerto SA of the Group\u2019s 75.7%
\n
stake in the thermal generation company Enel Generaci\u00f3n
\n
Costanera.
\n
At the same time, Enel has signed the agreement on the
\n
sale to Central Puerto of the Group\u2019s 41.2% stake in the
\n
thermal generation company Central Dock Sud. The total
\n
consideration for the sale of Enel\u2019s equity in the two com-
\n
panies amounts to $102 million.
\n
Enel signs agreement to sell its Romanian operations to
\n
PPC
\n
On March 9, 2023, Enel SpA signed an agreement with
\n
Greek company Public Power Corporation SA (PPC) for the
\n
sale of all the equity stakes held by the Enel Group in Ro-
\n
mania. The agreement provides that PPC will pay a total of
\n
approximately \u20ac1,260 million, equivalent to an enterprise
\n
value of about \u20ac1,900 million (on a 100% basis). The overall
\n
transaction is expected to generate a total positive effect
\n
on the Group\u2019s consolidated net debt of approximately
\n
\u20ac1.7 billion, of which about \u20ac0.1 billion in 2022 and the re-
\n
maining amount in 2023, alongside a cumulative negative
\n
impact for 2022-2023 on reported Group profit amounting
\n
to approximately \u20ac1.4 billion, of which around \u20ac0.6 billion
\n
related to the release of the foreign exchange reserve to
\n
be booked in 2023.
\n

\n\n\n
60. Fees of the Audit Firm pursuant to Article 149-duodecies
\n
of the CONSOB Issuers Regulation
\n
Fees pertaining to 2022 paid by Enel SpA and its subsid-
\n
iaries at December 31, 2022 to the Audit Firm and entities
\n
belonging to its network for services are summarized in
\n
the following table, pursuant to the provisions of Article
\n
149-duodecies of the CONSOB Issuers Regulation.
\n
Millions of euro
\n
Type of service Entity providing the service Fees
\n
Enel SpA
\n
Auditing
\n
of which:
\n
- KPMG SpA 0.5
\n
- entities of the KPMG network -
\n
Certification services
\n
of which:
\n
- KPMG SpA 2.1
\n
- entities of the KPMG network -
\n
Other services
\n
of which:
\n
- KPMG SpA -
\n
- entities of the KPMG network -
\n
Total 2.6
\n
Enel SpA subsidiaries
\n
Auditing
\n
of which:
\n
- KPMG SpA 4.3
\n
- entities of the KPMG network 7.9
\n
Certification services
\n
of which:
\n
- KPMG SpA 1.3
\n
- entities of the KPMG network 1.1
\n
Other services
\n
of which:
\n
- KPMG SpA 0.1
\n
- entities of the KPMG network -
\n
Total 14.7
\n
TOTAL 17.3
\n

\n\n

\n\n
\n\n
Declaration of the Chief Executive Officer and the officer in charge of
\n
financial reporting of the Enel Group at December 31, 2022, pursuant
\n
to the provisions of Article 154-bis, paragraph 5, of Legislative Decree
\n
58 of February 24, 1998 and Article 81-ter of CONSOB Regulation no.
\n
11971 of May 14, 1999
\n
1. The undersigned Francesco Starace and Alberto De
\n
Paoli, in their respective capacities as Chief Executive
\n
Officer and officer in charge of financial reporting of
\n
Enel SpA, hereby certify, taking account of the provi-
\n
sions of Article 154-bis, paragraphs 3 and 4, of Legisla-
\n
tive Decree 58 of February 24, 1998:
\n
a. the appropriateness with respect to the characteris-
\n
tics of the Enel Group and
\n
b. the effective adoption of
\n
the administrative and accounting procedures for the
\n
preparation of the consolidated financial statements of
\n
the Enel Group in the period between January 1, 2022
\n
and December 31, 2022.
\n
2. In this regard, we report that:
\n
a. the appropriateness of the administrative and ac-
\n
counting procedures used in the preparation of the
\n
consolidated financial statements of the Enel Group
\n
has been verified in an assessment of the internal
\n
control system for financial reporting. The assess-
\n
ment was carried out on the basis of the guidelines
\n
set out in the \u201cInternal Controls - Integrated Frame-
\n
work\u201d issued by the Committee of Sponsoring Or-
\n
ganizations of the Treadway Commission (COSO);
\n
b. the assessment of the internal control system for fi-
\n
nancial reporting did not identify any material issues.
\n
3. In addition, we certify that the consolidated financial
\n
statements of the Enel Group at December 31, 2022:
\n
a. have been prepared in compliance with the Inter-
\n
national Financial Reporting Standards endorsed by
\n
the European Union pursuant to Regulation (EC) no.
\n
1606/2002 of the European Parliament and of the
\n
Council of July 19, 2002;
\n
b. correspond to the information in the books and oth-
\n
er accounting records;
\n
c. provide a true and fair representation of the financial
\n
position, financial performance and cash flows of the
\n
issuer and the companies included in the consolida-
\n
tion scope.
\n
4. Finally, we certify that the Report on Operations, ac-
\n
companied by the consolidated financial statements of
\n
the Enel Group at December 31, 2022, contains a relia-
\n
ble analysis of operations and performance, as well as
\n
the situation of the issuer and the companies included
\n
in the consolidation scope, together with a description
\n
of the main risks and uncertainties to which they are ex-
\n
posed.
\n
Rome, March 16, 2023
\n
Francesco Starace
\n
Chief Executive Officer
\n
of Enel SpA
\n
Alberto De Paoli
\n
Officer in charge of financial reporting
\n
of Enel SpA
\n
\n\n

\n\n
\n
Attachments
\n

\n

\n\n
Subsidiaries, associates and other significant equity
\n
investments of the Enel Group at December 31, 2022
\n
In compliance with Articles 38 and 39 of Legislative Decree
\n
127/1991 and CONSOB Notice no. DEM/6064293 of July
\n
28, 2006, a list of subsidiaries and associates of Enel SpA
\n
at December 31, 2022, pursuant to Article 2359 of the Ita-
\n
lian Civil Code, and of other significant equity investments
\n
is provided below. Enel has full title to all investments.
\n
The following information is included for each company:
\n
name, registered office, share capital, currency in which
\n
share capital is denominated, business segment, method
\n
of consolidation, Group companies that have a stake in the
\n
company and their respective ownership share, and the
\n
Group\u2019s ownership share.
\n
The following provides a key to the icons representing the
\n
business segments.
\n
Business segment Description of business segments
\n
Group holding company
\n
Country holding company
\n
Enel Green Power
\n
Thermal Generation
\n
Trading
\n
Enel Grids
\n
Enel X
\n
End-user Markets
\n
Services
\n
Finance
\n
Enel X Way
\n
\n\n
\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parent
\n
Enel SpA Rome IT 10,166,679,946.00 EUR
\n
Holding 100.00%
\n
Subsidiaries
\n
25 Mile Creek
\n
Windfarm LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
25 Mile PPA LLC Andover US 1.00 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
25RoseFarms Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
3SUN Srl Catania IT 1,000,000.00 EUR
\n
AFS
\n
Enel Green Power
\n
Italia Srl
\n
96.74%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
3.26%
\n
3Sun USA LLC Andover US 1.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
400 Manley Solar LLC Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
4814 Investments LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
ABC Solar 11 SpA
\n
Santiago de
\n
Chile
\n
CL 1,000,000.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
100.00% 64.93%
\n
ABC Solar 3 SpA
\n
Santiago de
\n
Chile
\n
CL 1,000,000.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
100.00% 64.93%
\n
Ables Springs Solar
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ables Springs Storage
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Abu Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Ace High Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aced Renewables
\n
Hidden Valley (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Acefat AIE Barcelona ES 793,340.00 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Adams Solar PV Project
\n
Two (RF) (Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Adria Link Srl Gorizia IT 300,297.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Aferkat Wind Farm Benslimane MA 389,600.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
100.00% 100.00%
\n
Agassiz Beach LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Agatos Green Power
\n
Trino Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Solar Energy Srl
\n
100.00% 100.00%
\n
Aguil\u00f3n 20 SA Zaragoza ES 2,682,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Alba Energia Ltda Rio de Janeiro BR 16,045,169.00 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Albany Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Alliance SA Managua NI 6,180,150.00 NIO
\n
- Ufinet Latam SLU 99.90% 19.48%
\n
Alpe Adria Energia Srl Udine IT 900,000.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Alta Farms Azure
\n
Ranchland Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Alta Farms Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
Alvorada Energia SA Niter\u00f3i BR 22,317,415.92 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ampla Energia e
\n
Servi\u00e7os SA
\n
Rio de Janeiro BR 4,138,230,386.65 BRL
\n
Line-by-line Enel Brasil SA 99.82% 82.12%
\n
Annandale Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Apiac\u00e1s Energia SA Rio de Janeiro BR 14,216,846.33 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Aquilla Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Aragonesa de
\n
Actividades
\n
Energ\u00e9ticas SAU
\n
Teruel ES 60,100.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Aranort Desarrollos SLU Madrid ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Aravalli Surya (Project 1)
\n
Private Limited
\n
Gurugram IN 31,630,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Arcadia Power Inc. Washington DC US - USD
\n
-
\n
Enel X North
\n
America Inc.
\n
0.14% 0.14%
\n
Arena Green Power
\n
1 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
2 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
3 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
4 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
5 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Power Solar
\n
11 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
12 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
13 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
20 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Arena Power Solar
\n
33 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
34 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
35 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arrow Hills Solar
\n
Project
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Asociaci\u00f3n Nuclear
\n
Asc\u00f3-Vandell\u00f3s II AIE
\n
Tarragona ES 19,232,400.00 EUR
\n
Proportional
\n
Endesa Generaci\u00f3n
\n
SAU
\n
85.41% 59.89%
\n
Ateca Renovables SL Madrid ES 3,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 19.72%
\n
35.06%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
14.93%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
15.35%
\n
Athonet France SASU Paris FR 50,000.00 EUR
\n
- Athonet Srl 100.00% 16.00%
\n
Athonet Srl Trieste IT 68,927.57 EUR
\n
- Enel X Srl 16.00% 16.00%
\n
Athonet UK Ltd
\n
Battle, East
\n
Sussex
\n
GB 250,001.00 GBP
\n
- Athonet Srl 100.00% 16.00%
\n
Athonet USA Inc. Wilmington US 1.00 USD
\n
- Athonet Srl 100.00% 16.00%
\n
Atl\u00e1ntico Photovoltaic
\n
SAS ESP
\n
Barranquilla CO 50,587,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Atwater Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Aurora Distributed
\n
Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Solar
\n
Holdings LLC
\n
74 . 13 % 74 . 13 %
\n
Aurora Land Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Solar Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Aurora Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Autumn Hills LLC Wilmington US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Autumn Waltz Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Avikiran Energy India
\n
Private Limited
\n
Gurugram IN 100,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Avikiran Solar India
\n
Private Limited
\n
New Delhi IN 253,659,580.00 INR
\n
AFS
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Avikiran Surya India
\n
Private Limited
\n
Gurugram IN 200,000.00 INR
\n
Equity
\n
Enel Green Power
\n
India Private
\n
Limited
\n
51.00% 51.00%
\n
Avikiran Vayu India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Azure Blue Jay Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Azure Sky Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
AzureRanchII Wind
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Baikal Enterprise SLU
\n
Palma de
\n
Mallorca
\n
ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Baleares Energy SLU
\n
Palma de
\n
Mallorca
\n
ES 4,509.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Barnwell County Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Baylio Solar SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Beaver Falls Water
\n
Power Company
\n
Wilmington US - USD
\n
Line-by-line
\n
Beaver Valley
\n
Holdings LLC
\n
67.50% 67.50%
\n
Beaver Valley Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Beijing Tecnatom
\n
Nuclear Power Safety
\n
Technology Services
\n
Company Limited
\n
Beijing CN 280,000.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Bejaad Solar Plant Casablanca MA 10,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
99.00%
\n
99.00%
\n
Mrs Riveros Perez
\n
Paula Cristina
\n
1.00%
\n
Belltail Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Belomechetskaya WPS Moscow RU 3,010,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Bijou Hills Wind LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bioenergy Casei Gerola
\n
Srl
\n
Rome IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Bison Meadows
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Bison Meadows Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Blair Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Blue Jay Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Blue Jay Solar II LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Blue Star Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
BluRe MA San Jos\u00e9 LU 7,092,970.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
5.00% 1.65%
\n
Bogot\u00e1 ZE SAS Bogot\u00e1 CO 186,361,690.00 COP
\n
AFS Colombia ZE SAS 100.00% 47.18%
\n
Bold Elk Wind Limited
\n
Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Bondia Energia Ltda Niter\u00f3i BR 2,950,888.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Boone Stephens Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Bosa del Ebro SL Zaragoza ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Bottom Grass Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Boujdour Wind Farm Casablanca MA 300,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
90.00% 45.00%
\n
Bouldercombe Solar
\n
Farm Trust
\n
Sydney AU 10.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Bouldercombe
\n
Trust
\n
100.00% 100.00%
\n
Bouldercombe Solar
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Bouldercombe
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
Box Canyon Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
BP Hydro Finance
\n
Partnership
\n
Salt Lake City US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
24.08%
\n
100.00%
\n
Enel Kansas LLC 75.92%
\n
Brandonville Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Bravo Dome Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Brazatortas 220
\n
Renovables SL
\n
Madrid ES 3,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 16.98%
\n
23.81%
\n
Furatena Solar 1
\n
SLU
\n
16.98%
\n
Brazoria West Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Brazos Flat Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brick Road Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bronco Hills Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brush County Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Buck Canyon Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buckshutem Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Buckshutem Solar
\n
II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Buffalo Dunes Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buffalo Dunes Wind
\n
Project LLC
\n
Topeka US - USD
\n
Line-by-line
\n
EGPNA
\n
Development
\n
Holdings LLC
\n
75.00% 75.00%
\n
Buffalo Jump LP Alberta CA 10.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Buffalo Spirit Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bungala One Finco
\n
(Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Property Trust
\n
100.00% 51.00%
\n
Bungala One Operation
\n
Holding Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala One
\n
Operations (Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One
\n
Operations Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One Property
\n
Holding (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala One Property
\n
Holding Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala One Property
\n
(Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One Property
\n
Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Finco
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Property Trust
\n
100.00% 51.00%
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala Two
\n
Operations Holding
\n
Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala Two
\n
Operations (Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two
\n
Operations Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Property
\n
Holding (Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala Two Property
\n
Holding Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala Two Property
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Property
\n
Trust
\n
Sydney AU 1.00 AUD
\n
AFS
\n
Bungala Two
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Burgundy Spruce
\n
Solar LP
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Business Venture
\n
Investments 1468
\n
(Pty) Ltd
\n
Johannesburg ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Butterfly Meadows
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
C&C Castelvetere Srl Rome IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
C&C Uno Energy Srl Rome IT 118,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cactus Mesa Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Campos Promotores
\n
Renovables SL
\n
Elche ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.30% 17.74%
\n
Canastota Wind Power
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Fenner Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Caney River Wind
\n
Project LLC
\n
Overland Park US - USD
\n
Equity
\n
Rocky Caney Wind
\n
LLC
\n
100.00% 10.00%
\n
Canyon Top Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Castle Rock Ridge
\n
Limited Partnership
\n
Alberta CA - CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Catalana d\u2019Iniciatives
\n
SCR SA
\n
Barcelona ES 30,862,800.00 EUR
\n
- Endesa Red SAU 0.94% 0.66%
\n
Cattle Drive Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
CCP.RO Bucharest SA Bucharest RO 79,800,000.00 RON
\n
- Enel Romania SA 9.52% 9.52%
\n
Cdec - Sic Ltda
\n
Santiago de
\n
Chile
\n
CL 709,783,206.00 CLP
\n
-
\n
Enel Green Power
\n
Chile SA
\n
6.00% 3.90%
\n
Cedar Run Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Central Dock Sud SA Buenos Aires AR 1,231,270,567.54 ARS
\n
AFS
\n
Enel Argentina SA 0.24%
\n
33.94%
\n
Inversora Dock
\n
Sud SA
\n
71.78%
\n
Central Geradora
\n
Fotovoltaica Bom
\n
Nome Ltda
\n
Salvador BR 4,979,739.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Central Geradora
\n
Fotovoltaica S\u00e3o
\n
Francisco Ltda
\n
Niter\u00f3i BR 268,128,917.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 0.00%
\n
82.27%
\n
Enel X Brasil SA 100.00%
\n
Central Hidr\u00e1ulica
\n
G\u00fcejar-Sierra SL
\n
Seville ES 364,213.34 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.30% 23.35%
\n
Central T\u00e9rmica de
\n
Anllares AIE
\n
Madrid ES 595,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
33.33% 23.37%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Central Vuelta de
\n
Obligado SA
\n
Buenos Aires AR 500,000.00 ARS
\n
Equity
\n
Central Dock Sud
\n
SA
\n
6.40%
\n
20.93%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.30%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
33.20%
\n
Centrales Nucleares
\n
Almaraz-Trillo AIE
\n
Madrid ES - EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
24.18% 16.95%
\n
Centrum Pre Vedu A
\n
Vyskum SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 6,639.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
CES 1 Private Company Athens GR 500.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 2 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 3 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 4 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 5 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 6 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 7 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 8 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CESI - Centro
\n
Elettrotecnico
\n
Sperimentale Italiano
\n
Giacinto Motta SpA
\n
Milan IT 8,550,000.00 EUR
\n
Equity Enel SpA 42.70% 42.70%
\n
Champagne Storage
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Checkerboard Plains
\n
Solar Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Cheyenne Ridge II
\n
Wind Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cheyenne Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Chi Black River LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Minnesota Wind
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Operations Inc. Andover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Power Inc. Naples US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Power Marketing
\n
Inc.
\n
Wilmington US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi West LLC San Francisco US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Chinango SAC San Miguel PE 295,249,298.00 PEN Line-by-line
\n
Enel Generaci\u00f3n
\n
Per\u00fa SAA
\n
80.00% 55.02%
\n
Chisago Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Chisholm View II
\n
Holding LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Chisholm View Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Chisholm View II
\n
Holding LLC
\n
62.79% 62.79%
\n
Chisholm View Wind
\n
Project LLC
\n
New York US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
Cimarron Bend Assets
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Project I LLC
\n
49.00%
\n
100.00%
\n
Cimarron Bend
\n
Wind Project II LLC
\n
49.00%
\n
Cimarron Bend
\n
Wind Project III LLC
\n
1.00%
\n
Enel Kansas LLC 1.00%
\n
Cimarron Bend III
\n
HoldCo LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Cimarron Bend
\n
Wind Holdings
\n
III LLC
\n
100.00% 100.00%
\n
Cimarron Bend Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project III LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
III LLC
\n
100.00% 100.00%
\n
Cinch Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cipher Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
CityPoste Payment
\n
Digital Srl
\n
Teramo IT 10,000.00 EUR
\n
Equity
\n
CityPoste Payment
\n
SpA
\n
100.00% 50.00%
\n
CityPoste Payment SpA Teramo IT - EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Clear Sky Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Clinton Farms Battery
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Clinton Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cloudwalker Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Cogein Sannio Srl Rome IT 10,000.00 EUR Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cogeneraci\u00f3n El Salto
\n
SL in liquidation
\n
Zaragoza ES 36,060.73 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
20.00% 14.02%
\n
Cogenio Iberia SL Madrid ES 2,874,621.80 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
20.00% 14.02%
\n
Cogenio Srl Rome IT 2,310,000.00 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Cohuna Solar Farm
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Cohuna Holdings
\n
(Pty) Ltd
\n
100.00% 100.00%
\n
Cohuna Solar Farm
\n
Trust
\n
Sydney AU 1.00 AUD
\n
AFS
\n
Enel Green Power
\n
Cohuna Trust
\n
100.00% 100.00%
\n
Colombia ZE SAS Bogot\u00e1 CO 5,503,986,000.00 COP
\n
AFS
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Comanche Crest
\n
Ranch LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Comercializadora
\n
El\u00e9ctrica de C\u00e1diz SA
\n
Cadiz ES 600,000.00 EUR
\n
Equity Endesa Red SAU 33.50% 23.49%
\n
Compagnia Porto di
\n
Civitavecchia SpA in
\n
liquidation
\n
Rome IT 14,730,800.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
25.00% 25.00%
\n
Companhia Energ\u00e9tica
\n
do Cear\u00e1 - Coelce
\n
Fortaleza BR 1,085,346,885.76 BRL
\n
Line-by-line Enel Brasil SA 74.05% 60.92%
\n
Compa\u00f1\u00eda de
\n
Trasmisi\u00f3n del
\n
Mercosur SA - CTM
\n
Buenos Aires AR 2,025,191,313.00 ARS
\n
Line-by-line
\n
Enel Brasil SA 74.15%
\n
82.27%Enel CIEN SA 25.85%
\n
Enel SpA 0.00%
\n
Compa\u00f1\u00eda Energ\u00e9tica
\n
Veracruz SAC
\n
San Miguel PE 2,886,000.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 100.00% 82.27%
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas SA
\n
Soria ES 13,222,000.00 EUR
\n
Equity
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas SA
\n
5.00%
\n
26.29%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
35.63%
\n
Compass Rose Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Concert Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Concho Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Concord Vine Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Consolidated Hydro
\n
Southeast LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Consolidated Pumped
\n
Storage Inc.
\n
Wilmington US 550,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
81.83% 81.83%
\n
Conza Green Energy
\n
Srl
\n
Rome IT 73,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Copper Landing Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Corporaci\u00f3n
\n
Empresarial de
\n
Extremadura SA
\n
Badajoz ES 44,538,000.00 EUR
\n
- Endesa SA 1.01% 0.71%
\n
Corporaci\u00f3n E\u00f3lica de
\n
Zaragoza SL
\n
La Puebla de
\n
Alfinden
\n
ES 271,652.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.00% 17.53%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Country Roads Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cow Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cr\u00e9dito F\u00e1cil Codensa
\n
SA Compa\u00f1\u00eda de
\n
Financiamiento
\n
Bogot\u00e1 CO 32,000,000,000.00 COP
\n
Equity
\n
Colombia ZE SAS 0.00%
\n
23.12%
\n
Enel Colombia SA
\n
ESP
\n
48.99%
\n
Enel X Colombia
\n
SAS ESP
\n
0.00%
\n
Crockett Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cross Trails Energy
\n
Storage Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cross Trails GESS LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Dairy Meadows Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Daisy Patch Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Danax Energy (Pty) Ltd Sandton ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Dappled Colt Storage
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Dara Solar Investment
\n
Srl
\n
Bucharest RO 14,392,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Dauphin Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
De Rock Int\u2019l Srl Bucharest RO 5,629,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Decimalfigure -
\n
Unipessoal Ltda
\n
Pego PT 2,000.00 EUR
\n
Equity
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica
\n
SA
\n
100.00% 30.68%
\n
Dehesa de los
\n
Guadalupes Solar SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 03
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 04
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Derivex SA Bogot\u00e1 CO 715,292,000.00 COP
\n
-
\n
Enel Colombia SA
\n
ESP
\n
5.00% 2.36%
\n
Desarrollo de Fuerzas
\n
Renovables S de RL
\n
de Cv
\n
Mexico City MX 33,101,350.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99%
\n
100.00%
\n
Kino Facilities
\n
Manager SA de Cv
\n
0.01%
\n
Desert Willow Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n

\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
DI.T.N.E. - Distretto
\n
Tecnologico Nazionale
\n
sull\u2019Energia \u2013
\n
Societ\u00e0 Consortile a
\n
Responsabilit\u00e0 Limitata
\n
Rome IT 444,206.61 EUR
\n
-
\n
Enel Produzione
\n
SpA
\n
1.73% 1.73%
\n
Diamond Vista
\n
Holdings LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Diamond Vista Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Dispatch Renewable
\n
Energy Societe
\n
Anonyme
\n
Heraklion, Crete GR 440,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.00% 0.00%
\n
Distribuidora de
\n
Energ\u00eda El\u00e9ctrica del
\n
Bages SA
\n
Barcelona ES 108,240.00 EUR
\n
Line-by-line
\n
Endesa Red SAU 55.00%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
45.00%
\n
Distribuidora El\u00e9ctrica
\n
del Puerto de la Cruz
\n
SAU
\n
Santa Cruz de
\n
Tenerife
\n
ES 12,621,210.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Distrilec Inversora SA Buenos Aires AR 497,612,021.00 ARS
\n
Line-by-line Enel Am\u00e9ricas SA 51.50% 42.37%
\n
Dodge Center
\n
Distributed Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Dolores Wind SA de Cv Mexico City MX 200.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Dominica Energ\u00eda
\n
Limpia SA de Cv
\n
Mexico City MX 2,070,600,646.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Dorset Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Dover Solar I LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Dragonfly Fields Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Drift Sand Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity Enel Kansas LLC 50.00% 50.00%
\n
Drift Sand Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Drift Sand Wind
\n
Holdings LLC
\n
100.00% 50.00%
\n
Dwarka Vayu 1 Private
\n
Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
E.S.CO. Comuni Srl Bergamo IT 1,000,000.00 EUR
\n
Line-by-line Enel X Italia Srl 60.00% 60.00%
\n
Earthly Reflections
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Eastwood Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Ebenezer Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ecosolar2 Private
\n
Company
\n
Grevena GR 1,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.10%
\n
Edgartown Depot Solar
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
Madrid ES 1,204,540,060.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
E-Distribu\u0163ie Banat SA Timisoara RO 382,158,580.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
E-Distribu\u0163ie Dobrogea
\n
SA
\n
Constan\u0163a RO 280,285,560.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
E-Distribu\u0163ie Muntenia
\n
SA
\n
Bucharest RO 271,635,250.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 78.00% 78.00%
\n
e-distribuzione SpA Rome IT 2,600,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
EF Divesture LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Efficientya Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
EGP Australia (Pty) Ltd Sydney AU 10,000.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
EGP Bioenergy Srl Rome IT 1,000,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Puglia Srl
\n
100.00% 100.00%
\n
EGP fotovoltaica La
\n
Loma SAS in liquidation
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
EGP Geronimo Holding
\n
Company Inc.
\n
Wilmington US 1,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP HoldCo 1 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 10 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 11 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 12 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 13 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 14 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 15 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 16 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 17 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 18 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 2 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 3 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 4 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 5 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 6 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGP HoldCo 7 LLC Andover US - USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 8 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 9 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP Magdalena Solar
\n
SA de Cv
\n
Mexico City MX 691,771,740.00 MXN
\n
Line-by-line
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.00%
\n
100.00%
\n
Hidroelectricidad
\n
del Pac\u00edfico S de RL
\n
de Cv
\n
1.00%
\n
EGP Matimba NewCo
\n
1 Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
EGP Matimba NewCo
\n
2 Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
EGP Nevada Power LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP North America
\n
PPA LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP Salt Wells Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP San Leandro
\n
Microgrid I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP Solar Services LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
EGP Stillwater Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Stillwater LLC 100.00% 100.00%
\n
EGP Stillwater Solar PV
\n
II LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Stillwater Woods
\n
Hill Holdings LLC
\n
100.00% 100.00%
\n
EGP Timber Hills
\n
Project LLC
\n
Los Angeles US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
1 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
10 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
11 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
12 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
13 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
14 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
15 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
16 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
17 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
18 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2020 HoldCo
\n
19 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
2 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
20 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
21 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
22 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
23 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
24 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
25 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
26 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
27 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
28 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
29 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
3 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
30 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
4 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
5 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
6 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
7 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
8 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
9 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
1 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
10 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
11 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
12 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
13 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2023 HoldCo
\n
14 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
15 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
16 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
17 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
18 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
19 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
2 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
20 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
3 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
4 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
5 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
6 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
7 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
8 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
9 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA Development
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America
\n
Development LLC
\n
100.00% 100.00%
\n
EGPNA Hydro Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Preferred Wind
\n
Holdings II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Preferred Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
1 LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA Project HoldCo
\n
2 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
5 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
6 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
7 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Renewable
\n
Energy Partners LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA REP
\n
Holdings LLC
\n
10.00% 10.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA REP Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA REP Solar
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA REP Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Renewable
\n
Energy Partners
\n
LLC
\n
100.00% 10.00%
\n
EGPNA Wind Holdings
\n
1 LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
EGPNA-SP Seven
\n
Cowboy Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Elcogas SA in
\n
liquidation
\n
Puertollano
\n
(Ciudad Real)
\n
ES 809,690.40 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
40.99%
\n
33.06%
\n
Enel SpA 4.32%
\n
Elcomex Solar Energy
\n
Srl
\n
Bucharest RO 4,590,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Elecgas SA Pego PT 50,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
50.00% 35.06%
\n
Electra Capital (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
El\u00e9ctrica de Jafre SA Barcelona ES 165,876.00 EUR
\n
Line-by-line
\n
Endesa Red SAU 52.54%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
47.46%
\n
El\u00e9ctrica de Lijar SL Cadiz ES 1,081,821.79 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
El\u00e9ctrica del Ebro SAU Barcelona ES 500,000.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Electricidad de Puerto
\n
Real SA
\n
Cadiz ES 4,960,246.40 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
Electrometal\u00fargica del
\n
Ebro SL
\n
Barcelona ES 2,906,862.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
0.18% 0.12%
\n
Electrotest
\n
Instalaciones, Montajes
\n
y Mantenimientos SL
\n
Puerto Real ES 10,000.00 EUR
\n
- Epresa Energ\u00eda SA 50.00% 17.53%
\n
Eletropaulo
\n
Metropolitana
\n
Eletricidade de S\u00e3o
\n
Paulo SA
\n
S\u00e3o Paulo BR 3,079,524,934.33 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Elini Antwerp BE 76,273,810.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
4.00% 1.32%
\n
Emerald Crescent Solar
\n
Limited Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Emerging Networks El
\n
Salvador SA de Cv
\n
San Salvador SV 2,000.00 USD
\n
-
\n
Emerging Networks
\n
Guatemala SA
\n
1.00%
\n
19.50%
\n
Livister Latam SLU 99.00%
\n
Emerging Networks
\n
Guatemala SA
\n
Guatemala City GT 742,000.00 GTQ
\n
-
\n
Livister Latam SLU 99.99%
\n
19.50%
\n
Ufinet Guatemala
\n
SA
\n
0.01%
\n
Emerging Networks
\n
Latam Inc.
\n
Wilmington US 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
Emerging Networks
\n
Panama SA
\n
Panama City PA 300.00 USD
\n
-
\n
IFX/Eni - SPC
\n
Panama Inc.
\n
100.00% 19.50%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Emintegral Cycle SLU Madrid ES 3,000.00 EUR Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Empresa Carbon\u00edfera
\n
del Sur - ENCASUR
\n
SAU
\n
Madrid ES 18,030,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
Distribuci\u00f3n SAU
\n
Ceuta ES 9,335,000.00 EUR
\n
Line-by-line
\n
Empresa de
\n
Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
SA
\n
100.00% 67.61%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
Energ\u00eda SLU
\n
Ceuta ES 10,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta SA
\n
Ceuta ES 16,562,250.00 EUR
\n
Line-by-line Endesa Red SAU 96.42% 67.61%
\n
Empresa de
\n
Generaci\u00f3n El\u00e9ctrica
\n
Los Pinos SA
\n
San Miguel PE 7,928,044.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
0.00%
\n
Empresa de
\n
Generaci\u00f3n El\u00e9ctrica
\n
Marcona SAC
\n
San Miguel PE 3,368,424.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
0.00%
\n
Empresa Distribuidora
\n
Sur SA - Edesur
\n
Buenos Aires AR 898,585,028.00 ARS
\n
Line-by-line
\n
Distrilec Inversora
\n
SA
\n
56.36%
\n
59.33%
\n
Enel Argentina SA 43.10%
\n
Empresa El\u00e9ctrica
\n
Pehuenche SA
\n
Santiago de
\n
Chile
\n
CL 175,774,920,733.00 CLP
\n
Line-by-line
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
92.65% 56.27%
\n
Empresa Propietaria de
\n
la Red SA
\n
Panama City PA 58,500,000.00 USD
\n
- Enel SpA 11.11% 11.11%
\n
En. Solar 7 Single
\n
Member Private
\n
Company
\n
Maroussi GR 1,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Endesa Capital SAU Madrid ES 60,200.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa
\n
Comercializa\u00e7\u00e3o de
\n
Energia SA
\n
Porto PT 250,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Energ\u00eda
\n
Renovable SLU
\n
Madrid ES 100,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Energ\u00eda SAU Madrid ES 14,445,575.90 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Financiaci\u00f3n
\n
Filiales SAU
\n
Madrid ES 4,621,003,006.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
II SAU
\n
Seville ES 63,107.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
Nuclear SAU
\n
Seville ES 60,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
Lisbon PT 50,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
0.20%
\n
70.12%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
99.20%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
0.60%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
Seville ES 1,940,379,735.35 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Ingenier\u00eda SLU Seville ES 965,305.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Endesa Medios y
\n
Sistemas SLU
\n
Madrid ES 89,999,790.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Operaciones y
\n
Servicios Comerciales
\n
SLU
\n
Madrid ES 10,138,580.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Red SAU Madrid ES 719,901,723.26 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa X Servicios SLU Madrid ES 60,000.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa X Way SL Madrid ES 600,000.00 EUR
\n
Line-by-line
\n
Endesa X Servicios
\n
SLU
\n
49.00%
\n
85.36%
\n
Enel X Way Srl 51.00%
\n
Endesa SA Madrid ES 1,270,502,540.40 EUR
\n
Line-by-line
\n
Endesa SA 0.02%
\n
70.12%
\n
Enel Iberia SRLU 70.10%
\n
Enel Alberta Solar Inc. Calgary CA 1.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Alberta Storage
\n
Inc.
\n
Calgary CA 1.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Alberta Wind Inc. Alberta CA 16,251,021.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Am\u00e9ricas SA
\n
Santiago de
\n
Chile
\n
CL 15,799,498,544.85 USD
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.00%
\n
82.27%
\n
Enel SpA 82.27%
\n
Enel and Shikun & Binui
\n
Innovation Infralab Ltd
\n
Airport City IL 38,000.00 ILS
\n
Equity Enel Grids Srl 50.00% 50.00%
\n
Enel Argentina SA Buenos Aires AR 2,297,711,908.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.92%
\n
82.25%
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
0.08%
\n
Enel Bella Energy
\n
Storage LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Enel Brasil Central SA Rio de Janeiro BR 49,440.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 20.23%
\n
82.27%
\n
Enel X Brasil SA 79.77%
\n
Enel Brasil SA Niter\u00f3i BR 38,070,269,190.10 BRL
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.56%
\n
82.27%
\n
Enel Brasil SA 0.44%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Chile SA
\n
Santiago de
\n
Chile
\n
CL 3,882,103,470,184.00 CLP
\n
Line-by-line Enel SpA 64.93% 64.93%
\n
Enel CIEN SA Rio de Janeiro BR 285,044,682.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Colina SA
\n
Santiago de
\n
Chile
\n
CL 82,222,000.00 CLP
\n
Line-by-line
\n
Enel Chile SA 0.00%
\n
64.34%
\n
Enel Distribuci\u00f3n
\n
Chile SA
\n
100.00%
\n
Enel Colombia SA ESP Bogot\u00e1 CO 655,222,312,800.00 COP
\n
Line-by-line Enel Am\u00e9ricas SA 57.34% 47.18%
\n
Enel Costa Rica CAM
\n
SA
\n
San Jos\u00e9 CR 27,500,000.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Enel Cove Fort II LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Cove Fort LLC Beaver US - USD
\n
Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Distribuci\u00f3n Chile
\n
SA
\n
Santiago de
\n
Chile
\n
CL 177,568,664,063.00 CLP
\n
Line-by-line Enel Chile SA 99.09% 64.34%
\n
Enel Distribuci\u00f3n Per\u00fa
\n
SAA
\n
San Miguel PE 638,563,900.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 83.15% 68.41%
\n
Enel Energia SpA Rome IT 10,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Energ\u00eda SA de Cv Mexico City MX 25,000,100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00% 100.00%
\n
Enel Energie Muntenia
\n
SA
\n
Bucharest RO 37,004,350.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 78.00% 78.00%
\n
Enel Energie SA Bucharest RO 140,000,000.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
Enel Energy Australia
\n
(Pty) Ltd
\n
Sydney AU 200,100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Illinois LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Ohio LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Pennsylvania
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Texas LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel Energy South
\n
Africa
\n
Wilmington ZA 100.00 ZAR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel Energy Storage
\n
Holdings LLC (formerly
\n
EGP Energy Storage
\n
Holdings LLC)
\n
Andover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Finance America
\n
LLC
\n
Wilmington US 200,000,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Finance
\n
International NV
\n
Amsterdam NL 1,478,810,371.00 EUR
\n
Line-by-line
\n
Enel Holding
\n
Finance Srl
\n
75.00%
\n
100.00%
\n
Enel SpA 25.00%
\n
Enel Fortuna SA Panama City PA 100,000,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
50.06% 23.62%
\n
Enel Future Project
\n
2020 #1 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #10 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #11 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #12 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #13 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #14 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Future Project
\n
2020 #15 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #16 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #17 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #18 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #19 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #2 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #20 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #3 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #4 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #5 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #6 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #7 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #8 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #9 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Generaci\u00f3n Chile
\n
SA
\n
Santiago de
\n
Chile
\n
CL 552,777,320,871.00 CLP
\n
Line-by-line Enel Chile SA 93.55% 60.74%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
Buenos Aires AR 701,988,378.00 ARS
\n
AFS Enel Argentina SA 75.68% 62.25%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
Buenos Aires AR 18,321,776,559.00 ARS
\n
Line-by-line
\n
Enel Argentina SA 8.67%
\n
54.07%
\n
Hidroinvest SA 59.00%
\n
Enel Generaci\u00f3n Per\u00fa
\n
SAA
\n
San Miguel PE 1,538,101,266.24 PEN
\n
Line-by-line Enel Per\u00fa SAC 83.60% 68.78%
\n
Enel Generaci\u00f3n Piura
\n
SA
\n
San Miguel PE 73,982,594.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 96.50% 79.39%
\n
Enel Generaci\u00f3n SA
\n
de Cv
\n
Mexico City MX 7,100,100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00% 100.00%
\n
Enel Geothermal LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Global Services Srl Rome IT 10,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Global Trading
\n
SpA
\n
Rome IT 90,885,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power
\n
25RoseFarms Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Argentina SA
\n
Buenos Aires AR 463,577,761.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.86%
\n
82.27%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.14%
\n
Enel Green Power
\n
Aroeira 01 SA
\n
Rio de Janeiro BR 134,518,400.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 02 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 03 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 04 SA
\n
Rio de Janeiro BR 134,638,500.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Aroeira 05 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 06 SA
\n
Rio de Janeiro BR 134,511,000.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 07 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 08 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 09 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo Participa\u00e7\u00f5es
\n
SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Australia Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Azure Ranchland
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
AzureRanchII Wind
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Boa
\n
Vista 01 Ltda
\n
Salvador BR 3,554,607.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Boa
\n
Vista E\u00f3lica SA
\n
Rio de Janeiro BR 42,890,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Bouldercombe Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Bouldercombe Trust
\n
Sydney AU 10.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Brejol\u00e2ndia Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Bungala Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cabe\u00e7a de Boi SA
\n
Niter\u00f3i BR 270,114,539.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Cachoeira Dourada SA
\n
Cachoeira
\n
Dourada
\n
BR 64,339,835.85 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.61%
\n
82.07%
\n
Enel Green Power
\n
Cachoeira Dourada
\n
SA
\n
0.15%
\n
Enel Green Power
\n
Canada Inc.
\n
Montreal CA 85,681,857.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cerrado Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Chile SA
\n
Santiago de
\n
Chile
\n
CL 842,121,530.67 USD
\n
Line-by-line
\n
Enel Chile SA 99.99%
\n
64.93%
\n
Enel SpA 0.01%
\n
Enel Green Power
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Cohuna Holdings (Pty)
\n
Ltd
\n
Sydney AU 3,419,700.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cohuna Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power Cove
\n
Fort Solar LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Cristal E\u00f3lica SA
\n
Rio de Janeiro BR 87,784,899.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.63%
\n
82.27%
\n
Enel Green Power
\n
Cristal E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.37%
\n
Enel Green Power
\n
Cumaru 01 SA
\n
Niter\u00f3i BR 204,653,590.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 02 SA
\n
Niter\u00f3i BR 237,601,272.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 03 SA
\n
Rio de Janeiro BR 225,021,296.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 04 SA
\n
Rio de Janeiro BR 230,869,708.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 05 SA
\n
Rio de Janeiro BR 180,208,000.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.94%
\n
82.22%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Cumaru Participa\u00e7oes
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Cumaru Solar 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Cumaru Solar 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Damascena E\u00f3lica SA
\n
Rio de Janeiro BR 83,709,003.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.16%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.84%
\n
Enel Green Power
\n
Delfina A E\u00f3lica SA
\n
Rio de Janeiro BR 284,062,483.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina B E\u00f3lica SA
\n
Rio de Janeiro BR 93,068,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina C E\u00f3lica SA
\n
Rio de Janeiro BR 31,105,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina D E\u00f3lica SA
\n
Rio de Janeiro BR 105,864,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina E E\u00f3lica SA
\n
Niter\u00f3i BR 105,936,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Desenvolvimento Ltda
\n
Rio de Janeiro BR 61,617,590.35 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Green Power
\n
Development Srl
\n
Rome IT 20,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Diamond Vista Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Diamond Vista
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power Dois
\n
Riachos E\u00f3lica SA
\n
Rio de Janeiro BR 83,347,009.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Egypt SAE
\n
Cairo EG 250,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power El
\n
Salvador SA de Cv
\n
El Salvador SV 22,860.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.96%
\n
99.99%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.04%
\n
Enel Green Power
\n
Elkwater Wind Limited
\n
Partnership
\n
Alberta CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.00%
\n
Enel Green Power
\n
Elmsthorpe Wind LP
\n
Calgary CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power
\n
Emiliana E\u00f3lica SA
\n
Rio de Janeiro BR 97,191,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.35%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.65%
\n
Enel Green Power
\n
Emiliana E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
Madrid ES 11,152.74 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Esperan\u00e7a E\u00f3lica SA
\n
Rio de Janeiro BR 99,418,174.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.89%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.11%
\n
Enel Green Power
\n
Esperan\u00e7a Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Estonian Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Fazenda SA
\n
Niter\u00f3i BR 264,141,174.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Fence Post Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Flat
\n
Rocks One Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
EGP Australia (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Enel Green Power Flat
\n
Rocks One Holding
\n
Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Fontes dos Ventos 2 SA
\n
Rio de Janeiro BR 183,315,219.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Fontes dos Ventos 3 SA
\n
Rio de Janeiro BR 221,001,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Fontes II Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Fontes Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ganado Solar Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Germany GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Girgarre Holdings
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Girgarre Trust
\n
Sydney AU 10.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Global Investment BV
\n
Amsterdam NL 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hadros Wind Limited
\n
Partnership
\n
- CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.00%
\n
Enel Green Power
\n
Hellas SA
\n
Maroussi GR 40,187,850.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
Maroussi GR 600,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
Maroussi GR 141,569,641.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Hilltopper Wind LLC
\n
(formerly Hilltopper
\n
Wind Power LLC)
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Hilltopper Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Horizonte MP Solar SA
\n
Rio de Janeiro BR 431,566,053.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.01%
\n
82.27%
\n
Enel Brasil SA 99.99%
\n
Enel Green Power India
\n
Private Limited
\n
New Delhi IN 200,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
100.00% 100.00%
\n
Enel Green Power
\n
Italia Srl
\n
Rome IT 272,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Green Power
\n
Ituverava Norte Solar
\n
SA
\n
Rio de Janeiro BR 219,806,645.67 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.08%
\n
82.27%
\n
Enel Brasil SA 99.92%
\n
Enel Green Power
\n
Brasil Participa\u00e7\u00f5es
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ituverava Solar SA
\n
Rio de Janeiro BR 227,810,333.00 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Ituverava Sul Solar SA
\n
Rio de Janeiro BR 408,949,643.00 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Joana E\u00f3lica SA
\n
Rio de Janeiro BR 90,259,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.33%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.67%
\n
Enel Green Power
\n
Kenya Limited
\n
Nairobi KE 100,000.00 KES
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.00%
\n
100.00%
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
1.00%
\n
Enel Green Power
\n
Korea LLC
\n
Seoul KR 5,665,000,000.00 KRW
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Lagoa do Sol 01 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 02 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 03 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 04 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 06 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 07 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Lagoa do Sol 08 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 09 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa II Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa III Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa Participa\u00e7\u00f5es SA
\n
(formerly Enel Green
\n
Power Projetos 45 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Lily
\n
Solar Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Mani\u00e7oba E\u00f3lica SA
\n
Rio de Janeiro BR 90,722,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.20%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.80%
\n
Enel Green Power
\n
Matimba Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Enel Green Power
\n
Metehara Solar Privrate
\n
Limited Company
\n
- ET 5,600,000.00 ETB
\n
Line-by-line
\n
Enel Green Power
\n
Solar Metehara SpA
\n
80.00% 80.00%
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
Mexico City MX 662,949,966.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Enel Green Power
\n
Modelo I E\u00f3lica SA
\n
Rio de Janeiro BR 70,842,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Modelo II E\u00f3lica SA
\n
Rio de Janeiro BR 63,742,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morocco SARLAU
\n
Casablanca MA 639,000,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
0.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
100.00%
\n
Enel Green Power
\n
Morro do Chap\u00e9u I
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 248,138,287.11 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morro do Chap\u00e9u II
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 206,050,114.05 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morro do Chap\u00e9u
\n
Solar 01 SA (formerly
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo III
\n
Participa\u00e7\u00f5es SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Morro Norte 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 04 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Mour\u00e3o SA
\n
Rio de Janeiro BR 25,600,100.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Namibia (Pty) Ltd
\n
Windhoek NA 10,000.00 NAD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
North America
\n
Development LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Green Power
\n
North America Inc.
\n
Andover US - USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Green Power Nova
\n
Olinda 01 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 02 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 03 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 04 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 06 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 07 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 08 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 09 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Novo
\n
Lapa 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 04 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 05 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 06 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 07 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 08 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power O&M
\n
Solar LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Paranapanema SA
\n
Niter\u00f3i BR 162,567,500.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Partecipazioni Speciali
\n
Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Pau
\n
Ferro E\u00f3lica SA
\n
Rio de Janeiro BR 74,124,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 97.92%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
2.08%
\n
Enel Green Power
\n
Pau Ferro E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Pedra do Ger\u00f4nimo
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 119,319,527.57 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.25%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.75%
\n
Enel Green Power Per\u00fa
\n
SAC
\n
San Miguel PE 1,291,373,507.00 PEN
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Green Power
\n
Primavera E\u00f3lica SA
\n
Rio de Janeiro BR 95,674,900.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.50%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.50%
\n
Enel Green Power
\n
Puglia Srl
\n
Rome IT 1,000,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power RA
\n
SAE in liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Rattlesnake Creek
\n
Wind Project LLC
\n
(formerly Rattlesnake
\n
Creek Wind Project
\n
LLC)
\n
Delaware US 1.00 USD Line-by-line
\n
Rattlesnake Creek
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings II LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings II LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Rockhaven Ranchland
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Romania Srl
\n
Bucharest RO 2,430,631,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Roseland Solar LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power RSA
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
EGP Matimba
\n
NewCo 1 Srl
\n
100.00% 50.00%
\n
Enel Green Power RSA
\n
2 (RF) (Pty) Ltd
\n
Johannesburg ZA 120.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
Moscow RU 60,500,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
99.00%
\n
Enel Green Power SpA Rome IT 272,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power Salto
\n
Apiac\u00e1s SA (formerly
\n
Enel Green Power
\n
Damascena E\u00f3lica SA)
\n
Rio de Janeiro BR 274,420,832.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Sannio Srl
\n
Rome IT 750,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power S\u00e3o
\n
Abra\u00e3o E\u00f3lica SA
\n
Rio de Janeiro BR 91,300,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Cirilo 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Cirilo 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Cirilo 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 01 SA
\n
(formerly Enel Green
\n
Power Projetos 10)
\n
Teresina BR 74,960,396.92 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 02 SA
\n
(formerly Enel Green
\n
Power Projetos 11)
\n
Teresina BR 82,268,018.57 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 07 SA
\n
(formerly Enel Green
\n
Power Projetos 42 SA)
\n
Teresina BR 114,522,004.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 08 SA
\n
(formerly Enel Green
\n
Power Projetos 43 SA)
\n
Teresina BR 109,281,818.16 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 10 SA
\n
(formerly Enel Green
\n
Power Projetos 15)
\n
Teresina BR 82,871,484.32 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 11 SA
\n
(formerly Enel Green
\n
Power Projetos 44 SA)
\n
Teresina BR 114,475,154.82 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 12 SA
\n
(formerly Enel Green
\n
Power Projetos 22 SA)
\n
Teresina BR 108,022,914.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 14
\n
Teresina BR 147,279,287.77 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 15
\n
Teresina BR 120,057,468.67 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 17 SA
\n
Teresina BR 122,007,042.67 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 18 SA
\n
(formerly Enel Green
\n
Power Ventos de Santa
\n
\u00c2ngela 13 SA)
\n
Teresina BR 120,981,744.40 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 19 SA
\n
Teresina BR 122,467,788.77 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 21 SA
\n
(formerly Enel Green
\n
Power Projetos 16)
\n
Teresina BR 89,994,200.26 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 22 SA
\n
(formerly Enel Green
\n
Power Projetos 30)
\n
Teresina BR 89,787,960.25 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 3 SA (formerly
\n
Enel Green Power
\n
Projetos 12)
\n
Teresina BR 75,324,686.12 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 4 SA (formerly
\n
Enel Green Power
\n
Projetos 13)
\n
Teresina BR 82,925,257.61 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 5 SA (formerly
\n
Enel Green Power
\n
Projetos 14)
\n
Teresina BR 82,230,525.15 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 6 SA (formerly
\n
Enel Green Power
\n
Projetos 19 SA)
\n
Teresina BR 183,602,691.38 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Brasil Participa\u00e7\u00f5es
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Judas E\u00f3lica SA
\n
Niter\u00f3i BR 82,674,900.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.26%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.74%
\n
Enel Green Power S\u00e3o
\n
Micael 01 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 9 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
Enel Green Power S\u00e3o
\n
Micael 02 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 13)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power S\u00e3o
\n
Micael 03 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 16 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
Enel Green Power S\u00e3o
\n
Micael 04 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 20 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Micael 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Services LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power SHU
\n
SAE in liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Singapore Pte Ltd
\n
Singapore SG 8,000,000.00 SGD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Energy Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Metehara SpA
\n
Rome IT 50,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Ngonye SpA (formerly
\n
Enel Green Power
\n
Africa Srl)
\n
Rome IT 50,000.00 EUR
\n
AFS
\n
EGP Matimba
\n
NewCo 2 Srl
\n
100.00% 100.00%
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
South Africa 3 (Pty) Ltd
\n
Gauteng ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Stampede Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Swift
\n
Wind LP
\n
Calgary CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power
\n
Tacaic\u00f3 E\u00f3lica SA
\n
Rio de Janeiro BR 50,034,360.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 97.87%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
2.13%
\n
Enel Green Power
\n
Tefnut SAE in
\n
liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Turkey Enerj\u00ed Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 37,141,108.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
UB33 GmbH & Co. KG
\n
Berlin DE 75,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 1 SA
\n
Teresina BR 182,273,006.17 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 10 SA (formerly
\n
Enel Green Power
\n
Projetos 21)
\n
Teresina BR 122,100,849.07 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 11 SA (formerly
\n
Enel Green Power
\n
Projetos 23)
\n
Teresina BR 132,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 14 SA (formerly
\n
Enel Green Power
\n
Projetos 24)
\n
Teresina BR 198,554,956.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 15 SA (formerly
\n
Enel Green Power
\n
Projetos 25)
\n
Teresina BR 125,100,849.07 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 17 SA (formerly
\n
Enel Green Power
\n
Projetos 26)
\n
Teresina BR 152,022,288.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 19 SA (formerly
\n
Enel Green Power
\n
Projetos 27)
\n
Teresina BR 95,587,248.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 2 SA
\n
Teresina BR 299,922,006.17 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 20 SA (formerly
\n
Enel Green Power
\n
Projetos 28)
\n
Teresina BR 92,895,408.95 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 21 SA (formerly
\n
Enel Green Power
\n
Projetos 29)
\n
Teresina BR 41,179,409.72 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 3 SA (formerly
\n
Enel Green Power
\n
Projetos 4)
\n
Teresina BR 99,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 4 SA (formerly
\n
Enel Green Power
\n
Projetos 6)
\n
Teresina BR 100,732,205.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 5 SA (formerly
\n
Enel Green Power
\n
Projetos 7)
\n
Teresina BR 84,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 6 SA (formerly
\n
Enel Green Power
\n
Projetos 8)
\n
Teresina BR 83,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 7 SA (formerly
\n
Enel Green Power
\n
Projetos 9)
\n
Teresina BR 81,245,805.55 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
Esperan\u00e7a Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 8 SA (formerly
\n
Enel Green Power
\n
Projetos 18)
\n
Teresina BR 91,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 9 SA (formerly
\n
Enel Green Power
\n
Projetos 20)
\n
Teresina BR 118,786,606.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 12
\n
(formerly Enel Green
\n
Power Projetos 36)
\n
Teresina BR 94,727,364.09 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 13 SA
\n
(formerly Enel Green
\n
Power Projetos 17 SA)
\n
Teresina BR 77,496,725.02 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 16 SA
\n
(formerly Enel Green
\n
Power Projetos 38 SA)
\n
Teresina BR 89,917,563.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 18 SA
\n
(formerly Enel Green
\n
Power Projetos 47 SA)
\n
Teresina BR 86,496,703.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 08 SA
\n
(formerly Enel Green
\n
Power Projetos 34 SA)
\n
Rio de Janeiro BR 173,154,500.67 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 1 SA
\n
(formerly Enel Green
\n
Power Fonte dos
\n
Ventos 1 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 13 (formerly
\n
Enel Green Power
\n
Projetos 33 SA)
\n
Rio de Janeiro BR 221,832,010.12 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 15 SA
\n
Rio de Janeiro BR 292,888,027.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 16 SA
\n
(formerly Enel Green
\n
Power Projetos 35 SA)
\n
Rio de Janeiro BR 252,240,012.65 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 17 SA
\n
(formerly Enel Green
\n
Power Projetos 31 SA)
\n
Rio de Janeiro BR 252,240,012.65 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 21 SA
\n
(formerly Enel Green
\n
Power Projetos 37 SA)
\n
Rio de Janeiro BR 276,814,829.93 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 22 SA
\n
(formerly Enel Green
\n
Power Projetos 39 SA)
\n
Rio de Janeiro BR 274,625,153.91 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 25 SA
\n
(formerly Enel Green
\n
Power Projetos 40 SA)
\n
Rio de Janeiro BR 171,324,007.59 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 26 SA
\n
(formerly Enel Green
\n
Power Projetos 41 SA)
\n
Rio de Janeiro BR 344,251,125.91 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 26 SA
\n
(formerly Enel
\n
Green Power
\n
Projetos 41 SA)
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 3 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 7 SA
\n
(formerly Enel Green
\n
Power Lagedo Alto SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green
\n
Power Ventos de
\n
Santa Esperan\u00e7a
\n
Participa\u00e7\u00f5es SA
\n
(formerly Enel Green
\n
Power Cumaru 06 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santo
\n
Orestes 1 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santo
\n
Orestes 2 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
01 SA
\n
Teresina BR 383,436,550.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
02 SA
\n
Teresina BR 369,758,650.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
03 SA
\n
Teresina BR 112,576,700.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
04 SA
\n
Teresina BR 379,980,530.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
05 SA
\n
Teresina BR 212,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
06 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
07 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
08 SA
\n
Teresina BR 337,473,758.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
11 SA
\n
Teresina BR 318,740,450.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
13 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
16 SA
\n
Teresina BR 353,284,550.79 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
17 SA
\n
Teresina BR 298,952,100.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
18 SA
\n
Teresina BR 332,473,758.81 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
19 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
22 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
26 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
29 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Verwaltungs GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power
\n
Vietnam LLC (C\u00f4ng
\n
ty TNHH Enel Green
\n
Power Vi\u0265t Nam)
\n
Ho Chi Minh
\n
City
\n
VN 2,431,933.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Villoresi Srl
\n
Rome IT 1,200,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
51.00% 51.00%
\n
Enel Green Power Volta
\n
Grande SA (formerly
\n
Enel Green Power
\n
Projetos I SA)
\n
Niter\u00f3i BR 565,756,528.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Zambia Limited
\n
Lusaka ZM 15,000.00 ZMW
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
99.00%
\n
Enel Green Power Zeus
\n
II - Delfina 8 SA
\n
Rio de Janeiro BR 77,939,980.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Zeus
\n
Sul 1 Ltda
\n
Rio de Janeiro BR 6,986,993.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Zeus
\n
Sul 2 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Grids Srl Rome IT 10,100,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Guatemala SA Guatemala City GT 67,208,000.00 GTQ
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.00%
\n
47.18%
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Holding Finance
\n
Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Iberia SRLU Madrid ES 336,142,500.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Innovation Hubs
\n
Srl
\n
Rome IT 1,100,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Insurance NV Amsterdam NL 60,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Investment
\n
Holding BV
\n
Amsterdam NL 1,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Italia SpA Rome IT 100,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Kansas
\n
Development Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Kansas LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Land HoldCo LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Logistics Srl Rome IT 1,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Minnesota
\n
Holdings LLC
\n
Minneapolis US - USD
\n
Line-by-line
\n
EGP Geronimo
\n
Holding Company
\n
Inc.
\n
100.00% 100.00%
\n
Enel Nevkan Inc. Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel North America Inc. Andover US 50.00 USD
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Operations
\n
Canada Ltd
\n
Alberta CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Panam\u00e1 CAM Srl Panama City PA 3,001.00 USD
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.03%
\n
47.19%
\n
Enel Colombia SA
\n
ESP
\n
99.97%
\n
Enel Per\u00fa SAC San Miguel PE 5,361,789,105.00 PEN
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Enel Produzione SpA Rome IT 1,800,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Renovable Srl Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
Enel Rinnovabile SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
Global Investment
\n
BV
\n
99.00%
\n
100.00%
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
1.00%
\n
Enel Roadrunner Solar
\n
Project Holdings II LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Enel Roadrunner Solar
\n
Project Holdings LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel Romania SA Buftea RO 200,000.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Salt Wells LLC Fallon US - USD Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
Enel Saudi Arabia
\n
Limited
\n
Al Khobar SA 1,000,000.00 SAR
\n
Line-by-line
\n
e-distribuzione
\n
SpA
\n
60.00% 60.00%
\n
Enel Servicii Comune
\n
SA
\n
Bucharest RO 33,000,000.00 RON
\n
Discontinued
\n
operations
\n
E-Distribu\u0163ie Banat
\n
SA
\n
50.00%
\n
51.00%
\n
E-Distribu\u0163ie
\n
Dobrogea SA
\n
50.00%
\n
Enel Sole Srl Rome IT 4,600,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Solu\u00e7\u00f5es
\n
Energ\u00e9ticas Ltda
\n
Rio de Janeiro BR 42,863,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Solu\u00e7\u00f5es
\n
Energ\u00e9ticas Ltda
\n
0.00%
\n
Enel Stillwater LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
Enel Surprise Valley LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Texkan Inc. Wilmington US 100.00 USD
\n
Line-by-line Chi Power Inc. 100.00% 100.00%
\n
Enel Trade Energy Srl Bucharest RO 2,437,050.00 RON
\n
Discontinued
\n
operations
\n
Enel Romania SA 100.00% 100.00%
\n
Enel Trade Serbia doo
\n
Beograd in liquidation
\n
Belgrade RS 300,000.00 EUR
\n
Line-by-line
\n
Enel Global Trading
\n
SpA
\n
100.00% 100.00%
\n
Enel Trading Argentina
\n
Srl
\n
Buenos Aires AR 14,011,100.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 55.00%
\n
82.26%
\n
Enel Argentina SA 45.00%
\n
Enel Trading Brasil SA Rio de Janeiro BR 5,280,312.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Trading North
\n
America LLC
\n
Wilmington US 10,000,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Uruguay SA Montevideo UY 20,000.00 UYU
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Vayu (Project 2)
\n
Private Limited
\n
Gurugram IN 45,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Enel Wind Project
\n
(Amberi) Private Limited
\n
New Delhi IN 5,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services North America
\n
Inc.
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services Srl
\n
Rome IT - EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Advisory
\n
Services UK Limited
\n
London GB 502.00 GBP
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services USA LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Arecibo LLC Boston US - USD
\n
Line-by-line
\n
Enel X Pr Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X Argentina SAU Buenos Aires AR 127,800,000.00 ARS
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Asputeck Ave.
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Australia Holding
\n
(Pty) Ltd
\n
Melbourne AU 28,424,578.00 AUD
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Australia (Pty)
\n
Ltd
\n
Melbourne AU 7,209,880.00 AUD
\n
Line-by-line
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
100.00% 100.00%
\n
Enel X Battery Storage
\n
Limited Partnership
\n
Oakville CA 10,000.00 CAD
\n
Line-by-line
\n
Enel X Canada
\n
Holding Inc.
\n
0.01%
\n
100.00%
\n
Enel X Canada Ltd 99.99%
\n
Enel X Brasil
\n
Gerenciamento de
\n
Energia Ltda
\n
Sorocaba BR 5,538,403.00 BRL
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
0.00%
\n
100.00%
\n
EnerNOC UK II
\n
Limited
\n
100.00%
\n
Enel X Brasil SA Niter\u00f3i BR 471,725,892.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel X Canada Holding
\n
Inc.
\n
Oakville CA 1,000.00 CAD
\n
Line-by-line Enel X Canada Ltd 100.00% 100.00%
\n
Enel X Canada Ltd Mississauga CA 1,000.00 CAD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Chile SpA
\n
Santiago de
\n
Chile
\n
CL 3,341,831,929.00 CLP
\n
Line-by-line Enel Chile SA 100.00% 64.93%
\n
Enel X College Ave.
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X Colombia SAS
\n
ESP
\n
Bogot\u00e1 CO 50,368,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Enel X Federal LLC Boston US 5,000.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Finance Partner
\n
LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Financial
\n
Services Srl
\n
Rome IT 1,000,000.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Enel X Germany GmbH Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Hayden Rowe St.
\n
Project LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X International Srl Rome IT 100,000.00 EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Ireland Limited Dublin IE 10,841.00 EUR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Italia Srl Rome IT 200,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel X Japan KK Tokyo JP 1,030,000,000.00 JPY
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X KOMIPO Solar
\n
Limited
\n
Seoul KR 8,472,600,000.00 KRW
\n
Line-by-line
\n
Enel X Korea
\n
Limited
\n
80.00% 80.00%
\n
Enel X Korea Limited Seoul KR 11,800,000,000.00 KRW
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Las Piedras LLC Boston US - USD
\n
Line-by-line
\n
Enel X Pr Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X MA Holdings LLC Boston US 100.00 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X MA PV Portfolio
\n
2 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio
\n
3 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X M\u00e9xico S de RL
\n
de Cv
\n
Mexico City MX 39,921,546.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel X International
\n
Srl
\n
100.00%
\n
Enel X Mobility Srl Rome IT 100,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel X Morrissey Blvd.
\n
Project LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X New Zealand
\n
Limited
\n
Wellington NZ 313,606.00 AUD
\n
Line-by-line
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
100.00% 100.00%
\n
Enel X North America
\n
Inc.
\n
Boston US 1,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Norway AS Porsgrunn NO 11,000,000.00 NOK
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Per\u00fa SAC San Miguel PE 12,005,000.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 100.00% 82.27%
\n
Enel X Polska Sp. zo.o. Warsaw PL 12,275,150.00 PLN
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
Enel X Pr Holdings LLC Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Project MP
\n
Holdings LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Sponsor LLC
\n
100.00% 100.00%
\n
Enel X Project MP
\n
Sponsor LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Romania Srl Bucharest RO 7,044,450.00 RON
\n
Discontinued
\n
operations
\n
Enel X International
\n
Srl
\n
99.97%
\n
100.00%
\n
Enel X Srl 0.03%
\n
Enel X Rus LLC Moscow RU 8,000,000.00 RUB
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
99.00% 99.00%
\n
Enel X Srl Rome IT 1,050,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Services India
\n
Private Limited
\n
Mumbai City IN 45,000.00 INR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00%
\n
100.00%
\n
Enel X North
\n
America Inc.
\n
0.00%
\n
Enel X Singapore Pte
\n
Ltd
\n
Singapore SG 1,212,000.00 SGD
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Taiwan Co. Ltd Taipei City TW 76,100,000.00 TWD
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
Enel X UK Limited London GB 32,628.00 GBP
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Way (Shanghai)
\n
Co. Ltd
\n
Shanghai CN 3,500,000.00 USD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Brasil SA Rio de Janeiro BR 3,045,337.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 20.00%
\n
96.45%
\n
Enel X Way Srl 80.00%
\n
Enel X Way Canada
\n
Holding Ltd
\n
Vancouver CA - CAD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Way Chile SpA
\n
Santiago de
\n
Chile
\n
CL 11,229,030,071.00 CLP
\n
Line-by-line
\n
Enel Chile SA 49.00%
\n
82.81%
\n
Enel X Way Srl 51.00%
\n
Enel X Way France SAS Paris FR 2,901,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Germany
\n
GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Italia Srl Rome IT 5,000,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way North
\n
America Inc.
\n
San Carlos US 0.10 USD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Per\u00fa SAC Lima PE 1,561,900.00 PEN
\n
Line-by-line
\n
Enel Per\u00fa SAC 20.00%
\n
96.45%
\n
Enel X Way Srl 80.00%
\n
Enel X Way Romania Srl Bucharest RO 12,778,740.00 RON
\n
Discontinued
\n
operations
\n
Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Srl Rome IT 6,026,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Way Sweden AB Stockholm SE 50,000.00 SEK
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way UK Limited London GB 1.00 GBP
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way USA LLC San Carlos US - USD
\n
Line-by-line
\n
Enel X Way North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Wood St. Project
\n
LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Woodland Solar
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enelpower Contractor
\n
and Development
\n
Saudi Arabia Ltd
\n
Riyadh SA 5,000,000.00 SAR
\n
Line-by-line EnelPower Srl 51.00% 51.00%
\n
Enelpower do Brasil
\n
Ltda
\n
Rio de Janeiro BR 5,689,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
EnelPower Srl Milan IT 2,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
San Miguel PE 6,463,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Energ\u00eda Base Natural
\n
SLU
\n
Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda Ceuta XXI
\n
Comercializadora de
\n
Referencia SAU
\n
Ceuta ES 65,000.00 EUR
\n
Line-by-line
\n
Empresa de
\n
Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
SA
\n
100.00% 67.61%
\n
Energ\u00eda E\u00f3lica \u00c1brego
\n
SLU
\n
Madrid ES 3,576.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Galerna
\n
SLU
\n
Madrid ES 3,413.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Gregal
\n
SLU
\n
Madrid ES 3,250.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda Global de
\n
M\u00e9xico (Enermex) SA
\n
de Cv
\n
Mexico City MX 50,000.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.00% 99.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Energ\u00eda Global
\n
Operaciones Srl
\n
San Jos\u00e9 CR 10,000.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
100.00% 47.18%
\n
Energ\u00eda Limpia de
\n
Amistad SA de Cv
\n
Mexico City MX 33,452,769.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de Palo
\n
Alto SA de Cv
\n
Mexico City MX 673,583,489.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de
\n
Puerto Libertad S de
\n
RL de Cv
\n
Mexico City MX 2,953,980.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.01%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.99%
\n
Energ\u00eda Marina SpA
\n
Santiago de
\n
Chile
\n
CL 2,404,240,000.00 CLP
\n
Equity
\n
Enel Green Power
\n
Chile SA
\n
25.00% 16.23%
\n
Energ\u00eda Neta Sa Caseta
\n
Llucmajor SLU
\n
Palma de
\n
Mallorca
\n
ES 9,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda XXI
\n
Comercializadora de
\n
Referencia SLU
\n
Madrid ES 2,000,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Energ\u00eda y Naturaleza
\n
SLU
\n
Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
Santiago de
\n
Chile
\n
CL 12,120,575.70 USD
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Energ\u00edas Alternativas
\n
del Sur SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 546,919.10 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
54.95% 38.53%
\n
Energ\u00edas de Arag\u00f3n
\n
I SLU
\n
Zaragoza ES 3,200,000.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Energ\u00edas de Graus SL Barcelona ES 1,298,160.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.75%
\n
Energ\u00edas Especiales de
\n
Care\u00f3n SA
\n
Santiago de
\n
Compostela
\n
ES 270,450.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
97.00% 68.01%
\n
Energ\u00edas Especiales de
\n
Pe\u00f1a Armada SAU
\n
Madrid ES 963,300.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00edas Especiales del
\n
Alto Ulla SAU
\n
Madrid ES 9,210,840.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00edas Especiales del
\n
Bierzo SA
\n
Torre del Bierzo ES 1,635,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
Energ\u00edas Limpias de
\n
Carmona SL
\n
Seville ES 7,000.00 EUR
\n
Equity
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
6.25%
\n
13.15%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
6.25%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
6.25%
\n
Energ\u00edas Renovables La
\n
Mata SA de Cv
\n
Mexico City MX 656,615,400.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
1.00%
\n
Energie Electrique de
\n
Tahaddart SA
\n
Tangier MA 306,160,000.00 MAD
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
32.00% 22.44%
\n
Energo Sonne Srl Bucharest RO 31,520.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Energotel AS Bratislava SK 2,191,200.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
20.00% 6.60%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
ENergy Hydro Piave Srl
\n
in liquidation
\n
Belluno IT 800,000.00 EUR
\n
Line-by-line
\n
Enel Produzione
\n
SpA
\n
100.00% 100.00%
\n
Energy Podium Private
\n
Company
\n
Katerini Pieria GR 4,001.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.02% 0.02%
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
Melbourne AU 35,128,517.00 AUD
\n
Line-by-line
\n
Enel X Australia
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
EnerNOC GmbH Munich DE 25,000.00 EUR
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
EnerNOC Ireland
\n
Limited
\n
Dublin IE 10,589.00 EUR
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
EnerNOC UK II Limited London GB 21,000.00 GBP
\n
Line-by-line Enel X UK Limited 100.00% 100.00%
\n
Enigma Green Power
\n
1 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Entech (China)
\n
Information Technology
\n
Co. Ltd
\n
Shenzhen CN 140,000.00 USD
\n
Equity
\n
EnerNOC UK II
\n
Limited
\n
50.00% 50.00%
\n
Entech Utility Service
\n
Bureau Inc.
\n
Lutherville US 1,500.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
XX SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
E\u00f3lica Valle del Ebro SA Zaragoza ES 3,561,342.50 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.50% 35.41%
\n
E\u00f3lica Zopiloapan SA
\n
de Cv
\n
Mexico City MX 1,877,201.54 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
56.98%
\n
96.48%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
39.50%
\n
E\u00f3licas de Agaete SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 240,400.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
E\u00f3licas de Fuencaliente
\n
SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 216,360.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
55.00% 38.56%
\n
E\u00f3licas de
\n
Fuerteventura AIE
\n
Puerto del
\n
Rosario
\n
ES - EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
E\u00f3licas de la Patagonia
\n
SA
\n
Buenos Aires AR 480,930.00 ARS
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
E\u00f3licas de Lanzarote SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 1,758,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
E\u00f3licas de Tenerife AIE
\n
Santa Cruz de
\n
Tenerife
\n
ES 420,708.40 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
E\u00f3licos de Tirajana SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Epresa Energ\u00eda SA Cadiz ES 2,500,000.00 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ermis 2 Energeiaki
\n
Private Company
\n
Grevena GR 1,002.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.10%
\n
E-Solar 2 Srl Rome IT 2,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
E-Solar Srl Rome IT 2,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Essaouira Wind Farm Casablanca MA 300,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
European Energy
\n
Exchange AG
\n
Leipzig DE 40,050,000.00 EUR
\n
-
\n
Enel Global Trading
\n
SpA
\n
2.38% 2.38%
\n
Evacuaci\u00f3n Carmona
\n
400-220 kV
\n
Renovables SL
\n
Seville ES 10,003.00 EUR
\n
Equity
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
3.13%
\n
6.58%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
3.13%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
3.13%
\n
Evolution Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ewiva Srl Milan IT 1,000,000.00 EUR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Expedition Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explotaciones E\u00f3licas
\n
de Escucha SA
\n
Zaragoza ES 3,505,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
70.00% 49.08%
\n
Explotaciones E\u00f3licas
\n
El Puerto SA
\n
Zaragoza ES 3,230,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
73.60% 51.61%
\n
Explotaciones E\u00f3licas
\n
Santo Domingo de
\n
Luna SA
\n
Zaragoza ES 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Explotaciones E\u00f3licas
\n
Saso Plano SA
\n
Zaragoza ES 5,488,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
65.00% 45.58%
\n
Explotaciones E\u00f3licas
\n
Sierra Costera SA
\n
Zaragoza ES 8,046,800.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Explotaciones E\u00f3licas
\n
Sierra La Virgen SA
\n
Zaragoza ES 4,200,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Farrier Station Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Fayette Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fazenda Aroeira
\n
Empreendimento de
\n
Energia Ltda
\n
Rio de Janeiro BR 2,362,045.90 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fence Post Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Fence Post Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fence Post Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fenner Wind Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Field Day Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Finocchiara Solar Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Finsec Lab Ltd Tel Aviv IL 100.00 ILS
\n
Equity Enel X Srl 30.00% 30.00%
\n
Flagpay Srl Milan IT 10,000.00 EUR
\n
Equity PayTipper SpA 100.00% 50.00%
\n
Flat Rock Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Flat Rocks Girgarre
\n
Cohuna Finco (Pty) Ltd
\n
Sydney AU 120.00 AUD
\n
AFS
\n
Cohuna Solar Farm
\n
Trust
\n
33.33%
\n
100.00%
\n
Flat Rocks One
\n
Wind Farm Trust
\n
33.33%
\n
Girgarre Solar Farm
\n
Trust
\n
33.33%
\n
Flat Rocks One Wind
\n
Farm (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
Flat Rocks One Wind
\n
Farm Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding Trust
\n
100.00% 100.00%
\n
Flat Top Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Flint Rock Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Florence Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Flowing Spring Farms
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fontib\u00f3n ZE SAS Bogot\u00e1 CO 392,420,000.00 COP
\n
AFS Bogot\u00e1 ZE SAS 100.00% 47.18%
\n
F\u00f3tons de Santo
\n
Anchieta Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 577,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fotovoltaica Yunclillos
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Fourmile Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Fox Run Energy Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Franklintown Farm LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Freedom Energy
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Front Mar\u00edtim del
\n
Bes\u00f2s SL
\n
Barcelona ES 9,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
61.37% 43.03%
\n
Frontiersman Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
FRV Corchitos I SLU Madrid ES 75,800.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
FRV Corchitos II Solar
\n
SLU
\n
Madrid ES 22,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Gibalb\u00edn - Jerez
\n
SLU
\n
Madrid ES 23,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Tarifa SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Villalobillos SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 1
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 3
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRWF Stage 1 (Pty) Ltd Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Fundamental
\n
Recognized Systems
\n
SLU
\n
Andorra ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Furatena Solar 1 SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Ganado Solar Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Ganado Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ganado Solar LLC Andover US - USD
\n
Line-by-line
\n
Ganado Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ganado Storage LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Garob Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 100.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Gas y Electricidad
\n
Generaci\u00f3n SAU
\n
Palma de
\n
Mallorca
\n
ES 213,775,700.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Gauley Hydro LLC Wilmington US - USD
\n
Equity GRPP Holdings LC 100.00% 50.00%
\n
Gauley River
\n
Management LLC
\n
Willison US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Generadora de
\n
Occidente Ltda
\n
Guatemala City GT 16,262,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
99.00%
\n
47.18%
\n
Enel Guatemala SA 1.00%
\n
Generadora E\u00f3lica Alto
\n
Pacora Srl
\n
Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
Generadora
\n
Montecristo SA
\n
Guatemala City GT 3,820,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%
\n
Enel Guatemala SA 0.00%
\n
Generadora Solar
\n
Austral SA
\n
Chiriqu\u00ed PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar de
\n
Occidente SA
\n
Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar El
\n
Puerto SA
\n
Chiriqu\u00ed PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar
\n
Tol\u00e9 Srl
\n
Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Geot\u00e9rmica del Norte
\n
SA
\n
Santiago de
\n
Chile
\n
CL 326,577,419,702.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
84.59% 54.92%
\n
Gibson Bay Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Girgarre Solar Farm
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Girgarre Holdings
\n
(Pty) Ltd
\n
100.00% 100.00%
\n
Girgarre Solar Farm
\n
Trust
\n
Sydney AU 10.00 AUD
\n
AFS
\n
Enel Green Power
\n
Girgarre Trust
\n
100.00% 100.00%
\n
Glass Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Global Commodities
\n
Holdings Limited
\n
London GB 4,042,375.00 GBP
\n
-
\n
Enel Global Trading
\n
SpA
\n
4.68% 4.68%
\n
Globyte SA San Jos\u00e9 CR 900,000.00 CRC
\n
-
\n
Enel Costa Rica
\n
CAM SA
\n
10.00% 4.72%
\n
Gloucester Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
GNL Chile SA
\n
Santiago de
\n
Chile
\n
CL 3,026,160.00 USD
\n
Equity
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
33.33% 20.25%
\n
Goodwell Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Gooseneck Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gorona del Viento El
\n
Hierro SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 30,936,736.00 EUR
\n
Equity
\n
Uni\u00f3n El\u00e9ctrica
\n
de Canarias
\n
Generaci\u00f3n SAU
\n
23.21% 16.28%
\n
Grand Prairie Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Gridspertise Iberia SL Madrid ES 3,000.00 EUR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise Latam SA S\u00e3o Paulo BR 2,010,000.00 BRL
\n
Equity
\n
Enel Brasil SA 0.00%
\n
50.00%
\n
Gridspertise Srl 100.00%
\n
Gridspertise Srl Rome IT 7,500,000.00 EUR
\n
Equity Enel Grids Srl 50.00% 50.00%
\n
Gridspertise LLC Dover US 160,000.00 USD
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
GRPP Holdings LLC Andover US 2.00 USD
\n
Equity
\n
EGPNA REP
\n
Holdings LLC
\n
50.00% 50.00%
\n
Guadarranque Solar
\n
4 SLU
\n
Seville ES 3,006.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
II SAU
\n
100.00% 70.12%
\n
Guayepo Solar SAS Bogot\u00e1 CO 1,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Guir Wind Farm Casablanca MA 10,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
99.00%
\n
99.00%
\n
Mrs Riveros Perez
\n
Paula Cristina
\n
1.00%
\n
GulfStar Power LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gusty Hill Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
GV Energie Rigenerabili
\n
ITAL-RO Srl
\n
Bucharest RO 1,145,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Hadley Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Hamilton County Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Hansborough Valley
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Harmony Plains Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Hastings Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Heartland Farms Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
Barcelona ES 126,210.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Hidroel\u00e9ctrica de
\n
Ourol SL
\n
Lugo ES 1,608,200.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Hidroelectricidad del
\n
Pac\u00edfico S de RL de Cv
\n
Colima MX 30,890,736.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
Hidroflamicell SL Barcelona ES 78,120.00 EUR
\n
Line-by-line
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
75.00% 52.59%
\n
Hidroinvest SA Buenos Aires AR 55,312,093.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 41.94%
\n
79.55%
\n
Enel Argentina SA 54.76%
\n
HIF H2 SpA
\n
Santiago de
\n
Chile
\n
CL 6,303,000.00 USD
\n
Equity
\n
Enel Green Power
\n
Chile SA
\n
50.00% 32.46%
\n
High Chaparral Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome
\n
Storage LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind
\n
Holdings LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind
\n
Power LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
High Lonesome
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
High Noon Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Street
\n
Corporation (Pty) Ltd
\n
Melbourne AU 2.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Hilltopper Wind
\n
Holdings LLC
\n
Wilmington US 1,000.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hispano Generaci\u00f3n de
\n
Energ\u00eda Solar SL
\n
Jerez de los
\n
Caballeros
\n
ES 3,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Honey Stone Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Honeybee Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hope Creek LLC Crestview US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Hope Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Horse Run Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Horse Wrangler Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hubject eRoaming
\n
Technology (Shanghai)
\n
Co. Ltd
\n
Shangai CN 12,668,015.70 CNY
\n
- Hubject GmbH 100.00% 12.50%
\n
Hubject GmbH Berlin DE 65,943.00 EUR
\n
- Enel X Way Srl 12.50% 12.50%
\n
Hubject Inc. Santa Monica US 100,000.00 USD
\n
- Hubject GmbH 100.00% 12.50%
\n
ICE Tudela SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.12% 3.59%
\n
Idalia Park Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Idrosicilia SpA Milan IT 22,520,000.00 EUR
\n
Equity Enel SpA 1.00% 1.00%
\n
IFX Networks Argentina
\n
Srl
\n
Buenos Aires AR 2,260,551.00 ARS
\n
-
\n
IFX/Eni - SPC V Inc. 99.85%
\n
19.50%
\n
Minority Stock
\n
Holding Corp.
\n
0.15%
\n
IFX Networks Colombia
\n
SAS
\n
Bogot\u00e1 CO 18,951,211,000.00 COP
\n
-
\n
IFX Networks
\n
Panama SA
\n
48.43%
\n
19.50%
\n
IFX/Eni - SPC III Inc. 34.60%
\n
Livister Latam SLU 16.97%
\n
IFX Networks LLC Wilmington US 80,848,653.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
IFX Networks Ltd Tortola VG 50,001.00 USD
\n
- IFX Networks LLC 100.00% 19.50%
\n
IFX Networks Panama
\n
SA
\n
Panama City PA 26,460.00 USD
\n
-
\n
IFX/Eni - SPC
\n
Panama Inc.
\n
79.37%
\n
19.50%
\n
Livister Latam SLU 20.63%
\n
IFX/Eni - SPC III Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC IV Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC Panama
\n
Inc.
\n
Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC V Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IIK Energ\u00eda de Dzemul
\n
SA de Cv
\n
Mexico City MX 6,479,172.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
IIK Energ\u00eda de Telchac
\n
SA de Cv
\n
Mexico City MX - MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
Infraestructura de
\n
Evacuaci\u00f3n Pe\u00f1aflor
\n
220 kV SL
\n
Madrid ES 3,500.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
41.14% 28.85%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Infraestructuras Puerto
\n
Santa Mar\u00eda 220 SL
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda I SLU
\n
50.00%
\n
70.12%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda II SLU
\n
50.00%
\n
Infraestructuras San
\n
Serv\u00e1n 220 SL
\n
Madrid ES 12,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.80% 21.60%
\n
Infraestructuras San
\n
Serv\u00e1n Set 400 SL
\n
Madrid ES 90,000.00 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
6.41%
\n
13.48%Baylio Solar SLU 6.41%
\n
Furatena Solar 1
\n
SLU
\n
6.41%
\n
Inkolan Informaci\u00f3n
\n
y Coordinaci\u00f3n de
\n
Obras AIE
\n
Bilbao ES 84,141.68 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Inspectores y
\n
Consultores Ibercal
\n
SLU
\n
Vizcaya ES 3,100.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Instalaciones San
\n
Serv\u00e1n II 400 SL
\n
Madrid ES 11,026.00 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
7.94%
\n
16.69%Baylio Solar SLU 7.94%
\n
Furatena Solar 1
\n
SLU
\n
7.94%
\n
International
\n
Multimedia University
\n
Srl in bankruptcy
\n
- IT 24,000.00 EUR
\n
- Enel Italia SpA 13.04% 13.04%
\n
Inversora Dock Sud SA Buenos Aires AR 828,941,660.00 ARS
\n
AFS Enel Am\u00e9ricas SA 57.14% 47.01%
\n
Ipsomata DPGU Private
\n
Company
\n
Heraklion, Crete GR 5,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.02% 0.02%
\n
Iris Bloom Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Belt Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Bull Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Isamu Ikeda Energia SA Niter\u00f3i BR 16,474,475.77 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Italgest Energy (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Jack River LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Jade Energia Ltda Rio de Janeiro BR 4,107,097.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Jaguito Solar 10 MW SA Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Jessica Mills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Julia Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Junia Insurance Srl
\n
Mosciano
\n
Sant\u2019Angelo (TE)
\n
IT 100.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Juniper Canyon Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Keeneys Creek Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ken Renewables India
\n
Private Limited
\n
Gurugram IN 12,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Khaba Renewable
\n
Energy Private Limited
\n
Gurugram IN 18,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Khidrat Renewable
\n
Energy Private Limited
\n
Gurugram IN 78,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
King Branch Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Kingston Energy
\n
Storage LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Kino Contractor SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
1.00%
\n
Kino Facilities Manager
\n
SA de Cv
\n
Mexico City MX 2,933,340.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Kokkinari DPGU Private
\n
Company
\n
Heraklion, Crete GR 15,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.01% 0.01%
\n
Kongul Enerj\u00ed Sanay\u00ed Ve
\n
T\u00edcaret Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 14,537,500.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari Anon\u00edm
\n
\u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Koporie WPS LLC
\n
Leningrad
\n
Region
\n
RU 21,000,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Korea Line Corporation Seoul KR 122,132,520,000.00 KRW
\n
-
\n
Enel Global Trading
\n
SpA
\n
0.25% 0.25%
\n
Koukos Energy Private
\n
Company
\n
Athens GR 4,002.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.05% 0.05%
\n
Kromschroeder SA Barcelona ES 627,126.00 EUR
\n
Equity
\n
Endesa Medios y
\n
Sistemas SLU
\n
29.26% 20.52%
\n
Lake Emily Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Lake Pulaski Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Land Run Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Land Run Wind Project
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Sundance Wind
\n
Project LLC
\n
100.00% 100.00%
\n
Lantern Trail Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Latamsolar Energ\u00edas
\n
Renovables SAS
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Latamsolar Fotovoltaica
\n
Fundaci\u00f3n SAS
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Lathrop Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Lava Solar Project LLC Andover US 1.00 USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lawrence Creek Solar
\n
LLC
\n
Minneapolis US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Lebanon Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Legacy Blossom
\n
Storage Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Lemonade Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Liberty Energy Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Libyan Italian Joint
\n
Company - Azienda
\n
Libico-Italiana (A.L.I.)
\n
Tripoli LY 1,350,000.00 EUR
\n
- EnelPower Srl 0.33% 0.33%
\n
Light Cirrus Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lily Solar Holdings LLC Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Lily Solar Holdings
\n
LLC
\n
100.00% 100.00%
\n
Lily Solar LLC Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Lindahl Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Lindahl Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Lindahl Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Elk Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Little Elk Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Little Elk Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Salt Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Litus Energy Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Livister Chile SpA
\n
Santiago de
\n
Chile
\n
CL 11,843,107,407.00 CLP
\n
- Livister Latam SLU 100.00% 19.50%
\n
Livister Latam SLU Madrid ES 2,442,066.00 EUR
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Llano S\u00e1nchez Solar
\n
Power One Srl
\n
Panama City PA 10,020.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.20%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.80%
\n
Lone Pine Wind Inc. Alberta CA - CAD
\n
-
\n
Enel Green Power
\n
Canada Inc.
\n
10.00% 10.00%
\n
Lone Pine Wind Project
\n
LP
\n
Alberta CA - CAD
\n
Equity
\n
Enel Green Power
\n
Canada Inc.
\n
10.00% 10.00%
\n
Lucas Sostenible SL Madrid ES 1,099,775.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
35.29% 24.74%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Luminary Highlands
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Luz de Angra Energia
\n
SA
\n
Rio de Janeiro BR 4,062,085.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Caruaru Energia
\n
SA
\n
Rio de Janeiro BR 21,027,600.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Jaboat\u00e3o
\n
Energia SA
\n
Rio de Janeiro BR 21,114,200.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Macap\u00e1 Energia
\n
SA
\n
Rio de Janeiro BR 24,338,000.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Maicor Wind Srl Rome IT 20,850,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Malaspina Energy Scarl
\n
in liquidation
\n
Bergamo IT 100,000.00 EUR
\n
Line-by-line Enel X Italia Srl 100.00% 100.00%
\n
Mansar Renewable
\n
Energy Private Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Maple Canada
\n
Solutions Holdings Ltd
\n
- CA - CAD
\n
Equity Enel X Canada Ltd 20.00% 20.00%
\n
Maple Energy Solutions
\n
LP
\n
- CA - CAD
\n
Equity
\n
Enel X Canada
\n
Holding Inc.
\n
20.00% 20.00%
\n
Maple Run Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Marte Srl Rome IT 6,100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Marudhar Wind Energy
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
M\u00e1s Energ\u00eda S de RL
\n
de Cv
\n
Mexico City MX 61,872,926.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99%
\n
100.00%
\n
Hidroelectricidad
\n
del Pac\u00edfico S de RL
\n
de Cv
\n
0.01%
\n
Mason Mountain Wind
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
Matrigenix (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Maty Energia Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
MC Solar I LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
McBride Wind Project
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Medidas Ambientales
\n
SL
\n
Burgos ES 60,100.00 EUR
\n
- Tecnatom SA 50.00% 15.78%
\n
Merit Wind Project LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Metro Wind LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Mexicana de
\n
Hidroelectricidad
\n
Mexhidro S de RL de Cv
\n
Mexico City MX 181,728,901.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mibgas SA Madrid ES 3,000,000.00 EUR - Endesa SA 1.35% 0.95%
\n
Midelt Wind Farm SA Casablanca MA 145,000,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
Minglanilla Renovables
\n
400 kV AIE
\n
Valencia ES - EUR
\n
Proportional
\n
Energ\u00eda Base
\n
Natural SLU
\n
4.79%
\n
25.36%
\n
Energ\u00eda E\u00f3lica
\n
\u00c1brego SLU
\n
7.98%
\n
Energ\u00eda E\u00f3lica
\n
Galerna SLU
\n
9.31%
\n
Energ\u00eda E\u00f3lica
\n
Gregal SLU
\n
9.31%
\n
Energ\u00eda y
\n
Naturaleza SLU
\n
4.79%
\n
Minicentrales Acequia
\n
Cinco Villas AIE
\n
Ejea de los
\n
Caballeros
\n
ES 3,346,993.04 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.39% 3.78%
\n
Minicentrales del Canal
\n
de las B\u00e1rdenas AIE
\n
Zaragoza ES 1,202,000.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
15.00% 10.52%
\n
Minicentrales del Canal
\n
Imperial-Gallur SL
\n
Zaragoza ES 1,820,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.50% 25.59%
\n
Minority Stock Holding
\n
Corp.
\n
Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
Mira Energy (Pty) Ltd Johannesburg ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Miranda Plataforma
\n
Log\u00edstica SA
\n
Burgos ES 1,800,000.00 EUR
\n
- Nuclenor SA 0.22% 0.08%
\n
MO Land Holdings
\n
1358 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Moebius Tecnologia
\n
em Informatica SA
\n
Rio de Janeiro BR 150,000.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
100.00% 19.50%
\n
Monte Reina
\n
Renovables SL
\n
Madrid ES 4,000.00 EUR
\n
Equity
\n
FRV Zamora Solar
\n
1 SLU
\n
20.58% 14.43%
\n
Montrose Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Moonbeam Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Mooney Group SpA Milan IT 10,050,000.00 EUR
\n
Equity Enel X Srl 50.00% 50.00%
\n
Mooney SpA Milan IT 87,833,331.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Mooney Servizi SpA Milan IT 8,549,999.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Morgan Branch Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Mount Pleasant Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Mountrail Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
MPG Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Mucho Viento Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mule Bit Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Muskegon County
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Muskegon Green Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Mustang Run Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Nabb Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Napolean Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Nareva Enel Green
\n
Power Morocco SA
\n
Casablanca MA 98,750,000.00 MAD
\n
Equity
\n
Enel Green Power
\n
Morocco SARLAU
\n
50.00% 50.00%
\n
Negocios y Telefon\u00eda
\n
NEDETEL SA
\n
Guayaquil EC 4,773,525.00 USD
\n
- Ufinet Latam SLU 70.00% 13.65%
\n
Net Botanic Internet
\n
Inteligente SA
\n
Rio de Janeiro BR 450,000.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
100.00% 19.50%
\n
Netra Renewable
\n
Energy Private Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Nevkan Renewables
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Nevkan Inc. 100.00% 100.00%
\n
New York Distributed
\n
Storage Projects LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ngonye Power
\n
Company Limited
\n
Lusaka ZM 10.00 ZMW
\n
AFS
\n
Enel Green Power
\n
Solar Ngonye SpA
\n
(formerly Enel
\n
Green Power Africa
\n
Srl)
\n
80.00% 80.00%
\n
Nojoli Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
North English Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
North Rock Wind LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northland Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northstar Wind Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northumberland Solar
\n
Project I LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Northwest Hydro LLC Wilmington US - USD
\n
Line-by-line Chi West LLC 100.00% 100.00%
\n
Novolitio Recuperaci\u00f3n
\n
de Bater\u00edas SL
\n
Ponferrada ES 180,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
45.00% 31.55%
\n
Nuclenor SA Burgos ES 102,000,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
50.00% 35.06%
\n
Nuove Energie Srl
\n
Porto
\n
Empedocle
\n
IT 5,204,028.73 EUR
\n
Line-by-line
\n
Enel Global Trading
\n
SpA
\n
100.00% 100.00%
\n
Nxuba Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
51.00% 25.50%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
NYC Storage (353
\n
Chester) SPE LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ochrana A Bezpecnost
\n
Se SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 33,193.92 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Olathe Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Olivum PV Farm 01 SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
OMIP - Operador
\n
do Mercado Ib\u00e9rico
\n
(Portugal) SGPS SA
\n
Lisbon PT 2,610,000.00 EUR
\n
-
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
5.00% 3.51%
\n
Open Range Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Operador del Mercado
\n
Ib\u00e9rico de Energ\u00eda -
\n
Polo Espa\u00f1ol SA
\n
Madrid ES 1,999,998.00 EUR
\n
- Endesa SA 5.00% 3.51%
\n
Oravita Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Orchid Acres Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Origin Goodwell
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Wind
\n
Holdings 1 LLC
\n
100.00% 10.00%
\n
Origin Wind Energy
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Osage Wind Holdings
\n
LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line Enel Kansas LLC 50.00% 50.00%
\n
Osage Wind LLC Wilmington US - USD
\n
Line-by-line
\n
Osage Wind
\n
Holdings LLC
\n
100.00% 50.00%
\n
Ossining Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ovacik Eol\u00edko Enerj\u00ed
\n
Elektr\u00edk \u00dcret\u00edm Ve
\n
T\u00edcaret Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 2,925,900.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Oxagesa AIE in
\n
liquidation
\n
Alca\u00f1iz ES 6,010.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Oyster Bay Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Padoma Wind Power
\n
LLC
\n
Elida US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Painted Rose Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Palo Alto Farms Wind
\n
Project LLC
\n
Dallas US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pampinus PV Farm
\n
01 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Paradise Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Paravento SL Lugo ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Parc E\u00f2lic La Tossa-La
\n
Mola d\u2019en Pascual SL
\n
Madrid ES 1,183,100.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parc E\u00f2lic Los Aligars
\n
SL
\n
Madrid ES 1,313,100.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Parco Eolico Monti
\n
Sicani Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Parque Amistad II SA
\n
de Cv
\n
Mexico City MX 1,413,533,480.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad III SA
\n
de Cv
\n
Mexico City MX 931,692,540.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad IV SA
\n
de Cv
\n
Mexico City MX 1,489,508,400.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque E\u00f3lico A
\n
Capelada SLU
\n
A Coru\u00f1a ES 5,857,704.33 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico
\n
Belmonte SA
\n
Madrid ES 120,400.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.17% 35.18%
\n
Parque E\u00f3lico BR-1
\n
SAPI de Cv
\n
Mexico City MX - MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
25.50%
\n
Enel Rinnovabile SA
\n
de Cv
\n
25.00%
\n
Parque E\u00f3lico
\n
Carretera de Arinaga
\n
SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 1,603,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
Parque E\u00f3lico de
\n
Barbanza SA
\n
A Coru\u00f1a ES 3,606,072.60 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.00%
\n
52.59%
\n
Parque E\u00f3lico de
\n
Barbanza SA
\n
0.00%
\n
Parque E\u00f3lico de San
\n
Andr\u00e9s SA
\n
A Coru\u00f1a ES 552,920.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
82.00% 57.50%
\n
Parque E\u00f3lico de Santa
\n
Luc\u00eda SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 901,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
65.67%
\n
46.51%
\n
Parque E\u00f3lico de
\n
Santa Luc\u00eda SA
\n
1.00%
\n
Parque E\u00f3lico Finca de
\n
Mog\u00e1n SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 3,810,340.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Parque E\u00f3lico Montes
\n
de las Navas SA
\n
Madrid ES 6,540,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.50% 52.94%
\n
Parque E\u00f3lico Muniesa
\n
SLU
\n
Madrid ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico Palmas
\n
dos Ventos Ltda
\n
Salvador BR 4,096,626.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Parque E\u00f3lico Pampa
\n
SA
\n
Buenos Aires AR 477,139,364.00 ARS
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Parque E\u00f3lico Punta de
\n
Teno SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 528,880.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
52.00% 36.46%
\n
Parque E\u00f3lico Sierra del
\n
Madero SA
\n
Madrid ES 7,193,970.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
58.00% 40.67%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parque Salitrillos SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Solar Cauchari
\n
IV SA
\n
San Salvador
\n
de Jujuy
\n
AR 500,000.00 ARS
\n
Line-by-line
\n
Enel Green Power
\n
Argentina SA
\n
95.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
5.00%
\n
Parque Solar Don Jos\u00e9
\n
SA de Cv
\n
Mexico City MX 100.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Solar Villanueva
\n
Tres SA de Cv
\n
Mexico City MX 306,024,631.13 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Talinay Oriente
\n
SA
\n
Santiago de
\n
Chile
\n
CL 66,092,165,170.93 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
60.91%
\n
78.64%
\n
Enel Green Power
\n
SpA
\n
39.09%
\n
Pastis - Centro
\n
Nazionale per la
\n
ricerca e lo sviluppo
\n
dei materiali SCPA in
\n
liquidation
\n
Brindisi IT 2,065,000.00 EUR
\n
- Enel Italia SpA 1.14% 1.14%
\n
Paynesville Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
PayTipper Network Srl Cascina IT 40,000.00 EUR
\n
Equity PayTipper SpA 100.00% 50.00%
\n
PayTipper SpA Milan IT 3,000,000.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
PDP Technologies Ltd Israel IL 1,129,252.00 ILS
\n
- Enel Grids Srl 5.72% 5.72%
\n
Pearl Star Wind Limited
\n
Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Pebble Stream Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pegop - Energia
\n
El\u00e9ctrica SA
\n
Pego PT 50,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
0.02%
\n
35.06%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
49.98%
\n
PH Chucas SA San Jos\u00e9 CR 100,000.00 CRC
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
24.69%
\n
30.67%
\n
Enel Costa Rica
\n
CAM SA
\n
40.31%
\n
PH Don Pedro SA San Jos\u00e9 CR 100,001.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
33.44%
\n
18.92%
\n
Globyte SA 66.54%
\n
PH R\u00edo Volc\u00e1n SA San Jos\u00e9 CR 100,001.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
34.32%
\n
19.29%
\n
Globyte SA 65.66%
\n
Piebald Hill Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pike Den Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pilesgrove Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Pincher Creek LP Alberta CA - CAD Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
51.00%
\n
51.00%
\n
Enel Green Power
\n
Canada Inc.
\n
1.00%
\n
Pine Island Distributed
\n
Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Point Rider Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pomerado Energy
\n
Storage LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Potoc Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
PowerCrop
\n
Macchiareddu Srl
\n
Bologna IT 100,000.00 EUR
\n
Equity
\n
PowerCrop
\n
SpA (formerly
\n
PowerCrop Srl)
\n
100.00% 50.00%
\n
PowerCrop Russi Srl Bologna IT 100,000.00 EUR
\n
Equity
\n
PowerCrop
\n
SpA (formerly
\n
PowerCrop Srl)
\n
100.00% 50.00%
\n
PowerCrop SpA
\n
(formerly PowerCrop
\n
Srl)
\n
Bologna IT 4,000,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Prairie Rose
\n
Transmission LLC
\n
Minneapolis US - USD
\n
Equity
\n
Prairie Rose Wind
\n
LLC
\n
100.00% 10.00%
\n
Prairie Rose Wind LLC Albany US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
Primavera Energia SA Niter\u00f3i BR 36,965,444.64 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Productive Solar
\n
Systems SLU
\n
Andorra ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Productora de Energ\u00edas
\n
SA
\n
Barcelona ES 60,101.22 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Productora El\u00e9ctrica
\n
Urgellenca SA
\n
L\u00e9rida ES 8,400,000.00 EUR
\n
- Endesa SA 8.43% 5.91%
\n
Progreso Solar 20
\n
MW SA
\n
Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Promociones
\n
Energ\u00e9ticas del Bierzo
\n
SLU
\n
Madrid ES 12,020.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Promotores Mud\u00e9jar
\n
400 kV SL
\n
Zaragoza ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
24.75%
\n
26.08%
\n
Renovables La
\n
Pedrera SLU
\n
6.75%
\n
Renovables
\n
Mediavilla SLU
\n
5.69%
\n
Proveedora de
\n
Electricidad de
\n
Occidente S de RL
\n
de Cv
\n
Mexico City MX 89,708,835.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
Prowind Windfarm
\n
Bogdanesti Srl
\n
Bucharest RO 118,460,800.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Prowind Windfarm
\n
Deleni Srl
\n
Bucharest RO 202,009,300.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Prowind Windfarm
\n
Ivesti Srl
\n
Bucharest RO 720,455,300.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Prowind Windfarm
\n
Viisoara Srl
\n
Bucharest RO 142,540,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Proyectos
\n
Universitarios de
\n
Energ\u00edas Renovables SL
\n
Alicante ES 27,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Proyectos y Soluciones
\n
Renovables SAC
\n
San Miguel PE 1,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
99.90%
\n
99.98%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.10%
\n
PSG Energy Private
\n
Limited
\n
Hyderabad IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
PT Enel Green Power
\n
Optima Way Ratai
\n
Jakarta ID 10,002,740.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
90.00% 90.00%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda I SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda II SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Pulida Energy (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
52.70% 52.70%
\n
Pumpkin Vine Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Quatiara Energia SA Niter\u00f3i BR 13,766,118.96 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Queens Energy
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Raleigh Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ranchland Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rattlesnake Creek
\n
Holdings LLC
\n
Delaware US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rausch Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
RC Wind Srl Milan IT 10,000.00 EUR
\n
-
\n
Enel Green Power
\n
Italia Srl
\n
0.50% 0.50%
\n
RE Arroyo LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Reaktortest SRO Trnava SK 66,389.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
49.00% 16.17%
\n
Rebuilding Agente
\n
Rehabilitador SL
\n
Madrid ES 250,000.00 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
50.00% 35.06%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Red Cardinal Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Centroamericana
\n
de Telecomunicaciones
\n
SA
\n
Panama City PA 2,700,000.00 USD
\n
- Enel SpA 11.11% 11.11%
\n
Red Dirt Wind Holdings
\n
I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Red Dirt Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Dirt Wind Project
\n
LLC
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Red Dirt Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Red Fox Wind Project
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Stag Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Redes y
\n
Telecomunicaciones S
\n
de RL de Cv
\n
San Pedro Sula HN 82,395,000.00 HNL
\n
- Livister Latam SLU 95.00% 18.53%
\n
Regal Rising Solar
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Ren Wave Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Renovables Andorra
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Brovales
\n
400 kV SL
\n
Seville ES 5,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 6.24%
\n
44.98%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
6.24%
\n
Emintegral Cycle
\n
SLU
\n
16.99%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
22.20%
\n
Furatena Solar 1
\n
SLU
\n
6.24%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
6.24%
\n
Renovables de
\n
Guatemala SA
\n
Guatemala City GT 1,924,465,600.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%
\n
Enel Guatemala SA 0.00%
\n
Renovables La Pedrera
\n
SLU
\n
Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables
\n
Manzanares 400 kV SL
\n
Madrid ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
27.86%
\n
30.84%
\n
Stonewood
\n
Desarrollos SLU
\n
16.12%
\n
Renovables Mediavilla
\n
SLU
\n
Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Teruel SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Ribina Renovables
\n
400 SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
39.24% 27.51%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Riverbend Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Riverview LP Alberta CA - CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
51.00%
\n
51.00%
\n
Enel Green Power
\n
Canada Inc.
\n
1.00%
\n
Riverview Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Solar
\n
Project LLC
\n
Andover US 100.00 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rochelle Solar LLC Coral Springs US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Project LLC
\n
Clayton US 1.00 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Prairie Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Ranchland
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rocky Caney Holdings
\n
LLC
\n
Oklahoma City US 1.00 USD
\n
Equity Enel Kansas LLC 10.00% 10.00%
\n
Rocky Caney Wind LLC Albany US - USD
\n
Equity
\n
Rocky Caney
\n
Holdings LLC
\n
100.00% 10.00%
\n
Rocky Ridge Wind
\n
Project LLC
\n
Oklahoma City US - USD
\n
Equity
\n
Rocky Caney Wind
\n
LLC
\n
100.00% 10.00%
\n
Rodnikovskaya WPS Moscow RU 6,010,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Roha Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Rolling Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Rosy Range Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rusenergosbyt LLC Moscow RU 18,000,000.00 RUB
\n
Equity Enel SpA 49.50% 49.50%
\n
Rusenergosbyt Siberia
\n
LLC
\n
Krasnoyarsk
\n
City
\n
RU 4,600,000.00 RUB
\n
Equity Rusenergosbyt LLC 50.00% 24.75%
\n
Ruthton Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,000.00 PLN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Saburoy SA Montevideo UY 100,000.00 UYU - IFX Networks LLC 100.00% 19.50%
\n
Sacme SA Buenos Aires AR 12,000.00 ARS
\n
Equity
\n
Empresa
\n
Distribuidora Sur
\n
SA - Edesur
\n
50.00% 29.66%
\n
Saddle House Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Salt Springs Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Salto de San Rafael SL Seville ES 462,185.98 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
San Francisco de
\n
Borja SA
\n
Zaragoza ES 60,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.75%
\n
San Juan Mesa Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
Sanosari Energy Private
\n
Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Santo Rostro
\n
Cogeneraci\u00f3n SA in
\n
liquidation
\n
Seville ES 207,340.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Sardhy Green
\n
Hydrogen Srl
\n
Sarroch IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Saugus River Energy
\n
Storage LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Savanna Power Solar
\n
10 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
12 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
13 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
4 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
5 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
6 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
9 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Se Slu\u017eby In\u017einierskych
\n
Stavieb SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 200,000.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Seccionadora
\n
Almod\u00f3var Renovables
\n
SL
\n
Malaga ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
37.50% 26.29%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
Madrid ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Servizio Elettrico
\n
Nazionale SpA
\n
Rome IT 10,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Set Carmona 400 kV
\n
Renovables SL
\n
Seville ES 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
16.00% 11.22%
\n
Setyl Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 27.50% 27.50%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Seven Cowboy PPA LLC Andover US 1.00 USD Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Seven Cowboy
\n
Wind Project
\n
Holdings LLC
\n
100.00% 100.00%
\n
Seven Cowboys Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shark Power REN 10
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 4
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 5
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 6
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 7
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 8
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 9
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power SLU Seville ES 143,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Shepherd Pass Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shiawassee Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shield Energy Storage
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Shikhar Surya (One)
\n
Private Limited
\n
Gurugram IN 340,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
SIET - Societ\u00e0
\n
Informazioni
\n
Esperienze
\n
Termoidrauliche SpA
\n
Piacenza IT 697,820.00 EUR
\n
Equity
\n
Enel Innovation
\n
Hubs Srl
\n
41.55% 41.55%
\n
Silt Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Silver Dollar Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Silverware Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sinergia GP6 Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Sinergia GP7 Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Sistema El\u00e9ctrico de
\n
Conexi\u00f3n Valcaire SL
\n
Madrid ES 175,200.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
28.13% 19.72%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Sistemas Energ\u00e9ticos
\n
Ma\u00f1\u00f3n Ortigueira SA
\n
A Coru\u00f1a ES 2,007,750.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
96.00% 67.31%
\n
Skyview Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Skyview Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
SL Energy SAC Lima PE 1,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
99.90%
\n
82.27%
\n
Enel Per\u00fa SAC 0.10%
\n
Sleep Hollow Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Slovak Power Holding
\n
BV
\n
Amsterdam NL 25,010,000.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
- Energetick\u00e9 Slu\u017eby
\n
SRO
\n
Bratislava SK 4,505,000.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
Bratislava SK 1,269,295,724.66 EUR
\n
Equity
\n
Slovak Power
\n
Holding BV
\n
66.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
\u010cesk\u00e1 Republika SRO
\n
Moravsk\u00e1
\n
Ostrava
\n
CZ 295,819.00 CZK
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Smoky Hill Holdings
\n
II LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Smoky Hills Wind Farm
\n
LLC
\n
Topeka US - USD
\n
Line-by-line
\n
EGPNA Project
\n
HoldCo 1 LLC
\n
100.00% 100.00%
\n
Smoky Hills Wind
\n
Project II LLC
\n
Lenexa US - USD
\n
Line-by-line
\n
EGPNA Project
\n
HoldCo 1 LLC
\n
100.00% 100.00%
\n
Snowy Knoll Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Snyder Wind Farm LLC Hermleigh US - USD
\n
Line-by-line Texkan Wind LLC 100.00% 100.00%
\n
Socibe Energia SA Niter\u00f3i BR 12,969,032.25 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Sociedad Agr\u00edcola de
\n
Cameros Ltda
\n
Santiago de
\n
Chile
\n
CL 5,738,046,495.00 CLP
\n
Line-by-line Enel Chile SA 57.50% 37.33%
\n
Sociedad E\u00f3lica de
\n
Andaluc\u00eda SA
\n
Seville ES 4,507,590.78 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
64.75% 45.40%
\n
Sociedad E\u00f3lica El
\n
Puntal SL
\n
Seville ES 1,643,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
Sociedad E\u00f3lica Los
\n
Lances SA
\n
Seville ES 2,404,048.42 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Sociedad para el
\n
Desarrollo de Sierra
\n
Morena Cordobesa SA
\n
Cordoba ES 86,063.20 EUR
\n
-
\n
Endesa Generaci\u00f3n
\n
SAU
\n
1.82% 1.27%
\n
Sociedad Portuaria
\n
Central Cartagena SA
\n
Bogot\u00e1 CO 89,714,600.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
94.94%
\n
47.17%
\n
Enel X Colombia
\n
SAS ESP
\n
5.05%
\n
Societ\u00e0 Elettrica Trigno
\n
Srl
\n
Trivento IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Soetwater Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Solana Renovables SL Madrid ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
49.84% 34.95%
\n
\n\n
\n\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Solas Electricity Srl Bucharest RO 17,740,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Soliloquoy Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Sona Enerj\u00ed \u00dcret\u00edm
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 50,000.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Sonak Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Sotavento Galicia SA
\n
Santiago de
\n
Compostela
\n
ES 601,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.00% 25.24%
\n
South Italy Green
\n
Hydrogen Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
South Rock Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
South Wind Energy Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Southwest
\n
Transmission LLC
\n
Cedar Bluff US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
100.00% 100.00%
\n
Southwestern Rays
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Spartan Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Spinazzola SPV Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Spring Wheat Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Square Dance Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sreeja Infrastructure
\n
Private Limited
\n
Hyderabad IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Stable Brook Storage
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Stampede Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Stampede Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Stampede Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Star Catcher Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Star Energy Single
\n
Member P.C.
\n
Maroussi GR 28,010.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Station Tales Solar
\n
Limited Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Sterling and Wilson
\n
Enel X e-Mobility
\n
Private Limited
\n
Mumbai IN 90,000,000.00 INR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Stillman Valley Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Stillwater Woods Hill
\n
Holdings LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stipa Naya\u00e1 SA de Cv Mexico City MX 1,811,016,348.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
55.21%
\n
95.37%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
40.16%
\n
Stockyard Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stonewood Desarrollos
\n
SLU
\n
Madrid ES 4,053,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Storey Plains Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stormy Hills Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Strinestown Solar I LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Suave Energ\u00eda S de RL
\n
de Cv
\n
Mexico City MX 1,000.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.10%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.90%
\n
Sublunary Trading (RF)
\n
(Pty) Ltd
\n
Bryanston ZA 13,750,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
57.00% 57.00%
\n
Sugar Pine Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Suggestion Power
\n
Unipessoal Ltda
\n
Pa\u00e7o de Arcos PT 50,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
100.00% 70.12%
\n
Suministradora
\n
El\u00e9ctrica de C\u00e1diz SA
\n
Cadiz ES 12,020,240.00 EUR
\n
Equity Endesa Red SAU 33.50% 23.49%
\n
Suministro de Luz y
\n
Fuerza SL
\n
Barcelona ES 2,800,000.00 EUR
\n
Line-by-line
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
60.00% 42.07%
\n
Summit Energy
\n
Storage Inc.
\n
Wilmington US 1,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
75.00% 75.00%
\n
Sun River LLC Bend US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Sun4 Koryta Sp\u00f3\u0142ka
\n
Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,750.00 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z
\n
Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
80.00% 80.00%
\n
Sun4 Torzym Sp\u00f3\u0142ka
\n
Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,750.00 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z
\n
Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
80.00% 80.00%
\n
Sundance Wind
\n
Project LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sunflower Prairie Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Swather Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sweet Apple Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
TAE Technologies Inc.
\n
Pauling US 53,207,936.00 USD
\n
-
\n
Enel Produzione
\n
SpA
\n
1.12%
\n
1.12%
\n
TAE Technologies
\n
Inc.
\n
0.00%
\n
Tasseling Jewel Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tauste Energ\u00eda
\n
Distribuida SL
\n
Zaragoza ES 60,508.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Tecnatom do Brasil
\n
Enghenaria e Servi\u00e7os
\n
Ltda
\n
Rio de Janeiro BR 1,600,000.00 BRL
\n
Equity Tecnatom SA 90.00% 28.40%
\n
Tecnatom France SAS
\n
Saint Loup de
\n
Varennes
\n
FR 1,888,870.38 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom M\u00e9xico SA
\n
de Cv
\n
Veracruz MX 6,000,000.00 MXN
\n
Equity
\n
Inspectores y
\n
Consultores Ibercal
\n
SLU
\n
0.17%
\n
31.56%
\n
Tecnatom SA 99.83%
\n
Tecnatom Servicios
\n
T\u00e9cnicos y Consultor\u00eda
\n
SLU
\n
Sebasti\u00e1n de
\n
los Reyes
\n
ES 3,000.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom UK Ltd London GB 1.00 GBP
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom USA
\n
Corporation
\n
Wilmington US 3,000.00 USD
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom SA Madrid ES 4,025,700.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
45.00% 31.56%
\n
Tecnoguat SA Guatemala City GT 30,948,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
75.00% 35.38%
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica SA
\n
Lisbon PT 5,025,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
43.75% 30.68%
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y Viento
\n
SAPI de Cv
\n
Mexico City MX 2,892,643,576.00 MXN
\n
Equity
\n
Enel Green Power
\n
SpA
\n
32.89% 32.90%
\n
Tera Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Termica Colleferro SpA Bologna IT 6,100,000.00 EUR
\n
Equity Cogenio Srl 60.00% 12.00%
\n
Termoel\u00e9ctrica Jos\u00e9 de
\n
San Mart\u00edn SA
\n
Buenos Aires AR 7,078,298.00 ARS
\n
-
\n
Central Dock Sud
\n
SA
\n
0.42%
\n
4.22%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.68%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
5.60%
\n
Termoel\u00e9ctrica Manuel
\n
Belgrano SA
\n
Buenos Aires AR 7,078,307.00 ARS
\n
-
\n
Central Dock Sud
\n
SA
\n
0.47%
\n
4.71%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.89%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
6.23%
\n
Termotec Energ\u00eda AIE
\n
in liquidation
\n
La Pobla de
\n
Vallbona
\n
ES 481,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Terrer Renovables SL Madrid ES 5,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 11.66%
\n
20.73%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
8.83%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
9.08%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Texas Sage Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Texkan Wind LLC Andover US - USD
\n
Line-by-line Enel Texkan Inc. 100.00% 100.00%
\n
Thar Surya 1 Private
\n
Limited
\n
Gurgaon IN 200,000.00 INR
\n
Equity
\n
Avikiran Surya India
\n
Private Limited
\n
100.00% 51.00%
\n
Thunder Ranch Wind
\n
Holdings I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Thunder Ranch Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Thunder Ranch Wind
\n
Project LLC
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Thunder Ranch
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Thunderegg Storage
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Thunderegg Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tico Solar 1 SLU Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tico Solar 2 SLU Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tieton Storage Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tobivox (RF) (Pty) Ltd Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Toledo PV AIE Madrid ES 26,887.96 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Toplet Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Topwind Energy Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Toro Renovables 400
\n
kV SL
\n
Madrid ES 3,000.00 EUR
\n
Equity
\n
FRV Zamora Solar
\n
1 SLU
\n
8.28% 5.81%
\n
Torrepalma Energy
\n
1 SLU
\n
Madrid ES 3,100.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tradewind Energy Inc. Wilmington US 1,000.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trading Post Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trail Ride Canyon Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Transformadora
\n
Almod\u00f3var Renovables
\n
SL
\n
Seville ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.53% 42.44%
\n
Transmisora de Energ\u00eda
\n
Renovable SA
\n
Guatemala City GT 233,561,800.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%Enel Guatemala SA 0.00%
\n
Generadora
\n
Montecristo SA
\n
0.00%
\n
Transportadora de
\n
Energ\u00eda SA - TESA
\n
Buenos Aires AR 2,584,473,416.00 ARS
\n
Line-by-line
\n
Enel Argentina SA 0.00%
\n
82.27%Enel Brasil SA 60.15%
\n
Enel CIEN SA 39.85%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Transportes y
\n
Distribuciones
\n
El\u00e9ctricas SA in
\n
liquidation
\n
Girona ES 72,121.45 EUR
\n
Line-by-line
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
73.33% 51.42%
\n
Tr\u00e9vago Renovables SL Madrid ES 3,000.00 EUR
\n
Equity
\n
Furatena Solar 1
\n
SLU
\n
17.73%
\n
24.89%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
17.77%
\n
Tsar Nicholas LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Tula WPS LLC Tula RU - RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Tulip Grove Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tumbleweed Flat Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tunga Renewable
\n
Energy Private Limited
\n
Gurugram IN 96,300,000.00 INR
\n
Line-by-line
\n
Avikiran Energy
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
TWE Franklin Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
TWE ROT DA LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Twin Lake Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Twin Saranac Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Tyme Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
Ufinet Argentina SA Buenos Aires AR 9,745,583.00 ARS
\n
-
\n
Ufinet Latam SLU 99.95%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.05%
\n
Ufinet Brasil
\n
Participa\u00e7\u00f5es Ltda
\n
Santo Andr\u00e9 BR 120,784,639.00 BRL
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
19.50%
\n
Ufinet Latam SLU 100.00%
\n
Ufinet Brasil SA Barueri BR 51,766,147.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
80.00% 15.60%
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o Ltda
\n
Santo Andr\u00e9 BR 120,784,638.00 BRL
\n
-
\n
Ufinet Brasil
\n
Participa\u00e7\u00f5es Ltda
\n
100.00% 19.50%
\n
Ufinet Chile SpA
\n
Santiago de
\n
Chile
\n
CL 233,750,000.00 CLP
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Colombia
\n
Participaciones SAS
\n
Bogot\u00e1 CO 10,001,001,000.00 COP
\n
- Ufinet Colombia SA 100.00% 17.55%
\n
Ufinet Colombia SA Bogot\u00e1 CO 1,180,000,000.00 COP
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
17.55%
\n
Ufinet Honduras SA 0.00%
\n
Ufinet Latam SLU 90.00%
\n
Ufinet Panam\u00e1 SA 0.00%
\n
Ufinet Costa Rica SA San Jos\u00e9 CR 25,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Ecuador Ufiec
\n
SA
\n
Quito EC 9,865,110.00 USD
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
14.04%
\n
Ufinet Latam SLU 71.97%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ufinet El Salvador SA
\n
de Cv
\n
San Salvador SV 10,000.00 USD
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.01%
\n
19.50%
\n
Ufinet Latam SLU 99.99%
\n
Ufinet FTTH Guatemala
\n
Ltda
\n
Guatemala City GT 7,007,000.00 GTQ
\n
- Ufinet Latam SLU 51.00% 9.94%
\n
Ufinet Guatemala SA Guatemala City GT 3,000,000.00 GTQ
\n
-
\n
Ufinet Latam SLU 99.99%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.01%
\n
Ufinet Honduras SA Tegucigalpa HN 194,520.00 HNL
\n
-
\n
Ufinet Latam SLU 99.99%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.01%
\n
Ufinet Latam SLU Madrid ES 15,906,312.00 EUR
\n
- Zacapa S\u00e0rl 100.00% 19.50%
\n
Ufinet M\u00e9xico S de RL
\n
de Cv
\n
Mexico City MX 7,635,430.00 MXN
\n
-
\n
Ufinet Guatemala
\n
SA
\n
1.31%
\n
19.50%
\n
Ufinet Latam SLU 98.69%
\n
Ufinet Nicaragua SA Managua NI 2,800,000.00 NIO
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.50%
\n
19.50%
\n
Ufinet Latam SLU 99.00%
\n
Ufinet Panam\u00e1 SA 0.50%
\n
Ufinet Panam\u00e1 SA Panama City PA 1,275,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Paraguay SA Asunci\u00f3n PY 79,488,240,000.00 PYG
\n
- Ufinet Latam SLU 75.00% 14.63%
\n
Ufinet Per\u00fa SAC Lima PE 2,836,474.00 PEN
\n
-
\n
Ufinet Latam SLU 100.00%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.00%
\n
Ufinet US LLC Wilmington US 1,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Uni\u00f3n El\u00e9ctrica de
\n
Canarias Generaci\u00f3n
\n
SAU
\n
Las Palmas de
\n
Gran Canaria
\n
ES 190,171,520.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Upington Solar (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Usina E\u00f3lica Pedra
\n
Pintada A Ltda
\n
Rio de Janeiro BR 653,327.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada B Ltda
\n
Rio de Janeiro BR 748,697.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada C Ltda
\n
Rio de Janeiro BR 805,024.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada D Ltda
\n
Rio de Janeiro BR 653,327.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 11 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 12 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 13 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 14 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 15 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 16 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Usina Fotovoltaica
\n
Arinos E 17 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 21 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 22 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 23 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 24 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
USME ZE SAS Bogot\u00e1 CO 104,872,000.00 COP
\n
AFS Bogot\u00e1 ZE SAS 100.00% 47.18%
\n
Ustav Jadern\u00e9ho
\n
V\u00fdzkumu Rez AS
\n
\u0158e\u017e CZ 524,139,000.00 CZK
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
27.77% 9.17%
\n
Vayu (Project 1) Private
\n
Limited
\n
Gurugram IN 30,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Vekt\u00f6r Enerj\u00ed \u00dcret\u00edm
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 3,500,000.00 TRY
\n
AFS Enel SpA 100.00% 100.00%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 7,315,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santa
\n
Esperan\u00e7a Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 4,727,414.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santo
\n
Orestes Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 1,754,031.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o Cirilo
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,572,010.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o M\u00e1rio
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,492,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o Roque
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 10,188,722.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Vientos del Altiplano
\n
SA de Cv
\n
Mexico City MX 1,455,854,094.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Villanueva Solar SA
\n
de Cv
\n
Mexico City MX 205,316,027.15 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Viruleiros SL
\n
Santiago de
\n
Compostela
\n
ES 160,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
67.00% 46.98%
\n
Viva Labs AS Oslo NO 1,047,249.00 NOK
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Walking Horse Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wapella Bluffs Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Waseca Solar LLC Waseca US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Waypost Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Weber Energy Storage
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Wespire Inc. Boston US 1,625,000.00 USD
\n
-
\n
Enel X North
\n
America Inc.
\n
11.21% 11.21%
\n
West Faribault Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
West Waconia Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Western New York
\n
Wind Corporation
\n
Albany US 300.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Wharton-El Campo
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
White Cloud Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
White Cloud Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
White Cloud Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
White Peaks Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitetail Trails Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Whitney Hill Wind
\n
Power Holdings LLC
\n
Andover US 99.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitney Hill Wind
\n
Power LLC
\n
Andover US - USD
\n
Line-by-line
\n
Whitney Hill Wind
\n
Power Holdings
\n
LLC
\n
100.00% 100.00%
\n
Whittle\u2019s Ferry Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wild Ox Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wild Run LP Alberta CA 10.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Wildcat Flats Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Wilderness Range
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildflower Flats Battery
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildflower Flats Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wind Belt Transco LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Wind Energy Green
\n
Park Srl
\n
Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Wind Parks Anatolis -
\n
Prinias Single Member
\n
SA
\n
Maroussi GR 15,803,388.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n

\n\n

\n\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Wind Parks Katharas
\n
Single Member SA
\n
Maroussi GR 19,932,048.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Kerasias
\n
Single Member SA
\n
Maroussi GR 26,107,790.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Milias
\n
Single Member SA
\n
Maroussi GR 19,909,374.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Mitikas
\n
Single Member SA
\n
Maroussi GR 22,268,039.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Platanos
\n
Single Member SA
\n
Maroussi GR 13,342,867.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Spilias
\n
Single Member SA
\n
Maroussi GR 28,267,490.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Windbreaker Storage
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Winter\u2019s Spawn LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
WKN Basilicata
\n
Development PE1 Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Woods Hill Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Stillwater Woods
\n
Hill Holdings LLC
\n
100.00% 100.00%
\n
Xaloc Solar SLU Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
X-bus Italia Srl Milan IT 15,000.00 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Yacylec SA Buenos Aires AR 20,000,000.00 ARS
\n
Equity Enel Am\u00e9ricas SA 33.33% 27.42%
\n
Yedesa Cogeneraci\u00f3n
\n
SA in liquidation
\n
Almer\u00eda ES 234,394.72 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
Yellow Rose Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Yorktown Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Zacapa HoldCo S\u00e0rl Luxembourg LU 76,180,812.49 EUR
\n
- Zacapa Topco S\u00e0rl 100.00% 19.50%
\n
Zacapa LLC Wilmington US 100.00 USD
\n
- Zacapa S\u00e0rl 100.00% 19.50%
\n
Zacapa S\u00e0rl Luxembourg LU 82,866,475.04 USD
\n
- Zacapa HoldCo S\u00e0rl 100.00% 19.50%
\n
Zacapa Topco S\u00e0rl Luxembourg LU 29,970,000.00 EUR
\n
-
\n
Enel X International
\n
Srl
\n
19.50% 19.50%
\n
Zephir 3 Constanta Srl Bucharest RO 1,031,260.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Zoo Solar Project LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNotesAndOtherExplanatoryInformationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag21": { "value": "\n

\n\n

\n

\n

\n

\n
1. Form and content of the consolidated financial statements
\n
Enel SpA has its registered office in Viale Regina Margherita
\n
137, Rome, Italy, and since 1999 has been listed on the Milan
\n
stock exchange.
\n
There were no changes in the company name in 2022.
\n\n
Enel is an energy multinational and is one of the world\u2019s
\n
leading integrated operators in the electricity and gas in-
\n
dustries, with a special focus on Europe and Latin America.
\n

\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 comprise the financial state-
\n
ments of Enel SpA, its subsidiaries and Group holdings in
\n
associates and joint ventures, as well as the Group\u2019s share of
\n
the assets, liabilities, costs and revenue of joint operations
\n
(\u201cthe Group\u201d).
\n
A list of the subsidiaries, associates, joint operations and
\n
joint ventures included in the consolidation scope is at-
\n
tached.
\n\n
These consolidated financial statements were approved
\n
and authorized for publication by the Board of Directors on
\n
March 16, 2023.
\n

\n\n
These consolidated financial statements have been audited
\n
by KPMG SpA.
\n
Basis of presentation
\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 have been prepared in accor-
\n
dance with international accounting standards (Internation-
\n
al Accounting Standards - IAS and International Financial
\n
Reporting Standards - IFRS) issued by the International Ac-
\n
counting Standards Board (IASB), the interpretations of the
\n
IFRS Interpretations Committee (IFRSIC) and the Standing
\n
Interpretations Committee (SIC), recognized in the Europe-
\n
an Union pursuant to Regulation (EC) no. 1606/2002 and in
\n

\n\n
effect as of the close of the year. All of these standards and
\n
interpretations are hereinafter referred to as the \u201cIFRS-EU\u201d.
\n
The consolidated financial statements have also been pre-
\n
pared in conformity with measures issued in implementa-
\n
tion of Article 9, paragraph 3, of Legislative Decree 38 of
\n
February 28, 2005.
\n
The consolidated financial statements consist of the con-
\n
solidated income statement, the statement of consolidated
\n
comprehensive income, the statement of consolidated fi-
\n
nancial position, the statement of changes in consolidated
\n
equity and the consolidated statement of cash flows and
\n
the related notes.
\n
The assets and liabilities recognized in the statement of
\n
financial position are classified on a \u201ccurrent/non-current
\n
basis\u201d, with separate reporting of assets held for sale and
\n
liabilities included in disposal groups held for sale. Current
\n
assets, which include cash and cash equivalents, are assets
\n
that are intended to be realized, sold or consumed during
\n
the normal operating cycle of the Group; current liabilities
\n
are liabilities that are expected to be settled during the nor-
\n
mal operating cycle of the Group.
\n
The income statement classifies costs on the basis of their
\n
nature, with separate reporting of profit/(loss) from continu-
\n
ing operations and profit/(loss) from discontinued opera-
\n
tions attributable to owners of the Parent and to non-con-
\n
trolling interests.
\n\n
The consolidated cash flow statement is prepared using the
\n
indirect method, with separate reporting of any cash flows
\n
by operating, investing and financing activities associated
\n
with discontinued operations.
\n
Note that the items reported in the cash flow statement also
\n
include any impacts deriving from companies classified as
\n
discontinued operations. In particular, although the Group
\n
does not diverge from the provisions of IAS 7 in the classi-
\n
fication of items:
\n
\u2022 cash flows from operating activities report cash flows
\n
from core operations, interest on loans granted and ob-
\n
tained and dividends received from associates or joint
\n
ventures;
\n
\u2022 investing activities comprise investments in property, plant
\n
and equipment and intangible assets and disposals of such
\n
assets and contract assets related to service concession
\n
arrangements. They include, also, the effects of business
\n
combinations in which the Group acquires or loses control
\n
of companies, as well as other minor investments;
\n
\u2022 cash flows from financing activities include cash flows
\n
generated by liability management transactions and leas-
\n
es, dividends and interim dividends paid to owners of
\n

\n\n

\n\n

\n\n

\n\n

\n\n
the Parent and non-controlling interests and the effects
\n
of transactions in non-controlling interests that do not
\n
change the status of control of the companies involved;
\n
\u2022 a separate item is used to report the impact of exchange
\n
rates on cash and cash equivalents and their impact on
\n
profit or loss is eliminated in full in order to neutralize the
\n
effect on cash flows from operating activities.
\n
For more information on cash flows as reported in the
\n
statement of cash flows, please see the note 46 \u201cCash
\n
flows\u201d.
\n

\n\n
The consolidated financial statements have been prepared
\n
on a going concern basis using the cost method, with the
\n
exception of items measured at fair value in accordance
\n
with IFRS, as explained in the measurement bases applied
\n
to each individual item, and of non-current assets and
\n
disposal groups classified as held for sale, which are mea-
\n
sured at the lower of their carrying amount and fair value
\n
less costs to sell.
\n
The consolidated financial statements are presented in
\n
euro, the functional currency of the Parent Enel SpA. All
\n
figures are shown in millions of euro unless stated other-
\n
wise.
\n
The consolidated income statement, the statement of fi-
\n
nancial position and the consolidated statement of cash
\n
flows report transactions with related parties, the defini-
\n
tion of which is given in note 2.2 \u201cSignificant accounting
\n
policies\u201d.
\n
The consolidated financial statements provide compara-
\n
tive information in respect of the previous year.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag19": { "value": "\n

\n

\n

\n

\n
1. Form and content of the consolidated financial statements
\n
Enel SpA has its registered office in Viale Regina Margherita
\n
137, Rome, Italy, and since 1999 has been listed on the Milan
\n
stock exchange.
\n
There were no changes in the company name in 2022.
\n\n
Enel is an energy multinational and is one of the world\u2019s
\n
leading integrated operators in the electricity and gas in-
\n
dustries, with a special focus on Europe and Latin America.
\n

\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 comprise the financial state-
\n
ments of Enel SpA, its subsidiaries and Group holdings in
\n
associates and joint ventures, as well as the Group\u2019s share of
\n
the assets, liabilities, costs and revenue of joint operations
\n
(\u201cthe Group\u201d).
\n
A list of the subsidiaries, associates, joint operations and
\n
joint ventures included in the consolidation scope is at-
\n
tached.
\n\n
These consolidated financial statements were approved
\n
and authorized for publication by the Board of Directors on
\n
March 16, 2023.
\n

\n\n
These consolidated financial statements have been audited
\n
by KPMG SpA.
\n
Basis of presentation
\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 have been prepared in accor-
\n
dance with international accounting standards (Internation-
\n
al Accounting Standards - IAS and International Financial
\n
Reporting Standards - IFRS) issued by the International Ac-
\n
counting Standards Board (IASB), the interpretations of the
\n
IFRS Interpretations Committee (IFRSIC) and the Standing
\n
Interpretations Committee (SIC), recognized in the Europe-
\n
an Union pursuant to Regulation (EC) no. 1606/2002 and in
\n

\n\n
effect as of the close of the year. All of these standards and
\n
interpretations are hereinafter referred to as the \u201cIFRS-EU\u201d.
\n
The consolidated financial statements have also been pre-
\n
pared in conformity with measures issued in implementa-
\n
tion of Article 9, paragraph 3, of Legislative Decree 38 of
\n
February 28, 2005.
\n
The consolidated financial statements consist of the con-
\n
solidated income statement, the statement of consolidated
\n
comprehensive income, the statement of consolidated fi-
\n
nancial position, the statement of changes in consolidated
\n
equity and the consolidated statement of cash flows and
\n
the related notes.
\n
The assets and liabilities recognized in the statement of
\n
financial position are classified on a \u201ccurrent/non-current
\n
basis\u201d, with separate reporting of assets held for sale and
\n
liabilities included in disposal groups held for sale. Current
\n
assets, which include cash and cash equivalents, are assets
\n
that are intended to be realized, sold or consumed during
\n
the normal operating cycle of the Group; current liabilities
\n
are liabilities that are expected to be settled during the nor-
\n
mal operating cycle of the Group.
\n
The income statement classifies costs on the basis of their
\n
nature, with separate reporting of profit/(loss) from continu-
\n
ing operations and profit/(loss) from discontinued opera-
\n
tions attributable to owners of the Parent and to non-con-
\n
trolling interests.
\n\n
The consolidated cash flow statement is prepared using the
\n
indirect method, with separate reporting of any cash flows
\n
by operating, investing and financing activities associated
\n
with discontinued operations.
\n
Note that the items reported in the cash flow statement also
\n
include any impacts deriving from companies classified as
\n
discontinued operations. In particular, although the Group
\n
does not diverge from the provisions of IAS 7 in the classi-
\n
fication of items:
\n
\u2022 cash flows from operating activities report cash flows
\n
from core operations, interest on loans granted and ob-
\n
tained and dividends received from associates or joint
\n
ventures;
\n
\u2022 investing activities comprise investments in property, plant
\n
and equipment and intangible assets and disposals of such
\n
assets and contract assets related to service concession
\n
arrangements. They include, also, the effects of business
\n
combinations in which the Group acquires or loses control
\n
of companies, as well as other minor investments;
\n
\u2022 cash flows from financing activities include cash flows
\n
generated by liability management transactions and leas-
\n
es, dividends and interim dividends paid to owners of
\n

\n\n

\n\n

\n\n
the Parent and non-controlling interests and the effects
\n
of transactions in non-controlling interests that do not
\n
change the status of control of the companies involved;
\n
\u2022 a separate item is used to report the impact of exchange
\n
rates on cash and cash equivalents and their impact on
\n
profit or loss is eliminated in full in order to neutralize the
\n
effect on cash flows from operating activities.
\n
For more information on cash flows as reported in the
\n
statement of cash flows, please see the note 46 \u201cCash
\n
flows\u201d.
\n

\n\n
The consolidated financial statements have been prepared
\n
on a going concern basis using the cost method, with the
\n
exception of items measured at fair value in accordance
\n
with IFRS, as explained in the measurement bases applied
\n
to each individual item, and of non-current assets and
\n
disposal groups classified as held for sale, which are mea-
\n
sured at the lower of their carrying amount and fair value
\n
less costs to sell.
\n
The consolidated financial statements are presented in
\n
euro, the functional currency of the Parent Enel SpA. All
\n
figures are shown in millions of euro unless stated other-
\n
wise.
\n
The consolidated income statement, the statement of fi-
\n
nancial position and the consolidated statement of cash
\n
flows report transactions with related parties, the defini-
\n
tion of which is given in note 2.2 \u201cSignificant accounting
\n
policies\u201d.
\n
The consolidated financial statements provide compara-
\n
tive information in respect of the previous year.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag6": { "value": "Enel SpA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag18": { "value": "137in Viale Regina Margherita", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag8": { "value": "Rome", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag17": { "value": "Italy", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag13": { "value": "There were no changes in the company name in 2022.", "dimensions": { "concept": "ifrs-full:ExplanationOfChangeInNameOfReportingEntityOrOtherMeansOfIdentificationFromEndOfPrecedingReportingPeriod", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag7": { "value": "\n
Enel is an energy multinational and is one of the world\u2019s
\n
leading integrated operators in the electricity and gas in-
\n
dustries, with a special focus on Europe and Latin America.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag20": { "value": "Europe and Latin America", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag10": { "value": "Enel", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag15": { "value": "SpA", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag23": { "value": "\n
These consolidated financial statements were approved
\n
and authorized for publication by the Board of Directors on
\n
March 16, 2023.
\n

\n\n
Declaration of the Chief Executive Officer and the officer in charge of
\n
financial reporting of the Enel Group at December 31, 2022, pursuant
\n
to the provisions of Article 154-bis, paragraph 5, of Legislative Decree
\n
58 of February 24, 1998 and Article 81-ter of CONSOB Regulation no.
\n
11971 of May 14, 1999
\n
1. The undersigned Francesco Starace and Alberto De
\n
Paoli, in their respective capacities as Chief Executive
\n
Officer and officer in charge of financial reporting of
\n
Enel SpA, hereby certify, taking account of the provi-
\n
sions of Article 154-bis, paragraphs 3 and 4, of Legisla-
\n
tive Decree 58 of February 24, 1998:
\n
a. the appropriateness with respect to the characteris-
\n
tics of the Enel Group and
\n
b. the effective adoption of
\n
the administrative and accounting procedures for the
\n
preparation of the consolidated financial statements of
\n
the Enel Group in the period between January 1, 2022
\n
and December 31, 2022.
\n
2. In this regard, we report that:
\n
a. the appropriateness of the administrative and ac-
\n
counting procedures used in the preparation of the
\n
consolidated financial statements of the Enel Group
\n
has been verified in an assessment of the internal
\n
control system for financial reporting. The assess-
\n
ment was carried out on the basis of the guidelines
\n
set out in the \u201cInternal Controls - Integrated Frame-
\n
work\u201d issued by the Committee of Sponsoring Or-
\n
ganizations of the Treadway Commission (COSO);
\n
b. the assessment of the internal control system for fi-
\n
nancial reporting did not identify any material issues.
\n
3. In addition, we certify that the consolidated financial
\n
statements of the Enel Group at December 31, 2022:
\n
a. have been prepared in compliance with the Inter-
\n
national Financial Reporting Standards endorsed by
\n
the European Union pursuant to Regulation (EC) no.
\n
1606/2002 of the European Parliament and of the
\n
Council of July 19, 2002;
\n
b. correspond to the information in the books and oth-
\n
er accounting records;
\n
c. provide a true and fair representation of the financial
\n
position, financial performance and cash flows of the
\n
issuer and the companies included in the consolida-
\n
tion scope.
\n
4. Finally, we certify that the Report on Operations, ac-
\n
companied by the consolidated financial statements of
\n
the Enel Group at December 31, 2022, contains a relia-
\n
ble analysis of operations and performance, as well as
\n
the situation of the issuer and the companies included
\n
in the consolidation scope, together with a description
\n
of the main risks and uncertainties to which they are ex-
\n
posed.
\n
Rome, March 16, 2023
\n
Francesco Starace
\n
Chief Executive Officer
\n
of Enel SpA
\n
Alberto De Paoli
\n
Officer in charge of financial reporting
\n
of Enel SpA
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag14": { "value": "\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2022 have been prepared in accor-
\n
dance with international accounting standards (Internation-
\n
al Accounting Standards - IAS and International Financial
\n
Reporting Standards - IFRS) issued by the International Ac-
\n
counting Standards Board (IASB), the interpretations of the
\n
IFRS Interpretations Committee (IFRSIC) and the Standing
\n
Interpretations Committee (SIC), recognized in the Europe-
\n
an Union pursuant to Regulation (EC) no. 1606/2002 and in
\n

\neffect as of the close of the year.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag22": { "value": "\n
The consolidated cash flow statement is prepared using the
\n
indirect method, with separate reporting of any cash flows
\n
by operating, investing and financing activities associated
\n
with discontinued operations.
\n
Note that the items reported in the cash flow statement also
\n
include any impacts deriving from companies classified as
\n
discontinued operations. In particular, although the Group
\n
does not diverge from the provisions of IAS 7 in the classi-
\n
fication of items:
\n
\u2022 cash flows from operating activities report cash flows
\n
from core operations, interest on loans granted and ob-
\n
tained and dividends received from associates or joint
\n
ventures;
\n
\u2022 investing activities comprise investments in property, plant
\n
and equipment and intangible assets and disposals of such
\n
assets and contract assets related to service concession
\n
arrangements. They include, also, the effects of business
\n
combinations in which the Group acquires or loses control
\n
of companies, as well as other minor investments;
\n
\u2022 cash flows from financing activities include cash flows
\n
generated by liability management transactions and leas-
\n
es, dividends and interim dividends paid to owners of
\n

\n\n
the Parent and non-controlling interests and the effects
\n
of transactions in non-controlling interests that do not
\n
change the status of control of the companies involved;
\n
\u2022 a separate item is used to report the impact of exchange
\n
rates on cash and cash equivalents and their impact on
\n
profit or loss is eliminated in full in order to neutralize the
\n
effect on cash flows from operating activities.
\n
For more information on cash flows as reported in the
\n
statement of cash flows, please see the note 46 \u201cCash
\n
flows\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCashFlowsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag12": { "value": "The consolidated financial statements have been preparedon a going concern basis", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag5": { "value": "Enel SpA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag9": { "value": "\n
2.1 Use of estimates and management
\n
judgment
\n
Preparing the consolidated financial statements under IF-
\n
RS-EU requires management to take decisions and make
\n
estimates and assumptions that may impact the carrying
\n
amount of revenue, costs, assets and liabilities and the
\n
related disclosures concerning the items involved as well
\n
as contingent assets and liabilities at the reporting date.
\n
The estimates and management\u2019s judgments are based
\n
on previous experience and other factors considered rea-
\n
sonable in the circumstances. They are formulated when
\n
the carrying amount of assets and liabilities is not easily
\n
determined from other sources. The actual results may
\n
therefore differ from these estimates. The estimates and
\n
assumptions are periodically revised and the effects of any
\n
changes are reflected through profit or loss if they only in-
\n
volve that period. If the revision involves both the current
\n
and future periods, the change is recognized in the period
\n
in which the revision is made and in the related future pe-
\n
riods.
\n
In order to enhance understanding of the consolidated
\n
financial statements, the following sections examine the
\n
main items affected by the use of estimates and the cases
\n
that reflect management judgments to a significant de-
\n
gree, underscoring the main assumptions used by man-
\n
agement in measuring these items in compliance with the
\n
IFRS-EU. The critical element of such valuations is the use
\n
of assumptions and professional judgments concerning
\n
issues that are by their very nature uncertain.
\n
Changes in the conditions underlying the assumptions
\n
and judgments could have a substantial impact on future
\n
results.
\n
The information included in the consolidated financial
\n
statements is selected on the basis of a materiality analysis
\n
carried out in accordance with the requirements of Prac-
\n
tice Statement 2 \u201cMaking Materiality Judgments\u201d, issued by
\n
the International Accounting Standards Board (IASB).
\n
With regard to the effects of climate change issues, the
\n
Group believes that climate change represents an implic-
\n
it element in the application of the methodologies and
\n
models used to perform estimates in the valuation and/or
\n
measurement of certain accounting items. Furthermore,
\n
the Group has also taken account of the impact of climate
\n
change in the significant judgments made by manage-
\n
ment. In this regard, the main items included in the consol-
\n
idated financial statements at December 31, 2022 affected
\n
by management\u2019s use of estimates and judgments refer
\n
to the impairment of non-financial assets and obligations
\n
connected with the energy transition, including those for
\n
decommissioning and site restoration of certain genera-
\n
tion plants. For further details on these items, see note 19
\n
\u201cProperty, plant and equipment\u201d, note 24 \u201cGoodwill\u201d, and
\n
note 40 \u201cProvisions for risks and charges\u201d.
\n
Use of estimates
\n
Revenue from contracts with customers
\n
Revenue from supply of electricity and gas to end users is
\n
recognized at the time the electricity or gas is delivered and
\n
includes, in addition to amounts invoiced on the basis of pe-
\n
riodic (and pertaining to the year) meter readings or on the
\n
volumes notified by distributors and transporters, an esti-
\n
mate of the electricity and gas delivered during the period
\n
but not yet invoiced that is equal to the difference between
\n
the amount of electricity and gas delivered to the distribu-
\n
tion network and that invoiced in the period, taking account
\n
of any network losses. Revenue between the date of the last
\n
meter reading and the year-end is based on estimates of
\n

\n\n
the daily consumption of individual customers, primarily de-
\n
termined on their historical information, adjusted to reflect
\n
the climate factors or other matters that may affect the es-
\n
timated consumption.
\n
For more details on such revenue, see note 11.a \u201cRevenue
\n
from sales and services\u201d.
\n
Impairment of non-financial assets
\n
When the carrying amount of property, plant and equip-
\n
ment, investment property, intangible assets, right-of-use
\n
assets, goodwill and investments in associates/joint ven-
\n
tures exceeds its recoverable amount, which is the higher
\n
of the fair value less costs to sell and the value in use, the
\n
assets are impaired.
\n
Such impairments are carried out in accordance with the
\n
provisions of IAS 36, as described in greater detail in note
\n
24 \u201cGoodwill\u201d.
\n
In order to determine the recoverable amount, the Group
\n
generally adopts the value in use criterion. Value in use is
\n
based on the estimated future cash flows generated by
\n
the asset, discounted to their present value using a pre-tax
\n
discount rate that reflects the current market assessment
\n
of the time value of money and of the specific risks of the
\n
asset.
\n
Future cash flows used to determine value in use are based
\n
on the most recent Business Plan, approved by the man-
\n
agement, containing forecasts for volumes, revenue, oper-
\n
ating costs and investments. These projections cover the
\n
next three years. For subsequent years, account is taken of:
\n
\u2022 assumptions concerning the long-term evolution of
\n
the main variables considered in the calculation of cash
\n
flows, as well as the average residual useful life of the
\n
assets or the duration of the concessions, based on the
\n
specific characteristics of the businesses;
\n
\u2022 a long-term growth rate equal to the long-term growth
\n
of electricity demand and/or inflation (depending on the
\n
country and business) that does not in any case exceed
\n
the average long-term growth rate of the market in-
\n
volved.
\n
The recoverable amount is sensitive to the estimates and
\n
assumptions used in the calculation of cash flows and the
\n
discount rates applied. Nevertheless, possible changes in
\n
the underlying assumptions on which the calculation of
\n
such amounts is based could generate different recover-
\n
able amounts. The analysis of each group of non-financial
\n
assets is unique and requires management to use esti-
\n
mates and assumptions considered prudent and reason-
\n
able in the specific circumstances.
\n
In line with its business model and in the context of the
\n
acceleration of the decarbonization of the generation mix
\n
and driving the energy transition process, the Group has
\n
also carefully assessed whether climate change issues
\n
have affected the reasonable and supportable assump-
\n
tion used to estimated expected cash flows. In this regard,
\n
where necessary, the Group has also taken account of the
\n
long-term impact of climate change, in particular by con-
\n
sidering in the estimation of the terminal value a long-term
\n
growth rate in line with the change in electricity demand
\n
determined using energy models for each country.
\n
Information on the main assumptions used to estimate
\n
the recoverable amount of assets with reference to the
\n
impacts relating to climate change, as well as information
\n
on changes in these assumptions, is provided in note 24
\n
\u201cGoodwill\u201d.
\n
Expected credit losses on financial assets
\n
At the end of each reporting period, the Group recognizes
\n
a loss allowance for expected credit losses on trade re-
\n
ceivables and other financial assets measured at amortized
\n
cost, debt instruments measured at fair value through oth-
\n
er comprehensive income, contract assets and all other
\n
assets in scope.
\n
Loss allowances for financial assets are based on assump-
\n
tions about risk of default and on the measurement of ex-
\n
pected credit losses. Management uses judgment in mak-
\n
ing these assumptions and selecting the inputs for the
\n
impairment calculation, based on the Group\u2019s past experi-
\n
ence, current market conditions as well as forward-looking
\n
estimates at the end of each reporting period.
\n
The expected credit loss (i.e., ECL) \u2013 determined consid-
\n
ering probability of default (PD), loss given default (LGD),
\n
and exposure at default (EAD) \u2013 is the difference between
\n
all contractual cash flows that are due in accordance with
\n
the contract and all cash flows that are expected to be re-
\n
ceived (including all shortfalls) discounted at the original
\n
effective interest rate (EIR).
\n
In particular, for trade receivables, contract assets and
\n
lease receivables, including those with a significant fi-
\n
nancial component, the Group applies the simplified ap-
\n
proach, determining expected credit losses over a period
\n
corresponding to the entire life of the asset, generally
\n
equal to 12 months.
\n
Based on the specific reference market and the regulatory
\n
context of the sector, as well as expectations of recovery
\n
after 90 days, for such assets, the Group mainly applies a
\n
default definition of 180 days past due to determine ex-
\n
pected credit losses, as this is considered an effective in-
\n
dication of a significant increase in credit risk. Accordingly,
\n
financial assets that are more than 90 days past due are
\n
generally not considered to be in default, except for some
\n
specific regulated markets.
\n
For trade receivables and contract assets the Group mainly
\n
applies a collective approach based on grouping trade re-
\n
ceivables and contract assets into specific clusters, taking
\n
into account the specific regulatory and business context.
\n
Only if the trade receivables are deemed to be individually
\n
significant by management and there is specific informa-
\n
tion about any significant increase in credit risk, does the
\n
Group apply an analytical approach.
\n

\n\n
In case of individual assessment, PD is mainly obtained
\n
from an external provider.
\n
Conversely, for collective assessment, trade receivables
\n
are grouped based on shared credit risk characteristics
\n
and past due information, considering a specific definition
\n
of default.
\n
Based on each business and local regulatory framework as
\n
well as differences in customer portfolios also in terms of
\n
risk, default rates and recovery expectations, specific clus-
\n
ters are defined.
\n
The contract assets are considered to have substantially
\n
the same risk characteristics as the trade receivables for
\n
the same types of contracts.
\n
In order to measure the ECL for trade receivables on a
\n
collective basis, as well as for contract assets, the Group
\n
considers the following assumptions related to ECL pa-
\n
rameters:
\n
\u2022 PD, assumed as to be the average default rate, is cal-
\n
culated on a cluster basis and taking into consideration
\n
minimum 24-month historical data;
\n
\u2022 LGD is function of the default bucket\u2019s recovery rates,
\n
discounted at the EIR; and
\n
\u2022 EAD is estimated as the carrying exposure at the report-
\n
ing date net of cash deposits, including invoices issued
\n
but not expired and invoices to be issued.
\n
Based on specific management evaluations, the for-
\n
ward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
possible future events and macroeconomic scenarios,
\n
which may affect the risk of the portfolio or the financial
\n
instrument.
\n
For additional details on the key assumptions and inputs
\n
used please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n
Depreciable amount of certain elements of Italian
\n
hydroelectric plants subsequent to enactment of Law
\n
134/2012
\n
Italian regulations governing large-scale hydroelectric
\n
concessions were significantly modified by the \u201cSimpli-
\n
fications Decree\u201d (Decree Law 135 of 2018 ratified with
\n
Law 12 of February 11, 2019). The regulations introduce a
\n
number of innovations which, if applied to existing con-
\n
cessions, would require a review of the useful lives of cer-
\n
tain investments in hydroelectric plants in order to reflect
\n
the possibility that, at the end of the concession, some
\n
assets could be transferred free of charge to the new
\n
concession holder. However, in estimating the useful lives
\n
of these plants, management, with the support of a legal
\n
opinion, considered the foreseeable outcome of the ap-
\n
peals promptly lodged by the Company \u2013 and others \u2013 and
\n
the related constitutionality issues, which have also been
\n
raised by industrial associations. Consequently, we believe
\n
that the legislation raises serious constitutionality issues
\n
that will be effectively recognized in the appropriate fora.
\n
Accordingly, management deemed it appropriate not to
\n
reflect the changes introduced by the regulations and
\n
therefore has continued to measure the useful lives of the
\n
plants as has been done in previous years under the pre-
\n
vious regulatory system, considering this to be the most
\n
realistic estimate.
\n
Law 134 of August 7, 2012 containing \u201curgent measures for
\n
growth\u201d (published in the Gazzetta Ufficiale of August 11,
\n
2012), introduced a sweeping overhaul of the rules gov-
\n
erning hydroelectric concessions. Among its various pro-
\n
visions, the law establishes that five years before the expi-
\n
ration of a major hydroelectric water diversion concession
\n
and in cases of lapse, relinquishment or revocation, where
\n
there is no prevailing public interest for a different use of
\n
the water, incompatible with its use for hydroelectric gen-
\n
eration, the competent public entity shall organize a pub-
\n
lic call for tenders for the award for consideration of the
\n
concession for a period ranging from 20 to a maximum of
\n
30 years.
\n
In order to ensure operational continuity, the law also gov-
\n
erns the methods of transferring ownership of the busi-
\n
ness unit necessary to operate the concession, including
\n
all legal relationships relating to the concession, from the
\n
outgoing concession holder to the new concession holder,
\n
in exchange for payment of a price to be determined in ne-
\n
gotiations between the departing concession holder and
\n
the grantor agency, taking due account of the following
\n
elements:
\n
\u2022 for intake and governing works, penstocks and outflow
\n
channels, which under the consolidated law governing
\n
waters and electrical plants are to be relinquished free of
\n
charge (Article 25 of Royal Decree 1775 of December 11,
\n
1933), the revalued cost less government capital grants,
\n
also revalued, received by the concession holder for the
\n
construction of such works, depreciated for ordinary
\n
wear and tear;
\n
\u2022 for other property, plant and equipment, the market val-
\n
ue, meaning replacement value, reduced by estimated
\n
depreciation for ordinary wear and tear.
\n
While acknowledging that the new regulations introduce
\n
important changes as to the transfer of ownership of the
\n
business unit with regard to the operation of the hydro-
\n
electric concession, the practical application of these
\n
principles faces difficulties, given the uncertainties that
\n
do not permit the formulation of a reliable estimate of the
\n
value that can be recovered at the end of existing conces-
\n
sions (residual value).
\n
Accordingly, management has decided it could not pro-
\n
duce a reasonable and reliable estimate of residual value.
\n
The fact that the legislation requires the new concession
\n
holder to make a payment to the departing concession
\n

\n\n

\n
holder prompted management to review the depreciation
\n
schedules for assets classified as to be relinquished free
\n
of charge prior to Law 134/2012 (until the year ended on
\n
December 31, 2011, given that the assets were to be relin-
\n
quished free of charge, the depreciation period was equal
\n
to the closest date between the term of the concession
\n
and the end of the useful life of the individual asset), calcu-
\n
lating depreciation no longer over the term of the conces-
\n
sion but, if longer, over the useful life of the individual as-
\n
sets. If additional information becomes available to enable
\n
the calculation of residual value, the carrying amounts of
\n
the assets involved will be adjusted prospectively.
\n
Determining the fair value of financial instruments
\n
The fair value of financial instruments is determined on the
\n
basis of prices directly observable in the market, where
\n
available, or, for unlisted financial instruments, using spe-
\n
cific valuation techniques (mainly based on present val-
\n
ue) that maximize the use of observable market inputs. In
\n
rare circumstances where this is not possible, the inputs
\n
are estimated by management taking due account of the
\n
characteristics of the instruments being measured.
\n
For more information on financial instruments measured
\n
at fair value, please see note 52 \u201cAssets and liabilities mea-
\n
sured at fair value\u201d.
\n
In accordance with IFRS 13, the Group includes a mea-
\n
surement of credit risk, both of the counterparty (Credit
\n
Valuation Adjustment or CVA) and its own (Debit Valua-
\n
tion Adjustment or DVA), in order to adjust the fair value
\n
of financial instruments for the corresponding amount of
\n
counterparty risk, using the method discussed in note 52
\n
\u201cAssets and liabilities measured at fair value\u201d.
\n
Changes in the assumptions made in estimating the input
\n
data could have an impact on the fair value recognized for
\n
those instruments, especially in current conditions where
\n
markets are volatile and the economic outlook is highly un-
\n
certain and subject to rapid change.
\n
Development expenditure
\n
In order to determine the recoverability of development
\n
expenditure, the recoverable amount is estimated mak-
\n
ing assumptions regarding any further cash outflow that is
\n
expected to be incurred before the asset is ready for use
\n
or sale, the discount rates to be applied and the expected
\n
period of benefits.
\n
Pensions and other post-employment benefits
\n
Some of the Group\u2019s employees participate in pension
\n
plans offering benefits based on their wage history and
\n
years of service. Certain employees are also eligible for
\n
other post-employment benefit schemes.
\n
The expenses and liabilities of such plans are calculated on
\n
the basis of estimates carried out by consulting actuaries,
\n
who use a combination of statistical and actuarial elements
\n
in their calculations, including statistical data on past years
\n
and forecasts of future costs. Other components of the
\n
estimation that are considered include mortality and re-
\n
tirement rates as well as assumptions concerning future
\n
developments in discount rates, the rate of wage increas-
\n
es, the inflation rate and trends in healthcare cost.
\n
These estimates can differ significantly from actual devel-
\n
opments owing to changes in economic and market con-
\n
ditions, increases or decreases in retirement rates and the
\n
lifespan of participants, as well as changes in the effective
\n
cost of healthcare.
\n
Such differences can have a substantial impact on the
\n
quantification of pension costs and other related expens-
\n
es.
\n
For more details on the main actuarial assumptions adopt-
\n
ed, please see note 39.
\n\n
Provisions for risks and charges
\n
For more details on provisions for risks and charges, please
\n
see note 40 \u201cProvisions for risks and charges\u201d.
\n
Note 57 \u201cContingent assets and liabilities\u201d also provides
\n
information regarding the most significant contingent as-
\n
sets and liabilities for the Group at year end.
\n
Litigation
\n
The Group is involved in various civil, administrative and tax
\n
disputes connected with the normal pursuit of its activi-
\n
ties that could give rise to significant liabilities. It is not al-
\n
ways objectively possible to predict the outcome of these
\n
disputes. The assessment of the risks associated with this
\n
litigation is based on complex factors whose very nature
\n
requires recourse to management judgments, even when
\n
taking account of the contribution of external advisors as-
\n
sisting the Group, about whether to classify them as con-
\n
tingent liabilities or liabilities.
\n
Provisions have been recognized to cover all significant li-
\n
abilities for cases in which legal counsel feels an adverse
\n
outcome is likely and a reasonable estimate of the amount
\n
of the expense can be made.
\n
Obligations associated with generation plants, including
\n
decommissioning and site restoration
\n
Generation activities may entail obligations for the opera-
\n
tor with regard to future interventions that will have to be
\n
performed following the end of the operating life of the
\n
plant.
\n
Such interventions may involve the decommissioning of
\n
plants and site restoration, or other obligations linked to
\n
the type of generation technology involved. The nature of
\n
such obligations may also have a major impact on the ac-
\n
counting treatment used for them.
\n
In the case of nuclear power plants, where the costs re-
\n
gard both decommissioning and the storage of waste fuel
\n
and other radioactive materials, the estimation of the fu-
\n

\n\n

\n\n

\n\n
ture cost is a critical process, given that the costs will be
\n
incurred over a very long span of time, estimated at up to
\n
100 years.
\n
The obligation, based on financial and engineering as-
\n
sumptions, is calculated by discounting the expected fu-
\n
ture cash flows that the Group considers it will have to pay
\n
to meet the obligations it has assumed.
\n
The discount rate used to determine the present value of
\n
the liability is the pre-tax risk-free rate and is based on the
\n
economic parameters of the country in which the plant is
\n
located.
\n
That liability is quantified by management on the basis of
\n
the technology existing at the measurement date and is re-
\n
viewed each year, taking account of developments in stor-
\n
age, decommissioning and site restoration technology, as
\n
well as the ongoing evolution of the legislative framework
\n
governing health and environmental protection.
\n
Subsequently, the value of the obligation is adjusted to re-
\n
flect the passage of time and any changes in estimates.
\n
Please see note 40 \u201cProvisions for risks and charges\u201d for
\n
more information on discount rates, undiscounted esti-
\n
mated costs and their timing, which are used to calculate
\n
the plant decommissioning and site restoration provision.
\n
Onerous contracts
\n
In order to identify an onerous contract, the Group esti-
\n
mates the non-discretionary costs necessary to fulfil the
\n
obligations assumed (including any penalties) under the
\n
contract and the economic benefits that are presumed to
\n
be obtained from the contract.
\n

\n\n
Leases
\n
When the interest rate implicit in the lease cannot be read-
\n
ily determined, the Group uses the incremental borrowing
\n
rate (IBR) at the lease commencement date to calculate
\n
the present value of the lease payments. This is the inter-
\n
est rate that the lessee would have to pay to borrow over a
\n
similar term, and with a similar security, the funds neces-
\n
sary to obtain an asset of a similar value to the rightofuse
\n
asset in a similar economic environment. When no observ-
\n
able inputs are available, the Group estimates the IBR mak-
\n
ing assumptions to reflect the terms and conditions of the
\n
lease and certain lessee-specific estimates.
\n
One of the most significant judgments for the Group is de-
\n
termining this IBR necessary to calculate the present value
\n
of the lease payments required to be paid to the lessor.
\n
The Group approach to determine an IBR is based on the
\n
assessment of the following three key components:
\n
\u2022 the risk free rate, that consider the currency flows of the
\n
lease payments, the economic environment where the
\n
lease contract has been negotiated and also the lease
\n
term;
\n
\u2022 the credit spread adjustment, in order to calculate an IBR
\n
that is specific for the lessee considering any underlying
\n
Parent or other guarantee;
\n
\u2022 the lease related adjustments, in order to reflect into the
\n
IBR calculation the fact that the discount rate is directly
\n
linked to the type of the underlying asset, rather than
\n
being a general incremental borrowing rate. In particu-
\n
lar, the risk of default is mitigated for the lessors as they
\n
have the right to reclaim the underlying asset itself.
\n
For more information on lease liabilities, please see note
\n
48 \u201cFinancial instruments by category\u201d.
\n
Income tax
\n
Recovery of deferred tax assets
\n
At December 31, 2022, the consolidated financial state-
\n
ments report deferred tax assets in respect of tax loss-
\n
es or tax credits usable in subsequent years and income
\n
components whose deductibility is deferred in an amount
\n
whose future recovery is considered by management to be
\n
highly probable.
\n
The recoverability of such assets is subject to the achieve-
\n
ment of future profits sufficient to absorb such tax losses
\n
and to use the benefits of the other deferred tax assets.
\n
Significant management judgment is required to assess
\n
the probability of recovering deferred tax assets, consid-
\n
ering all negative and positive evidence, and to determine
\n
the amount that can be recognized, based upon the likely
\n
timing and the level of future taxable profits together with
\n
future tax planning strategies and the tax rates applicable
\n
at the date of reversal. However, where the Group should
\n
become aware that it is unable to recover all or part of rec-
\n
ognized tax assets in future years, the consequent adjust-
\n
ment would be taken to profit or loss in the year in which
\n
this circumstance arises.
\n
The recoverability of deferred tax assets is reviewed at the
\n
end of each period. Deferred tax assets not recognized
\n
are reassessed at each reporting date in order to verify the
\n
conditions for their recognition.
\n
For more detail in deferred tax assets recognized or not
\n
recognized, please see note 25 \u201cDeferred tax assets and
\n
liabilities\u201d.
\n
Management judgment
\n
Identification of cash generating units (CGUs)
\n
For impairment testing, if the recoverable amount cannot
\n
be determined for an individual asset, the Group identi-
\n
fies the smallest group of assets that generate largely in-
\n
dependent cash inflows. The smallest group of assets that
\n
generates cash inflows that are largely independent of the
\n

\n\n
cash inflows from other assets or group of assets is a CGU.
\n
Identifying such CGUs involves management judgments
\n
regarding the specific nature of the assets and the busi-
\n
ness involved (geographical segment, business segment,
\n
regulatory framework, etc.) and the evidence that the cash
\n
inflows of the group of assets are largely independent of
\n
those associated with other assets (or groups of assets).
\n
The assets of each CGU are also identified on the basis of
\n
the manner in which management manages and monitors
\n
those assets within the business model adopted. In partic-
\n
ular, the number and scope of the CGUs are updated sys-
\n
tematically to reflect the impact of new business combi-
\n
nations and reorganizations carried out by the Group, and
\n
to take account of external factors that could influence the
\n
ability of assets to generate independent cash inflows.
\n
In particular, if certain specific identified assets owned by
\n
the Group are impacted by adverse economic or operating
\n
conditions that undermine their capacity to contribute to
\n
the generation of cash flows, they can be isolated from the
\n
rest of the assets of the CGU, undergo separate analysis of
\n
their recoverability and be impaired where necessary.
\n
The CGUs identified by management to which the goodwill
\n
recognized in these consolidated financial statements has
\n
been allocated and the criteria used to identify the CGUs
\n
are indicated in note 24 \u201cGoodwill\u201d.
\n
Determining the useful life of non-financial assets
\n
In determining the useful life of property, plant and equip-
\n
ment and intangible assets with a finite useful life, the
\n
Group considers not only the future economic benefits \u2013
\n
contained in the assets \u2013 obtained through their use, but
\n
also many other factors, such as physical wear and tear,
\n
the technical, commercial or other obsolescence of the
\n
product or service produced with the asset, legal or similar
\n
limits (e.g., safety, environmental or other restrictions) on
\n
the use of the asset, if the useful life of the asset depends
\n
on the useful life of other assets.
\n
Furthermore, in estimating the useful lives of the assets
\n
concerned, the Group has taken account of its commit-
\n
ment under the Paris Agreement. For more information on
\n
this issue, please see note 19 \u201cProperty, plant and equip-
\n
ment\u201d.
\n
Determination of the existence of control
\n
Under the provisions of IFRS 10, control is achieved when
\n
the Group is exposed, or has rights, to variable returns
\n
from its involvement with the investee and has the ability
\n
to affect those returns through its power over the investee.
\n
Power is defined as the current ability to direct the relevant
\n
activities of the investee based on existing substantive
\n
rights.
\n
The existence of control does not depend solely on owner-
\n
ship of a majority investment, but rather it arises from sub-
\n
stantive rights that each investor holds over the investee.
\n
Consequently, management must use its judgment in as-
\n
sessing whether specific situations determine substantive
\n
rights that give the Group the power to direct the relevant
\n
activities of the investee in order to affect its returns.
\n
For the purpose of assessing control, management an-
\n
alyzes all facts and circumstances including any agree-
\n
ments with other investors, rights arising from other con-
\n
tractual arrangements and potential voting rights (call
\n
options, warrants, put options granted to non-controlling
\n
shareholders, etc.). These other facts and circumstances
\n
could be especially significant in such assessment when
\n
the Group holds less than a majority of voting rights, or
\n
similar rights, in the investee.
\n
Furthermore, even if it holds more than half of the voting
\n
rights in an entity, the Group considers all the relevant
\n
facts and circumstances in assessing whether it controls
\n
the investee.
\n
The Group reassesses whether or not it controls an in-
\n
vestee if facts and circumstances indicate that there are
\n
changes to one or more of the elements considered in
\n
verifying the existence of control.
\n
As reported in Enel\u2019s consolidated financial statements at
\n
December 31, 2022, the Enel Group holds minor interests
\n
in Enel Green Power Rus LLC and Enel X Rus LLC.
\n
In the wake of the Ukrainian conflict, a number of measures
\n
were adopted or undertaken that resulted in the termina-
\n
tion of Enel\u2019s management and coordination role at the
\n
Russian companies in which the Group holds investments.
\n
These measures include: (i) the resignation of all non-in-
\n
dependent directors and all managers of non-Russian
\n
nationality; (ii) the termination of intercompany contracts;
\n
and (iii) the modification of the organizational structure of
\n
the Enel Group in order to terminate reporting by the staff
\n
or business functions to Enel.
\n
At December 31, 2022 the Enel Group continues to control
\n
the companies from an accounting point of view, in com-
\n
pliance with \u201cIFRS 10 - Consolidated Financial Statements\u201d.
\n
Determination of the existence of joint control and of
\n
the type of joint arrangement
\n
Under the provisions of IFRS 11, a joint arrangement is an
\n
agreement where two or more parties have joint control.
\n
Joint control exists only when the decisions over the rele-
\n
vant activities require the unanimous consent of the par-
\n
ties that share joint control.
\n
A joint arrangement can be configured as a joint venture
\n
or a joint operation. Joint ventures are joint arrangements
\n
whereby the parties that have joint control have rights to
\n
the net assets of the arrangement. Conversely, joint op-
\n
erations are joint arrangements whereby the parties that
\n

\n\n
have joint control have rights to the assets and obligations
\n
for the liabilities relating to the arrangement.
\n
In order to determine the existence of the joint control
\n
and the type of joint arrangement, management must ap-
\n
ply judgment and assess its rights and obligations arising
\n
from the arrangement. For this purpose, the management
\n
considers the structure and legal form of the arrangement,
\n
the terms agreed by the parties in the contractual arrange-
\n
ment and, when relevant, other facts and circumstances.
\n
Following that analysis, the Group has considered its in-
\n
terest in Asociaci\u00f3n Nuclear Asc\u00f3-Vandell\u00f3s II as a joint
\n
operation.
\n
The Group re-assesses whether or not it has joint control
\n
if facts and circumstances indicate that changes have oc-
\n
curred in one or more of the elements considered in veri-
\n
fying the existence of joint control and the type of the joint
\n
arrangement.
\n
In the wake of the Ukrainian conflict, a number of mea-
\n
sures were adopted or undertaken that resulted in the
\n
termination of Enel\u2019s management of Rusenergosbyt LLC
\n
(Group\u2019s associate). These measures include the resigna-
\n
tion of all non-independent directors and all managers of
\n
non-Russian nationality and the termination of reporting
\n
by the staff or business functions to Enel.
\n
At December 31, 2022 the Enel Group continues to exer-
\n
cise joint control of the company from an accounting point
\n
of view, in accordance with \u201cIFRS 11 - Joint arrangements\u201d.
\n
For more information on the Group\u2019s investments in joint
\n
ventures, please see note 26 \u201cEquity-accounted invest-
\n
ments\u201d.
\n
Determination of the existence of significant influence
\n
over an associate
\n
Associates are those in which the Group exercises signifi-
\n
cant influence, i.e., the power to participate in the financial
\n
and operating policy decisions of the investee but not ex-
\n
ercise control or joint control over those policies. In gener-
\n
al, it is presumed that the Group has a significant influence
\n
when it has an ownership interest of 20% or more.
\n
In order to determine the existence of significant influence,
\n
management must apply judgment and consider all facts
\n
and circumstances.
\n
The Group re-assesses whether or not it has significant
\n
influence if facts and circumstances indicate that there
\n
are changes to one or more of the elements considered in
\n
verifying the existence of significant influence.
\n
For more information on the Group\u2019s equity investments in
\n
associates, please see note 26 \u201cEquity-accounted invest-
\n
ments\u201d.
\n
Application of \u201cIFRIC 12 - Service concession
\n
arrangements\u201d to concessions
\n
IFRIC 12 applies to \u201cpublic-to-private\u201d service concession
\n
arrangements, which can be defined as contracts under
\n
which the operator is obligated to provide public services,
\n
i.e., give access to major economic and social services for
\n
a certain period of time, on behalf of a public entity (the
\n
grantor). In these contracts, the grantor conveys to an op-
\n
erator the right to manage the infrastructure used to pro-
\n
vide services.
\n
More specifically, IFRIC 12 gives guidance on the account-
\n
ing by operators for \u201cpublic-to-private\u201d service conces-
\n
sion arrangements in the event that:
\n
\u2022 the grantor controls or regulates what services the op-
\n
erator must provide with the infrastructure, to whom it
\n
must provide them, and at what price; and
\n
\u2022 the grantor controls \u2013 through ownership, beneficial en-
\n
titlement or otherwise \u2013 any significant residual interest
\n
in the infrastructure at the end of the term of the ar-
\n
rangement.
\n
In assessing the applicability of these requirements for the
\n
Group, as operator, management carefully analyzed exist-
\n
ing concessions.
\n
On the basis of that analysis, the provisions of IFRIC 12 are
\n
applicable to some of the infrastructure of a number of
\n
companies that operate primarily in Brazil.
\n
Further details about the infrastructure used in the service
\n
concession arrangements in the scope of IFRIC 12 are pro-
\n
vided in note 20 \u201cInfrastructure within the scope of \u2018IFRIC
\n
12 - Service concession arrangements\u2019\u201d.
\n
Revenue from contracts with customers
\n
In the process of applying IFRS 15, the Group has made the
\n
following judgments (further details about the most signif-
\n
icant effect on the Group\u2019s revenue are provided in note
\n
11.a \u201cRevenue from sales and services\u201d).
\n
The Group carefully analyzes the contractual terms and
\n
conditions on a jurisdictional level in order to determine
\n
when a contract exists and the terms of that contract\u2019s en-
\n
forceability so as to apply IFRS 15 only to such contracts.
\n
When a contract includes multiple promised goods or ser-
\n
vices, in order to assess if they should be accounted for
\n
separately or as a group, the Group considers both the in-
\n
dividual characteristics of goods/services and the nature of
\n
the promise within the context of the contract, also evalu-
\n
ating all the facts and circumstances relating to the specific
\n
contract under the relevant legal and regulatory framework.
\n
To evaluate when a performance obligation is satisfied, the
\n
Group evaluates when the control of the goods or services
\n
is transferred to the customer, assessed primarily from the
\n
perspective of the customer.
\n

\n\n

\n

\n
For each performance obligation, and in relation to the
\n
type of transaction:
\n
\u2022 revenue is recognized over time on the basis of the prog-
\n
ress towards complete satisfaction of the performance
\n
obligation, as in the case of the provision of services.
\n
The measurement of progress towards complete satis-
\n
faction of a performance obligation is carried out con-
\n
sistently for performance obligations and similar circum-
\n
stances using an \u201coutput\u201d or \u201cinput\u201d method. In particu-
\n
lar, the cost incurred method (cost-to-cost method) is
\n
considered appropriate for measuring progress except
\n
when a specific analysis of the contract counsels the use
\n
of an alternative method. If it should prove impossible to
\n
reasonably assess progress towards satisfaction of the
\n
performance obligation, the Group recognizes revenue
\n
only to the extent of the incurred costs that are consid-
\n
ered recoverable;
\n
\u2022 if, on the other hand, the performance obligation is sat-
\n
isfied at a given moment, as in the case of the supply
\n
of goods, revenue is recognized at the point in time in
\n
which the customer obtains the control of the goods,
\n
considering all relevant indicators.
\n
The Group considers all relevant facts and circumstanc-
\n
es in determining whether a contract includes variable
\n
consideration (i.e., consideration that may vary or de-
\n
pends upon the occurrence or non-occurrence of a fu-
\n
ture event). In estimating variable consideration, the Group
\n
uses the method that better predicts the consideration to
\n
which it will be entitled, applying it consistently throughout
\n
the contract and for similar contracts, also considering all
\n
available information, and updating such estimates until
\n
the uncertainly is resolved. The Group includes the esti-
\n
mated variable consideration in the transaction price only
\n
to the extent that it is highly probable that a significant re-
\n
versal in the cumulative revenue recognized will not occur
\n
when the uncertainty is resolved.
\n
The Group considers that it is an agent in some con-
\n
tracts in which it is not primarily responsible for fulfilling
\n
the contract and therefore it does not control goods or
\n
services before they are being transferred to customers.
\n
For example, the Group acts as an agent in some contracts
\n
for electricity/gas network connection services and other
\n
related activities depending on local legal and regulatory
\n
framework.
\n
For contracts that have more than one performance obli-
\n
gation (e.g., \u201cbundled\u201d sale contracts), the Group generally
\n
allocates the transaction price to each performance ob-
\n
ligation in proportion to its stand-alone selling price. The
\n
Group determines stand-alone selling prices considering
\n
all information and using observable prices when they are
\n
available in the market or, if not, using an estimation meth-
\n
od that maximizes the use of observable inputs and apply-
\n
ing it consistently to similar arrangements.
\n
If the Group evaluates that a contract includes an option
\n
for additional goods or services (e.g., customer loyalty pro-
\n
grams or renewal options) that represents a material right,
\n
it allocates the transaction price to this option since the
\n
option gives rise to an additional performance obligation.
\n\n
The Group assesses recoverability of the incremental costs
\n
of obtaining a contract either on a contract-by-contract
\n
basis, or for a group of contracts if those costs are associ-
\n
ated with the group of contracts.
\n
The Group supports the recoverability of such costs on
\n
the basis of its experience with other similar transactions
\n
and evaluating various factors, including potential renew-
\n
als, amendments and follow-on contracts with the same
\n
customer.
\n
The Group amortizes such costs over the average custom-
\n
er term. In order to determine this expected period of ben-
\n
efit from the contract, the Group considers its past experi-
\n
ence (e.g., \u201cchurn rate\u201d), the predictive evidence from sim-
\n
ilar contracts and available information about the market.
\n

\n\n
Power Purchase Agreements
\n
Power Purchase Agreements (PPAs), which provide for the
\n
physical delivery of energy and which do not comply with
\n
the requirements of IFRS 10 for the existence of control
\n
or joint control over a company or an asset, and IFRS 16
\n
for the recognition of a lease, but which comply with the
\n
definition of a derivative under IFRS 9, are accounted for
\n
on the basis of the own use exemption when the relevant
\n
conditions are met.
\n
For more information on Virtual PPAs complying with the
\n
definition of derivative pursuant to IFRS 9, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n
Classification and measurement of financial assets
\n
At initial recognition, in order to classify financial assets
\n
as financial assets at amortized cost, at fair value through
\n
other comprehensive income and at fair value through
\n
profit or loss, management assesses both the contractual
\n
cash-flow characteristics of the instrument and the busi-
\n
ness model for managing financial assets in order to gen-
\n
erate cash flows.
\n
In order to evaluate the contractual cash-flow characteris-
\n
tics of the instrument, management performs the SPPI test
\n
at an instrument level, in order to determine if it gives rise to
\n
cash flows that are solely payments of principal and inter-
\n
est (SPPI) on the principal amount outstanding, performing
\n
specific assessment on the contractual clauses of the finan-
\n
cial instruments, as well as quantitative analysis, if required.
\n
The business model determines whether cash flows will
\n

\n\n
result from collecting contractual cash flows, selling the
\n
financial assets, or both.
\n
For more details, please see note 48 \u201cFinancial instruments
\n
by category\u201d.
\n
Hedge accounting
\n
Hedge accounting is applied to derivatives in order to re-
\n
flect into the financial statements the effect of risk man-
\n
agement strategies.
\n
Accordingly, at the inception of the transaction the Group
\n
documents the hedge relationship between hedging in-
\n
struments and hedged items, as well as its risk manage-
\n
ment objectives and strategy. The Group also assesses,
\n
both at hedge inception and on an ongoing basis, wheth-
\n
er hedging instruments are highly effective in offsetting
\n
changes in the fair values or cash flows of hedged items.
\n
On the basis of management\u2019s judgment, the effectiveness
\n
assessment based on the existence of an economic rela-
\n
tionship between the hedging instruments and the hedged
\n
items, the dominance of credit risk in the changes in fair
\n
value and the hedge ratio, as well as the measurement of
\n
the ineffectiveness, is evaluated through a qualitative as-
\n
sessment or a quantitative computation, depending on the
\n
specific facts and circumstances and on the characteristics
\n
of the hedged items and the hedging instruments.
\n
For cash flow hedges of forecast transactions designated
\n
as hedged items, management assesses and documents
\n
that they are highly probable and present an exposure to
\n
changes in cash flows that affect profit or loss.
\n
For additional details on the key assumptions about effec-
\n
tiveness assessment and ineffectiveness measurement,
\n
please refer to note 51.1 \u201cDerivatives designated as hedging
\n
instruments\u201d.
\n
Leases
\n
The complexity of the assessment of the lease contracts,
\n
and also their long-term expiring date, requires consider-
\n
able professional judgments for application of IFRS 16. In
\n
particular, this regards:
\n
\u2022 the application of the definition of a lease to the cases
\n
typical of the sectors in which the Group operates;
\n
\u2022 the identification of the non-lease component into the
\n
lease arrangements;
\n
\u2022 the evaluation of any renewable and termination options
\n
included in the lease in order to determine the term of
\n
leases, also considering the probability of their exercise
\n
and any significant leasehold improvements on the un-
\n
derlying asset, taking due consideration of recent inter-
\n
pretations issued by the IFRS Interpretations Committee;
\n
\u2022 the identification of any variable lease payments that
\n
depend on an index or a rate to determine whether the
\n
changes of the latter impact the future lease payments
\n
and also the amount of the right-of-use asset;
\n
\u2022 the estimate of the discount rate to calculate the pres-
\n
ent value of the lease payments; further details on as-
\n
sumptions about this rate are provided in the paragraph
\n
\u201cUse of estimates\u201d.
\n
For more information on leases, please see note 21 \u201cLeas-
\n
es\u201d.
\n
Uncertainty over income tax treatments
\n
The Group determines whether to consider each uncer-
\n
tain income tax treatment separately or together with one
\n
or more other uncertain tax treatments as well as whether
\n
to reflect the effect of uncertainty by using the most like-
\n
ly amount or the expected value method, based on which
\n
approach better predicts the resolution of the uncertainty
\n
for each uncertain tax treatments, taking account of local
\n
tax regulations.
\n
The Group makes significant use of professional judgment
\n
in identifying uncertainties about income tax treatments
\n
and reviews the judgments and estimates made in the event
\n
of a change in facts and circumstances that could change
\n
its assessment of the acceptability of a specific tax treat-
\n
ment or the estimate of the effects of uncertainty, or both.
\n
For more information on income taxes, please see note 17
\n
\u201cIncome taxes\u201d.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag16": { "value": "\n
Provisions for risks and charges
\n
For more details on provisions for risks and charges, please
\n
see note 40 \u201cProvisions for risks and charges\u201d.
\n
Note 57 \u201cContingent assets and liabilities\u201d also provides
\n
information regarding the most significant contingent as-
\n
sets and liabilities for the Group at year end.
\n
Litigation
\n
The Group is involved in various civil, administrative and tax
\n
disputes connected with the normal pursuit of its activi-
\n
ties that could give rise to significant liabilities. It is not al-
\n
ways objectively possible to predict the outcome of these
\n
disputes. The assessment of the risks associated with this
\n
litigation is based on complex factors whose very nature
\n
requires recourse to management judgments, even when
\n
taking account of the contribution of external advisors as-
\n
sisting the Group, about whether to classify them as con-
\n
tingent liabilities or liabilities.
\n
Provisions have been recognized to cover all significant li-
\n
abilities for cases in which legal counsel feels an adverse
\n
outcome is likely and a reasonable estimate of the amount
\n
of the expense can be made.
\n
Obligations associated with generation plants, including
\n
decommissioning and site restoration
\n
Generation activities may entail obligations for the opera-
\n
tor with regard to future interventions that will have to be
\n
performed following the end of the operating life of the
\n
plant.
\n
Such interventions may involve the decommissioning of
\n
plants and site restoration, or other obligations linked to
\n
the type of generation technology involved. The nature of
\n
such obligations may also have a major impact on the ac-
\n
counting treatment used for them.
\n
In the case of nuclear power plants, where the costs re-
\n
gard both decommissioning and the storage of waste fuel
\n
and other radioactive materials, the estimation of the fu-
\n

\n\n
ture cost is a critical process, given that the costs will be
\n
incurred over a very long span of time, estimated at up to
\n
100 years.
\n
The obligation, based on financial and engineering as-
\n
sumptions, is calculated by discounting the expected fu-
\n
ture cash flows that the Group considers it will have to pay
\n
to meet the obligations it has assumed.
\n
The discount rate used to determine the present value of
\n
the liability is the pre-tax risk-free rate and is based on the
\n
economic parameters of the country in which the plant is
\n
located.
\n
That liability is quantified by management on the basis of
\n
the technology existing at the measurement date and is re-
\n
viewed each year, taking account of developments in stor-
\n
age, decommissioning and site restoration technology, as
\n
well as the ongoing evolution of the legislative framework
\n
governing health and environmental protection.
\n
Subsequently, the value of the obligation is adjusted to re-
\n
flect the passage of time and any changes in estimates.
\n
Please see note 40 \u201cProvisions for risks and charges\u201d for
\n
more information on discount rates, undiscounted esti-
\n
mated costs and their timing, which are used to calculate
\n
the plant decommissioning and site restoration provision.
\n
Onerous contracts
\n
In order to identify an onerous contract, the Group esti-
\n
mates the non-discretionary costs necessary to fulfil the
\n
obligations assumed (including any penalties) under the
\n
contract and the economic benefits that are presumed to
\n
be obtained from the contract.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag4": { "value": "\n
The Group assesses recoverability of the incremental costs
\n
of obtaining a contract either on a contract-by-contract
\n
basis, or for a group of contracts if those costs are associ-
\n
ated with the group of contracts.
\n
The Group supports the recoverability of such costs on
\n
the basis of its experience with other similar transactions
\n
and evaluating various factors, including potential renew-
\n
als, amendments and follow-on contracts with the same
\n
customer.
\n
The Group amortizes such costs over the average custom-
\n
er term. In order to determine this expected period of ben-
\n
efit from the contract, the Group considers its past experi-
\n
ence (e.g., \u201cchurn rate\u201d), the predictive evidence from sim-
\n
ilar contracts and available information about the market.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCustomerAcquisitionCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag30": { "value": "\n

\n

\n
2.2 Significant accounting policies
\n\n
Related parties
\n
Related parties are mainly those that share the same con-
\n
trolling entity with Enel SpA, the companies that directly or
\n
indirectly are controlled by Enel SpA, the associates or joint
\n
ventures (including their subsidiaries) of Enel SpA, or the
\n
associates or joint ventures (including their subsidiaries) of
\n
any Group company. Related parties also include entities
\n
that operate post-employment benefit plans for employ-
\n
ees of Enel SpA or its associates (specifically, the FOPEN
\n
and FONDENEL pension funds), as well as the members
\n
of the boards of statutory auditors, and their immediate
\n
family, and the key management personnel, and their im-
\n
mediate family, of Enel SpA and its subsidiaries. Key man-
\n
agement personnel comprises management personnel
\n
who have the power and direct or indirect responsibility
\n
for the planning, management and control of the activities
\n
of the Company. They include directors (whether executive
\n
or not).
\n

\n\n\n
Subsidiaries
\n
Subsidiaries are all entities over which the Group has con-
\n
trol. The Group controls an entity, regardless of the nature
\n
of the formal relationship between them, when it is ex-
\n
posed, or has rights, to variable returns deriving from its
\n
involvement and has the ability, through the exercise of its
\n
power over the investee, to affect its returns.
\n

\n\n

\n\n

\n

\n

\n\n
The figures of the subsidiaries are consolidated on a full
\n
line-by-line basis as from the date control is acquired until
\n
such control ceases.
\n

\n\n\n

\n

\n
Consolidation procedures
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2022 in accordance with the accounting
\n
policies adopted by the Group.
\n
If a subsidiary uses different accounting policies from
\n
those adopted in preparing the consolidated financial
\n
statements for similar transactions and facts in similar cir-
\n
cumstances, appropriate adjustments are made to ensure
\n
conformity with Group accounting policies.
\n
Assets, liabilities, revenue and expenses of a subsidiary ac-
\n
quired or disposed of during the year are included in or
\n
excluded from the consolidated financial statements, re-
\n
spectively, from the date the Group gains control or until
\n
the date the Group ceases to control the subsidiary.
\n\n
Profit or loss for the year and the other comprehensive
\n
income are attributed to the owners of the Parent and
\n
non-controlling interests, even if this results in a loss for
\n
non-controlling interests.
\n
All intercompany assets and liabilities, equity item, revenue,
\n
expenses and cash flows relating to transactions between
\n
entities of the Group are eliminated in full.
\n
Changes in ownership interest in subsidiaries that do not
\n
result in loss of control are accounted for as equity trans-
\n
actions, with the carrying amounts of the controlling and
\n
non-controlling interests adjusted to reflect changes in
\n
their interests in the subsidiary. Any difference between
\n
the amount to which non-controlling interests are adjust-
\n
ed and the fair value of the consideration paid or received
\n
is recognized in consolidated equity.
\n

\n\n\n
When the Group ceases to have control over a subsidiary,
\n
any interest retained in the entity is remeasured to its fair
\n
value, recognized through profit or loss, at the date when
\n
control is lost, recognizing any gain or loss from the loss
\n
of control through profit or loss. In addition, any amounts
\n
previously recognized in other comprehensive income in
\n
respect of the former subsidiary are accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n\n

\n\n\n

\n\n

\n\n
Investments in associates and joint ventures
\n
An associate is an entity over which the Group has signifi-
\n
cant influence. Significant influence is the power to partic-
\n
ipate in decisions concerning the financial and operating
\n
policies of the investee without having control or joint con-
\n
trol over the investee.
\n
A joint venture is a joint arrangement over which the Group
\n
exercises joint control and has rights to the net assets of
\n
the arrangement. Joint control is the sharing of control of
\n
an arrangement, whereby decisions about the relevant ac-
\n
tivities require unanimous consent of the parties sharing
\n
control.
\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method.
\n
Under the equity method, these investments are initial-
\n
ly recognized at cost and any goodwill arising from the
\n
difference between the cost of the investment and the
\n
Group\u2019s share of the net fair value of the investee\u2019s identifi-
\n
able assets and liabilities at the acquisition date is included
\n
in the carrying amount of the investment.
\n
After the acquisition date, their carrying amount is adjust-
\n
ed to recognize changes in the Group\u2019s share of profit or
\n
loss of the associate or joint venture in Group profit or loss.
\n
Adjustments to the carrying amount may also be neces-
\n
sary following changes in the Group\u2019s share in the asso-
\n
ciate or joint venture as a result of changes in the other
\n
comprehensive income of the investee. The Group\u2019s share
\n
of these changes is recognized in the Group\u2019s other com-
\n
prehensive income.
\n
Distributions received from joint venture and associates
\n
reduce the carrying amount of the investments.
\n
Gains and losses resulting from transactions between the
\n
Group and the associates or joint ventures are eliminated
\n
to the extent of the interest in the associate or joint ven-
\n
ture.
\n
The financial statements of the associates or joint ventures
\n
are prepared for the same reporting period as the Group.
\n
When necessary, adjustments are made to bring the ac-
\n
counting policies in line with those of the Group.
\n
After application of the equity method, the Group deter-
\n
mines whether it is necessary to recognize an impairment
\n
loss on its investment in an associate or joint venture. If
\n
there is objective evidence of a loss of value, the entire
\n
carrying amount of the investment undergoes impairment
\n
testing pursuant to IAS 36 as a single asset. For more in-
\n
formation on impairment, please see the section \u201cImpair-
\n
ment of non-financial assets\u201d in note 2.1 \u201cUse of estimates
\n
and management judgment\u201d.
\n
If the investment ceases to be an associate or a joint ven-
\n
ture, the Group recognizes any retained investment at its
\n
fair value, through profit or loss. Any amounts previously
\n
recognized in other comprehensive income in respect of
\n
the former associate or joint venture are accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\n
If the ownership interest in an associate or a joint venture is
\n
reduced, but the Group continues to exercise a significant
\n
influence or joint control, the Group continues to apply
\n
the equity method and the share of the gain or loss that
\n
had previously been recognized in other comprehensive
\n
income relating to that reduction is accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n

\n\n

\n

\n\n

\n

\n\n

\n\n

\n

\n

\n

\n\n

\n\n

\n\n
When a portion of an investment in an associate or joint
\n
venture meets the criteria to be classified as held for sale,
\n
any retained portion of an investment in the associate or
\n
joint venture that has not been classified as held for sale
\n
is accounted for using the equity method until disposal of
\n
the portion classified as held for sale takes place.
\n
Joint operations are joint arrangements whereby the
\n
Group, which holds joint control, has rights to the assets
\n
and obligations for the liabilities relating to the arrange-
\n
ment. For each joint operation, the Group recognized as-
\n
sets, liabilities, costs and revenue on the basis of the pro-
\n
visions of the arrangement rather than the interest held.
\n
Where there is an increase in the interest in a joint ar-
\n
rangement that meets the definition of a business:
\n
\u2022 if the Group acquires control, and had rights over the
\n
assets and obligations for the liabilities of the joint ar-
\n
rangement immediately before the acquisition date,
\n
then the transaction represents a business combination
\n
achieved in stages. Consequently, the Group applies the
\n
requirements for a business combination achieved in
\n
stages, including the remeasurement of the interest it
\n
held previously in the joint operation at its fair value at
\n
the acquisition date;
\n
\u2022 if the Group obtains joint control (i.e., it already had an
\n
interest in a joint operation without holding joint control),
\n
the interest previously held in the joint operation shall
\n
not be remeasured.
\n
For more information on the Group\u2019s investments in asso-
\n
ciates and joint ventures, please see note 26 \u201cEquity-ac-
\n
counted investments\u201d.
\n

\n\n

\n\n

\n\n\n
Translation of foreign currency items
\n
Transactions in currencies other than the functional cur-
\n
rency are initially recognized at the spot exchange rate
\n
prevailing on the date of the transaction.
\n
Monetary assets and liabilities denominated in a foreign
\n
currency other than the functional currency are subse-
\n
quently translated using the closing exchange rate (i.e., the
\n
spot exchange rate prevailing at the reporting date).
\n
Non-monetary assets and liabilities denominated in for-
\n
eign currency that are recognized at historical cost are
\n
translated using the exchange rate at the date of the
\n
transaction. Non-monetary assets and liabilities in foreign
\n
currency measured at fair value are translated using the
\n
exchange rate at the date the fair value was determined.
\n
Any exchange differences are recognized through profit or
\n
loss.
\n
In determining the spot exchange rate to use on initial rec-
\n
ognition of the related asset, expense or income (or part
\n
of it) on the derecognition of a non-monetary asset or
\n
non-monetary liability relating to advance consideration in
\n
foreign currency paid or received, the date of the transac-
\n
tion is the date on which the Group initially recognizes the
\n
non-monetary asset or non-monetary liability associated
\n
with the advance consideration.
\n
If there are multiple advance payments or receipts, the
\n
Group determines the transaction date for each payment
\n
or receipt of advance consideration.
\n

\n

\n\n\n
Translation of financial statements
\n
denominated in a foreign currency
\n
For the purposes of the consolidated financial statements,
\n
all revenue, expenses, assets and liabilities are stated in
\n
euro, which is the presentation currency of the Parent.
\n
In order to prepare the consolidated financial statements,
\n
the financial statements of consolidated companies with
\n
functional currencies other than the presentation curren-
\n
cy used in the consolidated financial statements are trans-
\n
lated into euros by applying the closing exchange rate to
\n
the assets and liabilities, including goodwill and consolida-
\n
tion adjustments, and the average exchange rate for the
\n
period to the income statement items on the condition it
\n
approximates the exchange rates prevailing at the date of
\n
the respective transactions.
\n
Any resulting exchange gains or losses are recognized as
\n
a separate component of equity in a special reserve. The
\n
gains and losses are recognized proportionately in the
\n
income statement on the disposal (partial or total) of the
\n
subsidiary.
\n
When the functional currency of a consolidated company
\n
is the currency of a hyperinflationary economy, the Group
\n
restates the financial statements in accordance with IAS
\n
29 before applying the specific conversion method set out
\n
below.
\n
In order to consider the impact of hyperinflation on the
\n
local currency exchange rate, the financial position and
\n
performance (i.e., assets, liabilities, equity items, revenue
\n
and expenses) of a company whose functional currency is
\n
the currency of a hyperinflationary economy are translated
\n
into the Group\u2019s presentation currency (the euro) using the
\n
exchange rate prevailing at the reporting date, except for
\n
comparative amounts presented in the previous year\u2019s fi-
\n
nancial statements which are not adjusted for subsequent
\n
changes in the price level or subsequent changes in ex-
\n
change rates.
\n

\n\n\n

\n\n
Business combinations
\n
Business combinations initiated before January 1, 2010
\n
and completed within that financial year are recognized on
\n
the basis of IFRS 3 (2004).
\n
Such business combinations were recognized using the
\n
purchase method, where the purchase cost is equal to the
\n
fair value at the date of the exchange of the assets ac-
\n
quired and the liabilities incurred or assumed, plus costs
\n
directly attributable to the acquisition. This cost was allo-
\n
cated by recognizing the assets, liabilities and identifiable
\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n

\n
contingent liabilities of the acquired company at their fair
\n
values. Any positive difference between the cost of the
\n
acquisition and the fair value of the net assets acquired
\n
attributable to the owners of the Parent was recognized
\n
as goodwill. If the difference is negative, it is recognized
\n
through profit or loss.
\n\n
The carrying amount of non-controlling interests was de-
\n
termined in proportion to the interest held by non-con-
\n
trolling shareholders in the net assets. In the case of busi-
\n
ness combinations achieved in stages, at the date of ac-
\n
quisition any adjustment to the fair value of the net assets
\n
acquired previously was recognized in equity; the amount
\n
of goodwill was determined for each transaction separate-
\n
ly based on the fair values of the acquiree\u2019s net assets at
\n
the date of each exchange transaction.
\n

\n\n
Business combinations carried out as from January 1, 2010
\n
are recognized on the basis of IFRS 3 (2008), which is re-
\n
ferred to as IFRS 3 (Revised) hereafter.
\n
More specifically, business combinations are recognized
\n
using the acquisition method, where the purchase cost
\n
(the consideration transferred) is equal to the fair value at
\n
the purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments is-
\n
sued by the purchaser. The consideration transferred in-
\n
cludes the fair value of any asset or liability resulting from
\n
a contingent consideration arrangement.
\n
Costs directly attributable to the acquisition are recog-
\n
nized through profit or loss.
\n
The consideration transferred is allocated by recognizing
\n
the assets, liabilities and identifiable contingent liabili-
\n
ties of the acquired company at their fair values as at the
\n
acquisition date. The excess of the consideration trans-
\n
ferred, measured at fair value as at the acquisition date,
\n
the amount of any non-controlling interest in the acquiree
\n
plus the fair value of any equity interest in the acquiree
\n
previously held by the Group (in a business combination
\n
achieved in stages) over the net amount of the identifiable
\n
assets acquired and the liabilities incurred or assumed
\n
measured at fair value is recognized as goodwill. If the dif-
\n
ference is negative, the Group verifies whether it has cor-
\n
rectly identified all the assets acquired and liabilities as-
\n
sumed and reviews the procedures used to determine the
\n
amounts to recognize at the acquisition date. If after this
\n
assessment the fair value of the net assets acquired still
\n
exceeds the total consideration transferred, this excess
\n
represents the profit on a bargain purchase and is recog-
\n
nized through profit or loss.
\n
The carrying amount of non-controlling interests is deter-
\n
mined either in proportion to the interest held by non-con-
\n
trolling shareholders in the net identifiable assets of the
\n
acquiree or at their fair value as at the acquisition date.
\n
In the case of business combinations achieved in stages, at
\n
the date of acquisition of control the previously held equi-
\n
ty interest in the acquiree is remeasured to fair value and
\n
any positive or negative difference is recognized in profit
\n
or loss.
\n
Any contingent consideration is recognized at fair value at
\n
the acquisition date. Subsequent changes to the fair val-
\n
ue of the contingent consideration classified as an asset
\n
or a liability, or as a financial instrument within the scope
\n
of IFRS 9, are recognized in profit or loss. If the contin-
\n
gent consideration is not within the scope of IFRS 9, it is
\n
measured in accordance with the appropriate IFRS-EU.
\n
Contingent consideration that is classified as equity is not
\n
re-measured, and its subsequent settlement is accounted
\n
for within equity.
\n
If the fair values of the assets, liabilities and contingent li-
\n
abilities can only be calculated on a provisional basis, the
\n
business combination is recognized using such provisional
\n
values. Any adjustments resulting from the completion of
\n
the measurement process are recognized within 12 months
\n
of the date of acquisition, restating comparative figures.
\n

\n

\n\n

\n

\n\n\n
Fair value measurement
\n
For all fair value measurements and disclosures of fair val-
\n
ue, that are either required or permitted by IFRS, the Group
\n
applies IFRS 13.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The fair value measurement assumes that the transaction
\n
to sell an asset or transfer a liability takes place in the prin-
\n
cipal market, i.e., the market with the greatest volume and
\n
level of activity for the asset or liability. In the absence of a
\n
principal market, it is assumed that the transaction takes
\n
place in the most advantageous market to which the Group
\n
has access, i.e., the market that maximizes the amount
\n
that would be received to sell the asset or minimizes the
\n
amount that would be paid to transfer the liability.
\n
The fair value of an asset or a liability is measured using
\n
the assumptions that market participants would use when
\n
pricing the asset or liability, assuming that market partic-
\n
ipants act in their economic best interest. Market partici-
\n
pants are independent, knowledgeable sellers and buyers
\n
who are able to enter into a transaction for the asset or the
\n
liability and who are motivated but not forced or otherwise
\n
compelled to do so.
\n
When measuring fair value, the Group considers the char-
\n
acteristics of the asset or liability, in particular:
\n
\u2022 for a non-financial asset, a fair value measurement takes
\n
into account a market participant\u2019s ability to generate
\n
economic benefits by using the asset in its highest and
\n
best use or by selling it to another market participant
\n
that would use the asset in its highest and best use;
\n

\n\n

\n\n

\n

\n\n
\u2022 for liabilities and own equity instruments, the fair val-
\n
ue reflects the effect of non-performance risk, i.e., the
\n
risk that an entity will not fulfill an obligation, including
\n
among others the credit risk of the Group itself;
\n
\u2022 in the case of groups of financial assets and financial lia-
\n
bilities with offsetting positions in market risk or credit risk,
\n
managed on the basis of an entity\u2019s net exposure to such
\n
risks, it is permitted to measure fair value on a net basis.
\n
In measuring the fair value of assets and liabilities, the
\n
Group uses valuation techniques that are appropriate in
\n
the circumstances and for which sufficient data are avail-
\n
able, maximizing the use of relevant observable inputs and
\n
minimizing the use of unobservable inputs.
\n

\n\n\n

\n

\n

\n
Property, plant and equipment
\n
Property, plant and equipment is stated at cost, net of
\n
accumulated depreciation and accumulated impairment
\n
losses, if any. Such cost includes expenses directly attrib-
\n
utable to bringing the asset to the location and condition
\n
necessary for its intended use.
\n\n
The cost is also increased by the present value of the es-
\n
timate of the costs of decommissioning and restoring the
\n
site on which the asset is located where there is a legal
\n
or constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
The accounting treatment of changes in the estimate of
\n
these costs, the passage of time and the discount rate is
\n
discussed in note 40 \u201cProvisions for risks and charges\u201d.
\n

\n\n
Property, plant and equipment transferred from custom-
\n
ers to connect them to the electricity distribution network
\n
and/or to provide them with other related services is ini-
\n
tially recognized at its fair value at the date on which con-
\n
trol is obtained.
\n\n
Borrowing costs that are directly attributable to the ac-
\n
quisition, construction or production of a qualifying asset,
\n
i.e., an asset that takes a substantial period of time to get
\n
ready for its intended use or sale, are capitalized as part
\n
of the cost of the assets themselves. Borrowing costs as-
\n
sociated with the purchase/construction of assets that do
\n
not meet such requirement are expensed in the period in
\n
which they are incurred.
\n

\n\n
Certain assets that were revalued at the IFRS-EU transi-
\n
tion date or in previous periods are recognized at their fair
\n
value, which is considered to be their deemed cost at the
\n
revaluation date.
\n
Where individual items of major components of property,
\n
plant and equipment have different useful lives, the com-
\n
ponents are recognized and depreciated separately.
\n
Subsequent costs are recognized as an increase in the
\n
carrying amount of the asset when it is probable that fu-
\n
ture economic benefits associated with the cost incurred
\n
to replace a part of the asset will flow to the Group and the
\n
cost of the item can be measured reliably. All other costs
\n
are recognized in profit or loss as incurred.
\n
The cost of replacing part or all of an asset is recognized
\n
as an increase in the carrying amount of the asset and is
\n
depreciated over its useful life; the carrying amount of the
\n
replaced unit is derecognized through profit or loss.
\n\n
Property, plant and equipment, net of its residual value,
\n
is depreciated on a straight-line basis over its estimated
\n
useful life, which is reviewed annually. Any changes in de-
\n
preciation criteria shall be applied prospectively. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\n
Depreciation begins when the asset is available for use.
\n
The estimated useful life of the main items of property,
\n
plant and equipment is as follows:
\n
Civil buildings 10-60 years
\n
Buildings and civil works incorporated in plants 10-100 years
\n
Hydroelectric power plants:
\n
- penstock 10-65 years
\n
- mechanical and electrical machinery 10-65 years
\n
- other fixed hydraulic works 10-100 years
\n
Thermal power plants:
\n
- boilers and auxiliary components 20-40 years
\n
- gas turbine components 10-40 years
\n
- mechanical and electrical machinery 5-40 years
\n
- other fixed hydraulic works 60 years
\n
Nuclear power plants 50 years
\n
Geothermal power plants:
\n
- cooling towers 20 years
\n
- turbines and generators 10-50 years
\n
- turbine parts in contact with fluid 10 years
\n
- mechanical and electrical machinery 20-40 years
\n
Wind power plants:
\n
- towers 20-30 years
\n
- turbines and generators 20-30 years
\n
- mechanical and electrical machinery 15-30 years
\n
Solar power plants:
\n
- mechanical and electrical machinery 15-30 years
\n
Public and artistic lighting:
\n
- public lighting installations 10-20 years
\n
- artistic lighting installations 20 years
\n
Transport lines 10-60 years
\n
Transformer stations 20-55 years
\n
Distribution plants:
\n
- high-voltage lines 10-60 years
\n
- primary transformer stations 10-50 years
\n
- low and medium-voltage lines 10-50 years
\n
Meters:
\n
- electromechanical meters 5-40 years
\n
- electricity balance measurement equipment 10 years
\n
- electronic meters 15 years
\n
Charging stations 7-15 years
\n

\n\n

\n

\n\n

\n\n

\n

\n

\n\n

\n\n
The useful life of leasehold improvements is determined
\n
on the basis of the term of the lease or, if shorter, on the
\n
duration of the benefits produced by the improvements
\n
themselves.
\n
Land is not depreciated as it has an indefinite useful life.
\n

\n\n
Assets recognized under property, plant and equipment
\n
are derecognized either upon their disposal (i.e., at the
\n
date the recipient obtains control) or when no future eco-
\n
nomic benefit is expected from their use or disposal. Any
\n
gain or loss, recognized through profit or loss, is calculat-
\n
ed as the difference between the net disposal proceeds,
\n
determined in accordance with the transaction price re-
\n
quirements of IFRS 15, and the carrying amount of the
\n
derecognized assets.
\n

\n\n
Assets to be relinquished free of charge
\n
The Group\u2019s plants include assets to be relinquished free
\n
of charge at the end of the concessions. These mainly
\n
regard major water diversion works and the public lands
\n
used for the operation of the thermal power plants.
\n
Within the Italian regulatory framework in force until 2011,
\n
if the concessions are not renewed, at those dates all in-
\n
take and governing works, penstocks, outflow channels
\n
and other assets on public lands were to be relinquished
\n
free of charge to the State in good operating condition.
\n
Accordingly, depreciation on assets to be relinquished was
\n
calculated over the shorter of the term of the concession
\n
and the useful life of the assets.
\n
In the wake of the legislative changes introduced with Law
\n
134 of August 7, 2012, the assets previously classified as
\n
assets \u201cto be relinquished free of charge\u201d connected with
\n
the hydroelectric water diversion concessions are now
\n
considered in the same manner as other categories of
\n
\u201cProperty, plant and equipment\u201d and are therefore depre-
\n
ciated over the useful life of the asset (where this exceeds
\n
the term of the concession), as discussed in the section
\n
above on the \u201cDepreciable amount of certain elements of
\n
Italian hydroelectric plants subsequent to enactment of
\n
Law 134/2012\u201d, which you are invited to consult for more
\n
details.
\n
In accordance with Spanish laws 29/1985 and 46/1999,
\n
hydroelectric power stations in Spanish territory operate
\n
under administrative concessions at the end of which the
\n
plants will be returned to the government in good oper-
\n
ating condition. The terms of the concessions extend up
\n
to 2078.
\n
A number of generation companies that operate in Lat-
\n
in America hold administrative concessions with similar
\n
conditions to those applied under the Spanish concession
\n
system. These concessions will expire in Argentina in 2087,
\n
in Brazil in 2047, in Costa Rica in 2031, in Panama in 2060
\n
and in Guatemala in 2062.
\n\n
Infrastructure serving a concession not within the scope
\n
of \u201cIFRIC 12 - Service concession arrangements\u201d
\n
As regards the distribution of electricity, the Group is a
\n
concession holder in Italy for this service. The concession,
\n
granted by the Ministry for Economic Development, was
\n
issued free of charge and terminates on December 31,
\n
2030. If the concession is not renewed upon expiry, the
\n
grantor is required to pay an indemnity. The amount of the
\n
indemnity will be determined by agreement of the parties
\n
using appropriate valuation methods, based on both the
\n
carrying amount of the assets themselves and their prof-
\n
itability.
\n
In determining the indemnity, such profitability will be rep-
\n
resented by the present value of future cash flows. The in-
\n
frastructure serving the concession is owned and available
\n
to the concession holder. It is recognized under \u201cProperty,
\n
plant and equipment\u201d and is depreciated over the useful
\n
lives of the assets.
\n
Enel also operates under administrative concessions for
\n
the distribution of electricity in other countries (including
\n
Spain and Romania). These concessions give the right to
\n
build and operate distribution networks for an indefinite
\n
period of time.
\n

\n\n\n
Infrastructure within the scope of \u201cIFRIC 12 -
\n
Service concession arrangements\u201d
\n
Under a \u201cpublic-to-private\u201d service concession arrange-
\n
ment within the scope of \u201cIFRIC 12 - Service concession
\n
arrangements\u201d the operator acts as a service provider and,
\n
in accordance with the terms specified in the contract, it
\n
constructs/upgrades infrastructure used to provide a
\n
public service and/or operates and maintains that infra-
\n
structure for the years of the concession.
\n
The Group, as operator, does not account for the infra-
\n
structure within the scope of IFRIC 12 as property, plant
\n
and equipment and it recognizes and measures revenue
\n
in accordance with IFRS 15 for the services it performs. In
\n
particular, when the Group provides construction or up-
\n
grade services, depending on the characteristics of the
\n
service concession arrangement, it recognizes:
\n
\u2022 a financial asset, if the Group has an unconditional con-
\n
tractual right to receive cash or another financial asset
\n
from the grantor (or from a third party at the direction
\n
of the grantor), that is the grantor has little discretion
\n
to avoid payment. In this case, the grantor contractually
\n
guarantees to pay to the operator specified or deter-
\n
minable amounts or the shortfall between the amounts
\n
received from the users of the public service and spec-
\n
ified or determinable amounts (defined by the contract),
\n
and such payments are not dependent on the usage of
\n
the infrastructure; and/or
\n
\u2022 an intangible asset, if the Group receives the right (a li-
\n
cense) to charge users of the public service provided. In
\n

\n\n

\n\n

\n

\n\n
such a case, the operator does not have an uncondition-
\n
al right to receive cash because the amounts are contin-
\n
gent on the extent that the public uses the service.
\n
If the Group (as operator) has a contractual right to re-
\n
ceive an intangible asset (a right to charge users of public
\n
service), borrowing costs are capitalized using the criteria
\n
specified in note 19 \u201cProperty, plant and equipment\u201d.
\n
However, for construction/upgrade services, both types of
\n
consideration are classified as a contract asset during the
\n
construction/upgrade period.
\n
For more details about such consideration, please see
\n
note 11.a \u201cRevenue from sales and services\u201d.
\n

\n\n\n
Leases
\n
The Group holds property, plant and equipment for its
\n
various activities under lease contracts. At inception of
\n
a contract, the Group assesses whether a contract is, or
\n
contains, a lease.
\n
For contracts entered into or changed on or after January
\n
1, 2019, the Group has applied the definition of a lease un-
\n
der IFRS 16, that is met if the contract conveys the right to
\n
control the use of an identified asset for a period of time in
\n
exchange for consideration.
\n
Conversely, for contracts entered into before January 1,
\n
2019, the Group determined whether the arrangement
\n
was or contained a lease under IFRIC 4.
\n
Group as a lessee
\n
At commencement or on modification of a contract that
\n
contains a lease component
\n
and one or more additional
\n
lease or non-lease components
\n
, the Group allocates the
\n
consideration in the contract to each lease component on
\n
the basis of its relative stand-alone price.
\n
The Group recognizes a right-of-use asset and a lease lia-
\n
bility at the commencement date of the lease (i.e., the date
\n
the underlying asset is available for use).
\n
The right-of-use asset represents a lessee\u2019s right to use an
\n
underlying asset for the lease term; it is initially measured
\n
at cost, which includes the initial amount of lease liabili-
\n
ty adjusted for any lease payments made at or before the
\n
commencement date less any lease incentives received,
\n
plus any initial direct costs incurred and an estimate of
\n
costs to retire and remove the underlying asset and to re-
\n
store the underlying asset or the site on which it is located.
\n
Right-of-use assets are subsequently depreciated on a
\n
straight-line basis over the shorter of the lease term and
\n
the estimated useful lives of the right-of-use assets, as
\n
follows:
\n
Average residual life (years)
\n
Buildings 6
\n
Ground rights of renewable energy plants 31
\n
Vehicles and other means of transport 5
\n
If the lease transfers ownership of the underlying asset to
\n
the Group at the end of the lease term or if the cost of the
\n
right-of-use asset
\n
reflects the fact that the Group will exer-
\n
cise a purchase option, depreciation is calculated using the
\n
estimated useful life of the underlying asset.
\n
In addition, the right-of-use assets are subject to impair-
\n
ment and adjusted for any remeasurement of lease liabili-
\n
ties.
\n
The lease liability is initially measured at the present value of
\n
lease payments to be made over the lease term. In calcu-
\n
lating the present value of lease payments, the Group uses
\n
the lessee\u2019s incremental borrowing rate at the lease com-
\n
mencement date when the interest rate implicit in the lease
\n
is not readily determinable.
\n
Variable lease payments that do not depend on an index or
\n
a rate are recognized as expenses in the period in which the
\n
event or condition that triggers the payment occurs.
\n
After the commencement date, the lease liability is mea-
\n
sured at amortized cost using the effective interest method
\n
and is remeasured upon the occurrence of certain events.
\n
The Group applies the short-term lease recognition ex-
\n
emption to its lease contracts that have a lease term of 12
\n
months or less from the commencement date. It also ap-
\n
plies the low-value assets recognition exemption to lease
\n
contracts for which the underlying asset is of low-value
\n
whose amount is estimated not material. For example, the
\n
Group has leases of certain office equipment (i.e., personal
\n
computers, printing and photocopying machines) that are
\n
considered of low-value. Lease payments on short-term
\n
leases and leases of low-value assets are recognized as
\n
expense on a straight-line basis over the lease term.
\n
The Group presents right-of-use assets that do not meet
\n
the definition of investment property in \u201cProperty, plant
\n
and equipment\u201d and lease liabilities in \u201cBorrowings\u201d.
\n
Consistent with the requirement of the standard, the
\n
Group presents separately the interest expense on lease
\n
liabilities under \u201cOther financial expense\u201d and the depreci-
\n
ation charge on the right-of-use assets under \u201cDeprecia-
\n
tion, amortization and impairment losses\u201d.
\n
Group as a lessor
\n
When the Group acts as a lessor, it determines at the lease
\n
inception date whether each lease is a finance lease or an
\n
operating lease.
\n
Leases in which the Group essentially transfers all the risks
\n
and rewards associated with ownership of the underlying
\n
asset are classified as finance leases; otherwise, they are
\n
classified as operating leases. To make this assessment, the
\n
Group considers the indicators provided by IFRS 16. If a con-
\n
tract contains lease and non-lease components, the Group
\n
allocates the consideration in the contract applying IFRS 15.
\n
The Group accounts for rental income arising from oper-
\n
ating leases on a straight-line basis over the lease terms
\n
and it recognizes it as other revenue.
\n

\n

\n\n

\n\n

\n

\n\n
Investment property
\n
Investment property consists of the Group\u2019s real estate
\n
held to earn rentals and/or for capital appreciation rath-
\n
er than for use in the production or supply of goods and
\n
services.
\n
Investment property is measured at acquisition cost less
\n
any accumulated depreciation and any accumulated im-
\n
pairment losses.
\n
Investment property, excluding land, is depreciated on a
\n
straight-line basis over the useful lives of the related as-
\n
sets.
\n
Impairment losses are determined on the basis of the cri-
\n
teria following described.
\n
The breakdown of the fair value of investment property is
\n
detailed in note 52 \u201cAssets and liabilities measured at fair
\n
value\u201d.
\n
Investment property is derecognized either when it has
\n
been transferred (i.e., at the date the recipient obtains
\n
control) or when it is permanently withdrawn from use
\n
and no future economic benefit is expected from its dis-
\n
posal. Any gain or loss, recognized through profit or loss,
\n
is calculated as the difference between the net disposal
\n
proceeds, determined in accordance with the transaction
\n
price requirements of IFRS 15, and the carrying amount of
\n
the derecognized assets.
\n
Transfers are made to (or from) investment property only
\n
when there is a change in use.
\n

\n\n\n

\n

\n\n

\n
Intangible assets
\n
Intangible assets are identifiable assets without physical
\n
substance controlled by the Group and capable of gen-
\n
erating future economic benefits. They are measured at
\n
purchase or internal development cost when it is probable
\n
that the use of such assets will generate future economic
\n
benefits and the related cost can be reliably determined.
\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n\n
Development expenditure is recognized as an intangible
\n
asset only when Group can demonstrate the technical fea-
\n
sibility of completing the asset, its intention and ability to
\n
complete development and to use or sell the asset and the
\n
availability of resources to complete the asset.
\n
Research costs are recognized as expenses.
\n

\n\n
Intangible assets with a finite useful life are recognized net
\n
of accumulated amortization and any impairment losses.
\n
Amortization is calculated on a straight-line basis over the
\n
asset\u2019s estimated useful life, which is reassessed at least
\n
annually; any changes in amortization policies are reflected
\n
on a prospective basis. For more information on estimating
\n
useful life, please see note 2.1 \u201cUse of estimates and man-
\n
agement judgment\u201d.
\n
Amortization commences when the asset is ready for use.
\n
Consequently, intangible assets not yet available for use
\n
are not amortized, but are tested for impairment at least
\n
annually.
\n
The Group\u2019s intangible assets have a finite useful life, with the
\n
exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amortized,
\n
but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annually
\n
to determine whether the indefinite useful life continues to
\n
be supportable. If not, the change in useful life from indefinite
\n
to finite is accounted for as a change in accounting estimate.
\n
Intangible assets are derecognized either at the time of
\n
their disposal (at the date when the recipient obtains con-
\n
trol) or when no future economic benefit is expected from
\n
their use or disposal. Any gain or loss, recognized through
\n
profit or loss, is calculated as the difference between the
\n
net consideration received in the disposal, determined
\n
in accordance with the provisions of IFRS 15 concern-
\n
ing the transaction price, and the carrying amount of the
\n
derecognized assets.
\n
The estimated useful life of the main intangible assets,
\n
distinguishing between internally generated and acquired
\n
assets, is as follows:
\n
Development expenditure:
\n
- internally generated 5 years
\n
- acquired 3-26 years
\n
Industrial patents and intellectual property rights:
\n
- internally generated 3-10 years
\n
- acquired 3-10 years
\n
Concessions, licenses, trademarks and similar rights:
\n
- internally generated 20 years
\n
- acquired 10-18 years
\n
Other:
\n
- internally generated 2-28 years
\n
- acquired 3-15 years
\n
The Group also presents costs to obtain a contract with a
\n
customer capitalized in accordance with IFRS 15 as intan-
\n
gible assets.
\n
The Group recognized such costs as an asset only if:
\n
\u2022 the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group would
\n
not have incurred them if the contract had not been ob-
\n
tained;
\n
\u2022 the Group expects to recover them, through reimburse-
\n
ments (direct recoverability) or the margin (indirect re-
\n
coverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the cap-
\n
italization criteria are met.
\n
Capitalized customer contract costs are amortized on a
\n
systematic basis, consistent with the pattern of the trans-
\n
fer of the goods or services to which they relate, and un-
\n
dergo impairment testing to identify any impairment loss-
\n
es to the extent that the carrying amount of the asset rec-
\n
ognized exceeds the recoverable amount.
\n

\n

\n\n

\n

\n\n

\n\n

\n

\n

\n

\n

\n\n

\n\n
The Group amortizes the capitalized customer contract
\n
costs
\n
on a straight-line basis over the expected period of
\n
benefit from the contract (i.e., the average term of the cus-
\n
tomer relationship);
\n
any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n

\n

\n\n\n

\n\n

\n\n
Goodwill
\n
Goodwill represents the future economic benefits arising
\n
from other assets acquired in a business combination that
\n
are not individually identified and separately recognized.
\n
For further details, please see the section of the account-
\n
ing policies \u201cBusiness combinations\u201d.
\n
Goodwill arising on the acquisition of subsidiaries is rec-
\n
ognized separately. After initial recognition, goodwill is not
\n
amortized, but is tested for impairment at least annually as
\n
part of the CGU to which it pertains.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU that is expect-
\n
ed to benefit from the synergies of the combination.
\n
Goodwill relating to equity investments in associates and
\n
joint venture is included in their carrying amount.
\n

\n\n

\n\n

\n\n\n

\n\n
Impairment of non-financial assets
\n
At each reporting date, property, plant and equipment, in-
\n
vestment property, intangible assets, right-of-use assets,
\n
goodwill and equity investments in associates/joint ven-
\n
tures are reviewed to determine whether there is evidence
\n
of impairment.
\n
CGUs to which goodwill, intangible assets with an indef-
\n
inite useful life and intangible assets not yet available for
\n
use are allocated are tested for recoverability annually or
\n
more frequently if there is evidence suggesting that the
\n
assets can be impaired.
\n
If such evidence exists, the recoverable amount of any in-
\n
volved asset is estimated on the basis of the use of the as-
\n
set and its future disposal, in accordance with the Group\u2019s
\n
most recent Business Plan. For the estimate of the recov-
\n
erable amount, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The recoverable amount is determined for an individual as-
\n
set, unless the asset do not generate cash inflows that are
\n
largely independent of those from other assets or groups
\n
of assets and therefore it is determined for the CGU to
\n
which the asset belongs.
\n
If the carrying amount of an asset or of a CGU to which it
\n
is allocated is greater than its recoverable amount, an im-
\n
pairment loss is recognized in profit or loss and presented
\n
under \u201cDepreciation, amortization and other impairment
\n
losses\u201d.
\n
Impairment losses of CGUs are firstly charged against the
\n
carrying amount of any goodwill attributed to it and then
\n
against the other assets, in proportion to their carrying
\n
amount.
\n
If the reasons for a previously recognized impairment loss
\n
no longer apply, the carrying amount of the asset is restored
\n
through profit or loss, under \u201cDepreciation, amortization
\n
and other impairment losses\u201d, in an amount that shall not
\n
exceed the carrying amount that the asset would have had
\n
if the impairment loss had not been recognized. The origi-
\n
nal amount of goodwill is not restored even if in subsequent
\n
years the reasons for the impairment no longer apply.
\n
If certain specific identified assets owned by the Group are
\n
impacted by adverse economic or operating conditions
\n
that undermine their capacity to contribute to the gener-
\n
ation of cash flows, they can be isolated from the rest of
\n
the assets of the CGU, undergo separate analysis of their
\n
recoverability and be impaired where necessary.
\n

\n

\n\n

\n

\n\n\n

\n
Inventories
\n
Inventories are measured at the lower of cost and net re-
\n
alizable value except for inventories involved in trading ac-
\n
tivities, which are measured at fair value with recognition
\n
through profit or loss. Cost is determined on the basis of
\n
average weighted cost, which includes related ancillary
\n
charges. Net estimated realizable value is the estimated
\n
normal selling price net of estimated costs to sell or, where
\n
applicable, replacement cost.
\n
For the portion of inventories held to discharge sales that
\n
have already been made, the net realizable value is deter-
\n
mined on the basis of the amount established in the con-
\n
tract of sale.
\n\n
Inventories include environmental certificates (for example,
\n
green certificates, energy efficiency certificates and Euro-
\n
pean CO
\n
2
\n
emissions allowances and guarantees of origin)
\n
exceeding compliance in the reporting period. As regards
\n
CO
\n
2
\n
emissions allowances, inventories are allocated be-
\n
tween the trading portfolio and the compliance portfolio,
\n
i.e., those used for compliance with greenhouse gas emis-
\n
sions requirements.
\n

\n

\n\n
Inventories also include nuclear fuel stocks, use of which is
\n
determined on the basis of the electricity generated.
\n
Materials and other consumables (including energy com-
\n
modities) held for use in production are not written down
\n
if it is expected that the final product in which they will be
\n
incorporated will be sold at a price sufficient to enable re-
\n
covery of the cost incurred.
\n

\n

\n\n\n
Financial instruments
\n
Financial instruments are any contract that gives rise to a
\n
financial asset of one entity and a financial liability or eq-
\n
uity instrument of another entity; they are recognized and
\n
measured in accordance with IAS 32 and IFRS 9.
\n
A financial asset or liability is recognized in the consolidat-
\n
ed financial statements when, and only when, the Group
\n
becomes party to the contractual provision of the instru-
\n
ment (i.e., the trade date).
\n

\n\n

\n\n

\n

\n

\n

\n

\n

\n\n

\n
Trade receivables arising from contracts with customers, in
\n
the scope of IFRS 15, are initially measured at their trans-
\n
action price (as defined in IFRS 15) if such receivables do
\n
not contain a significant financing component or when the
\n
Group applies the practical expedient allowed by IFRS 15.
\n
Conversely, the Group initially measures financial assets
\n
other than the above-mentioned trade receivables at their
\n
fair value plus, in the case of a financial asset not measured
\n
at fair value through profit or loss, transaction costs.
\n
Financial assets are classified, at initial recognition, as fi-
\n
nancial assets at amortized cost, at fair value through oth-
\n
er comprehensive income and at fair value through profit
\n
or loss, on the basis of both the Group\u2019s business model
\n
and the contractual cash-flow characteristics of the in-
\n
strument.
\n
For this purpose, the assessment to determine whether
\n
the instrument gives rise to cash flows that are solely pay-
\n
ments of principal and interest (SPPI) on the principal amount
\n
outstanding is referred to as the SPPI test and is performed at
\n
an instrument level.
\n
The Group\u2019s business model for managing financial assets
\n
refers to how it manages its financial assets in order to gener-
\n
ate cash flows. The business model determines whether cash
\n
flows will result from collecting contractual cash flows, selling
\n
the financial assets, or both.
\n
For purposes of subsequent measurement, financial assets
\n
are classified in four categories:
\n
\u2022 financial assets measured at amortized cost (debt instru-
\n
ments);
\n
\u2022 financial assets at fair value through OCI with reclassifica-
\n
tion of cumulative gains and losses (debt instruments);
\n
\u2022 financial assets designated at fair value through OCI with
\n
no reclassification of cumulative gains and losses upon
\n
derecognition (equity instruments); and
\n
\u2022 financial assets at fair value through profit or loss.
\n

\n\n

\n

\n

\n

\n\n
Financial assets measured at amortized cost
\n
This category mainly includes trade receivables, other fi-
\n
nancial assets and loan assets.
\n
Financial assets at amortized cost are held within a busi-
\n
ness model whose objective is to hold financial assets in
\n
order to collect contractual cash flows and whose con-
\n
tractual terms give rise, on specified dates, to cash flows
\n
that are solely payments of principal and interest on the
\n
principal amount outstanding.
\n
Such assets are initially recognized at fair value, adjusted
\n
for any transaction costs, and subsequently measured at
\n
amortized cost using the effective interest method and are
\n
subject to impairment.
\n
Gains and losses are recognized in profit or loss when the
\n
asset is derecognized, modified or impaired.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Debt instruments
\n
This category mainly includes:
\n
\u2022 listed debt securities held by the Group reinsurance
\n
company and not classified as held for trading; and
\n
\u2022 tax credits deriving from application of Decree Law
\n
34/2020 (so-called \u201cRevival Decree\u201d).
\n
Financial assets at fair value through other comprehensive
\n
income are assets held within a business model whose
\n
objective is achieved by both collecting contractual cash
\n
flows and selling financial assets and whose contractual
\n
cash flows give rise, on specified dates, to cash flows that
\n
are solely payments of principal and interest on the princi-
\n
pal amount outstanding.
\n
Changes in fair value for these financial assets are recog-
\n
nized in other comprehensive income as well as loss al-
\n
lowances that do not reduce the carrying amount of the
\n
financial assets.
\n
When a financial asset is derecognized (e.g., at the time
\n
of sale), the cumulative gains and losses previously recog-
\n
nized in equity (except impairment and foreign exchange
\n
gains and losses to be recognized in profit or loss) are re-
\n
versed to profit or loss.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Equity instruments
\n
This category includes mainly equity investments in other
\n
entities irrevocably designated as such upon initial recog-
\n
nition.
\n
Gains and losses on these financial assets are never reclas-
\n
sified to profit or loss. The Group may transfer the cumula-
\n
tive gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of the
\n
cost of the investment.
\n

\n\n

\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes: securities, equity invest-
\n
ments in other companies, financial investments in fund
\n
held for trading and financial assets designated as at fair
\n
value through profit or loss at initial recognition.
\n
Financial assets at fair value through profit or loss are:
\n
\u2022 financial assets with cash flows that are not solely pay-
\n
ments of principal and interest, irrespective of the busi-
\n
ness model;
\n
\u2022 financial assets held for trading because acquired or
\n
incurred principally for the purpose of selling or repur-
\n
chasing in short term;
\n

\n\n

\n

\n\n

\n\n

\n\n

\n

\n

\n

\n\n

\n\n
\u2022 debt instruments designated upon initial recognition,
\n
under the option allowed by IFRS 9 (fair value option),
\n
if doing so eliminates, or significantly reduces, an ac-
\n
counting mismatch;
\n
\u2022 derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments.
\n
Such financial assets are initially recognized at fair value
\n
with subsequent gains and losses from changes in their
\n
fair value recognized through profit or loss.
\n
This category also includes listed equity investments
\n
which the Group had not irrevocably elected to classify at
\n
fair value through OCI. Dividends on such investments are
\n
also recognized as other income in the income statement
\n
when the right of payment has been established.
\n
Financial assets that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n\n

\n\n

\n\n
Impairment of financial assets
\n
At each reporting date, the Group recognizes a loss allow-
\n
ance for expected credit losses on trade receivables and
\n
other financial assets measured at amortized cost, debt
\n
instruments measured at fair value through other com-
\n
prehensive income (FVOCI), contract assets and all other
\n
assets within the scope of IFRS 9.
\n
In compliance with IFRS 9, as from January 1, 2018, the
\n
Group adopted a new impairment model based on the
\n
determination of expected credit losses (ECL) using a for-
\n
ward-looking approach. In essence, the model provides
\n
for:
\n
\u2022 the application of a single framework for all financial as-
\n
sets;
\n
\u2022 the recognition of expected credit losses on an ongoing
\n
basis and the updating of the amount of such losses at
\n
the end of each reporting period, reflecting changes in
\n
the credit risk of the financial instrument;
\n
\u2022 the measurement of expected losses on the basis of
\n
reasonable information, obtainable without undue cost,
\n
about past events, current conditions and forecasts of
\n
future conditions.
\n
For trade receivables, contract assets and lease receiv-
\n
ables, including those with a significant financial compo-
\n
nent, the Group adopts the simplified approach, determin-
\n
ing expected credit losses over a period corresponding to
\n
the entire life of the asset, generally equal to 12 months.
\n
For all financial assets other than trade receivables, con-
\n
tract assets and lease receivables, the Group applies the
\n
general approach under IFRS 9, based on the assessment
\n
of a significant increase in credit risk since initial recogni-
\n
tion. Under such approach, a loss allowance on financial
\n
assets is recognized at an amount equal to the lifetime
\n
expected credit losses, if the credit risk on those financial
\n
assets has increased significantly, since initial recognition,
\n
considering all reasonable and supportable information,
\n
including also forward-looking inputs.
\n
If at the reporting date the credit risk on financial assets
\n
has not increased significantly since initial recognition,
\n
the Group measures the loss allowance for those financial
\n
assets at an amount equal to 12-month expected credit
\n
losses.
\n
For financial assets on which a loss allowance equal to life-
\n
time expected credit losses has been recognized in the
\n
previous reporting period, the Group measures the loss al-
\n
lowance at an amount equal to 12-month expected credit
\n
losses when the condition regarding a significant increase
\n
in credit risk is no longer met.
\n
The Group recognizes in profit or loss, as an impairment
\n
gain or loss, the amount of expected credit losses (or re-
\n
versal) that is required to adjust the loss allowance at the
\n
reporting date to the amount that is required to be recog-
\n
nized in accordance with IFRS 9.
\n
The Group applies the low credit risk exemption, avoid-
\n
ing the recognition of loss allowances at an amount equal
\n
to lifetime expected credit losses due to a significant in-
\n
crease in credit risk of debt securities at fair value through
\n
OCI, whose counterparty has a strong financial capacity
\n
to meet its contractual cash-flow obligations (e.g., invest-
\n
ment grade).
\n
For more information on the impairment of financial as-
\n
sets, please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n

\n

\n\n

\n

\n\n

\n

\n\n\n
Cash and cash equivalents
\n
This category includes deposits that are available on de-
\n
mand or at very short term, as well as highly liquid short-
\n
term financial investments that are readily convertible into
\n
a known amount of cash and which are subject to insignif-
\n
icant risk of changes in value.
\n
In addition, for the purpose of the consolidated statement
\n
of cash flows, cash and cash equivalents do not include
\n
bank overdrafts at period-end.
\n

\n\n\n

\n\n

\n\n
Financial liabilities at amortized cost
\n
This category mainly includes borrowings, trade payables,
\n
lease liabilities and debt instruments.
\n
Financial liabilities, other than derivatives, are recognized
\n
when the Group becomes a party to the contractual claus-
\n
es of the instrument and are initially measured at fair value
\n
adjusted for directly attributable transaction costs. Finan-
\n
cial liabilities are subsequently measured at amortized cost
\n
using the effective interest rate method. The effective in-
\n
terest rate is the rate that exactly discounts the estimated
\n
future cash payments or receipts over the expected life
\n
of the financial instrument or a shorter period, where ap-
\n
propriate, to the carrying amount of the financial asset or
\n
liability.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n\n

\n\n
Financial liabilities at fair value through profit or loss
\n
Financial liabilities at fair value through profit or loss in-
\n
clude financial liabilities held for trading and financial lia-
\n
bilities designated upon initial recognition as at fair value
\n
through profit or loss.
\n
Financial liabilities are classified as held for trading if they
\n
are incurred for the purpose of repurchasing in the near
\n
term. This category also includes derivative financial in-
\n
struments entered into by the Group that are not desig-
\n
nated as hedging instruments in hedge relationships as
\n
defined by IFRS 9. Separated embedded derivatives are
\n
also classified as at fair value through profit or loss unless
\n
they are designated as effective hedging instruments.
\n
Gains or losses on liabilities at fair value through profit or
\n
loss are recognized through profit or loss.
\n
Financial liabilities designated upon initial recognition at
\n
fair value through profit or loss are designated at the initial
\n
date of recognition, only if the criteria in IFRS 9 are satis-
\n
fied.
\n
In this case, the portion of the change in fair value attribut-
\n
able to own credit risk is recognized in other comprehen-
\n
sive income.
\n
The Group has not designated any financial liability as at
\n
fair value through profit or loss, upon initial recognition.
\n
Financial liabilities that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n\n

\n\n

\n\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022 the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022 the Group has transferred substantially all the risks and
\n
rewards associated with the asset, transferring its rights
\n
to receive the cash flows of the asset or assuming a con-
\n
tractual obligation to pay such cash flows to one or more
\n
beneficiaries under a contract that meets the require-
\n
ments provided by IFRS 9 (the \u201cpass through test\u201d);
\n
\u2022 the Group has not transferred or retained substantially
\n
all the risks and rewards associated with the asset but
\n
has transferred control over the asset.
\n
Financial liabilities are derecognized when they are extin-
\n
guished, i.e., when the contractual obligation has been dis-
\n
charged, cancelled or expired.
\n
When an existing financial liability is replaced by another
\n
from the same lender on substantially different terms, or
\n
the terms of an existing liability are substantially modi-
\n
fied, such an exchange or modification is treated as the
\n
derecognition of the original liability and the recognition
\n
of a new liability. The difference in the respective carrying
\n
amounts is recognized in profit or loss.
\n

\n\n

\n\n

\n\n\n

\n\n

\n\n
Derivative financial instruments
\n
A derivative is a financial instrument or another contract:
\n
\u2022 whose value changes in response to the changes in an
\n
underlying variable such as an interest rate, commodity
\n
or security price, foreign exchange rate, a price or rate
\n
index, a credit rating or other variable;
\n
\u2022 that requires no initial net investment, or one that is
\n
smaller than would be required for a contract with similar
\n
response to changes in market factors;
\n
\u2022 that is settled at a future date.
\n
Derivative instruments are classified as financial assets or
\n
liabilities depending on the positive or negative fair value
\n
and they are classified as \u201cheld for trading\u201d within \u201cOther
\n
business models\u201d and measured at fair value through prof-
\n
it or loss, except for those designated as effective hedging
\n
instruments.
\n
All derivatives held for trading are classified as current as-
\n
sets or liabilities.
\n
Derivatives not held for trading purposes, but measured at
\n
fair value through profit or loss since they do not qualify for
\n
hedge accounting, and derivatives designated as effective
\n
hedging instruments are classified as current or not cur-
\n
rent on the basis of their maturity date and the Group in-
\n
tention to hold the financial instrument till maturity or not.
\n
For more details about derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n\n
Embedded derivatives
\n
An embedded derivative is a derivative included in a \u201ccom-
\n
bined\u201d contract (the so-called \u201chybrid instrument\u201d) that
\n
contains another non-derivative contract (the so-called
\n
host contract) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows.
\n
The main Group contracts that may contain embedded
\n
derivatives are contracts to buy or sell non-financial items
\n
with clauses or options that affect the contract price, vol-
\n
ume or maturity.
\n
A derivative embedded in a hybrid contract containing a
\n
financial asset host is not accounted for separately. The fi-
\n
nancial asset host together with the embedded derivative
\n
is required to be classified in its entirety as a financial asset
\n
at fair value through profit or loss.
\n
Contracts that do not represent financial instruments to
\n
be measured at fair value are analyzed in order to identify
\n
any embedded derivatives, which are to be separated and
\n
measured at fair value. This analysis is performed when the
\n
Group becomes party to the contract or when the contract
\n
is renegotiated in a manner that significantly changes the
\n
original associated cash flows.
\n
Embedded derivatives are separated from the host con-
\n
tract and accounted for as derivatives when:
\n
\u2022 the host contract is not a financial instrument measured
\n
at fair value through profit or loss;
\n

\n\n

\n\n

\n

\n

\n

\n\n
\u2022 the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the host
\n
contract;
\n
\u2022 a separate contract with the same terms as the embed-
\n
ded derivative would meet the definition of a derivative.
\n
Embedded derivatives that are separated from the host
\n
contract are recognized in the consolidated financial
\n
statements at fair value with changes recognized in profit
\n
or loss (except when the embedded derivative is part of a
\n
designated hedge relationship).
\n

\n\n\n
Contracts to buy or sell non-financial items
\n
In general, contracts to buy or sell non-financial items that
\n
are entered into and continue to be held for receipt or
\n
delivery in accordance with the Group\u2019s normal expected
\n
purchase, sale or usage requirements are out of the scope
\n
of IFRS 9 and then recognized as executory contracts, ac-
\n
cording to the \u201cown use exemption\u201d.
\n
A contract to buy or sell non-financial items is classified as
\n
\u201cnormal purchase or sale\u201d if it is entered into:
\n
\u2022 for the purpose of the physical settlement;
\n
\u2022 in accordance with the entity\u2019s expected purchase, sale
\n
or usage requirements.
\n
Moreover, contracts to buy or sell non-financial items with
\n
physical settlement (for example, fixed-price forward con-
\n
tracts on energy commodities) that do not qualify for the
\n
own use exemption are recognized as derivatives mea-
\n
sured at fair value from the trade date only if:
\n
\u2022 they can be settled net in cash; and
\n
\u2022 they are not entered into in accordance with the Group\u2019s
\n
expected purchase, sale or usage requirements.
\n
Trading contracts are valued at fair value through profit or
\n
loss; the results of the measurement of changes in the fair
\n
value of contracts still outstanding at the reporting date
\n
are recognized on a net basis under the item \u201cNet results
\n
from commodity contracts\u201d, while at the settlement date:
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the sale of energy com-
\n
modities as well as the related revenue, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cRevenue from sales
\n
and services\u201d;
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the purchase of energy
\n
commodities as well as the related cost, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cElectricity, gas and
\n
fuel\u201d and \u201cServices and other materials\u201d.
\n
Contracts to buy or sell non-financial items falling with-
\n
in the scope of application of IFRS 9 can also be subse-
\n
quently designated as hedging instruments if they satisfy
\n
the requirements for hedge accounting.
\n
The Group analyzes all contracts to buy or sell non-fi-
\n
nancial assets on an ongoing basis, with a specific focus
\n
on forward purchases and sales of electricity and energy
\n
commodities, in order to determine if they shall be classi-
\n
fied and treated in accordance with IFRS 9 or if they have
\n
been entered into for \u201cown use\u201d.
\n

\n

\n\n\n
Offsetting financial assets and liabilities
\n
The Group offsets financial assets and liabilities when:
\n
\u2022 there is a legally enforceable right to set off the recog-
\n
nized amounts; and
\n
\u2022 there is the intention of settling on a net basis or realiz-
\n
ing the asset and settling the liability simultaneously.
\n

\n\n
Hyperinflation
\n
In a hyperinflationary economy, the Group adjusts
\n
non-monetary items, equity and items deriving from in-
\n
dex-linked contracts up to the limit of recoverable amount,
\n
using a price index that reflects changes in general pur-
\n
chasing power.
\n
The effects of initial application are recognized in equity
\n
net of tax effects. Conversely, during the hyperinflation-
\n
ary period (until it ceases), the gain or loss resulting from
\n
adjustments is recognized in profit or loss and disclosed
\n
separately in financial income and expense.
\n
Starting from 2018, this standard applies to the Group\u2019s
\n
transactions in Argentina, whose economy has been de-
\n
clared hyperinflationary from July 1, 2018.
\n\n

\n
Non-current assets (or disposal groups)
\n
classified as held for sale and discontinued
\n
operations
\n\n
Non-current assets (or disposal groups) are classified as
\n
held for sale if their carrying amount will be recovered
\n
principally through a sale transaction, rather than through
\n
continuing use.
\n
This classification criterion is applicable only when
\n
non-current assets (or disposal groups) are available in
\n
their present condition for immediate sale and the sale is
\n
highly probable.
\n
If the Group is committed to a sale plan involving loss of
\n
control of a subsidiary and the requirements provided for
\n
under IFRS 5 are met, all the assets and liabilities of that
\n
subsidiary are classified as held for sale when the classi-
\n
fication criteria are met, regardless of whether the Group
\n
will retain a non-controlling interest in its former subsidiary
\n
after the sale.
\n
The Group applies these classification criteria as envisaged
\n
in IFRS 5 to an investment, or a portion of an investment, in
\n
an associate or a joint venture. Any retained portion of an
\n
investment in an associate or a joint venture that has not
\n
been classified as held for sale is accounted for using the
\n
equity method until disposal of the portion that is classified
\n
as held for sale takes place.
\n
Non-current assets (or disposal groups) and liabilities of
\n
disposal groups classified as held for sale are presented
\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n

\n\n
separately from other assets and liabilities in the state-
\n
ment of financial position.
\n
The amounts presented for non-current assets or for the
\n
assets and liabilities of disposal groups classified as held
\n
for sale are not reclassified or re-presented for prior peri-
\n
ods presented.
\n
Immediately before the initial classification of non-current
\n
assets (or disposal groups) as held for sale, the carrying
\n
amounts of such assets (or disposal groups) are measured
\n
in accordance with the accounting standard applicable to
\n
those assets or liabilities. Non-current assets (or disposal
\n
groups) classified as held for sale are measured at the low-
\n
er of their carrying amount and fair value less costs to sell.
\n
Impairment losses for any initial or subsequent write-down
\n
of the assets (or disposal groups) to fair value less costs to
\n
sell and gains for their reversals are recognized in profit or
\n
loss from continuing operations.
\n
Non-current assets are not depreciated (or amortized)
\n
while they are classified as held for sale or while they are
\n
part of a disposal group classified as held for sale.
\n
If the classification criteria are no longer met, the Group
\n
ceases to classify the non-current assets (or disposal
\n
group) as held for sale. In this case they are measured at
\n
the lower of:
\n
\u2022 the carrying amount before the asset (or disposal group)
\n
was classified as held for sale, adjusted for any depre-
\n
ciation, amortization or reversals of impairment losses
\n
that would have been recognized if the asset (or disposal
\n
group) had not been classified as held for sale; and
\n
\u2022 the recoverable amount, which is equal to the greater of
\n
its fair value net of costs to sell and its value in use, as
\n
calculated at the date of the subsequent decision not
\n
to sell.
\n
Any adjustment to the carrying amount of a non-current
\n
asset that ceases to be classified as held for sale is includ-
\n
ed in profit or loss from continuing operations.
\n

\n\n\n
A discontinued operation is a component of the Group
\n
that either has been disposed of, or is classified as held
\n
for sale, and:
\n
\u2022 represents a separate major business line or geograph-
\n
ical segment;
\n
\u2022 is part of a single coordinated plan to dispose of a sep-
\n
arate major business line or geographical segment; or
\n
\u2022 is a subsidiary acquired exclusively with a view to resale.
\n
The Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022 the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022 the post-tax gain or loss recognized on the measure-
\n
ment at fair value less costs to sell or on the disposal of
\n
the assets or disposal groups constituting the discon-
\n
tinued operation.
\n
The corresponding amount is restated in the income
\n
statement for prior periods presented in the financial
\n
statements, so that the disclosures relate to all operations
\n
that are discontinued by the end of the current report-
\n
ing period. If the Group ceases to classify a component
\n
as held for sale, the results of the component previously
\n
presented in discontinued operations are reclassified and
\n
included in profit or loss from continuing operations for all
\n
periods presented.
\n

\n

\n\n

\n

\n\n\n

\n\n
Environmental certificates
\n
Some Group companies are affected by national regula-
\n
tions governing green certificates, guarantees of origin
\n
and energy efficiency certificates (so-called white certifi-
\n
cates), as well as the European \u201cEmissions Trading System\u201d.
\n
Green certificates and guarantees of origin accrued in
\n
proportion to electricity generated by renewable energy
\n
plants and energy efficiency certificates accrued in pro-
\n
portion to energy savings achieved that have been certified
\n
by the competent authority are treated as non-monetary
\n
government operating grants and are recognized at fair
\n
value, under other operating profit, with recognition of an
\n
asset under other non-financial assets, if the certificates
\n
are not yet credited to the ownership account, or under
\n
inventories, if the certificates have already been credited
\n
to that account.
\n
At the time the certificates are credited to the ownership
\n
account, they are reclassified from other assets to inven-
\n
tories.
\n
Revenue from the sale of such certificates is recognized
\n
under revenue, with a corresponding decrease in invento-
\n
ries.
\n
For the purposes of accounting for charges arising from
\n
such regulatory requirements, the Group uses the \u201cnet li-
\n
ability approach\u201d.
\n
Under this accounting policy, any environmental certifi-
\n
cates received free of charge and those self-produced as
\n
a result of Group\u2019s operations that will be used for com-
\n
pliance purposes are recognized at nominal value (nil). In
\n
addition, charges incurred for obtaining (in the market or
\n
in some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the re-
\n
porting period are recognized through profit or loss on an
\n
accrual basis under other operating costs, as they repre-
\n
sent \u201csystem charges\u201d consequent to compliance with a
\n
regulatory requirement.
\n

\n\n

\n\n\n
Employee benefits
\n
Liabilities related to employee benefits paid upon or after
\n
ceasing employment in connection with defined benefit
\n
plans or other long-term benefits accrued during the em-
\n
ployment period are determined separately for each plan,
\n
using actuarial assumptions to estimate the amount of the
\n
future benefits that employees have accrued at the report-
\n
ing date (using the projected unit credit method). More
\n
specifically, the present value of the defined benefit obli-
\n
gation is calculated by using a discount rate determined
\n
on the basis of market yields at the end of the reporting
\n

\n\n

\n\n

\n

\n\n

\n

\n
period on high-quality corporate bonds. If there is no deep
\n
market for high-quality corporate bonds in the currency in
\n
which the bond is denominated, the corresponding yield
\n
of government securities is used.
\n
The liability, net of any plan assets, is recognized on an
\n
accrual basis over the vesting period of the related rights.
\n
These appraisals are performed by independent actuaries.
\n
If the plan assets exceed the present value of the related
\n
defined benefit obligation, the surplus (up to the limit of
\n
any cap) is recognized as an asset.
\n
As regards the liabilities/(assets) of defined benefit plans,
\n
the cumulative actuarial gains and losses from the actuari-
\n
al measurement of the liabilities, the return on the plan as-
\n
sets (net of the associated interest income) and the effect
\n
of the asset ceiling (net of the associated interest) are rec-
\n
ognized in other comprehensive income when they occur.
\n
For other long-term benefits, the related actuarial gains
\n
and losses are recognized through profit or loss.
\n
In the event of a change being made to an existing defined
\n
benefit plan or the introduction of a new plan, any past
\n
service cost is recognized immediately in profit or loss.
\n
In addition, the Group is involved in defined contribution
\n
plans under which it pays fixed contributions to a separate
\n
entity (a fund) and has no legal or constructive obligation
\n
to pay further contributions if the fund does not hold suf-
\n
ficient assets to pay all employee benefits relating to em-
\n
ployee service in the current and prior periods. Such plans
\n
are usually aimed to supplement pension benefits due to
\n
employees post-employment. The related costs are rec-
\n
ognized through profit or loss on the basis of the amount
\n
of contributions paid in the period.
\n\n
Termination benefits
\n
Liabilities for benefits due to employees for the early ter-
\n
mination of employee service arise out of the Group\u2019s de-
\n
cision to terminate an employee\u2019s employment before the
\n
normal retirement date or an employee\u2019s decision to ac-
\n
cept an offer of benefits in exchange for the termination
\n
of employment. The event that gives rise to an obligation is
\n
the termination of employment rather than employee ser-
\n
vice. Termination
\n
benefits are recognized at the earlier of
\n
the following dates:
\n
\u2022 when the entity can no longer withdraw its offer of ben-
\n
efits; and
\n
\u2022 when the entity recognizes a cost for a restructuring
\n
that is within the scope of IAS 37 and involves the pay-
\n
ment of termination benefits.
\n
The liabilities are measured on the basis of the nature of
\n
the employee benefits. More specifically, when the bene-
\n
fits represent an enhancement of other post-employment
\n
benefits, the associated liability is measured in accordance
\n
with the rules governing that type of benefits. Otherwise, if
\n
the termination benefits due to employees are expected to
\n
be settled wholly before 12 months of the close of the pe-
\n
riod in which the benefits are recognized, the entity mea-
\n
sures the liability in accordance with the requirements for
\n
short-term employee benefits; if they are not expected to
\n
be settled wholly before 12 months of the close of period
\n
in which the benefits are recognized, the entity measures
\n
the liability in accordance with the requirements for other
\n
long-term employee benefits.
\n

\n

\n\n\n
Share-based payments
\n
The Group undertakes share-based payment transactions
\n
settled with equity instruments as part of the remunera-
\n
tion policy adopted for the Chief Executive Officer/General
\n
Manager and for key management personnel.
\n
The most recent long-term incentive plans provide for
\n
the grant to recipients of an incentive represented by an
\n
equity component (settled with equity instruments) and
\n
a monetary component (paid in cash), which will accrue if
\n
specific conditions are met. The monetary component is
\n
classified as a cash-settled transaction if it is based on the
\n
price (or value) of the equity instruments of the company
\n
that issued the plan or, in other cases, as another long-
\n
term employee benefit.
\n
In order to settle the equity component through the bonus
\n
award of Enel shares, a program for the purchase of trea-
\n
sury shares to support these plans was approved. For more
\n
details on share-based incentive plans, please see note 53
\n
\u201cShare-based payments\u201d.
\n
For the equity component, the Group recognizes the ser-
\n
vices rendered by employees as personnel expenses over
\n
the period in which the conditions for remaining in service
\n
and for achieving certain results must be satisfied (vesting
\n
period) and indirectly estimates their value, and the corre-
\n
sponding increase in a specific equity item, on the basis
\n
of the fair value of the equity instruments (i.e., the issuer
\n
shares) at the grant date. This fair value is based on the ob-
\n
servable market price of the share, taking account of the
\n
terms and conditions under which the shares were grant-
\n
ed (with the exception of vesting conditions excluded from
\n
the measurement of fair value).
\n
The overall expense recognized is adjusted at each report-
\n
ing date until the vesting date to reflect the best estimate
\n
available to the Group of the number of equity instru-
\n
ments for which the service and performance conditions
\n
other than market conditions will be satisfied, so that the
\n
amount recognized at the end is based on the effective
\n
number of equity instruments that satisfy the service and
\n
performance conditions other than market conditions at
\n
the vesting date.
\n
No expense is recognized for awards which ultimately do
\n
not vest because the performance conditions other than
\n
market conditions and/or the service conditions have not
\n
been satisfied. Conversely, the transactions are consid-
\n
ered to have vested irrespective of whether the market or
\n
non-vesting conditions are satisfied, provided that all oth-
\n
er vesting conditions are met.
\n
If the incentive based on equity instruments is paid in cash,
\n

\n\n

\n\n

\n\n

\n

\n

\n\n

\n\n
the Group recognizes the services rendered by employ-
\n
ees as personnel expenses over the vesting period and a
\n
corresponding liability measured at the fair value of the li-
\n
ability incurred. Subsequently, and until its extinction, the
\n
liability is remeasured at fair value at each reporting date,
\n
considering the best possible estimate of the incentive
\n
that will vest, with changes in fair value recognized under
\n
personnel expenses. If the right to receive the monetary
\n
incentive does not vest because one or more conditions
\n
are not met, the related liability is reversed.
\n

\n\n

\n\n\n

\n
Provisions for risks and charges
\n
Provisions are recognized where there is a legal or con-
\n
structive obligation as a result of a past event at the end
\n
of the reporting period, the settlement of which is expect-
\n
ed to result in an outflow of resources whose amount can
\n
be reliably estimated. Where the impact is significant, the
\n
accruals are determined by discounting expected future
\n
cash flows using a pre-tax discount rate that reflects the
\n
current market assessment of the time value of money
\n
and, if applicable, the risks specific to the liability.
\n
If the provision is discounted, the periodic adjustment of
\n
the present value for the time factor is recognized as a fi-
\n
nancial expense.
\n
When the Group expects some or all charges to be reim-
\n
bursed, the reimbursement is recognized as a separate
\n
asset, but only when the reimbursement is virtually certain.
\n\n
Where the liability relates to decommissioning and/or site
\n
restoration in respect of property, plant and equipment,
\n
the initial recognition of the provision is made against the
\n
related asset and the expense is then recognized in profit
\n
or loss through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of
\n
nuclear waste and other radioactive materials, the provi-
\n
sion is recognized against the related operating costs.
\n

\n\n
A liability for restructuring refers to a program planned
\n
and controlled by management that materially changes
\n
the scope of a business undertaken by the Group or the
\n
manner in which the business is conducted. Such a liabil-
\n
ity is recognized when a constructive obligation is estab-
\n
lished, i.e., when the Group has approved a detailed formal
\n
restructuring plan and has started to implement the plan
\n
or has announced its main features to those affected by it.
\n
Provisions do not include liabilities in respect of uncertain
\n
income tax treatments that are recognized as tax liabilities.
\n
The Group could provide a warranty in connection with
\n
the sale of a product (whether a good or service) from
\n
contracts with customers in the scope of IFRS 15, in ac-
\n
cordance with the contract, the law or its customary busi-
\n
ness practices. In this case, the Group assesses whether
\n
the warranty provides the customer with assurance that
\n
the related product will function as the parties intended
\n
because it complies with agreed-upon specifications or
\n
whether the warranty provides the customer with a service
\n
in addition to the assurance that the product complies
\n
with agreed-upon specifications.
\n
After the assessment, if the Group establishes that an
\n
assurance warranty is provided, it recognizes a separate
\n
warranty liability and corresponding expense when trans-
\n
ferring the product to the customer, as additional costs of
\n
providing goods or services, without attributing any of the
\n
transaction price (and therefore revenue) to the warranty.
\n
The liability is measured and presented as a provision.
\n
Otherwise, if the Group determines that a service warran-
\n
ty is provided, it accounts for the promised warranty as a
\n
performance obligation in accordance with IFRS 15, recog-
\n
nizing the contract liability as revenue over the period the
\n
warranty service is provided and the costs associated as
\n
they are incurred.
\n
Finally,
\n
if the warranty includes both an assurance element
\n
and a service element and the Group cannot reasonably
\n
account for them separately, then it accounts for both of
\n
the warranties together as a single performance obliga-
\n
tion.
\n
In the case of contracts in which the unavoidable costs of
\n
meeting the obligations under the contract exceed the
\n
economic benefits expected to be received under it (oner-
\n
ous contracts), the Group recognizes a provision as the
\n
lower of the excess of unavoidable costs of meeting the
\n
obligations (i.e., costs that relate directly to the contract,
\n
whether incremental or resulting from an allotment of oth-
\n
er costs) under the contract over the economic benefits
\n
expected to be received under it and any compensation or
\n
penalty arising from failure to fulfil it.
\n
Changes in estimates of accruals to the provisions ad-
\n
dressed here are recognized through profit or loss in the
\n
period in which the changes occur, with the exception of
\n
those in the costs of decommissioning, retiring and/or res-
\n
toration resulting from changes in the timetable and costs
\n
necessary to extinguish the obligation or from a change
\n
in the discount rate. These changes increase or decrease
\n
the carrying amount of the related assets and are taken to
\n
profit or loss through depreciation. Where they increase
\n
the carrying amount of the assets, it is also determined
\n
whether the new carrying amount of the assets is fully re-
\n
coverable. If this is not the case, a loss equal to the unre-
\n
coverable amount is recognized through profit or loss.
\n
Decreases in estimates are recognized up to the carrying
\n
amount of the assets. Any excess is recognized immedi-
\n
ately in profit or loss.
\n
For more information on the estimation criteria adopted
\n
in determining provisions for retiring and/or restoration of
\n
property, plant and equipment, especially those associated
\n
with decommissioning nuclear power plants and storage
\n
of waste fuel and other radioactive materials, please see
\n
note 2.1 \u201cUse of estimates and management judgment\u201d.
\n

\n

\n

\n\n\n
Revenue from contracts with customers
\n
The Group recognizes revenue from contracts with cus-
\n
tomers at an amount that reflects the consideration at
\n

\n\n

\n\n

\n

\n

\n\n

\n

\n

\n
which the Group expects to be entitled in exchange for
\n
those goods or services, using the five-step model envis-
\n
aged by IFRS 15:
\n
\u2022 identify the contract with the customer (step 1) as from
\n
when the contract is legally enforceable. If the criteria en-
\n
visaged for step 1 are not met, any consideration received
\n
from the customer is generally recognized as an advance;
\n
\u2022 identify the performance obligations in the contract (step
\n
2), that is, all goods or services promised in the contract,
\n
separating them into performance obligations to account
\n
for separately, if they are both capable of being distinct
\n
and distinct within the context of the contract, or, as an
\n
exception, as a single performance obligation, if they are
\n
a series of distinct goods or services that are substantially
\n
the same and that have the same pattern of transfer to
\n
the customer over time.
\n\n
For each distinct good or service identified, the Group
\n
determines whether it acts as a principal or agent. When
\n
the Group acts as agent, it recognizes revenue (corre-
\n
sponding to any fee or commission) on a net basis;
\n

\n\n
\u2022 determine the transaction price at inception of the con-
\n
tract (step 3) considering:
\n
\u2013 the amount of consideration to which the Group ex-
\n
pects to be entitled in exchange for transferring goods
\n
or services to a customer, excluding amounts collected
\n
on behalf of third parties (e.g., some sale taxes and val-
\n
ue-added taxes);
\n\n
\u2013 variable consideration, non-cash consideration re-
\n
ceived from a customer, consideration payable to a
\n

\n\n
customer and a significant financing component. The
\n
transaction price is updated each reporting period for
\n
any changes in circumstances;
\n
\u2022 allocate the transaction price (step 4) at contract incep-
\n
tion to each separate performance obligation, including
\n
any option to acquire additional goods or services that
\n
represents a material right (deferring the relative revenue
\n
until those future goods or services are transferred or
\n
the option expires), generally on the basis of the relative
\n
stand-alone selling price of each distinct good or service
\n
promised in the contract;
\n\n
\u2022 recognize revenue (step 5), when (or as) each perfor-
\n
mance obligation is satisfied by transferring the promised
\n
good or service to the customer.
\n

\n\n
The Group does not disclose the information about the
\n
remaining performance obligations in existing contracts if
\n
the performance obligation is part of a contract that has
\n
an original expected duration of one year or less and if the
\n
Group recognizes revenue in the amount to which it has a
\n
right to invoice the customer.
\n
More information on the application of this revenue recog-
\n
nition model is provided in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and in note 11.a \u201cRevenue from
\n
sales and services\u201d.
\n

\n\n
Other revenue
\n
The Group recognizes revenue other than that deriving
\n
from contracts with customers mainly referring to:
\n\n
\u2022 revenue from the sale of energy commodities based on
\n
contracts with physical settlement, which do not qualify
\n
for the own use exemption and therefore is recognized
\n
at FVTPL in accordance with IFRS 9;
\n

\n\n
\u2022 changes in the fair value of settled contracts to sell ener-
\n
gy commodities with physical settlement, which do not
\n
qualify for the own use exemption and therefore are rec-
\n
ognized at FVTPL in accordance with IFRS 9;
\n
\u2022 operating lease revenue accounted for on an accrual
\n
basis in accordance with the substance of the relevant
\n
lease agreement.
\n\n
Other operating income
\n
Other operating income primarily includes gains on dis-
\n
posal of assets that are not an output of the Group\u2019s ordi-
\n
nary activities and government grants.
\n
Government grants, including non-monetary grants at fair
\n
value, are recognized where there is reasonable assurance
\n
that they will be received and that the Group will comply
\n
with all conditions attaching to them as set by the govern-
\n
ment, government agencies and similar bodies whether
\n
local, national or international.
\n
When loans are provided by governments at a below-mar-
\n
ket rate of interest, the benefit is regarded as a govern-
\n
ment grant. The loan is initially recognized and measured
\n
at fair value and the government grant is measured as the
\n
difference between the initial carrying amount of the loan
\n
and the funds received. The loan is subsequently measured
\n
in accordance with the requirements for financial liabilities.
\n
Government grants are recognized in profit or loss on a
\n
systematic basis over the periods in which the Group rec-
\n
ognizes as expenses the costs that the grants are intended
\n
to compensate.
\n
Where the Group receives government grants in the form
\n
of a transfer of a non-monetary asset for the use of the
\n
Group, it accounts for both the grant and the asset at the
\n
fair value of the non-monetary asset received at the date
\n
of the transfer.
\n
Capital grants, including non-monetary grants at fair val-
\n
ue, i.e., those received to purchase, build or otherwise ac-
\n
quire non-current assets (for example, an item of property,
\n
plant and equipment or an intangible asset), are deducted
\n
from the carrying amount of the asset and are recognized
\n
in profit or loss over the depreciable/amortizable life of
\n
the asset as a reduction in the depreciation/amortization
\n
charge. If there is insufficient information to enable ade-
\n
quate attribution to the fixed assets to which they refer,
\n
capital grants are recognized as deferred income under
\n
other liabilities, and credited to profit or loss on a system-
\n
atic basis over the useful life of the asset.
\n

\n\n

\n\n

\n

\n

\n\n

\n\n

\n

\n

\n

\n
Financial income and expense from derivatives
\n
Financial income and expense from derivatives include:
\n\n
\u2022 income and expense from derivatives measured at fair
\n
value through profit or loss on interest rate and currency
\n
risk;
\n

\n\n\n
\u2022 income and expense from fair value hedge derivatives
\n
on interest rate risk;
\n
\u2022 income and expense from cash flow hedge derivatives
\n
on interest rate and currency risks.
\n

\n\n
Other financial income and expense
\n
For all financial assets and liabilities measured at amortized
\n
cost and interest-bearing financial assets classified as at
\n
fair value through other comprehensive income, interest
\n
income and expense are recognized using the effective
\n
interest rate method.
\n
Interest income is recognized to the extent that it is prob-
\n
able that the economic benefits will flow to the Group and
\n
the amount can be reliably measured.
\n
Other financial income and expense include also changes
\n
in the fair value of financial instruments other than deriv-
\n
atives.
\n

\n\n

\n\n\n
Dividends
\n
Dividends are recognized when the unconditional right to
\n
receive payment is established.
\n
Dividends and interim dividends payable to the Parent\u2019s
\n
shareholders and non-controlling interests are recognized
\n
as changes in equity in the period in which they are ap-
\n
proved by the Shareholders\u2019 Meeting and the Board of Di-
\n
rectors, respectively.
\n

\n\n\n

\n
Income taxes
\n
Current income taxes
\n
Current income taxes for the year, which are recognized
\n
under \u201cIncome tax liabilities\u201d net of payments on account,
\n
or under \u201cTax assets\u201d where there is a credit balance, are
\n
determined using an estimate of taxable income and in
\n
conformity with the applicable regulations.
\n
Such liabilities and assets are determined using the tax
\n
rates and tax laws that are enacted or substantively en-
\n
acted by the end of the reporting period in the countries
\n
where taxable income has been generated.
\n
Current income taxes are recognized in profit or loss with
\n
the exception of current income taxes related to items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n\n
Deferred tax
\n
Deferred tax liabilities and assets are calculated on the
\n
temporary differences between the carrying amounts of
\n
liabilities and assets in the financial statements and their
\n
corresponding amounts recognized for tax purposes on
\n
the basis of tax rates in effect on the date the temporary
\n
difference will reverse, which is determined on the basis of
\n
tax rates that are enacted or substantively enacted as at
\n
the end of the reporting period.
\n
Deferred tax liabilities are recognized for all taxable tem-
\n
porary differences, except when such liability arises from
\n
the initial recognition of goodwill or in respect of taxable
\n
temporary differences associated with investments in sub-
\n
sidiaries, associates and joint ventures, when the Group
\n
can control the timing of the reversal of the temporary dif-
\n
ferences and it is probable that the temporary differences
\n
will not reverse in the foreseeable future.
\n
Deferred tax assets are recognized for all deductible tem-
\n
porary differences, the carry forward of tax losses and any
\n
unused tax credits. For more information concerning the
\n
recoverability of such assets, please see the appropriate
\n
section of the discussion of estimates.
\n
Deferred taxes and liabilities are recognized in profit or
\n
loss, with the exception of those in respect of items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n
Deferred tax assets and deferred tax liabilities are offset
\n
only if there is a legally enforceable right to offset current
\n
tax assets with current tax liabilities and when they relate
\n
to income taxes levied by the same taxation authority on
\n
either the same taxable entity or different taxable entities
\n
which intend either to settle current tax liabilities and as-
\n
sets on a net basis, or to realize the assets and settle the
\n
liabilities simultaneously, in each future period in which
\n
significant amounts of deferred tax liabilities or assets are
\n
expected to be settled or recovered.
\n

\n

\n\n
Uncertainty over income tax treatments
\n
In defining \u201cuncertainty\u201d, it shall be considered whether a
\n
particular tax treatment will be accepted by the relevant
\n
taxation authority. If it is deemed probable that the tax
\n
treatment will be accepted (where the term \u201cprobable\u201d is
\n
defined as \u201cmore likely than not\u201d), then the Group recog-
\n
nizes and measures its current/deferred tax asset or liabil-
\n
ities applying the requirements in IAS 12.
\n
Conversely, when the Group feels that it is not likely that
\n
the taxation authority will accept the tax treatment for
\n
income tax purposes, the Group reflects the uncertainty
\n
in the manner that best predicts the resolution of the un-
\n
certain tax treatment. The Group determines whether to
\n
consider each uncertain tax treatment separately or to-
\n
gether with one or more other uncertain tax treatments
\n
based on which approach provides better predictions of
\n
the resolution of the uncertainty. In assessing whether and
\n
how the uncertainty affects the tax treatment, the Group
\n
assumes that a taxation authority will accept or not an un-
\n
certain tax treatment supposing that the taxation authority
\n

\n

\n\n

\n\n

\n\n
will examine amounts it has a right to examine and have full
\n
knowledge of all related information when making those
\n
examinations. The Group reflects the effect of uncertainty
\n
in accounting for current and deferred tax using the ex-
\n
pected value or the most likely amount, whichever method
\n
better predicts the resolution of the uncertainty.
\n
Since uncertain income tax positions meet the definition
\n
of income taxes, the Group presents uncertain tax liabili-
\n
ties/assets as current tax liabilities/assets or deferred tax
\n
liabilities/assets.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag58": { "value": "\n
Related parties
\n
Related parties are mainly those that share the same con-
\n
trolling entity with Enel SpA, the companies that directly or
\n
indirectly are controlled by Enel SpA, the associates or joint
\n
ventures (including their subsidiaries) of Enel SpA, or the
\n
associates or joint ventures (including their subsidiaries) of
\n
any Group company. Related parties also include entities
\n
that operate post-employment benefit plans for employ-
\n
ees of Enel SpA or its associates (specifically, the FOPEN
\n
and FONDENEL pension funds), as well as the members
\n
of the boards of statutory auditors, and their immediate
\n
family, and the key management personnel, and their im-
\n
mediate family, of Enel SpA and its subsidiaries. Key man-
\n
agement personnel comprises management personnel
\n
who have the power and direct or indirect responsibility
\n
for the planning, management and control of the activities
\n
of the Company. They include directors (whether executive
\n
or not).
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithRelatedPartiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag36": { "value": "\n
Subsidiaries
\n
Subsidiaries are all entities over which the Group has con-
\n
trol. The Group controls an entity, regardless of the nature
\n
of the formal relationship between them, when it is ex-
\n
posed, or has rights, to variable returns deriving from its
\n
involvement and has the ability, through the exercise of its
\n
power over the investee, to affect its returns.
\n

\n\n
The figures of the subsidiaries are consolidated on a full
\n
line-by-line basis as from the date control is acquired until
\n
such control ceases.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag29": { "value": "\n

\n

\n
Consolidation procedures
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2022 in accordance with the accounting
\n
policies adopted by the Group.
\n
If a subsidiary uses different accounting policies from
\n
those adopted in preparing the consolidated financial
\n
statements for similar transactions and facts in similar cir-
\n
cumstances, appropriate adjustments are made to ensure
\n
conformity with Group accounting policies.
\n
Assets, liabilities, revenue and expenses of a subsidiary ac-
\n
quired or disposed of during the year are included in or
\n
excluded from the consolidated financial statements, re-
\n
spectively, from the date the Group gains control or until
\n
the date the Group ceases to control the subsidiary.
\n\n
Profit or loss for the year and the other comprehensive
\n
income are attributed to the owners of the Parent and
\n
non-controlling interests, even if this results in a loss for
\n
non-controlling interests.
\n
All intercompany assets and liabilities, equity item, revenue,
\n
expenses and cash flows relating to transactions between
\n
entities of the Group are eliminated in full.
\n
Changes in ownership interest in subsidiaries that do not
\n
result in loss of control are accounted for as equity trans-
\n
actions, with the carrying amounts of the controlling and
\n
non-controlling interests adjusted to reflect changes in
\n
their interests in the subsidiary. Any difference between
\n
the amount to which non-controlling interests are adjust-
\n
ed and the fair value of the consideration paid or received
\n
is recognized in consolidated equity.
\n

\n\n\n
When the Group ceases to have control over a subsidiary,
\n
any interest retained in the entity is remeasured to its fair
\n
value, recognized through profit or loss, at the date when
\n
control is lost, recognizing any gain or loss from the loss
\n
of control through profit or loss. In addition, any amounts
\n
previously recognized in other comprehensive income in
\n
respect of the former subsidiary are accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag43": { "value": "\n
Profit or loss for the year and the other comprehensive
\n
income are attributed to the owners of the Parent and
\n
non-controlling interests, even if this results in a loss for
\n
non-controlling interests.
\n
All intercompany assets and liabilities, equity item, revenue,
\n
expenses and cash flows relating to transactions between
\n
entities of the Group are eliminated in full.
\n
Changes in ownership interest in subsidiaries that do not
\n
result in loss of control are accounted for as equity trans-
\n
actions, with the carrying amounts of the controlling and
\n
non-controlling interests adjusted to reflect changes in
\n
their interests in the subsidiary. Any difference between
\n
the amount to which non-controlling interests are adjust-
\n
ed and the fair value of the consideration paid or received
\n
is recognized in consolidated equity.
\n

\n\n
The carrying amount of non-controlling interests was de-
\n
termined in proportion to the interest held by non-con-
\n
trolling shareholders in the net assets. In the case of busi-
\n
ness combinations achieved in stages, at the date of ac-
\n
quisition any adjustment to the fair value of the net assets
\n
acquired previously was recognized in equity; the amount
\n
of goodwill was determined for each transaction separate-
\n
ly based on the fair values of the acquiree\u2019s net assets at
\n
the date of each exchange transaction.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag52": { "value": "\n
When the Group ceases to have control over a subsidiary,
\n
any interest retained in the entity is remeasured to its fair
\n
value, recognized through profit or loss, at the date when
\n
control is lost, recognizing any gain or loss from the loss
\n
of control through profit or loss. In addition, any amounts
\n
previously recognized in other comprehensive income in
\n
respect of the former subsidiary are accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Equity instruments
\n
This category includes mainly equity investments in other
\n
entities irrevocably designated as such upon initial recog-
\n
nition.
\n
Gains and losses on these financial assets are never reclas-
\n
sified to profit or loss. The Group may transfer the cumula-
\n
tive gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of the
\n
cost of the investment.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsOtherThanInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag32": { "value": "\n

\n\n

\n\n
Investments in associates and joint ventures
\n
An associate is an entity over which the Group has signifi-
\n
cant influence. Significant influence is the power to partic-
\n
ipate in decisions concerning the financial and operating
\n
policies of the investee without having control or joint con-
\n
trol over the investee.
\n
A joint venture is a joint arrangement over which the Group
\n
exercises joint control and has rights to the net assets of
\n
the arrangement. Joint control is the sharing of control of
\n
an arrangement, whereby decisions about the relevant ac-
\n
tivities require unanimous consent of the parties sharing
\n
control.
\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method.
\n
Under the equity method, these investments are initial-
\n
ly recognized at cost and any goodwill arising from the
\n
difference between the cost of the investment and the
\n
Group\u2019s share of the net fair value of the investee\u2019s identifi-
\n
able assets and liabilities at the acquisition date is included
\n
in the carrying amount of the investment.
\n
After the acquisition date, their carrying amount is adjust-
\n
ed to recognize changes in the Group\u2019s share of profit or
\n
loss of the associate or joint venture in Group profit or loss.
\n
Adjustments to the carrying amount may also be neces-
\n
sary following changes in the Group\u2019s share in the asso-
\n
ciate or joint venture as a result of changes in the other
\n
comprehensive income of the investee. The Group\u2019s share
\n
of these changes is recognized in the Group\u2019s other com-
\n
prehensive income.
\n
Distributions received from joint venture and associates
\n
reduce the carrying amount of the investments.
\n
Gains and losses resulting from transactions between the
\n
Group and the associates or joint ventures are eliminated
\n
to the extent of the interest in the associate or joint ven-
\n
ture.
\n
The financial statements of the associates or joint ventures
\n
are prepared for the same reporting period as the Group.
\n
When necessary, adjustments are made to bring the ac-
\n
counting policies in line with those of the Group.
\n
After application of the equity method, the Group deter-
\n
mines whether it is necessary to recognize an impairment
\n
loss on its investment in an associate or joint venture. If
\n
there is objective evidence of a loss of value, the entire
\n
carrying amount of the investment undergoes impairment
\n
testing pursuant to IAS 36 as a single asset. For more in-
\n
formation on impairment, please see the section \u201cImpair-
\n
ment of non-financial assets\u201d in note 2.1 \u201cUse of estimates
\n
and management judgment\u201d.
\n
If the investment ceases to be an associate or a joint ven-
\n
ture, the Group recognizes any retained investment at its
\n
fair value, through profit or loss. Any amounts previously
\n
recognized in other comprehensive income in respect of
\n
the former associate or joint venture are accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\n
If the ownership interest in an associate or a joint venture is
\n
reduced, but the Group continues to exercise a significant
\n
influence or joint control, the Group continues to apply
\n
the equity method and the share of the gain or loss that
\n
had previously been recognized in other comprehensive
\n
income relating to that reduction is accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n

\n\n

\n

\n\n

\n

\n\n

\n\n

\n\n
When a portion of an investment in an associate or joint
\n
venture meets the criteria to be classified as held for sale,
\n
any retained portion of an investment in the associate or
\n
joint venture that has not been classified as held for sale
\n
is accounted for using the equity method until disposal of
\n
the portion classified as held for sale takes place.
\n
Joint operations are joint arrangements whereby the
\n
Group, which holds joint control, has rights to the assets
\n
and obligations for the liabilities relating to the arrange-
\n
ment. For each joint operation, the Group recognized as-
\n
sets, liabilities, costs and revenue on the basis of the pro-
\n
visions of the arrangement rather than the interest held.
\n
Where there is an increase in the interest in a joint ar-
\n
rangement that meets the definition of a business:
\n
\u2022 if the Group acquires control, and had rights over the
\n
assets and obligations for the liabilities of the joint ar-
\n
rangement immediately before the acquisition date,
\n
then the transaction represents a business combination
\n
achieved in stages. Consequently, the Group applies the
\n
requirements for a business combination achieved in
\n
stages, including the remeasurement of the interest it
\n
held previously in the joint operation at its fair value at
\n
the acquisition date;
\n
\u2022 if the Group obtains joint control (i.e., it already had an
\n
interest in a joint operation without holding joint control),
\n
the interest previously held in the joint operation shall
\n
not be remeasured.
\n
For more information on the Group\u2019s investments in asso-
\n
ciates and joint ventures, please see note 26 \u201cEquity-ac-
\n
counted investments\u201d.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag46": { "value": "\n

\n\n
Investments in associates and joint ventures
\n
An associate is an entity over which the Group has signifi-
\n
cant influence. Significant influence is the power to partic-
\n
ipate in decisions concerning the financial and operating
\n
policies of the investee without having control or joint con-
\n
trol over the investee.
\n
A joint venture is a joint arrangement over which the Group
\n
exercises joint control and has rights to the net assets of
\n
the arrangement. Joint control is the sharing of control of
\n
an arrangement, whereby decisions about the relevant ac-
\n
tivities require unanimous consent of the parties sharing
\n
control.
\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method.
\n
Under the equity method, these investments are initial-
\n
ly recognized at cost and any goodwill arising from the
\n
difference between the cost of the investment and the
\n
Group\u2019s share of the net fair value of the investee\u2019s identifi-
\n
able assets and liabilities at the acquisition date is included
\n
in the carrying amount of the investment.
\n
After the acquisition date, their carrying amount is adjust-
\n
ed to recognize changes in the Group\u2019s share of profit or
\n
loss of the associate or joint venture in Group profit or loss.
\n
Adjustments to the carrying amount may also be neces-
\n
sary following changes in the Group\u2019s share in the asso-
\n
ciate or joint venture as a result of changes in the other
\n
comprehensive income of the investee. The Group\u2019s share
\n
of these changes is recognized in the Group\u2019s other com-
\n
prehensive income.
\n
Distributions received from joint venture and associates
\n
reduce the carrying amount of the investments.
\n
Gains and losses resulting from transactions between the
\n
Group and the associates or joint ventures are eliminated
\n
to the extent of the interest in the associate or joint ven-
\n
ture.
\n
The financial statements of the associates or joint ventures
\n
are prepared for the same reporting period as the Group.
\n
When necessary, adjustments are made to bring the ac-
\n
counting policies in line with those of the Group.
\n
After application of the equity method, the Group deter-
\n
mines whether it is necessary to recognize an impairment
\n
loss on its investment in an associate or joint venture. If
\n
there is objective evidence of a loss of value, the entire
\n
carrying amount of the investment undergoes impairment
\n
testing pursuant to IAS 36 as a single asset. For more in-
\n
formation on impairment, please see the section \u201cImpair-
\n
ment of non-financial assets\u201d in note 2.1 \u201cUse of estimates
\n
and management judgment\u201d.
\n
If the investment ceases to be an associate or a joint ven-
\n
ture, the Group recognizes any retained investment at its
\n
fair value, through profit or loss. Any amounts previously
\n
recognized in other comprehensive income in respect of
\n
the former associate or joint venture are accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\n
If the ownership interest in an associate or a joint venture is
\n
reduced, but the Group continues to exercise a significant
\n
influence or joint control, the Group continues to apply
\n
the equity method and the share of the gain or loss that
\n
had previously been recognized in other comprehensive
\n
income relating to that reduction is accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n

\n\n

\n

\n\n

\n\n
When a portion of an investment in an associate or joint
\n
venture meets the criteria to be classified as held for sale,
\n
any retained portion of an investment in the associate or
\n
joint venture that has not been classified as held for sale
\n
is accounted for using the equity method until disposal of
\n
the portion classified as held for sale takes place.
\n
Joint operations are joint arrangements whereby the
\n
Group, which holds joint control, has rights to the assets
\n
and obligations for the liabilities relating to the arrange-
\n
ment. For each joint operation, the Group recognized as-
\n
sets, liabilities, costs and revenue on the basis of the pro-
\n
visions of the arrangement rather than the interest held.
\n
Where there is an increase in the interest in a joint ar-
\n
rangement that meets the definition of a business:
\n
\u2022 if the Group acquires control, and had rights over the
\n
assets and obligations for the liabilities of the joint ar-
\n
rangement immediately before the acquisition date,
\n
then the transaction represents a business combination
\n
achieved in stages. Consequently, the Group applies the
\n
requirements for a business combination achieved in
\n
stages, including the remeasurement of the interest it
\n
held previously in the joint operation at its fair value at
\n
the acquisition date;
\n
\u2022 if the Group obtains joint control (i.e., it already had an
\n
interest in a joint operation without holding joint control),
\n
the interest previously held in the joint operation shall
\n
not be remeasured.
\n
For more information on the Group\u2019s investments in asso-
\n
ciates and joint ventures, please see note 26 \u201cEquity-ac-
\n
counted investments\u201d.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociates", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag54": { "value": "\n
Investments in associates and joint ventures
\n
An associate is an entity over which the Group has signifi-
\n
cant influence. Significant influence is the power to partic-
\n
ipate in decisions concerning the financial and operating
\n
policies of the investee without having control or joint con-
\n
trol over the investee.
\n
A joint venture is a joint arrangement over which the Group
\n
exercises joint control and has rights to the net assets of
\n
the arrangement. Joint control is the sharing of control of
\n
an arrangement, whereby decisions about the relevant ac-
\n
tivities require unanimous consent of the parties sharing
\n
control.
\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method.
\n
Under the equity method, these investments are initial-
\n
ly recognized at cost and any goodwill arising from the
\n
difference between the cost of the investment and the
\n
Group\u2019s share of the net fair value of the investee\u2019s identifi-
\n
able assets and liabilities at the acquisition date is included
\n
in the carrying amount of the investment.
\n
After the acquisition date, their carrying amount is adjust-
\n
ed to recognize changes in the Group\u2019s share of profit or
\n
loss of the associate or joint venture in Group profit or loss.
\n
Adjustments to the carrying amount may also be neces-
\n
sary following changes in the Group\u2019s share in the asso-
\n
ciate or joint venture as a result of changes in the other
\n
comprehensive income of the investee. The Group\u2019s share
\n
of these changes is recognized in the Group\u2019s other com-
\n
prehensive income.
\n
Distributions received from joint venture and associates
\n
reduce the carrying amount of the investments.
\n
Gains and losses resulting from transactions between the
\n
Group and the associates or joint ventures are eliminated
\n
to the extent of the interest in the associate or joint ven-
\n
ture.
\n
The financial statements of the associates or joint ventures
\n
are prepared for the same reporting period as the Group.
\n
When necessary, adjustments are made to bring the ac-
\n
counting policies in line with those of the Group.
\n
After application of the equity method, the Group deter-
\n
mines whether it is necessary to recognize an impairment
\n
loss on its investment in an associate or joint venture. If
\n
there is objective evidence of a loss of value, the entire
\n
carrying amount of the investment undergoes impairment
\n
testing pursuant to IAS 36 as a single asset. For more in-
\n
formation on impairment, please see the section \u201cImpair-
\n
ment of non-financial assets\u201d in note 2.1 \u201cUse of estimates
\n
and management judgment\u201d.
\n
If the investment ceases to be an associate or a joint ven-
\n
ture, the Group recognizes any retained investment at its
\n
fair value, through profit or loss. Any amounts previously
\n
recognized in other comprehensive income in respect of
\n
the former associate or joint venture are accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\n
If the ownership interest in an associate or a joint venture is
\n
reduced, but the Group continues to exercise a significant
\n
influence or joint control, the Group continues to apply
\n
the equity method and the share of the gain or loss that
\n
had previously been recognized in other comprehensive
\n
income relating to that reduction is accounted for as if
\n
the Group had directly disposed of the related assets or
\n
liabilities.
\n

\n

\n\n
When a portion of an investment in an associate or joint
\n
venture meets the criteria to be classified as held for sale,
\n
any retained portion of an investment in the associate or
\n
joint venture that has not been classified as held for sale
\n
is accounted for using the equity method until disposal of
\n
the portion classified as held for sale takes place.
\n
Joint operations are joint arrangements whereby the
\n
Group, which holds joint control, has rights to the assets
\n
and obligations for the liabilities relating to the arrange-
\n
ment. For each joint operation, the Group recognized as-
\n
sets, liabilities, costs and revenue on the basis of the pro-
\n
visions of the arrangement rather than the interest held.
\n
Where there is an increase in the interest in a joint ar-
\n
rangement that meets the definition of a business:
\n
\u2022 if the Group acquires control, and had rights over the
\n
assets and obligations for the liabilities of the joint ar-
\n
rangement immediately before the acquisition date,
\n
then the transaction represents a business combination
\n
achieved in stages. Consequently, the Group applies the
\n
requirements for a business combination achieved in
\n
stages, including the remeasurement of the interest it
\n
held previously in the joint operation at its fair value at
\n
the acquisition date;
\n
\u2022 if the Group obtains joint control (i.e., it already had an
\n
interest in a joint operation without holding joint control),
\n
the interest previously held in the joint operation shall
\n
not be remeasured.
\n
For more information on the Group\u2019s investments in asso-
\n
ciates and joint ventures, please see note 26 \u201cEquity-ac-
\n
counted investments\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag48": { "value": "\n
Translation of foreign currency items
\n
Transactions in currencies other than the functional cur-
\n
rency are initially recognized at the spot exchange rate
\n
prevailing on the date of the transaction.
\n
Monetary assets and liabilities denominated in a foreign
\n
currency other than the functional currency are subse-
\n
quently translated using the closing exchange rate (i.e., the
\n
spot exchange rate prevailing at the reporting date).
\n
Non-monetary assets and liabilities denominated in for-
\n
eign currency that are recognized at historical cost are
\n
translated using the exchange rate at the date of the
\n
transaction. Non-monetary assets and liabilities in foreign
\n
currency measured at fair value are translated using the
\n
exchange rate at the date the fair value was determined.
\n
Any exchange differences are recognized through profit or
\n
loss.
\n
In determining the spot exchange rate to use on initial rec-
\n
ognition of the related asset, expense or income (or part
\n
of it) on the derecognition of a non-monetary asset or
\n
non-monetary liability relating to advance consideration in
\n
foreign currency paid or received, the date of the transac-
\n
tion is the date on which the Group initially recognizes the
\n
non-monetary asset or non-monetary liability associated
\n
with the advance consideration.
\n
If there are multiple advance payments or receipts, the
\n
Group determines the transaction date for each payment
\n
or receipt of advance consideration.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag34": { "value": "\n
Translation of financial statements
\n
denominated in a foreign currency
\n
For the purposes of the consolidated financial statements,
\n
all revenue, expenses, assets and liabilities are stated in
\n
euro, which is the presentation currency of the Parent.
\n
In order to prepare the consolidated financial statements,
\n
the financial statements of consolidated companies with
\n
functional currencies other than the presentation curren-
\n
cy used in the consolidated financial statements are trans-
\n
lated into euros by applying the closing exchange rate to
\n
the assets and liabilities, including goodwill and consolida-
\n
tion adjustments, and the average exchange rate for the
\n
period to the income statement items on the condition it
\n
approximates the exchange rates prevailing at the date of
\n
the respective transactions.
\n
Any resulting exchange gains or losses are recognized as
\n
a separate component of equity in a special reserve. The
\n
gains and losses are recognized proportionately in the
\n
income statement on the disposal (partial or total) of the
\n
subsidiary.
\n
When the functional currency of a consolidated company
\n
is the currency of a hyperinflationary economy, the Group
\n
restates the financial statements in accordance with IAS
\n
29 before applying the specific conversion method set out
\n
below.
\n
In order to consider the impact of hyperinflation on the
\n
local currency exchange rate, the financial position and
\n
performance (i.e., assets, liabilities, equity items, revenue
\n
and expenses) of a company whose functional currency is
\n
the currency of a hyperinflationary economy are translated
\n
into the Group\u2019s presentation currency (the euro) using the
\n
exchange rate prevailing at the reporting date, except for
\n
comparative amounts presented in the previous year\u2019s fi-
\n
nancial statements which are not adjusted for subsequent
\n
changes in the price level or subsequent changes in ex-
\n
change rates.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag26": { "value": "\n

\n\n
Business combinations
\n
Business combinations initiated before January 1, 2010
\n
and completed within that financial year are recognized on
\n
the basis of IFRS 3 (2004).
\n
Such business combinations were recognized using the
\n
purchase method, where the purchase cost is equal to the
\n
fair value at the date of the exchange of the assets ac-
\n
quired and the liabilities incurred or assumed, plus costs
\n
directly attributable to the acquisition. This cost was allo-
\n
cated by recognizing the assets, liabilities and identifiable
\n

\n\n

\n\n

\n\n

\n
contingent liabilities of the acquired company at their fair
\n
values. Any positive difference between the cost of the
\n
acquisition and the fair value of the net assets acquired
\n
attributable to the owners of the Parent was recognized
\n
as goodwill. If the difference is negative, it is recognized
\n
through profit or loss.
\n\n
The carrying amount of non-controlling interests was de-
\n
termined in proportion to the interest held by non-con-
\n
trolling shareholders in the net assets. In the case of busi-
\n
ness combinations achieved in stages, at the date of ac-
\n
quisition any adjustment to the fair value of the net assets
\n
acquired previously was recognized in equity; the amount
\n
of goodwill was determined for each transaction separate-
\n
ly based on the fair values of the acquiree\u2019s net assets at
\n
the date of each exchange transaction.
\n

\n\n
Business combinations carried out as from January 1, 2010
\n
are recognized on the basis of IFRS 3 (2008), which is re-
\n
ferred to as IFRS 3 (Revised) hereafter.
\n
More specifically, business combinations are recognized
\n
using the acquisition method, where the purchase cost
\n
(the consideration transferred) is equal to the fair value at
\n
the purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments is-
\n
sued by the purchaser. The consideration transferred in-
\n
cludes the fair value of any asset or liability resulting from
\n
a contingent consideration arrangement.
\n
Costs directly attributable to the acquisition are recog-
\n
nized through profit or loss.
\n
The consideration transferred is allocated by recognizing
\n
the assets, liabilities and identifiable contingent liabili-
\n
ties of the acquired company at their fair values as at the
\n
acquisition date. The excess of the consideration trans-
\n
ferred, measured at fair value as at the acquisition date,
\n
the amount of any non-controlling interest in the acquiree
\n
plus the fair value of any equity interest in the acquiree
\n
previously held by the Group (in a business combination
\n
achieved in stages) over the net amount of the identifiable
\n
assets acquired and the liabilities incurred or assumed
\n
measured at fair value is recognized as goodwill. If the dif-
\n
ference is negative, the Group verifies whether it has cor-
\n
rectly identified all the assets acquired and liabilities as-
\n
sumed and reviews the procedures used to determine the
\n
amounts to recognize at the acquisition date. If after this
\n
assessment the fair value of the net assets acquired still
\n
exceeds the total consideration transferred, this excess
\n
represents the profit on a bargain purchase and is recog-
\n
nized through profit or loss.
\n
The carrying amount of non-controlling interests is deter-
\n
mined either in proportion to the interest held by non-con-
\n
trolling shareholders in the net identifiable assets of the
\n
acquiree or at their fair value as at the acquisition date.
\n
In the case of business combinations achieved in stages, at
\n
the date of acquisition of control the previously held equi-
\n
ty interest in the acquiree is remeasured to fair value and
\n
any positive or negative difference is recognized in profit
\n
or loss.
\n
Any contingent consideration is recognized at fair value at
\n
the acquisition date. Subsequent changes to the fair val-
\n
ue of the contingent consideration classified as an asset
\n
or a liability, or as a financial instrument within the scope
\n
of IFRS 9, are recognized in profit or loss. If the contin-
\n
gent consideration is not within the scope of IFRS 9, it is
\n
measured in accordance with the appropriate IFRS-EU.
\n
Contingent consideration that is classified as equity is not
\n
re-measured, and its subsequent settlement is accounted
\n
for within equity.
\n
If the fair values of the assets, liabilities and contingent li-
\n
abilities can only be calculated on a provisional basis, the
\n
business combination is recognized using such provisional
\n
values. Any adjustments resulting from the completion of
\n
the measurement process are recognized within 12 months
\n
of the date of acquisition, restating comparative figures.
\n

\n

\n\n

\n

\n\n

\n\n

\n\n
Goodwill
\n
Goodwill represents the future economic benefits arising
\n
from other assets acquired in a business combination that
\n
are not individually identified and separately recognized.
\n
For further details, please see the section of the account-
\n
ing policies \u201cBusiness combinations\u201d.
\n
Goodwill arising on the acquisition of subsidiaries is rec-
\n
ognized separately. After initial recognition, goodwill is not
\n
amortized, but is tested for impairment at least annually as
\n
part of the CGU to which it pertains.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU that is expect-
\n
ed to benefit from the synergies of the combination.
\n
Goodwill relating to equity investments in associates and
\n
joint venture is included in their carrying amount.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag45": { "value": "\n
Business combinations
\n
Business combinations initiated before January 1, 2010
\n
and completed within that financial year are recognized on
\n
the basis of IFRS 3 (2004).
\n
Such business combinations were recognized using the
\n
purchase method, where the purchase cost is equal to the
\n
fair value at the date of the exchange of the assets ac-
\n
quired and the liabilities incurred or assumed, plus costs
\n
directly attributable to the acquisition. This cost was allo-
\n
cated by recognizing the assets, liabilities and identifiable
\n

\n\n

\n
contingent liabilities of the acquired company at their fair
\n
values. Any positive difference between the cost of the
\n
acquisition and the fair value of the net assets acquired
\n
attributable to the owners of the Parent was recognized
\n
as goodwill. If the difference is negative, it is recognized
\n
through profit or loss.
\n\n
The carrying amount of non-controlling interests was de-
\n
termined in proportion to the interest held by non-con-
\n
trolling shareholders in the net assets. In the case of busi-
\n
ness combinations achieved in stages, at the date of ac-
\n
quisition any adjustment to the fair value of the net assets
\n
acquired previously was recognized in equity; the amount
\n
of goodwill was determined for each transaction separate-
\n
ly based on the fair values of the acquiree\u2019s net assets at
\n
the date of each exchange transaction.
\n

\n\n
Business combinations carried out as from January 1, 2010
\n
are recognized on the basis of IFRS 3 (2008), which is re-
\n
ferred to as IFRS 3 (Revised) hereafter.
\n
More specifically, business combinations are recognized
\n
using the acquisition method, where the purchase cost
\n
(the consideration transferred) is equal to the fair value at
\n
the purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments is-
\n
sued by the purchaser. The consideration transferred in-
\n
cludes the fair value of any asset or liability resulting from
\n
a contingent consideration arrangement.
\n
Costs directly attributable to the acquisition are recog-
\n
nized through profit or loss.
\n
The consideration transferred is allocated by recognizing
\n
the assets, liabilities and identifiable contingent liabili-
\n
ties of the acquired company at their fair values as at the
\n
acquisition date. The excess of the consideration trans-
\n
ferred, measured at fair value as at the acquisition date,
\n
the amount of any non-controlling interest in the acquiree
\n
plus the fair value of any equity interest in the acquiree
\n
previously held by the Group (in a business combination
\n
achieved in stages) over the net amount of the identifiable
\n
assets acquired and the liabilities incurred or assumed
\n
measured at fair value is recognized as goodwill. If the dif-
\n
ference is negative, the Group verifies whether it has cor-
\n
rectly identified all the assets acquired and liabilities as-
\n
sumed and reviews the procedures used to determine the
\n
amounts to recognize at the acquisition date. If after this
\n
assessment the fair value of the net assets acquired still
\n
exceeds the total consideration transferred, this excess
\n
represents the profit on a bargain purchase and is recog-
\n
nized through profit or loss.
\n
The carrying amount of non-controlling interests is deter-
\n
mined either in proportion to the interest held by non-con-
\n
trolling shareholders in the net identifiable assets of the
\n
acquiree or at their fair value as at the acquisition date.
\n
In the case of business combinations achieved in stages, at
\n
the date of acquisition of control the previously held equi-
\n
ty interest in the acquiree is remeasured to fair value and
\n
any positive or negative difference is recognized in profit
\n
or loss.
\n
Any contingent consideration is recognized at fair value at
\n
the acquisition date. Subsequent changes to the fair val-
\n
ue of the contingent consideration classified as an asset
\n
or a liability, or as a financial instrument within the scope
\n
of IFRS 9, are recognized in profit or loss. If the contin-
\n
gent consideration is not within the scope of IFRS 9, it is
\n
measured in accordance with the appropriate IFRS-EU.
\n
Contingent consideration that is classified as equity is not
\n
re-measured, and its subsequent settlement is accounted
\n
for within equity.
\n
If the fair values of the assets, liabilities and contingent li-
\n
abilities can only be calculated on a provisional basis, the
\n
business combination is recognized using such provisional
\n
values. Any adjustments resulting from the completion of
\n
the measurement process are recognized within 12 months
\n
of the date of acquisition, restating comparative figures.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag28": { "value": "\n
Fair value measurement
\n
For all fair value measurements and disclosures of fair val-
\n
ue, that are either required or permitted by IFRS, the Group
\n
applies IFRS 13.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The fair value measurement assumes that the transaction
\n
to sell an asset or transfer a liability takes place in the prin-
\n
cipal market, i.e., the market with the greatest volume and
\n
level of activity for the asset or liability. In the absence of a
\n
principal market, it is assumed that the transaction takes
\n
place in the most advantageous market to which the Group
\n
has access, i.e., the market that maximizes the amount
\n
that would be received to sell the asset or minimizes the
\n
amount that would be paid to transfer the liability.
\n
The fair value of an asset or a liability is measured using
\n
the assumptions that market participants would use when
\n
pricing the asset or liability, assuming that market partic-
\n
ipants act in their economic best interest. Market partici-
\n
pants are independent, knowledgeable sellers and buyers
\n
who are able to enter into a transaction for the asset or the
\n
liability and who are motivated but not forced or otherwise
\n
compelled to do so.
\n
When measuring fair value, the Group considers the char-
\n
acteristics of the asset or liability, in particular:
\n
\u2022 for a non-financial asset, a fair value measurement takes
\n
into account a market participant\u2019s ability to generate
\n
economic benefits by using the asset in its highest and
\n
best use or by selling it to another market participant
\n
that would use the asset in its highest and best use;
\n

\n\n
\u2022 for liabilities and own equity instruments, the fair val-
\n
ue reflects the effect of non-performance risk, i.e., the
\n
risk that an entity will not fulfill an obligation, including
\n
among others the credit risk of the Group itself;
\n
\u2022 in the case of groups of financial assets and financial lia-
\n
bilities with offsetting positions in market risk or credit risk,
\n
managed on the basis of an entity\u2019s net exposure to such
\n
risks, it is permitted to measure fair value on a net basis.
\n
In measuring the fair value of assets and liabilities, the
\n
Group uses valuation techniques that are appropriate in
\n
the circumstances and for which sufficient data are avail-
\n
able, maximizing the use of relevant observable inputs and
\n
minimizing the use of unobservable inputs.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag25": { "value": "\n

\n

\n

\n
Property, plant and equipment
\n
Property, plant and equipment is stated at cost, net of
\n
accumulated depreciation and accumulated impairment
\n
losses, if any. Such cost includes expenses directly attrib-
\n
utable to bringing the asset to the location and condition
\n
necessary for its intended use.
\n\n
The cost is also increased by the present value of the es-
\n
timate of the costs of decommissioning and restoring the
\n
site on which the asset is located where there is a legal
\n
or constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
The accounting treatment of changes in the estimate of
\n
these costs, the passage of time and the discount rate is
\n
discussed in note 40 \u201cProvisions for risks and charges\u201d.
\n

\n\n
Property, plant and equipment transferred from custom-
\n
ers to connect them to the electricity distribution network
\n
and/or to provide them with other related services is ini-
\n
tially recognized at its fair value at the date on which con-
\n
trol is obtained.
\n\n
Borrowing costs that are directly attributable to the ac-
\n
quisition, construction or production of a qualifying asset,
\n
i.e., an asset that takes a substantial period of time to get
\n
ready for its intended use or sale, are capitalized as part
\n
of the cost of the assets themselves. Borrowing costs as-
\n
sociated with the purchase/construction of assets that do
\n
not meet such requirement are expensed in the period in
\n
which they are incurred.
\n

\n\n
Certain assets that were revalued at the IFRS-EU transi-
\n
tion date or in previous periods are recognized at their fair
\n
value, which is considered to be their deemed cost at the
\n
revaluation date.
\n
Where individual items of major components of property,
\n
plant and equipment have different useful lives, the com-
\n
ponents are recognized and depreciated separately.
\n
Subsequent costs are recognized as an increase in the
\n
carrying amount of the asset when it is probable that fu-
\n
ture economic benefits associated with the cost incurred
\n
to replace a part of the asset will flow to the Group and the
\n
cost of the item can be measured reliably. All other costs
\n
are recognized in profit or loss as incurred.
\n
The cost of replacing part or all of an asset is recognized
\n
as an increase in the carrying amount of the asset and is
\n
depreciated over its useful life; the carrying amount of the
\n
replaced unit is derecognized through profit or loss.
\n\n
Property, plant and equipment, net of its residual value,
\n
is depreciated on a straight-line basis over its estimated
\n
useful life, which is reviewed annually. Any changes in de-
\n
preciation criteria shall be applied prospectively. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\n
Depreciation begins when the asset is available for use.
\n
The estimated useful life of the main items of property,
\n
plant and equipment is as follows:
\n
Civil buildings 10-60 years
\n
Buildings and civil works incorporated in plants 10-100 years
\n
Hydroelectric power plants:
\n
- penstock 10-65 years
\n
- mechanical and electrical machinery 10-65 years
\n
- other fixed hydraulic works 10-100 years
\n
Thermal power plants:
\n
- boilers and auxiliary components 20-40 years
\n
- gas turbine components 10-40 years
\n
- mechanical and electrical machinery 5-40 years
\n
- other fixed hydraulic works 60 years
\n
Nuclear power plants 50 years
\n
Geothermal power plants:
\n
- cooling towers 20 years
\n
- turbines and generators 10-50 years
\n
- turbine parts in contact with fluid 10 years
\n
- mechanical and electrical machinery 20-40 years
\n
Wind power plants:
\n
- towers 20-30 years
\n
- turbines and generators 20-30 years
\n
- mechanical and electrical machinery 15-30 years
\n
Solar power plants:
\n
- mechanical and electrical machinery 15-30 years
\n
Public and artistic lighting:
\n
- public lighting installations 10-20 years
\n
- artistic lighting installations 20 years
\n
Transport lines 10-60 years
\n
Transformer stations 20-55 years
\n
Distribution plants:
\n
- high-voltage lines 10-60 years
\n
- primary transformer stations 10-50 years
\n
- low and medium-voltage lines 10-50 years
\n
Meters:
\n
- electromechanical meters 5-40 years
\n
- electricity balance measurement equipment 10 years
\n
- electronic meters 15 years
\n
Charging stations 7-15 years
\n

\n\n

\n

\n\n

\n\n
The useful life of leasehold improvements is determined
\n
on the basis of the term of the lease or, if shorter, on the
\n
duration of the benefits produced by the improvements
\n
themselves.
\n
Land is not depreciated as it has an indefinite useful life.
\n

\n\n
Assets recognized under property, plant and equipment
\n
are derecognized either upon their disposal (i.e., at the
\n
date the recipient obtains control) or when no future eco-
\n
nomic benefit is expected from their use or disposal. Any
\n
gain or loss, recognized through profit or loss, is calculat-
\n
ed as the difference between the net disposal proceeds,
\n
determined in accordance with the transaction price re-
\n
quirements of IFRS 15, and the carrying amount of the
\n
derecognized assets.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag56": { "value": "\n
The cost is also increased by the present value of the es-
\n
timate of the costs of decommissioning and restoring the
\n
site on which the asset is located where there is a legal
\n
or constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
The accounting treatment of changes in the estimate of
\n
these costs, the passage of time and the discount rate is
\n
discussed in note 40 \u201cProvisions for risks and charges\u201d.
\n

\n\n
Where the liability relates to decommissioning and/or site
\n
restoration in respect of property, plant and equipment,
\n
the initial recognition of the provision is made against the
\n
related asset and the expense is then recognized in profit
\n
or loss through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of
\n
nuclear waste and other radioactive materials, the provi-
\n
sion is recognized against the related operating costs.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag50": { "value": "\n
Borrowing costs that are directly attributable to the ac-
\n
quisition, construction or production of a qualifying asset,
\n
i.e., an asset that takes a substantial period of time to get
\n
ready for its intended use or sale, are capitalized as part
\n
of the cost of the assets themselves. Borrowing costs as-
\n
sociated with the purchase/construction of assets that do
\n
not meet such requirement are expensed in the period in
\n
which they are incurred.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag39": { "value": "The cost of replacing part or all of an asset is recognizedas an increase in the carrying amount of the asset and isdepreciated over its useful life", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRepairsAndMaintenanceExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag53": { "value": "\n
Property, plant and equipment, net of its residual value,
\n
is depreciated on a straight-line basis over its estimated
\n
useful life, which is reviewed annually. Any changes in de-
\n
preciation criteria shall be applied prospectively. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\n
Depreciation begins when the asset is available for use.
\n
The estimated useful life of the main items of property,
\n
plant and equipment is as follows:
\n
Civil buildings 10-60 years
\n
Buildings and civil works incorporated in plants 10-100 years
\n
Hydroelectric power plants:
\n
- penstock 10-65 years
\n
- mechanical and electrical machinery 10-65 years
\n
- other fixed hydraulic works 10-100 years
\n
Thermal power plants:
\n
- boilers and auxiliary components 20-40 years
\n
- gas turbine components 10-40 years
\n
- mechanical and electrical machinery 5-40 years
\n
- other fixed hydraulic works 60 years
\n
Nuclear power plants 50 years
\n
Geothermal power plants:
\n
- cooling towers 20 years
\n
- turbines and generators 10-50 years
\n
- turbine parts in contact with fluid 10 years
\n
- mechanical and electrical machinery 20-40 years
\n
Wind power plants:
\n
- towers 20-30 years
\n
- turbines and generators 20-30 years
\n
- mechanical and electrical machinery 15-30 years
\n
Solar power plants:
\n
- mechanical and electrical machinery 15-30 years
\n
Public and artistic lighting:
\n
- public lighting installations 10-20 years
\n
- artistic lighting installations 20 years
\n
Transport lines 10-60 years
\n
Transformer stations 20-55 years
\n
Distribution plants:
\n
- high-voltage lines 10-60 years
\n
- primary transformer stations 10-50 years
\n
- low and medium-voltage lines 10-50 years
\n
Meters:
\n
- electromechanical meters 5-40 years
\n
- electricity balance measurement equipment 10 years
\n
- electronic meters 15 years
\n
Charging stations 7-15 years
\n

\n\n
The useful life of leasehold improvements is determined
\n
on the basis of the term of the lease or, if shorter, on the
\n
duration of the benefits produced by the improvements
\n
themselves.
\n
Land is not depreciated as it has an indefinite useful life.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag35": { "value": "\n
Infrastructure serving a concession not within the scope
\n
of \u201cIFRIC 12 - Service concession arrangements\u201d
\n
As regards the distribution of electricity, the Group is a
\n
concession holder in Italy for this service. The concession,
\n
granted by the Ministry for Economic Development, was
\n
issued free of charge and terminates on December 31,
\n
2030. If the concession is not renewed upon expiry, the
\n
grantor is required to pay an indemnity. The amount of the
\n
indemnity will be determined by agreement of the parties
\n
using appropriate valuation methods, based on both the
\n
carrying amount of the assets themselves and their prof-
\n
itability.
\n
In determining the indemnity, such profitability will be rep-
\n
resented by the present value of future cash flows. The in-
\n
frastructure serving the concession is owned and available
\n
to the concession holder. It is recognized under \u201cProperty,
\n
plant and equipment\u201d and is depreciated over the useful
\n
lives of the assets.
\n
Enel also operates under administrative concessions for
\n
the distribution of electricity in other countries (including
\n
Spain and Romania). These concessions give the right to
\n
build and operate distribution networks for an indefinite
\n
period of time.
\n

\n\n
Infrastructure within the scope of \u201cIFRIC 12 -
\n
Service concession arrangements\u201d
\n
Under a \u201cpublic-to-private\u201d service concession arrange-
\n
ment within the scope of \u201cIFRIC 12 - Service concession
\n
arrangements\u201d the operator acts as a service provider and,
\n
in accordance with the terms specified in the contract, it
\n
constructs/upgrades infrastructure used to provide a
\n
public service and/or operates and maintains that infra-
\n
structure for the years of the concession.
\n
The Group, as operator, does not account for the infra-
\n
structure within the scope of IFRIC 12 as property, plant
\n
and equipment and it recognizes and measures revenue
\n
in accordance with IFRS 15 for the services it performs. In
\n
particular, when the Group provides construction or up-
\n
grade services, depending on the characteristics of the
\n
service concession arrangement, it recognizes:
\n
\u2022 a financial asset, if the Group has an unconditional con-
\n
tractual right to receive cash or another financial asset
\n
from the grantor (or from a third party at the direction
\n
of the grantor), that is the grantor has little discretion
\n
to avoid payment. In this case, the grantor contractually
\n
guarantees to pay to the operator specified or deter-
\n
minable amounts or the shortfall between the amounts
\n
received from the users of the public service and spec-
\n
ified or determinable amounts (defined by the contract),
\n
and such payments are not dependent on the usage of
\n
the infrastructure; and/or
\n
\u2022 an intangible asset, if the Group receives the right (a li-
\n
cense) to charge users of the public service provided. In
\n

\n\n
such a case, the operator does not have an uncondition-
\n
al right to receive cash because the amounts are contin-
\n
gent on the extent that the public uses the service.
\n
If the Group (as operator) has a contractual right to re-
\n
ceive an intangible asset (a right to charge users of public
\n
service), borrowing costs are capitalized using the criteria
\n
specified in note 19 \u201cProperty, plant and equipment\u201d.
\n
However, for construction/upgrade services, both types of
\n
consideration are classified as a contract asset during the
\n
construction/upgrade period.
\n
For more details about such consideration, please see
\n
note 11.a \u201cRevenue from sales and services\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForServiceConcessionArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag38": { "value": "\n
Leases
\n
The Group holds property, plant and equipment for its
\n
various activities under lease contracts. At inception of
\n
a contract, the Group assesses whether a contract is, or
\n
contains, a lease.
\n
For contracts entered into or changed on or after January
\n
1, 2019, the Group has applied the definition of a lease un-
\n
der IFRS 16, that is met if the contract conveys the right to
\n
control the use of an identified asset for a period of time in
\n
exchange for consideration.
\n
Conversely, for contracts entered into before January 1,
\n
2019, the Group determined whether the arrangement
\n
was or contained a lease under IFRIC 4.
\n
Group as a lessee
\n
At commencement or on modification of a contract that
\n
contains a lease component
\n
and one or more additional
\n
lease or non-lease components
\n
, the Group allocates the
\n
consideration in the contract to each lease component on
\n
the basis of its relative stand-alone price.
\n
The Group recognizes a right-of-use asset and a lease lia-
\n
bility at the commencement date of the lease (i.e., the date
\n
the underlying asset is available for use).
\n
The right-of-use asset represents a lessee\u2019s right to use an
\n
underlying asset for the lease term; it is initially measured
\n
at cost, which includes the initial amount of lease liabili-
\n
ty adjusted for any lease payments made at or before the
\n
commencement date less any lease incentives received,
\n
plus any initial direct costs incurred and an estimate of
\n
costs to retire and remove the underlying asset and to re-
\n
store the underlying asset or the site on which it is located.
\n
Right-of-use assets are subsequently depreciated on a
\n
straight-line basis over the shorter of the lease term and
\n
the estimated useful lives of the right-of-use assets, as
\n
follows:
\n
Average residual life (years)
\n
Buildings 6
\n
Ground rights of renewable energy plants 31
\n
Vehicles and other means of transport 5
\n
If the lease transfers ownership of the underlying asset to
\n
the Group at the end of the lease term or if the cost of the
\n
right-of-use asset
\n
reflects the fact that the Group will exer-
\n
cise a purchase option, depreciation is calculated using the
\n
estimated useful life of the underlying asset.
\n
In addition, the right-of-use assets are subject to impair-
\n
ment and adjusted for any remeasurement of lease liabili-
\n
ties.
\n
The lease liability is initially measured at the present value of
\n
lease payments to be made over the lease term. In calcu-
\n
lating the present value of lease payments, the Group uses
\n
the lessee\u2019s incremental borrowing rate at the lease com-
\n
mencement date when the interest rate implicit in the lease
\n
is not readily determinable.
\n
Variable lease payments that do not depend on an index or
\n
a rate are recognized as expenses in the period in which the
\n
event or condition that triggers the payment occurs.
\n
After the commencement date, the lease liability is mea-
\n
sured at amortized cost using the effective interest method
\n
and is remeasured upon the occurrence of certain events.
\n
The Group applies the short-term lease recognition ex-
\n
emption to its lease contracts that have a lease term of 12
\n
months or less from the commencement date. It also ap-
\n
plies the low-value assets recognition exemption to lease
\n
contracts for which the underlying asset is of low-value
\n
whose amount is estimated not material. For example, the
\n
Group has leases of certain office equipment (i.e., personal
\n
computers, printing and photocopying machines) that are
\n
considered of low-value. Lease payments on short-term
\n
leases and leases of low-value assets are recognized as
\n
expense on a straight-line basis over the lease term.
\n
The Group presents right-of-use assets that do not meet
\n
the definition of investment property in \u201cProperty, plant
\n
and equipment\u201d and lease liabilities in \u201cBorrowings\u201d.
\n
Consistent with the requirement of the standard, the
\n
Group presents separately the interest expense on lease
\n
liabilities under \u201cOther financial expense\u201d and the depreci-
\n
ation charge on the right-of-use assets under \u201cDeprecia-
\n
tion, amortization and impairment losses\u201d.
\n
Group as a lessor
\n
When the Group acts as a lessor, it determines at the lease
\n
inception date whether each lease is a finance lease or an
\n
operating lease.
\n
Leases in which the Group essentially transfers all the risks
\n
and rewards associated with ownership of the underlying
\n
asset are classified as finance leases; otherwise, they are
\n
classified as operating leases. To make this assessment, the
\n
Group considers the indicators provided by IFRS 16. If a con-
\n
tract contains lease and non-lease components, the Group
\n
allocates the consideration in the contract applying IFRS 15.
\n
The Group accounts for rental income arising from oper-
\n
ating leases on a straight-line basis over the lease terms
\n
and it recognizes it as other revenue.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag37": { "value": "\n
Investment property
\n
Investment property consists of the Group\u2019s real estate
\n
held to earn rentals and/or for capital appreciation rath-
\n
er than for use in the production or supply of goods and
\n
services.
\n
Investment property is measured at acquisition cost less
\n
any accumulated depreciation and any accumulated im-
\n
pairment losses.
\n
Investment property, excluding land, is depreciated on a
\n
straight-line basis over the useful lives of the related as-
\n
sets.
\n
Impairment losses are determined on the basis of the cri-
\n
teria following described.
\n
The breakdown of the fair value of investment property is
\n
detailed in note 52 \u201cAssets and liabilities measured at fair
\n
value\u201d.
\n
Investment property is derecognized either when it has
\n
been transferred (i.e., at the date the recipient obtains
\n
control) or when it is permanently withdrawn from use
\n
and no future economic benefit is expected from its dis-
\n
posal. Any gain or loss, recognized through profit or loss,
\n
is calculated as the difference between the net disposal
\n
proceeds, determined in accordance with the transaction
\n
price requirements of IFRS 15, and the carrying amount of
\n
the derecognized assets.
\n
Transfers are made to (or from) investment property only
\n
when there is a change in use.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentPropertyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag51": { "value": "\n

\n

\n\n

\n
Intangible assets
\n
Intangible assets are identifiable assets without physical
\n
substance controlled by the Group and capable of gen-
\n
erating future economic benefits. They are measured at
\n
purchase or internal development cost when it is probable
\n
that the use of such assets will generate future economic
\n
benefits and the related cost can be reliably determined.
\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n\n
Development expenditure is recognized as an intangible
\n
asset only when Group can demonstrate the technical fea-
\n
sibility of completing the asset, its intention and ability to
\n
complete development and to use or sell the asset and the
\n
availability of resources to complete the asset.
\n
Research costs are recognized as expenses.
\n

\n\n
Intangible assets with a finite useful life are recognized net
\n
of accumulated amortization and any impairment losses.
\n
Amortization is calculated on a straight-line basis over the
\n
asset\u2019s estimated useful life, which is reassessed at least
\n
annually; any changes in amortization policies are reflected
\n
on a prospective basis. For more information on estimating
\n
useful life, please see note 2.1 \u201cUse of estimates and man-
\n
agement judgment\u201d.
\n
Amortization commences when the asset is ready for use.
\n
Consequently, intangible assets not yet available for use
\n
are not amortized, but are tested for impairment at least
\n
annually.
\n
The Group\u2019s intangible assets have a finite useful life, with the
\n
exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amortized,
\n
but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annually
\n
to determine whether the indefinite useful life continues to
\n
be supportable. If not, the change in useful life from indefinite
\n
to finite is accounted for as a change in accounting estimate.
\n
Intangible assets are derecognized either at the time of
\n
their disposal (at the date when the recipient obtains con-
\n
trol) or when no future economic benefit is expected from
\n
their use or disposal. Any gain or loss, recognized through
\n
profit or loss, is calculated as the difference between the
\n
net consideration received in the disposal, determined
\n
in accordance with the provisions of IFRS 15 concern-
\n
ing the transaction price, and the carrying amount of the
\n
derecognized assets.
\n
The estimated useful life of the main intangible assets,
\n
distinguishing between internally generated and acquired
\n
assets, is as follows:
\n
Development expenditure:
\n
- internally generated 5 years
\n
- acquired 3-26 years
\n
Industrial patents and intellectual property rights:
\n
- internally generated 3-10 years
\n
- acquired 3-10 years
\n
Concessions, licenses, trademarks and similar rights:
\n
- internally generated 20 years
\n
- acquired 10-18 years
\n
Other:
\n
- internally generated 2-28 years
\n
- acquired 3-15 years
\n
The Group also presents costs to obtain a contract with a
\n
customer capitalized in accordance with IFRS 15 as intan-
\n
gible assets.
\n
The Group recognized such costs as an asset only if:
\n
\u2022 the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group would
\n
not have incurred them if the contract had not been ob-
\n
tained;
\n
\u2022 the Group expects to recover them, through reimburse-
\n
ments (direct recoverability) or the margin (indirect re-
\n
coverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the cap-
\n
italization criteria are met.
\n
Capitalized customer contract costs are amortized on a
\n
systematic basis, consistent with the pattern of the trans-
\n
fer of the goods or services to which they relate, and un-
\n
dergo impairment testing to identify any impairment loss-
\n
es to the extent that the carrying amount of the asset rec-
\n
ognized exceeds the recoverable amount.
\n

\n

\n\n

\n

\n\n

\n\n
The Group amortizes the capitalized customer contract
\n
costs
\n
on a straight-line basis over the expected period of
\n
benefit from the contract (i.e., the average term of the cus-
\n
tomer relationship);
\n
any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag33": { "value": "\n

\n
Intangible assets
\n
Intangible assets are identifiable assets without physical
\n
substance controlled by the Group and capable of gen-
\n
erating future economic benefits. They are measured at
\n
purchase or internal development cost when it is probable
\n
that the use of such assets will generate future economic
\n
benefits and the related cost can be reliably determined.
\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n\n
Development expenditure is recognized as an intangible
\n
asset only when Group can demonstrate the technical fea-
\n
sibility of completing the asset, its intention and ability to
\n
complete development and to use or sell the asset and the
\n
availability of resources to complete the asset.
\n
Research costs are recognized as expenses.
\n

\n\n
Intangible assets with a finite useful life are recognized net
\n
of accumulated amortization and any impairment losses.
\n
Amortization is calculated on a straight-line basis over the
\n
asset\u2019s estimated useful life, which is reassessed at least
\n
annually; any changes in amortization policies are reflected
\n
on a prospective basis. For more information on estimating
\n
useful life, please see note 2.1 \u201cUse of estimates and man-
\n
agement judgment\u201d.
\n
Amortization commences when the asset is ready for use.
\n
Consequently, intangible assets not yet available for use
\n
are not amortized, but are tested for impairment at least
\n
annually.
\n
The Group\u2019s intangible assets have a finite useful life, with the
\n
exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amortized,
\n
but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annually
\n
to determine whether the indefinite useful life continues to
\n
be supportable. If not, the change in useful life from indefinite
\n
to finite is accounted for as a change in accounting estimate.
\n
Intangible assets are derecognized either at the time of
\n
their disposal (at the date when the recipient obtains con-
\n
trol) or when no future economic benefit is expected from
\n
their use or disposal. Any gain or loss, recognized through
\n
profit or loss, is calculated as the difference between the
\n
net consideration received in the disposal, determined
\n
in accordance with the provisions of IFRS 15 concern-
\n
ing the transaction price, and the carrying amount of the
\n
derecognized assets.
\n
The estimated useful life of the main intangible assets,
\n
distinguishing between internally generated and acquired
\n
assets, is as follows:
\n
Development expenditure:
\n
- internally generated 5 years
\n
- acquired 3-26 years
\n
Industrial patents and intellectual property rights:
\n
- internally generated 3-10 years
\n
- acquired 3-10 years
\n
Concessions, licenses, trademarks and similar rights:
\n
- internally generated 20 years
\n
- acquired 10-18 years
\n
Other:
\n
- internally generated 2-28 years
\n
- acquired 3-15 years
\n
The Group also presents costs to obtain a contract with a
\n
customer capitalized in accordance with IFRS 15 as intan-
\n
gible assets.
\n
The Group recognized such costs as an asset only if:
\n
\u2022 the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group would
\n
not have incurred them if the contract had not been ob-
\n
tained;
\n
\u2022 the Group expects to recover them, through reimburse-
\n
ments (direct recoverability) or the margin (indirect re-
\n
coverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the cap-
\n
italization criteria are met.
\n
Capitalized customer contract costs are amortized on a
\n
systematic basis, consistent with the pattern of the trans-
\n
fer of the goods or services to which they relate, and un-
\n
dergo impairment testing to identify any impairment loss-
\n
es to the extent that the carrying amount of the asset rec-
\n
ognized exceeds the recoverable amount.
\n

\n

\n\n
The Group amortizes the capitalized customer contract
\n
costs
\n
on a straight-line basis over the expected period of
\n
benefit from the contract (i.e., the average term of the cus-
\n
tomer relationship);
\n
any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n
Goodwill
\n
Goodwill represents the future economic benefits arising
\n
from other assets acquired in a business combination that
\n
are not individually identified and separately recognized.
\n
For further details, please see the section of the account-
\n
ing policies \u201cBusiness combinations\u201d.
\n
Goodwill arising on the acquisition of subsidiaries is rec-
\n
ognized separately. After initial recognition, goodwill is not
\n
amortized, but is tested for impairment at least annually as
\n
part of the CGU to which it pertains.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU that is expect-
\n
ed to benefit from the synergies of the combination.
\n
Goodwill relating to equity investments in associates and
\n
joint venture is included in their carrying amount.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag55": { "value": "\n
Development expenditure is recognized as an intangible
\n
asset only when Group can demonstrate the technical fea-
\n
sibility of completing the asset, its intention and ability to
\n
complete development and to use or sell the asset and the
\n
availability of resources to complete the asset.
\n
Research costs are recognized as expenses.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForResearchAndDevelopmentExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag40": { "value": "\n

\n\n
Goodwill
\n
Goodwill represents the future economic benefits arising
\n
from other assets acquired in a business combination that
\n
are not individually identified and separately recognized.
\n
For further details, please see the section of the account-
\n
ing policies \u201cBusiness combinations\u201d.
\n
Goodwill arising on the acquisition of subsidiaries is rec-
\n
ognized separately. After initial recognition, goodwill is not
\n
amortized, but is tested for impairment at least annually as
\n
part of the CGU to which it pertains.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU that is expect-
\n
ed to benefit from the synergies of the combination.
\n
Goodwill relating to equity investments in associates and
\n
joint venture is included in their carrying amount.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag42": { "value": "\n

\n\n
Impairment of non-financial assets
\n
At each reporting date, property, plant and equipment, in-
\n
vestment property, intangible assets, right-of-use assets,
\n
goodwill and equity investments in associates/joint ven-
\n
tures are reviewed to determine whether there is evidence
\n
of impairment.
\n
CGUs to which goodwill, intangible assets with an indef-
\n
inite useful life and intangible assets not yet available for
\n
use are allocated are tested for recoverability annually or
\n
more frequently if there is evidence suggesting that the
\n
assets can be impaired.
\n
If such evidence exists, the recoverable amount of any in-
\n
volved asset is estimated on the basis of the use of the as-
\n
set and its future disposal, in accordance with the Group\u2019s
\n
most recent Business Plan. For the estimate of the recov-
\n
erable amount, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The recoverable amount is determined for an individual as-
\n
set, unless the asset do not generate cash inflows that are
\n
largely independent of those from other assets or groups
\n
of assets and therefore it is determined for the CGU to
\n
which the asset belongs.
\n
If the carrying amount of an asset or of a CGU to which it
\n
is allocated is greater than its recoverable amount, an im-
\n
pairment loss is recognized in profit or loss and presented
\n
under \u201cDepreciation, amortization and other impairment
\n
losses\u201d.
\n
Impairment losses of CGUs are firstly charged against the
\n
carrying amount of any goodwill attributed to it and then
\n
against the other assets, in proportion to their carrying
\n
amount.
\n
If the reasons for a previously recognized impairment loss
\n
no longer apply, the carrying amount of the asset is restored
\n
through profit or loss, under \u201cDepreciation, amortization
\n
and other impairment losses\u201d, in an amount that shall not
\n
exceed the carrying amount that the asset would have had
\n
if the impairment loss had not been recognized. The origi-
\n
nal amount of goodwill is not restored even if in subsequent
\n
years the reasons for the impairment no longer apply.
\n
If certain specific identified assets owned by the Group are
\n
impacted by adverse economic or operating conditions
\n
that undermine their capacity to contribute to the gener-
\n
ation of cash flows, they can be isolated from the rest of
\n
the assets of the CGU, undergo separate analysis of their
\n
recoverability and be impaired where necessary.
\n

\n

\n\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag49": { "value": "\n
Impairment of non-financial assets
\n
At each reporting date, property, plant and equipment, in-
\n
vestment property, intangible assets, right-of-use assets,
\n
goodwill and equity investments in associates/joint ven-
\n
tures are reviewed to determine whether there is evidence
\n
of impairment.
\n
CGUs to which goodwill, intangible assets with an indef-
\n
inite useful life and intangible assets not yet available for
\n
use are allocated are tested for recoverability annually or
\n
more frequently if there is evidence suggesting that the
\n
assets can be impaired.
\n
If such evidence exists, the recoverable amount of any in-
\n
volved asset is estimated on the basis of the use of the as-
\n
set and its future disposal, in accordance with the Group\u2019s
\n
most recent Business Plan. For the estimate of the recov-
\n
erable amount, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The recoverable amount is determined for an individual as-
\n
set, unless the asset do not generate cash inflows that are
\n
largely independent of those from other assets or groups
\n
of assets and therefore it is determined for the CGU to
\n
which the asset belongs.
\n
If the carrying amount of an asset or of a CGU to which it
\n
is allocated is greater than its recoverable amount, an im-
\n
pairment loss is recognized in profit or loss and presented
\n
under \u201cDepreciation, amortization and other impairment
\n
losses\u201d.
\n
Impairment losses of CGUs are firstly charged against the
\n
carrying amount of any goodwill attributed to it and then
\n
against the other assets, in proportion to their carrying
\n
amount.
\n
If the reasons for a previously recognized impairment loss
\n
no longer apply, the carrying amount of the asset is restored
\n
through profit or loss, under \u201cDepreciation, amortization
\n
and other impairment losses\u201d, in an amount that shall not
\n
exceed the carrying amount that the asset would have had
\n
if the impairment loss had not been recognized. The origi-
\n
nal amount of goodwill is not restored even if in subsequent
\n
years the reasons for the impairment no longer apply.
\n
If certain specific identified assets owned by the Group are
\n
impacted by adverse economic or operating conditions
\n
that undermine their capacity to contribute to the gener-
\n
ation of cash flows, they can be isolated from the rest of
\n
the assets of the CGU, undergo separate analysis of their
\n
recoverability and be impaired where necessary.
\n

\n

\n\n

\n\n
Impairment of financial assets
\n
At each reporting date, the Group recognizes a loss allow-
\n
ance for expected credit losses on trade receivables and
\n
other financial assets measured at amortized cost, debt
\n
instruments measured at fair value through other com-
\n
prehensive income (FVOCI), contract assets and all other
\n
assets within the scope of IFRS 9.
\n
In compliance with IFRS 9, as from January 1, 2018, the
\n
Group adopted a new impairment model based on the
\n
determination of expected credit losses (ECL) using a for-
\n
ward-looking approach. In essence, the model provides
\n
for:
\n
\u2022 the application of a single framework for all financial as-
\n
sets;
\n
\u2022 the recognition of expected credit losses on an ongoing
\n
basis and the updating of the amount of such losses at
\n
the end of each reporting period, reflecting changes in
\n
the credit risk of the financial instrument;
\n
\u2022 the measurement of expected losses on the basis of
\n
reasonable information, obtainable without undue cost,
\n
about past events, current conditions and forecasts of
\n
future conditions.
\n
For trade receivables, contract assets and lease receiv-
\n
ables, including those with a significant financial compo-
\n
nent, the Group adopts the simplified approach, determin-
\n
ing expected credit losses over a period corresponding to
\n
the entire life of the asset, generally equal to 12 months.
\n
For all financial assets other than trade receivables, con-
\n
tract assets and lease receivables, the Group applies the
\n
general approach under IFRS 9, based on the assessment
\n
of a significant increase in credit risk since initial recogni-
\n
tion. Under such approach, a loss allowance on financial
\n
assets is recognized at an amount equal to the lifetime
\n
expected credit losses, if the credit risk on those financial
\n
assets has increased significantly, since initial recognition,
\n
considering all reasonable and supportable information,
\n
including also forward-looking inputs.
\n
If at the reporting date the credit risk on financial assets
\n
has not increased significantly since initial recognition,
\n
the Group measures the loss allowance for those financial
\n
assets at an amount equal to 12-month expected credit
\n
losses.
\n
For financial assets on which a loss allowance equal to life-
\n
time expected credit losses has been recognized in the
\n
previous reporting period, the Group measures the loss al-
\n
lowance at an amount equal to 12-month expected credit
\n
losses when the condition regarding a significant increase
\n
in credit risk is no longer met.
\n
The Group recognizes in profit or loss, as an impairment
\n
gain or loss, the amount of expected credit losses (or re-
\n
versal) that is required to adjust the loss allowance at the
\n
reporting date to the amount that is required to be recog-
\n
nized in accordance with IFRS 9.
\n
The Group applies the low credit risk exemption, avoid-
\n
ing the recognition of loss allowances at an amount equal
\n
to lifetime expected credit losses due to a significant in-
\n
crease in credit risk of debt securities at fair value through
\n
OCI, whose counterparty has a strong financial capacity
\n
to meet its contractual cash-flow obligations (e.g., invest-
\n
ment grade).
\n
For more information on the impairment of financial as-
\n
sets, please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n

\n

\n\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag41": { "value": "\n

\n
Inventories
\n
Inventories are measured at the lower of cost and net re-
\n
alizable value except for inventories involved in trading ac-
\n
tivities, which are measured at fair value with recognition
\n
through profit or loss. Cost is determined on the basis of
\n
average weighted cost, which includes related ancillary
\n
charges. Net estimated realizable value is the estimated
\n
normal selling price net of estimated costs to sell or, where
\n
applicable, replacement cost.
\n
For the portion of inventories held to discharge sales that
\n
have already been made, the net realizable value is deter-
\n
mined on the basis of the amount established in the con-
\n
tract of sale.
\n\n
Inventories include environmental certificates (for example,
\n
green certificates, energy efficiency certificates and Euro-
\n
pean CO
\n
2
\n
emissions allowances and guarantees of origin)
\n
exceeding compliance in the reporting period. As regards
\n
CO
\n
2
\n
emissions allowances, inventories are allocated be-
\n
tween the trading portfolio and the compliance portfolio,
\n
i.e., those used for compliance with greenhouse gas emis-
\n
sions requirements.
\n

\n

\n\n
Inventories also include nuclear fuel stocks, use of which is
\n
determined on the basis of the electricity generated.
\n
Materials and other consumables (including energy com-
\n
modities) held for use in production are not written down
\n
if it is expected that the final product in which they will be
\n
incorporated will be sold at a price sufficient to enable re-
\n
covery of the cost incurred.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag31": { "value": "\n
Inventories include environmental certificates (for example,
\n
green certificates, energy efficiency certificates and Euro-
\n
pean CO
\n
2
\n
emissions allowances and guarantees of origin)
\n
exceeding compliance in the reporting period. As regards
\n
CO
\n
2
\n
emissions allowances, inventories are allocated be-
\n
tween the trading portfolio and the compliance portfolio,
\n
i.e., those used for compliance with greenhouse gas emis-
\n
sions requirements.
\n

\n

\n\n
Environmental certificates
\n
Some Group companies are affected by national regula-
\n
tions governing green certificates, guarantees of origin
\n
and energy efficiency certificates (so-called white certifi-
\n
cates), as well as the European \u201cEmissions Trading System\u201d.
\n
Green certificates and guarantees of origin accrued in
\n
proportion to electricity generated by renewable energy
\n
plants and energy efficiency certificates accrued in pro-
\n
portion to energy savings achieved that have been certified
\n
by the competent authority are treated as non-monetary
\n
government operating grants and are recognized at fair
\n
value, under other operating profit, with recognition of an
\n
asset under other non-financial assets, if the certificates
\n
are not yet credited to the ownership account, or under
\n
inventories, if the certificates have already been credited
\n
to that account.
\n
At the time the certificates are credited to the ownership
\n
account, they are reclassified from other assets to inven-
\n
tories.
\n
Revenue from the sale of such certificates is recognized
\n
under revenue, with a corresponding decrease in invento-
\n
ries.
\n
For the purposes of accounting for charges arising from
\n
such regulatory requirements, the Group uses the \u201cnet li-
\n
ability approach\u201d.
\n
Under this accounting policy, any environmental certifi-
\n
cates received free of charge and those self-produced as
\n
a result of Group\u2019s operations that will be used for com-
\n
pliance purposes are recognized at nominal value (nil). In
\n
addition, charges incurred for obtaining (in the market or
\n
in some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the re-
\n
porting period are recognized through profit or loss on an
\n
accrual basis under other operating costs, as they repre-
\n
sent \u201csystem charges\u201d consequent to compliance with a
\n
regulatory requirement.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmissionRightsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag57": { "value": "\n
Financial instruments
\n
Financial instruments are any contract that gives rise to a
\n
financial asset of one entity and a financial liability or eq-
\n
uity instrument of another entity; they are recognized and
\n
measured in accordance with IAS 32 and IFRS 9.
\n
A financial asset or liability is recognized in the consolidat-
\n
ed financial statements when, and only when, the Group
\n
becomes party to the contractual provision of the instru-
\n
ment (i.e., the trade date).
\n

\n\n

\n
Trade receivables arising from contracts with customers, in
\n
the scope of IFRS 15, are initially measured at their trans-
\n
action price (as defined in IFRS 15) if such receivables do
\n
not contain a significant financing component or when the
\n
Group applies the practical expedient allowed by IFRS 15.
\n
Conversely, the Group initially measures financial assets
\n
other than the above-mentioned trade receivables at their
\n
fair value plus, in the case of a financial asset not measured
\n
at fair value through profit or loss, transaction costs.
\n
Financial assets are classified, at initial recognition, as fi-
\n
nancial assets at amortized cost, at fair value through oth-
\n
er comprehensive income and at fair value through profit
\n
or loss, on the basis of both the Group\u2019s business model
\n
and the contractual cash-flow characteristics of the in-
\n
strument.
\n
For this purpose, the assessment to determine whether
\n
the instrument gives rise to cash flows that are solely pay-
\n
ments of principal and interest (SPPI) on the principal amount
\n
outstanding is referred to as the SPPI test and is performed at
\n
an instrument level.
\n
The Group\u2019s business model for managing financial assets
\n
refers to how it manages its financial assets in order to gener-
\n
ate cash flows. The business model determines whether cash
\n
flows will result from collecting contractual cash flows, selling
\n
the financial assets, or both.
\n
For purposes of subsequent measurement, financial assets
\n
are classified in four categories:
\n
\u2022 financial assets measured at amortized cost (debt instru-
\n
ments);
\n
\u2022 financial assets at fair value through OCI with reclassifica-
\n
tion of cumulative gains and losses (debt instruments);
\n
\u2022 financial assets designated at fair value through OCI with
\n
no reclassification of cumulative gains and losses upon
\n
derecognition (equity instruments); and
\n
\u2022 financial assets at fair value through profit or loss.
\n

\n\n

\n

\n

\n

\n\n
Financial assets measured at amortized cost
\n
This category mainly includes trade receivables, other fi-
\n
nancial assets and loan assets.
\n
Financial assets at amortized cost are held within a busi-
\n
ness model whose objective is to hold financial assets in
\n
order to collect contractual cash flows and whose con-
\n
tractual terms give rise, on specified dates, to cash flows
\n
that are solely payments of principal and interest on the
\n
principal amount outstanding.
\n
Such assets are initially recognized at fair value, adjusted
\n
for any transaction costs, and subsequently measured at
\n
amortized cost using the effective interest method and are
\n
subject to impairment.
\n
Gains and losses are recognized in profit or loss when the
\n
asset is derecognized, modified or impaired.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Debt instruments
\n
This category mainly includes:
\n
\u2022 listed debt securities held by the Group reinsurance
\n
company and not classified as held for trading; and
\n
\u2022 tax credits deriving from application of Decree Law
\n
34/2020 (so-called \u201cRevival Decree\u201d).
\n
Financial assets at fair value through other comprehensive
\n
income are assets held within a business model whose
\n
objective is achieved by both collecting contractual cash
\n
flows and selling financial assets and whose contractual
\n
cash flows give rise, on specified dates, to cash flows that
\n
are solely payments of principal and interest on the princi-
\n
pal amount outstanding.
\n
Changes in fair value for these financial assets are recog-
\n
nized in other comprehensive income as well as loss al-
\n
lowances that do not reduce the carrying amount of the
\n
financial assets.
\n
When a financial asset is derecognized (e.g., at the time
\n
of sale), the cumulative gains and losses previously recog-
\n
nized in equity (except impairment and foreign exchange
\n
gains and losses to be recognized in profit or loss) are re-
\n
versed to profit or loss.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Equity instruments
\n
This category includes mainly equity investments in other
\n
entities irrevocably designated as such upon initial recog-
\n
nition.
\n
Gains and losses on these financial assets are never reclas-
\n
sified to profit or loss. The Group may transfer the cumula-
\n
tive gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of the
\n
cost of the investment.
\n

\n\n

\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes: securities, equity invest-
\n
ments in other companies, financial investments in fund
\n
held for trading and financial assets designated as at fair
\n
value through profit or loss at initial recognition.
\n
Financial assets at fair value through profit or loss are:
\n
\u2022 financial assets with cash flows that are not solely pay-
\n
ments of principal and interest, irrespective of the busi-
\n
ness model;
\n
\u2022 financial assets held for trading because acquired or
\n
incurred principally for the purpose of selling or repur-
\n
chasing in short term;
\n

\n\n

\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag44": { "value": "\n

\n

\n

\n

\n\n
Financial assets measured at amortized cost
\n
This category mainly includes trade receivables, other fi-
\n
nancial assets and loan assets.
\n
Financial assets at amortized cost are held within a busi-
\n
ness model whose objective is to hold financial assets in
\n
order to collect contractual cash flows and whose con-
\n
tractual terms give rise, on specified dates, to cash flows
\n
that are solely payments of principal and interest on the
\n
principal amount outstanding.
\n
Such assets are initially recognized at fair value, adjusted
\n
for any transaction costs, and subsequently measured at
\n
amortized cost using the effective interest method and are
\n
subject to impairment.
\n
Gains and losses are recognized in profit or loss when the
\n
asset is derecognized, modified or impaired.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Debt instruments
\n
This category mainly includes:
\n
\u2022 listed debt securities held by the Group reinsurance
\n
company and not classified as held for trading; and
\n
\u2022 tax credits deriving from application of Decree Law
\n
34/2020 (so-called \u201cRevival Decree\u201d).
\n
Financial assets at fair value through other comprehensive
\n
income are assets held within a business model whose
\n
objective is achieved by both collecting contractual cash
\n
flows and selling financial assets and whose contractual
\n
cash flows give rise, on specified dates, to cash flows that
\n
are solely payments of principal and interest on the princi-
\n
pal amount outstanding.
\n
Changes in fair value for these financial assets are recog-
\n
nized in other comprehensive income as well as loss al-
\n
lowances that do not reduce the carrying amount of the
\n
financial assets.
\n
When a financial asset is derecognized (e.g., at the time
\n
of sale), the cumulative gains and losses previously recog-
\n
nized in equity (except impairment and foreign exchange
\n
gains and losses to be recognized in profit or loss) are re-
\n
versed to profit or loss.
\n

\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) - Equity instruments
\n
This category includes mainly equity investments in other
\n
entities irrevocably designated as such upon initial recog-
\n
nition.
\n
Gains and losses on these financial assets are never reclas-
\n
sified to profit or loss. The Group may transfer the cumula-
\n
tive gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of the
\n
cost of the investment.
\n

\n\n

\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes: securities, equity invest-
\n
ments in other companies, financial investments in fund
\n
held for trading and financial assets designated as at fair
\n
value through profit or loss at initial recognition.
\n
Financial assets at fair value through profit or loss are:
\n
\u2022 financial assets with cash flows that are not solely pay-
\n
ments of principal and interest, irrespective of the busi-
\n
ness model;
\n
\u2022 financial assets held for trading because acquired or
\n
incurred principally for the purpose of selling or repur-
\n
chasing in short term;
\n

\n\n

\n

\n\n
\u2022 debt instruments designated upon initial recognition,
\n
under the option allowed by IFRS 9 (fair value option),
\n
if doing so eliminates, or significantly reduces, an ac-
\n
counting mismatch;
\n
\u2022 derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments.
\n
Such financial assets are initially recognized at fair value
\n
with subsequent gains and losses from changes in their
\n
fair value recognized through profit or loss.
\n
This category also includes listed equity investments
\n
which the Group had not irrevocably elected to classify at
\n
fair value through OCI. Dividends on such investments are
\n
also recognized as other income in the income statement
\n
when the right of payment has been established.
\n
Financial assets that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022 the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022 the Group has transferred substantially all the risks and
\n
rewards associated with the asset, transferring its rights
\n
to receive the cash flows of the asset or assuming a con-
\n
tractual obligation to pay such cash flows to one or more
\n
beneficiaries under a contract that meets the require-
\n
ments provided by IFRS 9 (the \u201cpass through test\u201d);
\n
\u2022 the Group has not transferred or retained substantially
\n
all the risks and rewards associated with the asset but
\n
has transferred control over the asset.
\n
Financial liabilities are derecognized when they are extin-
\n
guished, i.e., when the contractual obligation has been dis-
\n
charged, cancelled or expired.
\n
When an existing financial liability is replaced by another
\n
from the same lender on substantially different terms, or
\n
the terms of an existing liability are substantially modi-
\n
fied, such an exchange or modification is treated as the
\n
derecognition of the original liability and the recognition
\n
of a new liability. The difference in the respective carrying
\n
amounts is recognized in profit or loss.
\n

\n\n
Derivative financial instruments
\n
A derivative is a financial instrument or another contract:
\n
\u2022 whose value changes in response to the changes in an
\n
underlying variable such as an interest rate, commodity
\n
or security price, foreign exchange rate, a price or rate
\n
index, a credit rating or other variable;
\n
\u2022 that requires no initial net investment, or one that is
\n
smaller than would be required for a contract with similar
\n
response to changes in market factors;
\n
\u2022 that is settled at a future date.
\n
Derivative instruments are classified as financial assets or
\n
liabilities depending on the positive or negative fair value
\n
and they are classified as \u201cheld for trading\u201d within \u201cOther
\n
business models\u201d and measured at fair value through prof-
\n
it or loss, except for those designated as effective hedging
\n
instruments.
\n
All derivatives held for trading are classified as current as-
\n
sets or liabilities.
\n
Derivatives not held for trading purposes, but measured at
\n
fair value through profit or loss since they do not qualify for
\n
hedge accounting, and derivatives designated as effective
\n
hedging instruments are classified as current or not cur-
\n
rent on the basis of their maturity date and the Group in-
\n
tention to hold the financial instrument till maturity or not.
\n
For more details about derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag27": { "value": "\n
Financial assets measured at amortized cost
\n
This category mainly includes trade receivables, other fi-
\n
nancial assets and loan assets.
\n
Financial assets at amortized cost are held within a busi-
\n
ness model whose objective is to hold financial assets in
\n
order to collect contractual cash flows and whose con-
\n
tractual terms give rise, on specified dates, to cash flows
\n
that are solely payments of principal and interest on the
\n
principal amount outstanding.
\n
Such assets are initially recognized at fair value, adjusted
\n
for any transaction costs, and subsequently measured at
\n
amortized cost using the effective interest method and are
\n
subject to impairment.
\n
Gains and losses are recognized in profit or loss when the
\n
asset is derecognized, modified or impaired.
\n

\n\n
Impairment of financial assets
\n
At each reporting date, the Group recognizes a loss allow-
\n
ance for expected credit losses on trade receivables and
\n
other financial assets measured at amortized cost, debt
\n
instruments measured at fair value through other com-
\n
prehensive income (FVOCI), contract assets and all other
\n
assets within the scope of IFRS 9.
\n
In compliance with IFRS 9, as from January 1, 2018, the
\n
Group adopted a new impairment model based on the
\n
determination of expected credit losses (ECL) using a for-
\n
ward-looking approach. In essence, the model provides
\n
for:
\n
\u2022 the application of a single framework for all financial as-
\n
sets;
\n
\u2022 the recognition of expected credit losses on an ongoing
\n
basis and the updating of the amount of such losses at
\n
the end of each reporting period, reflecting changes in
\n
the credit risk of the financial instrument;
\n
\u2022 the measurement of expected losses on the basis of
\n
reasonable information, obtainable without undue cost,
\n
about past events, current conditions and forecasts of
\n
future conditions.
\n
For trade receivables, contract assets and lease receiv-
\n
ables, including those with a significant financial compo-
\n
nent, the Group adopts the simplified approach, determin-
\n
ing expected credit losses over a period corresponding to
\n
the entire life of the asset, generally equal to 12 months.
\n
For all financial assets other than trade receivables, con-
\n
tract assets and lease receivables, the Group applies the
\n
general approach under IFRS 9, based on the assessment
\n
of a significant increase in credit risk since initial recogni-
\n
tion. Under such approach, a loss allowance on financial
\n
assets is recognized at an amount equal to the lifetime
\n
expected credit losses, if the credit risk on those financial
\n
assets has increased significantly, since initial recognition,
\n
considering all reasonable and supportable information,
\n
including also forward-looking inputs.
\n
If at the reporting date the credit risk on financial assets
\n
has not increased significantly since initial recognition,
\n
the Group measures the loss allowance for those financial
\n
assets at an amount equal to 12-month expected credit
\n
losses.
\n
For financial assets on which a loss allowance equal to life-
\n
time expected credit losses has been recognized in the
\n
previous reporting period, the Group measures the loss al-
\n
lowance at an amount equal to 12-month expected credit
\n
losses when the condition regarding a significant increase
\n
in credit risk is no longer met.
\n
The Group recognizes in profit or loss, as an impairment
\n
gain or loss, the amount of expected credit losses (or re-
\n
versal) that is required to adjust the loss allowance at the
\n
reporting date to the amount that is required to be recog-
\n
nized in accordance with IFRS 9.
\n
The Group applies the low credit risk exemption, avoid-
\n
ing the recognition of loss allowances at an amount equal
\n
to lifetime expected credit losses due to a significant in-
\n
crease in credit risk of debt securities at fair value through
\n
OCI, whose counterparty has a strong financial capacity
\n
to meet its contractual cash-flow obligations (e.g., invest-
\n
ment grade).
\n
For more information on the impairment of financial as-
\n
sets, please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag47": { "value": "\n
Financial assets at fair value through profit or loss
\n
This category mainly includes: securities, equity invest-
\n
ments in other companies, financial investments in fund
\n
held for trading and financial assets designated as at fair
\n
value through profit or loss at initial recognition.
\n
Financial assets at fair value through profit or loss are:
\n
\u2022 financial assets with cash flows that are not solely pay-
\n
ments of principal and interest, irrespective of the busi-
\n
ness model;
\n
\u2022 financial assets held for trading because acquired or
\n
incurred principally for the purpose of selling or repur-
\n
chasing in short term;
\n

\n\n

\n\n
\u2022 debt instruments designated upon initial recognition,
\n
under the option allowed by IFRS 9 (fair value option),
\n
if doing so eliminates, or significantly reduces, an ac-
\n
counting mismatch;
\n
\u2022 derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments.
\n
Such financial assets are initially recognized at fair value
\n
with subsequent gains and losses from changes in their
\n
fair value recognized through profit or loss.
\n
This category also includes listed equity investments
\n
which the Group had not irrevocably elected to classify at
\n
fair value through OCI. Dividends on such investments are
\n
also recognized as other income in the income statement
\n
when the right of payment has been established.
\n
Financial assets that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n

\n\n
Financial liabilities at fair value through profit or loss
\n
Financial liabilities at fair value through profit or loss in-
\n
clude financial liabilities held for trading and financial lia-
\n
bilities designated upon initial recognition as at fair value
\n
through profit or loss.
\n
Financial liabilities are classified as held for trading if they
\n
are incurred for the purpose of repurchasing in the near
\n
term. This category also includes derivative financial in-
\n
struments entered into by the Group that are not desig-
\n
nated as hedging instruments in hedge relationships as
\n
defined by IFRS 9. Separated embedded derivatives are
\n
also classified as at fair value through profit or loss unless
\n
they are designated as effective hedging instruments.
\n
Gains or losses on liabilities at fair value through profit or
\n
loss are recognized through profit or loss.
\n
Financial liabilities designated upon initial recognition at
\n
fair value through profit or loss are designated at the initial
\n
date of recognition, only if the criteria in IFRS 9 are satis-
\n
fied.
\n
In this case, the portion of the change in fair value attribut-
\n
able to own credit risk is recognized in other comprehen-
\n
sive income.
\n
The Group has not designated any financial liability as at
\n
fair value through profit or loss, upon initial recognition.
\n
Financial liabilities that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n
Contracts to buy or sell non-financial items
\n
In general, contracts to buy or sell non-financial items that
\n
are entered into and continue to be held for receipt or
\n
delivery in accordance with the Group\u2019s normal expected
\n
purchase, sale or usage requirements are out of the scope
\n
of IFRS 9 and then recognized as executory contracts, ac-
\n
cording to the \u201cown use exemption\u201d.
\n
A contract to buy or sell non-financial items is classified as
\n
\u201cnormal purchase or sale\u201d if it is entered into:
\n
\u2022 for the purpose of the physical settlement;
\n
\u2022 in accordance with the entity\u2019s expected purchase, sale
\n
or usage requirements.
\n
Moreover, contracts to buy or sell non-financial items with
\n
physical settlement (for example, fixed-price forward con-
\n
tracts on energy commodities) that do not qualify for the
\n
own use exemption are recognized as derivatives mea-
\n
sured at fair value from the trade date only if:
\n
\u2022 they can be settled net in cash; and
\n
\u2022 they are not entered into in accordance with the Group\u2019s
\n
expected purchase, sale or usage requirements.
\n
Trading contracts are valued at fair value through profit or
\n
loss; the results of the measurement of changes in the fair
\n
value of contracts still outstanding at the reporting date
\n
are recognized on a net basis under the item \u201cNet results
\n
from commodity contracts\u201d, while at the settlement date:
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the sale of energy com-
\n
modities as well as the related revenue, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cRevenue from sales
\n
and services\u201d;
\n
\u2022 the results of the measurement of changes in the fair
\n
value of closed contracts for the purchase of energy
\n
commodities as well as the related cost, together with
\n
the impact on profit or loss of the derecognition of the
\n
derivative, are recognized under \u201cElectricity, gas and
\n
fuel\u201d and \u201cServices and other materials\u201d.
\n
Contracts to buy or sell non-financial items falling with-
\n
in the scope of application of IFRS 9 can also be subse-
\n
quently designated as hedging instruments if they satisfy
\n
the requirements for hedge accounting.
\n
The Group analyzes all contracts to buy or sell non-fi-
\n
nancial assets on an ongoing basis, with a specific focus
\n
on forward purchases and sales of electricity and energy
\n
commodities, in order to determine if they shall be classi-
\n
fied and treated in accordance with IFRS 9 or if they have
\n
been entered into for \u201cown use\u201d.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag174": { "value": "\n

\n\n

\n\n
Impairment of financial assets
\n
At each reporting date, the Group recognizes a loss allow-
\n
ance for expected credit losses on trade receivables and
\n
other financial assets measured at amortized cost, debt
\n
instruments measured at fair value through other com-
\n
prehensive income (FVOCI), contract assets and all other
\n
assets within the scope of IFRS 9.
\n
In compliance with IFRS 9, as from January 1, 2018, the
\n
Group adopted a new impairment model based on the
\n
determination of expected credit losses (ECL) using a for-
\n
ward-looking approach. In essence, the model provides
\n
for:
\n
\u2022 the application of a single framework for all financial as-
\n
sets;
\n
\u2022 the recognition of expected credit losses on an ongoing
\n
basis and the updating of the amount of such losses at
\n
the end of each reporting period, reflecting changes in
\n
the credit risk of the financial instrument;
\n
\u2022 the measurement of expected losses on the basis of
\n
reasonable information, obtainable without undue cost,
\n
about past events, current conditions and forecasts of
\n
future conditions.
\n
For trade receivables, contract assets and lease receiv-
\n
ables, including those with a significant financial compo-
\n
nent, the Group adopts the simplified approach, determin-
\n
ing expected credit losses over a period corresponding to
\n
the entire life of the asset, generally equal to 12 months.
\n
For all financial assets other than trade receivables, con-
\n
tract assets and lease receivables, the Group applies the
\n
general approach under IFRS 9, based on the assessment
\n
of a significant increase in credit risk since initial recogni-
\n
tion. Under such approach, a loss allowance on financial
\n
assets is recognized at an amount equal to the lifetime
\n
expected credit losses, if the credit risk on those financial
\n
assets has increased significantly, since initial recognition,
\n
considering all reasonable and supportable information,
\n
including also forward-looking inputs.
\n
If at the reporting date the credit risk on financial assets
\n
has not increased significantly since initial recognition,
\n
the Group measures the loss allowance for those financial
\n
assets at an amount equal to 12-month expected credit
\n
losses.
\n
For financial assets on which a loss allowance equal to life-
\n
time expected credit losses has been recognized in the
\n
previous reporting period, the Group measures the loss al-
\n
lowance at an amount equal to 12-month expected credit
\n
losses when the condition regarding a significant increase
\n
in credit risk is no longer met.
\n
The Group recognizes in profit or loss, as an impairment
\n
gain or loss, the amount of expected credit losses (or re-
\n
versal) that is required to adjust the loss allowance at the
\n
reporting date to the amount that is required to be recog-
\n
nized in accordance with IFRS 9.
\n
The Group applies the low credit risk exemption, avoid-
\n
ing the recognition of loss allowances at an amount equal
\n
to lifetime expected credit losses due to a significant in-
\n
crease in credit risk of debt securities at fair value through
\n
OCI, whose counterparty has a strong financial capacity
\n
to meet its contractual cash-flow obligations (e.g., invest-
\n
ment grade).
\n
For more information on the impairment of financial as-
\n
sets, please see note 48 \u201cFinancial instruments by cate-
\n
gory\u201d.
\n

\n

\n\n

\n

\n\n

\n

\n\n
The expected credit loss (ECL) \u2013 determined using proba-
\n
bility of default (PD), loss given default (LGD) and exposure
\n
at default (EAD) \u2013 is the difference between all contractual
\n
cash flows that are due in accordance with the contract
\n
and all cash flows that are expected to be received (i.e., all
\n
shortfalls) discounted at the original effective interest rate
\n
(EIR).
\n
For calculating ECL, the Group applies two different ap-
\n
proaches:
\n
\u2022 the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receivables.
\n
This approach, based on an assessment of any signif-
\n
icant increase in credit risk since initial recognition, is
\n
performed comparing the PD at origination with PD at
\n
the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss al-
\n
lowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e., staging):
\n
\u2013 12-month ECL, for financial assets for which there has
\n
not been a significant increase in credit risk since ini-
\n
tial recognition;
\n
\u2013 lifetime ECL, for financial assets for which there has
\n
been a significant increase in credit risk or which are
\n
credit impaired (i.e., defaulted based on past due in-
\n
formation);
\n
\u2022 the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a significant
\n
financing component, based on lifetime ECL without
\n
tracking changes in credit risk.
\n
A forward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
future events and macroeconomic developments that
\n
could impact the risk associated with the portfolio or fi-
\n
nancial instrument.
\n
Depending on the nature of the financial assets and the
\n
credit risk information available, the assessment of the in-
\n
crease in credit risk can be performed on:
\n
\u2022 an individual basis, if the receivables are individually sig-
\n
nificant and for all receivables which have been individ-
\n
ually identified for impairment based on reasonable and
\n
supportable information;
\n
\u2022 a collective basis, if no reasonable and supportable in-
\n
formation is available without undue cost or effort to
\n
measure expected credit losses on an individual instru-
\n
ment basis.
\n
When there is no reasonable expectation of recovering a
\n
financial asset in its entirety or a portion thereof, the gross
\n
carrying amount of the financial asset shall be reduced.
\n
A write-off represents a derecognition event (e.g., the right
\n
to cash flows is legally or contractually extinguished, trans-
\n
ferred or expired).
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag150": { "value": "\n
Cash and cash equivalents
\n
This category includes deposits that are available on de-
\n
mand or at very short term, as well as highly liquid short-
\n
term financial investments that are readily convertible into
\n
a known amount of cash and which are subject to insignif-
\n
icant risk of changes in value.
\n
In addition, for the purpose of the consolidated statement
\n
of cash flows, cash and cash equivalents do not include
\n
bank overdrafts at period-end.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag165": { "value": "\n

\n\n

\n\n
Financial liabilities at amortized cost
\n
This category mainly includes borrowings, trade payables,
\n
lease liabilities and debt instruments.
\n
Financial liabilities, other than derivatives, are recognized
\n
when the Group becomes a party to the contractual claus-
\n
es of the instrument and are initially measured at fair value
\n
adjusted for directly attributable transaction costs. Finan-
\n
cial liabilities are subsequently measured at amortized cost
\n
using the effective interest rate method. The effective in-
\n
terest rate is the rate that exactly discounts the estimated
\n
future cash payments or receipts over the expected life
\n
of the financial instrument or a shorter period, where ap-
\n
propriate, to the carrying amount of the financial asset or
\n
liability.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag164": { "value": "\n

\n\n
Financial liabilities at amortized cost
\n
This category mainly includes borrowings, trade payables,
\n
lease liabilities and debt instruments.
\n
Financial liabilities, other than derivatives, are recognized
\n
when the Group becomes a party to the contractual claus-
\n
es of the instrument and are initially measured at fair value
\n
adjusted for directly attributable transaction costs. Finan-
\n
cial liabilities are subsequently measured at amortized cost
\n
using the effective interest rate method. The effective in-
\n
terest rate is the rate that exactly discounts the estimated
\n
future cash payments or receipts over the expected life
\n
of the financial instrument or a shorter period, where ap-
\n
propriate, to the carrying amount of the financial asset or
\n
liability.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag155": { "value": "\n
Financial liabilities at amortized cost
\n
This category mainly includes borrowings, trade payables,
\n
lease liabilities and debt instruments.
\n
Financial liabilities, other than derivatives, are recognized
\n
when the Group becomes a party to the contractual claus-
\n
es of the instrument and are initially measured at fair value
\n
adjusted for directly attributable transaction costs. Finan-
\n
cial liabilities are subsequently measured at amortized cost
\n
using the effective interest rate method. The effective in-
\n
terest rate is the rate that exactly discounts the estimated
\n
future cash payments or receipts over the expected life
\n
of the financial instrument or a shorter period, where ap-
\n
propriate, to the carrying amount of the financial asset or
\n
liability.
\n

\n\n
Financial liabilities at fair value through profit or loss
\n
Financial liabilities at fair value through profit or loss in-
\n
clude financial liabilities held for trading and financial lia-
\n
bilities designated upon initial recognition as at fair value
\n
through profit or loss.
\n
Financial liabilities are classified as held for trading if they
\n
are incurred for the purpose of repurchasing in the near
\n
term. This category also includes derivative financial in-
\n
struments entered into by the Group that are not desig-
\n
nated as hedging instruments in hedge relationships as
\n
defined by IFRS 9. Separated embedded derivatives are
\n
also classified as at fair value through profit or loss unless
\n
they are designated as effective hedging instruments.
\n
Gains or losses on liabilities at fair value through profit or
\n
loss are recognized through profit or loss.
\n
Financial liabilities designated upon initial recognition at
\n
fair value through profit or loss are designated at the initial
\n
date of recognition, only if the criteria in IFRS 9 are satis-
\n
fied.
\n
In this case, the portion of the change in fair value attribut-
\n
able to own credit risk is recognized in other comprehen-
\n
sive income.
\n
The Group has not designated any financial liability as at
\n
fair value through profit or loss, upon initial recognition.
\n
Financial liabilities that qualify as contingent consideration
\n
are also measured at fair value through profit or loss.
\n

\n\n

\n\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022 the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022 the Group has transferred substantially all the risks and
\n
rewards associated with the asset, transferring its rights
\n
to receive the cash flows of the asset or assuming a con-
\n
tractual obligation to pay such cash flows to one or more
\n
beneficiaries under a contract that meets the require-
\n
ments provided by IFRS 9 (the \u201cpass through test\u201d);
\n
\u2022 the Group has not transferred or retained substantially
\n
all the risks and rewards associated with the asset but
\n
has transferred control over the asset.
\n
Financial liabilities are derecognized when they are extin-
\n
guished, i.e., when the contractual obligation has been dis-
\n
charged, cancelled or expired.
\n
When an existing financial liability is replaced by another
\n
from the same lender on substantially different terms, or
\n
the terms of an existing liability are substantially modi-
\n
fied, such an exchange or modification is treated as the
\n
derecognition of the original liability and the recognition
\n
of a new liability. The difference in the respective carrying
\n
amounts is recognized in profit or loss.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag149": { "value": "\n

\n\n

\n\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022 the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022 the Group has transferred substantially all the risks and
\n
rewards associated with the asset, transferring its rights
\n
to receive the cash flows of the asset or assuming a con-
\n
tractual obligation to pay such cash flows to one or more
\n
beneficiaries under a contract that meets the require-
\n
ments provided by IFRS 9 (the \u201cpass through test\u201d);
\n
\u2022 the Group has not transferred or retained substantially
\n
all the risks and rewards associated with the asset but
\n
has transferred control over the asset.
\n
Financial liabilities are derecognized when they are extin-
\n
guished, i.e., when the contractual obligation has been dis-
\n
charged, cancelled or expired.
\n
When an existing financial liability is replaced by another
\n
from the same lender on substantially different terms, or
\n
the terms of an existing liability are substantially modi-
\n
fied, such an exchange or modification is treated as the
\n
derecognition of the original liability and the recognition
\n
of a new liability. The difference in the respective carrying
\n
amounts is recognized in profit or loss.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag172": { "value": "\n

\n\n

\n\n
Derivative financial instruments
\n
A derivative is a financial instrument or another contract:
\n
\u2022 whose value changes in response to the changes in an
\n
underlying variable such as an interest rate, commodity
\n
or security price, foreign exchange rate, a price or rate
\n
index, a credit rating or other variable;
\n
\u2022 that requires no initial net investment, or one that is
\n
smaller than would be required for a contract with similar
\n
response to changes in market factors;
\n
\u2022 that is settled at a future date.
\n
Derivative instruments are classified as financial assets or
\n
liabilities depending on the positive or negative fair value
\n
and they are classified as \u201cheld for trading\u201d within \u201cOther
\n
business models\u201d and measured at fair value through prof-
\n
it or loss, except for those designated as effective hedging
\n
instruments.
\n
All derivatives held for trading are classified as current as-
\n
sets or liabilities.
\n
Derivatives not held for trading purposes, but measured at
\n
fair value through profit or loss since they do not qualify for
\n
hedge accounting, and derivatives designated as effective
\n
hedging instruments are classified as current or not cur-
\n
rent on the basis of their maturity date and the Group in-
\n
tention to hold the financial instrument till maturity or not.
\n
For more details about derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag153": { "value": "\n

\n\n
Derivative financial instruments
\n
A derivative is a financial instrument or another contract:
\n
\u2022 whose value changes in response to the changes in an
\n
underlying variable such as an interest rate, commodity
\n
or security price, foreign exchange rate, a price or rate
\n
index, a credit rating or other variable;
\n
\u2022 that requires no initial net investment, or one that is
\n
smaller than would be required for a contract with similar
\n
response to changes in market factors;
\n
\u2022 that is settled at a future date.
\n
Derivative instruments are classified as financial assets or
\n
liabilities depending on the positive or negative fair value
\n
and they are classified as \u201cheld for trading\u201d within \u201cOther
\n
business models\u201d and measured at fair value through prof-
\n
it or loss, except for those designated as effective hedging
\n
instruments.
\n
All derivatives held for trading are classified as current as-
\n
sets or liabilities.
\n
Derivatives not held for trading purposes, but measured at
\n
fair value through profit or loss since they do not qualify for
\n
hedge accounting, and derivatives designated as effective
\n
hedging instruments are classified as current or not cur-
\n
rent on the basis of their maturity date and the Group in-
\n
tention to hold the financial instrument till maturity or not.
\n
For more details about derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n
Embedded derivatives
\n
An embedded derivative is a derivative included in a \u201ccom-
\n
bined\u201d contract (the so-called \u201chybrid instrument\u201d) that
\n
contains another non-derivative contract (the so-called
\n
host contract) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows.
\n
The main Group contracts that may contain embedded
\n
derivatives are contracts to buy or sell non-financial items
\n
with clauses or options that affect the contract price, vol-
\n
ume or maturity.
\n
A derivative embedded in a hybrid contract containing a
\n
financial asset host is not accounted for separately. The fi-
\n
nancial asset host together with the embedded derivative
\n
is required to be classified in its entirety as a financial asset
\n
at fair value through profit or loss.
\n
Contracts that do not represent financial instruments to
\n
be measured at fair value are analyzed in order to identify
\n
any embedded derivatives, which are to be separated and
\n
measured at fair value. This analysis is performed when the
\n
Group becomes party to the contract or when the contract
\n
is renegotiated in a manner that significantly changes the
\n
original associated cash flows.
\n
Embedded derivatives are separated from the host con-
\n
tract and accounted for as derivatives when:
\n
\u2022 the host contract is not a financial instrument measured
\n
at fair value through profit or loss;
\n

\n\n
\u2022 the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the host
\n
contract;
\n
\u2022 a separate contract with the same terms as the embed-
\n
ded derivative would meet the definition of a derivative.
\n
Embedded derivatives that are separated from the host
\n
contract are recognized in the consolidated financial
\n
statements at fair value with changes recognized in profit
\n
or loss (except when the embedded derivative is part of a
\n
designated hedge relationship).
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag157": { "value": "\n
Offsetting financial assets and liabilities
\n
The Group offsets financial assets and liabilities when:
\n
\u2022 there is a legally enforceable right to set off the recog-
\n
nized amounts; and
\n
\u2022 there is the intention of settling on a net basis or realiz-
\n
ing the asset and settling the liability simultaneously.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOffsettingOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag170": { "value": "\n

\n
Non-current assets (or disposal groups)
\n
classified as held for sale and discontinued
\n
operations
\n\n
Non-current assets (or disposal groups) are classified as
\n
held for sale if their carrying amount will be recovered
\n
principally through a sale transaction, rather than through
\n
continuing use.
\n
This classification criterion is applicable only when
\n
non-current assets (or disposal groups) are available in
\n
their present condition for immediate sale and the sale is
\n
highly probable.
\n
If the Group is committed to a sale plan involving loss of
\n
control of a subsidiary and the requirements provided for
\n
under IFRS 5 are met, all the assets and liabilities of that
\n
subsidiary are classified as held for sale when the classi-
\n
fication criteria are met, regardless of whether the Group
\n
will retain a non-controlling interest in its former subsidiary
\n
after the sale.
\n
The Group applies these classification criteria as envisaged
\n
in IFRS 5 to an investment, or a portion of an investment, in
\n
an associate or a joint venture. Any retained portion of an
\n
investment in an associate or a joint venture that has not
\n
been classified as held for sale is accounted for using the
\n
equity method until disposal of the portion that is classified
\n
as held for sale takes place.
\n
Non-current assets (or disposal groups) and liabilities of
\n
disposal groups classified as held for sale are presented
\n

\n\n

\n\n

\n

\n\n
separately from other assets and liabilities in the state-
\n
ment of financial position.
\n
The amounts presented for non-current assets or for the
\n
assets and liabilities of disposal groups classified as held
\n
for sale are not reclassified or re-presented for prior peri-
\n
ods presented.
\n
Immediately before the initial classification of non-current
\n
assets (or disposal groups) as held for sale, the carrying
\n
amounts of such assets (or disposal groups) are measured
\n
in accordance with the accounting standard applicable to
\n
those assets or liabilities. Non-current assets (or disposal
\n
groups) classified as held for sale are measured at the low-
\n
er of their carrying amount and fair value less costs to sell.
\n
Impairment losses for any initial or subsequent write-down
\n
of the assets (or disposal groups) to fair value less costs to
\n
sell and gains for their reversals are recognized in profit or
\n
loss from continuing operations.
\n
Non-current assets are not depreciated (or amortized)
\n
while they are classified as held for sale or while they are
\n
part of a disposal group classified as held for sale.
\n
If the classification criteria are no longer met, the Group
\n
ceases to classify the non-current assets (or disposal
\n
group) as held for sale. In this case they are measured at
\n
the lower of:
\n
\u2022 the carrying amount before the asset (or disposal group)
\n
was classified as held for sale, adjusted for any depre-
\n
ciation, amortization or reversals of impairment losses
\n
that would have been recognized if the asset (or disposal
\n
group) had not been classified as held for sale; and
\n
\u2022 the recoverable amount, which is equal to the greater of
\n
its fair value net of costs to sell and its value in use, as
\n
calculated at the date of the subsequent decision not
\n
to sell.
\n
Any adjustment to the carrying amount of a non-current
\n
asset that ceases to be classified as held for sale is includ-
\n
ed in profit or loss from continuing operations.
\n

\n\n\n
A discontinued operation is a component of the Group
\n
that either has been disposed of, or is classified as held
\n
for sale, and:
\n
\u2022 represents a separate major business line or geograph-
\n
ical segment;
\n
\u2022 is part of a single coordinated plan to dispose of a sep-
\n
arate major business line or geographical segment; or
\n
\u2022 is a subsidiary acquired exclusively with a view to resale.
\n
The Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022 the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022 the post-tax gain or loss recognized on the measure-
\n
ment at fair value less costs to sell or on the disposal of
\n
the assets or disposal groups constituting the discon-
\n
tinued operation.
\n
The corresponding amount is restated in the income
\n
statement for prior periods presented in the financial
\n
statements, so that the disclosures relate to all operations
\n
that are discontinued by the end of the current report-
\n
ing period. If the Group ceases to classify a component
\n
as held for sale, the results of the component previously
\n
presented in discontinued operations are reclassified and
\n
included in profit or loss from continuing operations for all
\n
periods presented.
\n

\n

\n\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag173": { "value": "\n
Non-current assets (or disposal groups) are classified as
\n
held for sale if their carrying amount will be recovered
\n
principally through a sale transaction, rather than through
\n
continuing use.
\n
This classification criterion is applicable only when
\n
non-current assets (or disposal groups) are available in
\n
their present condition for immediate sale and the sale is
\n
highly probable.
\n
If the Group is committed to a sale plan involving loss of
\n
control of a subsidiary and the requirements provided for
\n
under IFRS 5 are met, all the assets and liabilities of that
\n
subsidiary are classified as held for sale when the classi-
\n
fication criteria are met, regardless of whether the Group
\n
will retain a non-controlling interest in its former subsidiary
\n
after the sale.
\n
The Group applies these classification criteria as envisaged
\n
in IFRS 5 to an investment, or a portion of an investment, in
\n
an associate or a joint venture. Any retained portion of an
\n
investment in an associate or a joint venture that has not
\n
been classified as held for sale is accounted for using the
\n
equity method until disposal of the portion that is classified
\n
as held for sale takes place.
\n
Non-current assets (or disposal groups) and liabilities of
\n
disposal groups classified as held for sale are presented
\n

\n\n
separately from other assets and liabilities in the state-
\n
ment of financial position.
\n
The amounts presented for non-current assets or for the
\n
assets and liabilities of disposal groups classified as held
\n
for sale are not reclassified or re-presented for prior peri-
\n
ods presented.
\n
Immediately before the initial classification of non-current
\n
assets (or disposal groups) as held for sale, the carrying
\n
amounts of such assets (or disposal groups) are measured
\n
in accordance with the accounting standard applicable to
\n
those assets or liabilities. Non-current assets (or disposal
\n
groups) classified as held for sale are measured at the low-
\n
er of their carrying amount and fair value less costs to sell.
\n
Impairment losses for any initial or subsequent write-down
\n
of the assets (or disposal groups) to fair value less costs to
\n
sell and gains for their reversals are recognized in profit or
\n
loss from continuing operations.
\n
Non-current assets are not depreciated (or amortized)
\n
while they are classified as held for sale or while they are
\n
part of a disposal group classified as held for sale.
\n
If the classification criteria are no longer met, the Group
\n
ceases to classify the non-current assets (or disposal
\n
group) as held for sale. In this case they are measured at
\n
the lower of:
\n
\u2022 the carrying amount before the asset (or disposal group)
\n
was classified as held for sale, adjusted for any depre-
\n
ciation, amortization or reversals of impairment losses
\n
that would have been recognized if the asset (or disposal
\n
group) had not been classified as held for sale; and
\n
\u2022 the recoverable amount, which is equal to the greater of
\n
its fair value net of costs to sell and its value in use, as
\n
calculated at the date of the subsequent decision not
\n
to sell.
\n
Any adjustment to the carrying amount of a non-current
\n
asset that ceases to be classified as held for sale is includ-
\n
ed in profit or loss from continuing operations.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag176": { "value": "\n
A discontinued operation is a component of the Group
\n
that either has been disposed of, or is classified as held
\n
for sale, and:
\n
\u2022 represents a separate major business line or geograph-
\n
ical segment;
\n
\u2022 is part of a single coordinated plan to dispose of a sep-
\n
arate major business line or geographical segment; or
\n
\u2022 is a subsidiary acquired exclusively with a view to resale.
\n
The Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022 the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022 the post-tax gain or loss recognized on the measure-
\n
ment at fair value less costs to sell or on the disposal of
\n
the assets or disposal groups constituting the discon-
\n
tinued operation.
\n
The corresponding amount is restated in the income
\n
statement for prior periods presented in the financial
\n
statements, so that the disclosures relate to all operations
\n
that are discontinued by the end of the current report-
\n
ing period. If the Group ceases to classify a component
\n
as held for sale, the results of the component previously
\n
presented in discontinued operations are reclassified and
\n
included in profit or loss from continuing operations for all
\n
periods presented.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag161": { "value": "\n

\n\n
Environmental certificates
\n
Some Group companies are affected by national regula-
\n
tions governing green certificates, guarantees of origin
\n
and energy efficiency certificates (so-called white certifi-
\n
cates), as well as the European \u201cEmissions Trading System\u201d.
\n
Green certificates and guarantees of origin accrued in
\n
proportion to electricity generated by renewable energy
\n
plants and energy efficiency certificates accrued in pro-
\n
portion to energy savings achieved that have been certified
\n
by the competent authority are treated as non-monetary
\n
government operating grants and are recognized at fair
\n
value, under other operating profit, with recognition of an
\n
asset under other non-financial assets, if the certificates
\n
are not yet credited to the ownership account, or under
\n
inventories, if the certificates have already been credited
\n
to that account.
\n
At the time the certificates are credited to the ownership
\n
account, they are reclassified from other assets to inven-
\n
tories.
\n
Revenue from the sale of such certificates is recognized
\n
under revenue, with a corresponding decrease in invento-
\n
ries.
\n
For the purposes of accounting for charges arising from
\n
such regulatory requirements, the Group uses the \u201cnet li-
\n
ability approach\u201d.
\n
Under this accounting policy, any environmental certifi-
\n
cates received free of charge and those self-produced as
\n
a result of Group\u2019s operations that will be used for com-
\n
pliance purposes are recognized at nominal value (nil). In
\n
addition, charges incurred for obtaining (in the market or
\n
in some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the re-
\n
porting period are recognized through profit or loss on an
\n
accrual basis under other operating costs, as they repre-
\n
sent \u201csystem charges\u201d consequent to compliance with a
\n
regulatory requirement.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEnvironmentRelatedExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag166": { "value": "\n
Employee benefits
\n
Liabilities related to employee benefits paid upon or after
\n
ceasing employment in connection with defined benefit
\n
plans or other long-term benefits accrued during the em-
\n
ployment period are determined separately for each plan,
\n
using actuarial assumptions to estimate the amount of the
\n
future benefits that employees have accrued at the report-
\n
ing date (using the projected unit credit method). More
\n
specifically, the present value of the defined benefit obli-
\n
gation is calculated by using a discount rate determined
\n
on the basis of market yields at the end of the reporting
\n

\n\n

\n

\n
period on high-quality corporate bonds. If there is no deep
\n
market for high-quality corporate bonds in the currency in
\n
which the bond is denominated, the corresponding yield
\n
of government securities is used.
\n
The liability, net of any plan assets, is recognized on an
\n
accrual basis over the vesting period of the related rights.
\n
These appraisals are performed by independent actuaries.
\n
If the plan assets exceed the present value of the related
\n
defined benefit obligation, the surplus (up to the limit of
\n
any cap) is recognized as an asset.
\n
As regards the liabilities/(assets) of defined benefit plans,
\n
the cumulative actuarial gains and losses from the actuari-
\n
al measurement of the liabilities, the return on the plan as-
\n
sets (net of the associated interest income) and the effect
\n
of the asset ceiling (net of the associated interest) are rec-
\n
ognized in other comprehensive income when they occur.
\n
For other long-term benefits, the related actuarial gains
\n
and losses are recognized through profit or loss.
\n
In the event of a change being made to an existing defined
\n
benefit plan or the introduction of a new plan, any past
\n
service cost is recognized immediately in profit or loss.
\n
In addition, the Group is involved in defined contribution
\n
plans under which it pays fixed contributions to a separate
\n
entity (a fund) and has no legal or constructive obligation
\n
to pay further contributions if the fund does not hold suf-
\n
ficient assets to pay all employee benefits relating to em-
\n
ployee service in the current and prior periods. Such plans
\n
are usually aimed to supplement pension benefits due to
\n
employees post-employment. The related costs are rec-
\n
ognized through profit or loss on the basis of the amount
\n
of contributions paid in the period.
\n\n
Termination benefits
\n
Liabilities for benefits due to employees for the early ter-
\n
mination of employee service arise out of the Group\u2019s de-
\n
cision to terminate an employee\u2019s employment before the
\n
normal retirement date or an employee\u2019s decision to ac-
\n
cept an offer of benefits in exchange for the termination
\n
of employment. The event that gives rise to an obligation is
\n
the termination of employment rather than employee ser-
\n
vice. Termination
\n
benefits are recognized at the earlier of
\n
the following dates:
\n
\u2022 when the entity can no longer withdraw its offer of ben-
\n
efits; and
\n
\u2022 when the entity recognizes a cost for a restructuring
\n
that is within the scope of IAS 37 and involves the pay-
\n
ment of termination benefits.
\n
The liabilities are measured on the basis of the nature of
\n
the employee benefits. More specifically, when the bene-
\n
fits represent an enhancement of other post-employment
\n
benefits, the associated liability is measured in accordance
\n
with the rules governing that type of benefits. Otherwise, if
\n
the termination benefits due to employees are expected to
\n
be settled wholly before 12 months of the close of the pe-
\n
riod in which the benefits are recognized, the entity mea-
\n
sures the liability in accordance with the requirements for
\n
short-term employee benefits; if they are not expected to
\n
be settled wholly before 12 months of the close of period
\n
in which the benefits are recognized, the entity measures
\n
the liability in accordance with the requirements for other
\n
long-term employee benefits.
\n

\n

\n\n\n
Share-based payments
\n
The Group undertakes share-based payment transactions
\n
settled with equity instruments as part of the remunera-
\n
tion policy adopted for the Chief Executive Officer/General
\n
Manager and for key management personnel.
\n
The most recent long-term incentive plans provide for
\n
the grant to recipients of an incentive represented by an
\n
equity component (settled with equity instruments) and
\n
a monetary component (paid in cash), which will accrue if
\n
specific conditions are met. The monetary component is
\n
classified as a cash-settled transaction if it is based on the
\n
price (or value) of the equity instruments of the company
\n
that issued the plan or, in other cases, as another long-
\n
term employee benefit.
\n
In order to settle the equity component through the bonus
\n
award of Enel shares, a program for the purchase of trea-
\n
sury shares to support these plans was approved. For more
\n
details on share-based incentive plans, please see note 53
\n
\u201cShare-based payments\u201d.
\n
For the equity component, the Group recognizes the ser-
\n
vices rendered by employees as personnel expenses over
\n
the period in which the conditions for remaining in service
\n
and for achieving certain results must be satisfied (vesting
\n
period) and indirectly estimates their value, and the corre-
\n
sponding increase in a specific equity item, on the basis
\n
of the fair value of the equity instruments (i.e., the issuer
\n
shares) at the grant date. This fair value is based on the ob-
\n
servable market price of the share, taking account of the
\n
terms and conditions under which the shares were grant-
\n
ed (with the exception of vesting conditions excluded from
\n
the measurement of fair value).
\n
The overall expense recognized is adjusted at each report-
\n
ing date until the vesting date to reflect the best estimate
\n
available to the Group of the number of equity instru-
\n
ments for which the service and performance conditions
\n
other than market conditions will be satisfied, so that the
\n
amount recognized at the end is based on the effective
\n
number of equity instruments that satisfy the service and
\n
performance conditions other than market conditions at
\n
the vesting date.
\n
No expense is recognized for awards which ultimately do
\n
not vest because the performance conditions other than
\n
market conditions and/or the service conditions have not
\n
been satisfied. Conversely, the transactions are consid-
\n
ered to have vested irrespective of whether the market or
\n
non-vesting conditions are satisfied, provided that all oth-
\n
er vesting conditions are met.
\n
If the incentive based on equity instruments is paid in cash,
\n

\n\n

\n\n

\n\n
the Group recognizes the services rendered by employ-
\n
ees as personnel expenses over the vesting period and a
\n
corresponding liability measured at the fair value of the li-
\n
ability incurred. Subsequently, and until its extinction, the
\n
liability is remeasured at fair value at each reporting date,
\n
considering the best possible estimate of the incentive
\n
that will vest, with changes in fair value recognized under
\n
personnel expenses. If the right to receive the monetary
\n
incentive does not vest because one or more conditions
\n
are not met, the related liability is reversed.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag167": { "value": "\n
Termination benefits
\n
Liabilities for benefits due to employees for the early ter-
\n
mination of employee service arise out of the Group\u2019s de-
\n
cision to terminate an employee\u2019s employment before the
\n
normal retirement date or an employee\u2019s decision to ac-
\n
cept an offer of benefits in exchange for the termination
\n
of employment. The event that gives rise to an obligation is
\n
the termination of employment rather than employee ser-
\n
vice. Termination
\n
benefits are recognized at the earlier of
\n
the following dates:
\n
\u2022 when the entity can no longer withdraw its offer of ben-
\n
efits; and
\n
\u2022 when the entity recognizes a cost for a restructuring
\n
that is within the scope of IAS 37 and involves the pay-
\n
ment of termination benefits.
\n
The liabilities are measured on the basis of the nature of
\n
the employee benefits. More specifically, when the bene-
\n
fits represent an enhancement of other post-employment
\n
benefits, the associated liability is measured in accordance
\n
with the rules governing that type of benefits. Otherwise, if
\n
the termination benefits due to employees are expected to
\n
be settled wholly before 12 months of the close of the pe-
\n
riod in which the benefits are recognized, the entity mea-
\n
sures the liability in accordance with the requirements for
\n
short-term employee benefits; if they are not expected to
\n
be settled wholly before 12 months of the close of period
\n
in which the benefits are recognized, the entity measures
\n
the liability in accordance with the requirements for other
\n
long-term employee benefits.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTerminationBenefits", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag158": { "value": "\n
Share-based payments
\n
The Group undertakes share-based payment transactions
\n
settled with equity instruments as part of the remunera-
\n
tion policy adopted for the Chief Executive Officer/General
\n
Manager and for key management personnel.
\n
The most recent long-term incentive plans provide for
\n
the grant to recipients of an incentive represented by an
\n
equity component (settled with equity instruments) and
\n
a monetary component (paid in cash), which will accrue if
\n
specific conditions are met. The monetary component is
\n
classified as a cash-settled transaction if it is based on the
\n
price (or value) of the equity instruments of the company
\n
that issued the plan or, in other cases, as another long-
\n
term employee benefit.
\n
In order to settle the equity component through the bonus
\n
award of Enel shares, a program for the purchase of trea-
\n
sury shares to support these plans was approved. For more
\n
details on share-based incentive plans, please see note 53
\n
\u201cShare-based payments\u201d.
\n
For the equity component, the Group recognizes the ser-
\n
vices rendered by employees as personnel expenses over
\n
the period in which the conditions for remaining in service
\n
and for achieving certain results must be satisfied (vesting
\n
period) and indirectly estimates their value, and the corre-
\n
sponding increase in a specific equity item, on the basis
\n
of the fair value of the equity instruments (i.e., the issuer
\n
shares) at the grant date. This fair value is based on the ob-
\n
servable market price of the share, taking account of the
\n
terms and conditions under which the shares were grant-
\n
ed (with the exception of vesting conditions excluded from
\n
the measurement of fair value).
\n
The overall expense recognized is adjusted at each report-
\n
ing date until the vesting date to reflect the best estimate
\n
available to the Group of the number of equity instru-
\n
ments for which the service and performance conditions
\n
other than market conditions will be satisfied, so that the
\n
amount recognized at the end is based on the effective
\n
number of equity instruments that satisfy the service and
\n
performance conditions other than market conditions at
\n
the vesting date.
\n
No expense is recognized for awards which ultimately do
\n
not vest because the performance conditions other than
\n
market conditions and/or the service conditions have not
\n
been satisfied. Conversely, the transactions are consid-
\n
ered to have vested irrespective of whether the market or
\n
non-vesting conditions are satisfied, provided that all oth-
\n
er vesting conditions are met.
\n
If the incentive based on equity instruments is paid in cash,
\n

\n\n
the Group recognizes the services rendered by employ-
\n
ees as personnel expenses over the vesting period and a
\n
corresponding liability measured at the fair value of the li-
\n
ability incurred. Subsequently, and until its extinction, the
\n
liability is remeasured at fair value at each reporting date,
\n
considering the best possible estimate of the incentive
\n
that will vest, with changes in fair value recognized under
\n
personnel expenses. If the right to receive the monetary
\n
incentive does not vest because one or more conditions
\n
are not met, the related liability is reversed.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag159": { "value": "\n

\n
Provisions for risks and charges
\n
Provisions are recognized where there is a legal or con-
\n
structive obligation as a result of a past event at the end
\n
of the reporting period, the settlement of which is expect-
\n
ed to result in an outflow of resources whose amount can
\n
be reliably estimated. Where the impact is significant, the
\n
accruals are determined by discounting expected future
\n
cash flows using a pre-tax discount rate that reflects the
\n
current market assessment of the time value of money
\n
and, if applicable, the risks specific to the liability.
\n
If the provision is discounted, the periodic adjustment of
\n
the present value for the time factor is recognized as a fi-
\n
nancial expense.
\n
When the Group expects some or all charges to be reim-
\n
bursed, the reimbursement is recognized as a separate
\n
asset, but only when the reimbursement is virtually certain.
\n\n
Where the liability relates to decommissioning and/or site
\n
restoration in respect of property, plant and equipment,
\n
the initial recognition of the provision is made against the
\n
related asset and the expense is then recognized in profit
\n
or loss through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of
\n
nuclear waste and other radioactive materials, the provi-
\n
sion is recognized against the related operating costs.
\n

\n\n
A liability for restructuring refers to a program planned
\n
and controlled by management that materially changes
\n
the scope of a business undertaken by the Group or the
\n
manner in which the business is conducted. Such a liabil-
\n
ity is recognized when a constructive obligation is estab-
\n
lished, i.e., when the Group has approved a detailed formal
\n
restructuring plan and has started to implement the plan
\n
or has announced its main features to those affected by it.
\n
Provisions do not include liabilities in respect of uncertain
\n
income tax treatments that are recognized as tax liabilities.
\n
The Group could provide a warranty in connection with
\n
the sale of a product (whether a good or service) from
\n
contracts with customers in the scope of IFRS 15, in ac-
\n
cordance with the contract, the law or its customary busi-
\n
ness practices. In this case, the Group assesses whether
\n
the warranty provides the customer with assurance that
\n
the related product will function as the parties intended
\n
because it complies with agreed-upon specifications or
\n
whether the warranty provides the customer with a service
\n
in addition to the assurance that the product complies
\n
with agreed-upon specifications.
\n
After the assessment, if the Group establishes that an
\n
assurance warranty is provided, it recognizes a separate
\n
warranty liability and corresponding expense when trans-
\n
ferring the product to the customer, as additional costs of
\n
providing goods or services, without attributing any of the
\n
transaction price (and therefore revenue) to the warranty.
\n
The liability is measured and presented as a provision.
\n
Otherwise, if the Group determines that a service warran-
\n
ty is provided, it accounts for the promised warranty as a
\n
performance obligation in accordance with IFRS 15, recog-
\n
nizing the contract liability as revenue over the period the
\n
warranty service is provided and the costs associated as
\n
they are incurred.
\n
Finally,
\n
if the warranty includes both an assurance element
\n
and a service element and the Group cannot reasonably
\n
account for them separately, then it accounts for both of
\n
the warranties together as a single performance obliga-
\n
tion.
\n
In the case of contracts in which the unavoidable costs of
\n
meeting the obligations under the contract exceed the
\n
economic benefits expected to be received under it (oner-
\n
ous contracts), the Group recognizes a provision as the
\n
lower of the excess of unavoidable costs of meeting the
\n
obligations (i.e., costs that relate directly to the contract,
\n
whether incremental or resulting from an allotment of oth-
\n
er costs) under the contract over the economic benefits
\n
expected to be received under it and any compensation or
\n
penalty arising from failure to fulfil it.
\n
Changes in estimates of accruals to the provisions ad-
\n
dressed here are recognized through profit or loss in the
\n
period in which the changes occur, with the exception of
\n
those in the costs of decommissioning, retiring and/or res-
\n
toration resulting from changes in the timetable and costs
\n
necessary to extinguish the obligation or from a change
\n
in the discount rate. These changes increase or decrease
\n
the carrying amount of the related assets and are taken to
\n
profit or loss through depreciation. Where they increase
\n
the carrying amount of the assets, it is also determined
\n
whether the new carrying amount of the assets is fully re-
\n
coverable. If this is not the case, a loss equal to the unre-
\n
coverable amount is recognized through profit or loss.
\n
Decreases in estimates are recognized up to the carrying
\n
amount of the assets. Any excess is recognized immedi-
\n
ately in profit or loss.
\n
For more information on the estimation criteria adopted
\n
in determining provisions for retiring and/or restoration of
\n
property, plant and equipment, especially those associated
\n
with decommissioning nuclear power plants and storage
\n
of waste fuel and other radioactive materials, please see
\n
note 2.1 \u201cUse of estimates and management judgment\u201d.
\n

\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag175": { "value": "\n
Revenue from contracts with customers
\n
The Group recognizes revenue from contracts with cus-
\n
tomers at an amount that reflects the consideration at
\n

\n\n

\n

\n

\n
which the Group expects to be entitled in exchange for
\n
those goods or services, using the five-step model envis-
\n
aged by IFRS 15:
\n
\u2022 identify the contract with the customer (step 1) as from
\n
when the contract is legally enforceable. If the criteria en-
\n
visaged for step 1 are not met, any consideration received
\n
from the customer is generally recognized as an advance;
\n
\u2022 identify the performance obligations in the contract (step
\n
2), that is, all goods or services promised in the contract,
\n
separating them into performance obligations to account
\n
for separately, if they are both capable of being distinct
\n
and distinct within the context of the contract, or, as an
\n
exception, as a single performance obligation, if they are
\n
a series of distinct goods or services that are substantially
\n
the same and that have the same pattern of transfer to
\n
the customer over time.
\n\n
For each distinct good or service identified, the Group
\n
determines whether it acts as a principal or agent. When
\n
the Group acts as agent, it recognizes revenue (corre-
\n
sponding to any fee or commission) on a net basis;
\n

\n\n
\u2022 determine the transaction price at inception of the con-
\n
tract (step 3) considering:
\n
\u2013 the amount of consideration to which the Group ex-
\n
pects to be entitled in exchange for transferring goods
\n
or services to a customer, excluding amounts collected
\n
on behalf of third parties (e.g., some sale taxes and val-
\n
ue-added taxes);
\n\n
\u2013 variable consideration, non-cash consideration re-
\n
ceived from a customer, consideration payable to a
\n

\n\n
customer and a significant financing component. The
\n
transaction price is updated each reporting period for
\n
any changes in circumstances;
\n
\u2022 allocate the transaction price (step 4) at contract incep-
\n
tion to each separate performance obligation, including
\n
any option to acquire additional goods or services that
\n
represents a material right (deferring the relative revenue
\n
until those future goods or services are transferred or
\n
the option expires), generally on the basis of the relative
\n
stand-alone selling price of each distinct good or service
\n
promised in the contract;
\n\n
\u2022 recognize revenue (step 5), when (or as) each perfor-
\n
mance obligation is satisfied by transferring the promised
\n
good or service to the customer.
\n

\n\n
The Group does not disclose the information about the
\n
remaining performance obligations in existing contracts if
\n
the performance obligation is part of a contract that has
\n
an original expected duration of one year or less and if the
\n
Group recognizes revenue in the amount to which it has a
\n
right to invoice the customer.
\n
More information on the application of this revenue recog-
\n
nition model is provided in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and in note 11.a \u201cRevenue from
\n
sales and services\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag160": { "value": "\n
For each distinct good or service identified, the Group
\n
determines whether it acts as a principal or agent. When
\n
the Group acts as agent, it recognizes revenue (corre-
\n
sponding to any fee or commission) on a net basis;
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFeeAndCommissionIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag168": { "value": "\n
\u2013 variable consideration, non-cash consideration re-
\n
ceived from a customer, consideration payable to a
\n

\ncustomer and a significant financing component.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDiscountsAndRebatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag171": { "value": "\n
\u2022 recognize revenue (step 5), when (or as) each perfor-
\n
mance obligation is satisfied by transferring the promised
\n
good or service to the customer.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForConstructionInProgressExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag154": { "value": "\n
\u2022 revenue from the sale of energy commodities based on
\n
contracts with physical settlement, which do not qualify
\n
for the own use exemption and therefore is recognized
\n
at FVTPL in accordance with IFRS 9;
\n

\n\n
\u2022 income and expense from derivatives measured at fair
\n
value through profit or loss on interest rate and currency
\n
risk;
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradingIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag152": { "value": "\n
Other operating income
\n
Other operating income primarily includes gains on dis-
\n
posal of assets that are not an output of the Group\u2019s ordi-
\n
nary activities and government grants.
\n
Government grants, including non-monetary grants at fair
\n
value, are recognized where there is reasonable assurance
\n
that they will be received and that the Group will comply
\n
with all conditions attaching to them as set by the govern-
\n
ment, government agencies and similar bodies whether
\n
local, national or international.
\n
When loans are provided by governments at a below-mar-
\n
ket rate of interest, the benefit is regarded as a govern-
\n
ment grant. The loan is initially recognized and measured
\n
at fair value and the government grant is measured as the
\n
difference between the initial carrying amount of the loan
\n
and the funds received. The loan is subsequently measured
\n
in accordance with the requirements for financial liabilities.
\n
Government grants are recognized in profit or loss on a
\n
systematic basis over the periods in which the Group rec-
\n
ognizes as expenses the costs that the grants are intended
\n
to compensate.
\n
Where the Group receives government grants in the form
\n
of a transfer of a non-monetary asset for the use of the
\n
Group, it accounts for both the grant and the asset at the
\n
fair value of the non-monetary asset received at the date
\n
of the transfer.
\n
Capital grants, including non-monetary grants at fair val-
\n
ue, i.e., those received to purchase, build or otherwise ac-
\n
quire non-current assets (for example, an item of property,
\n
plant and equipment or an intangible asset), are deducted
\n
from the carrying amount of the asset and are recognized
\n
in profit or loss over the depreciable/amortizable life of
\n
the asset as a reduction in the depreciation/amortization
\n
charge. If there is insufficient information to enable ade-
\n
quate attribution to the fixed assets to which they refer,
\n
capital grants are recognized as deferred income under
\n
other liabilities, and credited to profit or loss on a system-
\n
atic basis over the useful life of the asset.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGovernmentGrants", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag178": { "value": "\n

\n\n

\n

\n

\n

\n
Financial income and expense from derivatives
\n
Financial income and expense from derivatives include:
\n\n
\u2022 income and expense from derivatives measured at fair
\n
value through profit or loss on interest rate and currency
\n
risk;
\n

\n\n\n
\u2022 income and expense from fair value hedge derivatives
\n
on interest rate risk;
\n
\u2022 income and expense from cash flow hedge derivatives
\n
on interest rate and currency risks.
\n

\n\n
Other financial income and expense
\n
For all financial assets and liabilities measured at amortized
\n
cost and interest-bearing financial assets classified as at
\n
fair value through other comprehensive income, interest
\n
income and expense are recognized using the effective
\n
interest rate method.
\n
Interest income is recognized to the extent that it is prob-
\n
able that the economic benefits will flow to the Group and
\n
the amount can be reliably measured.
\n
Other financial income and expense include also changes
\n
in the fair value of financial instruments other than deriv-
\n
atives.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag151": { "value": "\n

\n

\n

\n

\n
Financial income and expense from derivatives
\n
Financial income and expense from derivatives include:
\n\n
\u2022 income and expense from derivatives measured at fair
\n
value through profit or loss on interest rate and currency
\n
risk;
\n

\n\n\n
\u2022 income and expense from fair value hedge derivatives
\n
on interest rate risk;
\n
\u2022 income and expense from cash flow hedge derivatives
\n
on interest rate and currency risks.
\n

\n\n
Other financial income and expense
\n
For all financial assets and liabilities measured at amortized
\n
cost and interest-bearing financial assets classified as at
\n
fair value through other comprehensive income, interest
\n
income and expense are recognized using the effective
\n
interest rate method.
\n
Interest income is recognized to the extent that it is prob-
\n
able that the economic benefits will flow to the Group and
\n
the amount can be reliably measured.
\n
Other financial income and expense include also changes
\n
in the fair value of financial instruments other than deriv-
\n
atives.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceIncomeAndCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag162": { "value": "\n
\u2022 income and expense from fair value hedge derivatives
\n
on interest rate risk;
\n
\u2022 income and expense from cash flow hedge derivatives
\n
on interest rate and currency risks.
\n

\n\n
51.1 Derivatives designated as hedging
\n
instruments
\n
Derivatives are initially recognized at fair value, on the trade
\n
date of the contract, and are subsequently re-measured at
\n
their fair value. The method of recognizing the resulting
\n
gain or loss depends on whether the derivative is desig-
\n
nated as a hedging instrument, and if so, the nature of the
\n
item being hedged.
\n
Hedge accounting is applied to derivatives entered into in
\n
order to reduce risks such as interest rate risk, currency
\n
risk, commodity price risk (including Virtual PPAs) and net
\n
investments in foreign operations when all the criteria pro-
\n
vided by IFRS 9 are met.
\n
At the inception of the transaction, the Group docu-
\n
ments the relationship between hedging instruments and
\n
hedged items, as well as its risk management objectives
\n
and strategy. The Group also documents its assessment,
\n
both at hedge inception and on an ongoing basis, of
\n
whether hedging instruments are highly effective in offset-
\n
ting changes in fair values or cash flows of hedged items.
\n
For cash flow hedges of forecast transactions designat-
\n
ed as hedged items, the Group assesses and documents
\n
that they are highly probable and present an exposure to
\n
changes in cash flows that affect profit or loss.
\n
Depending on the nature of the risk exposure, the Group
\n
designates derivatives as either:
\n
\u2022 fair value hedges;
\n
\u2022 cash flow hedges.
\n
For more details about the nature and the extent of risks
\n
arising from financial instruments to which the Group is
\n
exposed, please see note 49 \u201cRisk management\u201d.
\n
To be effective a hedge relationship shall meet all of the
\n
following criteria:
\n
\u2022 existence of an economic relationship between hedging
\n
instrument and hedged item;
\n
\u2022 the effect of credit risk does not dominate the value
\n
changes resulting from the economic relationship;
\n
\u2022 the hedge ratio defined at initial designation shall be
\n
equal to the one used for risk management purposes
\n
(i.e., same quantity of the hedged item that the entity
\n
actually hedges and the quantity of the hedging instru-
\n
ment that the entity actually uses to hedge the quantity
\n
of the hedged item).
\n
Based on the IFRS 9 requirements, the existence of an
\n
economic relationship is evaluated by the Group through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n

\n\n

\n
\u2022 if the underlying risk of the hedging instrument and the
\n
hedged item is the same, the existence of an economic
\n
relationship will be provided through a qualitative anal-
\n
ysis;
\n
\u2022 on the other hand, if the underling risk of the hedging
\n
instrument and the hedged item is not the same, the
\n
existence of the economic relationship will be demon-
\n
strated through a quantitative method in addition to a
\n
qualitative analysis of the nature of the economic rela-
\n
tionship (i.e., linear regression).
\n
In order to demonstrate that the behavior of the hedging
\n
instrument is in line with those of the hedged item, differ-
\n
ent scenarios will be analyzed.
\n
For hedging of commodity price risk, the existence of an
\n
economic relationship is deduced from a ranking matrix
\n
that defines, for each possible risk component, a set of all
\n
standard derivatives available in the market whose ranking
\n
is based on their effectiveness in hedging the considered
\n
risk.
\n
In order to evaluate the credit risk effects, the Group con-
\n
siders the existence of risk mitigating measures (collateral,
\n
mutual break-up clauses, netting agreements, etc.).
\n
The Group has established a hedge ratio of 1:1 for all the
\n
hedge relationships (including commodity price risk hedg-
\n
ing) as the underlying risk of the hedging derivative is
\n
identical to the hedged risk, in order to minimize hedging
\n
ineffectiveness.
\n
The hedge ineffectiveness will be evaluated through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument match and there are no other sources of inef-
\n
fectiveness including the credit risk adjustment on the
\n
hedging derivative, the hedge relationship will be con-
\n
sidered fully effective on the basis of a qualitative as-
\n
sessment;
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument do not match or there is at least one source of
\n
ineffectiveness, the hedge ineffectiveness will be quan-
\n
tified applying the dollar offset cumulative method with
\n
hypothetical derivative. This method compares changes
\n
in fair value of the hedging instrument and the hypo-
\n
thetical derivative between the reporting date and the
\n
inception date.
\n
The main causes of hedge ineffectiveness can be the fol-
\n
lowing:
\n
\u2022 basis differences (i.e., the fair value or cash flows of the
\n
hedged item depend on a variable that is different from
\n
the variable that causes the fair value or cash flows of
\n
the hedging instrument to change);
\n
\u2022 timing differences (i.e., the hedged item and hedging in-
\n
strument occur or are settled at different dates);
\n
\u2022 quantity or notional amount differences (i.e., the hedged
\n
item and hedging instrument are based on different
\n
quantities or notional amounts);
\n
\u2022 other risks (i.e., changes in the fair value or cash flows of
\n
a derivative hedging instrument or hedged item relate to
\n
risks other than the specific risk being hedged);
\n
\u2022 credit risk (i.e., the counterparty credit risk differently im-
\n
pact the changes in the fair value of the hedging instru-
\n
ments and hedged items).
\n
The macroeconomic context became particularly unstable
\n
in 2022, due to the conflict between Russia and Ukraine,
\n
impacting raw material supply chains and causing high
\n
price volatility, especially in the energy sector. In this con-
\n
text, the commodity risk was managed effectively and did
\n
not have a significant impact on the soundness of hedging
\n
relationships, also thanks to the solidity of the integrated
\n
portfolio models used in the main European areas in which
\n
the Group operates and the geographical diversification of
\n
our sources of supply. Even credit risk was essentially un-
\n
affected, as the Group\u2019s main trading counterparties have
\n
a high credit rating or are adequately secured by bank or
\n
insurance guarantees.
\n
The conflict and the difficult macroeconomic conditions
\n
had only a limited impact on the management of interest
\n
rate and exchange rate risk, being insufficient to direct-
\n
ly and significantly influence the valuation of derivative
\n
instruments and the outcome of effectiveness checks of
\n
hedges. The volatility that buffeted financial markets was
\n
offset by risk mitigation actions using derivative financial
\n
instruments.
\n
Fair value hedges
\n
Fair value hedges are used to protect the Group against
\n
exposures to changes in the fair value of assets, liabilities
\n
or firm commitment attributable to a particular risk that
\n
could affect profit or loss.
\n
Changes in the fair value of derivatives that qualify and are
\n
designated as hedging instruments are recognized in the
\n
income statement, together with changes in the fair value
\n
of the hedged item that are attributable to the hedged risk.
\n
If the hedge no longer meets the criteria for hedge ac-
\n
counting, the adjustment to the carrying amount of a
\n
hedged item for which the effective interest rate method
\n
is used is amortized to profit or loss over the period to ma-
\n
turity.
\n

\n\n

\n

\n
Cash flow hedges
\n
Cash flow hedges are applied in order to hedge the Group
\n
exposure to changes in future cash flows that are attribut-
\n
able to a particular risk associated with a recognized asset
\n
or liability or a highly probable transaction that could affect
\n
profit or loss.
\n
The effective portion of changes in the fair value of deriv-
\n
atives that are designated and qualify as cash flow hedges
\n
is recognized in other comprehensive income. The gain or
\n
loss relating to the ineffective portion is recognized imme-
\n
diately in the income statement.
\n
Amounts accumulated in equity are reclassified to profit
\n
or loss in the periods when the hedged item affects profit
\n
or loss (for example, when the hedged forecast sale takes
\n
place).
\n
If the hedged item results in the recognition of a non-fi-
\n
nancial asset (i.e., property, plant and equipment or inven-
\n
tories, etc.) or a non-financial liability, or a hedged forecast
\n
transaction for a non-financial asset or a non-financial
\n
liability becomes a firm commitment for which fair value
\n
hedge accounting is applied, the amount accumulated in
\n
equity (i.e., hedging reserve) shall be removed and included
\n
in the initial amount (cost or other carrying amount) of the
\n
asset or the liability hedged (i.e., \u201cbasis adjustment\u201d).
\n
When a hedging instrument expires or is sold, or when a
\n
hedge no longer meets the criteria for hedge accounting,
\n
any cumulative gain or loss existing in equity at that time
\n
remains in equity and is recognized when the forecast
\n
transaction is ultimately recognized in the income state-
\n
ment. When a forecast transaction is no longer expected
\n
to occur, the cumulative gain or loss that was reported in
\n
equity is immediately transferred to the income statement.
\n
For hedge relationships using forwards as a hedging in-
\n
strument, where only the change in the value of the spot
\n
element is designated as the hedging instrument, ac-
\n
counting for the forward element (profit or loss vs OCI) is
\n
defined case by case. This approach is actually applied by
\n
the Group for hedging of currency risk on renewables as-
\n
sets.
\n
Conversely, for hedge relationships using cross currency
\n
interest rate swaps as hedging instruments, the Group
\n
separates foreign currency basis spread, in designating
\n
the hedging derivative, and present them in other com-
\n
prehensive income (OCI) as hedging costs.
\n
With specific regard to cash flow hedges of commodity
\n
risk, in order to improve their consistency with the risk
\n
management strategy, the Enel Group applies a dynamic
\n
hedge accounting approach based on specific liquidity re-
\n
quirements (the so-called liquidity-based approach).
\n
This approach requires the designation of hedges through
\n
the use of the most liquid derivatives available on the mar-
\n
ket and replacing them with others that are more effective
\n
in covering the risk in question.
\n
Consistent with the risk management strategy, the liquid-
\n
ity-based approach allows the roll-over of a derivative by
\n
replacing it with a new derivative, not only in the event of
\n
expiry but also during the hedge relationship, if and only
\n
if the new derivative meets both of the following require-
\n
ments:
\n
\u2022 it represents a best proxy of the old derivative in terms
\n
of ranking;
\n
\u2022 it meets specific liquidity requirements.
\n
Satisfaction of these requirements is verified quarterly.
\n
At the roll-over date, the hedge relationship is not discon-
\n
tinued. Accordingly, starting from that date, changes in the
\n
effective fair value of the new derivative will be recognized
\n
in equity (the hedging reserve), while changes in the fair
\n
value of the old derivative are recognized through profit
\n
or loss.
\n\n
Reform of benchmarks for the determination of interest
\n
rates \u2013 IBOR reform
\n
Overview
\n
Interbank Offered Rates (\u201cIBORs\u201d) are benchmark rates at
\n
which banks can borrow funds on the interbank market on
\n
an unsecured basis for a given period ranging from over-
\n
night to 12 months, in a specific currency.
\n
In recent years there have been a number of cases of ma-
\n
nipulation of these rates by the banks contributing to their
\n
calculation. For this reason, regulators around the world
\n
have begun a sweeping reform of interest rate bench-
\n
marks that includes the replacement of some benchmarks
\n
with alternative risk-free rates (the IBOR reform).
\n
The Group\u2019s main exposure is based on Euribor and USD
\n
LIBOR.
\n
Euribor is still considered compliant with the European
\n
Benchmarks Regulation (BMR) and this permits market
\n
participants to continue to use it for both existing and new
\n
contracts.
\n
In line with the most recent guidance issued by the major
\n
regulatory bodies:
\n
\u2022 the 1-month, 3-month and 6-month USD LIBOR bench-
\n
marks will become unrepresentative after June 30, 2023
\n
and the alternative reference rate will be the Secured
\n
Overnight Financing Rate (SOFR);
\n
\u2022 the 1-month, 3-month and 6-month GBP LIBOR bench-
\n
marks will become unrepresentative after December 31,
\n
2021 and the alternative reference rate will be the Ster-
\n
ling Overnight Index Average (SONIA).
\n
As a result of the IBOR reform, a number of temporary ex-
\n
ceptions to the rules on hedge relationships have been al-
\n
lowed in implementation of the amendments to IFRS 9 is-
\n
sued in September 2019 (Phase 1) and August 2020 (Phase
\n
2) to address, respectively:
\n

\n\n

\n\n

\n

\n

\n\n
\u2022 pre-replacement issues that impact financial reporting
\n
in the period preceding the replacement of an existing
\n
interest rate benchmark with an alternative risk-free rate
\n
(Phase 1); and
\n
\u2022 post-replacement issues that could impact financial
\n
reporting when an existing interest rate benchmark is
\n
reformed or replaced and there is no longer any initial
\n
uncertainty, but hedge contracts and relationships still
\n
need to be updated to reflect the new benchmark rates
\n
(Phase 2).
\n
Impact of the IBOR reform on the Group
\n
In a context of uncertainty regarding the IBOR transition in
\n
the various countries, the Group has determined the over-
\n
all number and nominal value of the contracts impacted by
\n
the reform. In addition, a number of contractual amend-
\n
ments have already been implemented in contracts pre-
\n
viously indexed to GBP LIBOR in 2021 and others will be
\n
amended in 2023 on the basis of the evolution of the IBOR
\n
reform and market practice.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and USD LIBOR and is almost entirely
\n
hedged using financial derivatives.
\n
At the reporting date, the Group is planning to take no
\n
action with regard to Euribor since, as stated above, this
\n
benchmark has been comprehensively reformed to com-
\n
ply with the European Benchmarks Regulation. Despite the
\n
continuity with Euribor, replacement clauses may be re-
\n
quired and could therefore be implemented by the Group
\n
in the new contracts in accordance with the evolution of
\n
accepted market practice.
\n
During 2022, the Group obtained new US dollar loans in-
\n
dexed to SOFR. The main focus over the coming months
\n
will be how to change existing USD LIBOR to USD SOFR ex-
\n
posures and how to use the new, alternative risk-free rates
\n
for new financial transactions.
\n
The Group\u2019s derivative instruments are managed through
\n
contracts that are mainly based on framework agreements
\n
defined by the International Swaps and Derivatives Associ-
\n
ation (ISDA).
\n
The ISDA has revised its standardized contracts in light of
\n
the IBOR reform and amended the choices for floating rates
\n
within the 2006 ISDA definitions to include replacement
\n
clauses that would apply upon the permanent discontinu-
\n
ation of specific key benchmarks. These changes took ef-
\n
fect on January 25, 2021. Transactions represented in the
\n
2006 ISDA definitions carried out on January 25, 2021 or
\n
later include adjusted floating-rate options (e.g., the choice
\n
of floating rate with replacement clause), while transactions
\n
completed before that date (previous derivative contracts)
\n
continue to be based on the 2006 ISDA definitions.
\n
For this reason, the ISDA published an IBOR Fallback Pro-
\n
tocol to facilitate multilateral amendments to include the
\n
amended definitions.
\n
The Group is assessing whether to: (i) adopt that protocol
\n
in the light of its exposure and developments in the IBOR
\n
reform or (ii) adjust in advance any contracts impacted bi-
\n
laterally by the reform.
\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, USD LIBOR and
\n
SONIA.
\n
The Group has assessed the impact of uncertainty engen-
\n
dered by the IBOR reform on hedge relationships at De-
\n
cember 31, 2022 with reference to both hedging instru-
\n
ments and hedged items. Both the hedged items and the
\n
hedging instruments will change their parameterization
\n
from interbank market-based benchmarks (IBORs) to al-
\n
ternative risk-free rates (RFRs) as a result of the contrac-
\n
tual amendments that will take effect in the coming years.
\n
In particular, uncertainty remains as to how the replacement
\n
will take place with regard to both hedging instruments and
\n
hedged items indexed to USD LIBOR. The Group manages
\n
the uncertainty associated with these hedge relationships
\n
by continuing to apply the temporary exceptions provided
\n
for in the amendments to IFRS 9 issued in September 2019
\n
(Phase 1). It was therefore felt that the benchmark indices
\n
for determining the interest rates on which the cash flows
\n
of the hedged items or the hedging instruments are based
\n
would not change as a consequence of the IBOR reform.
\n
The exception was applied for the following hedge rela-
\n
tionship requirements:
\n
\u2022 determine if a forecast transaction is highly probable;
\n
\u2022 establish whether the future hedged cash flows will arise
\n
in a discontinued cash flow hedge relationship;
\n
\u2022 assess the economic relationship between the hedged
\n
item and the hedging instrument.
\n
The hedge relationships impacted may become ineffective
\n
attributable to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In any case,
\n
the Group will seek to implement the replacements at the
\n
same time.
\n
In addition, the Group changed the reference to GBP LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically equiv-
\n
alent, SONIA benchmark at the end of 2021. Consequently,
\n
the Group no longer applies the amendments to IFRS 9
\n
issued in September 2019 (Phase 1) to these hedge rela-
\n
tionships and, consequently, is applying the amendments
\n
to IFRS 9 issued in August 2020 (Phase 2), modifying the
\n
formal designation of the hedge relationship as required
\n
by the IBOR reform and without considering this event as a
\n
termination of the hedge relationship.
\n

\n\n

\n\n

\n

\n

\n

\n

\n\n
Furthermore, for cash flow hedge relationships, in modify-
\n
ing the description of the hedged item in the hedge rela-
\n
tionship, the amounts accumulated in the cash flow hedge
\n
reserve were considered on the basis of the alternative
\n
benchmark index in relation to which the future hedged
\n
cash flows are determined.
\n
The following table provides details of the notional amounts
\n
of the hedging instruments for which the amendments to
\n
IFRS 9 (both Phase 1 and Phase 2) were applied as at De-
\n
cember 31, 2022, broken down by the alternative bench-
\n
mark index used for determining the interest rate.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022
\n
Hedging instruments Phase 1 Phase 2
\n
USD LIBOR/SOFR 977 -
\n
GBP LIBOR/SONIA - 1,240
\n
Tot al 977
\n
1,240
\n

\n\n\n
Unamended contracts including those with specific
\n
replacement clauses
\n
The Group is monitoring the evolution of the transition
\n
from the old interest rate benchmarks to the new rates,
\n
reviewing the overall value of contracts that have not yet
\n
been indexed to the new benchmark rates and, among
\n
these, the value of contracts which already include specific
\n
replacement clauses. The Group considers a contract to
\n
have not yet incorporated an alternative benchmark rate
\n
when the interest rate of the contract is indexed to an in-
\n
terest rate benchmark still involved in the IBOR reform and,
\n
therefore, when uncertainties still exist as to how and when
\n
replacement with the new benchmark will take place.
\n

\n

\n\n
51.1.1 Hedge relationships by type of risk hedged
\n
Interest rate risk
\n
The following table shows the notional amount and the
\n
average interest rate of instruments hedging the interest
\n
rate risk on transactions outstanding at December 31,
\n
2022 and December 31, 2021, broken down by maturity.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Interest rate swaps
\n
Total notional amount 159 722 573 902 2,017 3,382 7,755
\n
Notional amount related to IRS in euro 159 623 573 682 1,558 2,724 6,319
\n
Average IRS rate in euro 4.41 2.24 1.91 2.20 1.84 1.61
\n
Notional amount related to IRS in US dollars - 47 - - 459 237 743
\n
Average IRS rate in US dollars 0.70 3.23 3.84
\n

\n\n

\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the interest rate risk
\n
of transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument
\n
Hedged item
\n
Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Fair value hedges
\n
Interest rate swaps Floating-rate borrowings/bonds 20 (2) 518 13 (1) 241
\n
Interest rate swaps Fixed-rate borrowings/bonds 2 (90) 1,239 6 (4)
\n
558
\n
Cash flow hedges
\n
Interest rate swaps Floating-rate bonds 29 (44)
\n
1,190 - (167) 1,190
\n
Interest rate swaps Floating-rate loan assets - (9) 162 13 (1) 164
\n
Interest rate swaps Floating-rate borrowings 307 (7) 4,646 6 (461)
\n
6,510
\n
Tot al 358 (152) 7,755 38 (634) 8,663
\n
The following table shows the notional amount and the fair
\n
value of hedging derivatives on interest rate risk as at De-
\n
cember 31, 2022 and December 31, 2021 broken down by
\n
type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
Interest rate swaps 154 139 22 19 1,603 660 (92) (5)
\n
Total 154 139 22 19 1,603 660 (92) (5)
\n
Cash flow hedges
\n
Interest rate swaps 4,958 404 336 19 1,040 7,460 (60) (629)
\n
Total 4,958 404 336 19 1,040 7,460 (60) (629)
\n
TOTAL INTEREST RATE
\n
DERIVATIVES
\n
5,112 543 358 38 2,643 8,120 (152) (634)
\n
The notional amount of derivatives classified as hedging
\n
instruments at December 31, 2022 came to \u20ac7,755 million,
\n
with a corresponding positive fair value of \u20ac206 million.
\n
Compared with December 31, 2021, the notional amount
\n
decreased by \u20ac908 million, mainly reflecting:
\n
\u2022 the expiry of interest rate swaps amounting to \u20ac481 mil-
\n
lion;
\n
\u2022 the classification as assets held for sale of Australian
\n
companies holding interest rate financial derivatives in
\n
the amount of \u20ac340 million;
\n
\u2022 new interest rate swaps amounting to \u20ac1,174 million;
\n
\u2022 the reduction in the notional amount of amortizing inter-
\n
est rate swaps in the amount of \u20ac211 million.
\n
We also note the early closure of interest rate swaps for
\n
an amount of \u20ac1,050 million. The improvement in the fair
\n
value of \u20ac802 million mainly reflects developments in the
\n
yield curve.
\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss in respect of fair value hedge
\n
derivatives and the hedged item that are attributable to in-
\n
terest rate risk both in 2022 and the previous year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (84) (10)
\n
Hedged item 75 3
\n
Ineffective portion (9) (7)
\n

\n\n
The following table shows the impact of fair value hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 1,757 (70) (70) 799 14 14
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds 1,152 (87) (81) 562 4 (8)
\n
Floating-rate borrowings/bonds 576 (16) (18) 262 (9) 12
\n
Total 1,728 (103) (99) 824 (5) 4
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on interest rate
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on interest
\n
rates
\n
Positive fair value 336 80 98 60 48 64 -
\n
Negative fair value (60) (15) (10) (10) (8) (24) -
\n
The following table shows the impact of cash flow hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 5,998 276 276 7,864 (610)
\n
(610)
\n

\n\n

\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
bonds
\n
15 - (15) - - 167 - (167) - -
\n
Floating-rate
\n
loan assets
\n
9 - (9) - - (12) - 12 - -
\n
Floating-rate
\n
borrowings
\n
(327) (28) 326 - 2 417 (32) (417) - (6)
\n
Total (303) (28) 302 - 2 572 (32) (572) - (6)
\n\n
Currency risk
\n
The following table reports the maturity profile of the no-
\n
tional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRS)
\n
Total notional amount of CCIRS 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRS EUR/USD 1,171 2,290 2,107 1,171 1,615 11,529 19,883
\n
Average exchange rate EUR/USD 1.33 1.13 1.07 1.18 1.10 1.15
\n
Notional amount for CCIRS EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount for CCIRS EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 140 288 239 94 - - 761
\n
Average exchange rate USD/BRL 5.22 5.50 5.22 5.29
\n
Notional amount for CCIRS EUR/BRL 597 438 181 - 70 - 1,286
\n
Average exchange rate EUR/BRL 6.09 6.25 6.16 3.92
\n
Currency forwards
\n
Total notional amount of forwards 6,127 2,374 625 - - - 9,126
\n
Notional amount - currency forwards EUR/USD 4,713 2,345 625 - - - 7,683
\n
Average currency forward rate - EUR/USD 1.09 1.10 1.11
\n
Notional amount - currency forwards USD/BRL 333 -----333
\n
Average currency forward rate - USD/BRL 5.61
\n
Notional amount - currency forwards EUR/CNH 311 -----311
\n
Average currency forward rate - EUR/CNH 7.41
\n
Notional amount - currency forwards USD/CLP 199 20----219
\n
Average currency forward rate - USD/CLP 906.90 921.05
\n
Notional amount - currency forwards USD/COP 156 2----158
\n
Average currency forward rate - USD/COP 4,720.74 4,444.96
\n

\n\n

\n\n

\n\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026 Beyond Total
\n
At Dec. 31, 2021
\n
Cross currency interest rate swap (CCIRS)
\n
Total notional amount of CCIRS 258 1,574 4,638 1,002 1,153 12,814 21,439
\n
Notional amount for CCIRS EUR/USD - 1,104 2,158 661 1,104 8,632 13,659
\n
Average exchange rate EUR/USD 1.33 1.13 1.17 1.18 1.21
\n
Notional amount for CCIRS EUR/GBP - - 1,012 - - 3,678 4,690
\n
Average exchange rate EUR/GBP 0.88 0.82
\n
Notional amount for CCIRS EUR/CHF - - 218 - - 126 344
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 98 132 295 155 49 244 973
\n
Average exchange rate USD/BRL 4.81 5.22 5.55 5.29 5.39 3.57
\n
Notional amount for CCIRS EUR/BRL 160 339 402 79 - 77 1,057
\n
Average exchange rate EUR/BRL 6.41 6.44 6.25 6.71 3.92
\n
Currency forward
\n
Total notional amount of forwards 4,324 1,320 371 4 - - 6,019
\n
Notional amount - currency forwards EUR/USD 3,064 1,268 371 4 - - 4,707
\n
Average currency forward rate - EUR/USD 1.16 1.19 1.18 1.18
\n
Notional amount - currency forwards USD/BRL 311 -----311
\n
Average currency forward rate - USD/BRL 5.65
\n
Notional amount - currency forwards USD/COP 284-----284
\n
Average currency forward rate - USD/COP 3,963.3
\n
Notional amount - currency forwards USD/CLP 145-----145
\n
Average currency forward rate - USD/CLP 818.94
\n
Notional amount - currency forwards USD/CAD 107-----107
\n
Average currency forward rate - USD/CAD 1.24
\n

\n\n

\n\n

\n\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the currency risk of
\n
transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument Hedged item Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
15 (99) 1,097 12 - 595
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings in foreign
\n
currencies
\n
-- -30-77
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings/financial
\n
assets in foreign currencies
\n
95 (76) 1,061 88 (19) 953
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
4 (233) 2,445 43 (58) 2,553
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate bonds in foreign
\n
currencies
\n
60 - 414 37 - 344
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
1,864 (1,293) 23,381 1,159 (1,095) 16,601
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Future cash flows denominated in
\n
foreign currencies
\n
- (50) 335 - (75) 316
\n
Currency forwards
\n
Future cash flows denominated in
\n
foreign currencies
\n
9 (6) 326 7 (3) 378
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign currencies
\n
192 (135) 7,508 106 (36) 4,802
\n
Currency forwards
\n
Purchases of investment goods and
\n
other in foreign currencies
\n
19 (23) 1,292 20 (7) 839
\n
Tot al 2,258 (1,915) 37,859 1,502 (1,293) 27,458
\n
Cash flow hedges and fair value hedges include:
\n
\u2022 CCIRSs with a notional amount of \u20ac26,923 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac258 million;
\n
\u2022 CCIRSs with a notional amount of \u20ac1,810 million used to
\n
hedge the currency risk on floating-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac29 million;
\n
\u2022 currency forwards with a notional amount of \u20ac7,834
\n
million used to hedge the currency risk associated with
\n
purchases of natural gas, purchases of fuel and expect-
\n
ed cash flows in currencies other than the euro, with a
\n
total positive fair value of \u20ac60 million;
\n
\u2022 currency forwards with a notional amount of \u20ac1,292
\n
million and a negative fair value of \u20ac4 million, in respect
\n
of OTC transactions to mitigate the currency risk on ex-
\n
pected cash flows in currencies other than the presen-
\n
tation currency connected with the purchase of invest-
\n
ment goods in the renewables and infrastructure and
\n
networks sectors (new generation digital meters), on
\n
operating costs for the supply of cloud services and on
\n
revenue from the sale of renewable energy.
\n
The following table reports the notional amount and fair
\n
value of foreign exchange derivatives at December 31,
\n
2022 and December 31, 2021, broken down by type of
\n
hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
CCIRS 99 672 15 42 998 - (99) -
\n
Total 99 672 15 42 998 - (99) -
\n
Cash flow hedges
\n
Currency forwards 4,313 4,117 220 133 4,813 1,902 (164) (46)
\n
CCIRS 16,695 13,553 2,023 1,327 10,941 7,214 (1,652) (1,247)
\n
Total 21,008 17,670 2,243 1,460 15,754 9,116 (1,816) (1,293)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
21,107 18,342 2,258 1,502 16,752 9,116 (1,915) (1,293)
\n

\n\n

\n\n

\n\n
The notional amount of CCIRS at December 31, 2022
\n
amounted to \u20ac28,733 million (\u20ac21,439 million at Decem-
\n
ber 31, 2021), an increase of \u20ac7,294 million. Cross curren-
\n
cy interest rate swaps with a total amount of \u20ac258 million
\n
expired, while new derivatives amounted to \u20ac7,500 million,
\n
of which \u20ac6,936 million in respect of bond issues denomi-
\n
nated in British pounds and US dollars in 2022. In addition,
\n
following the novation of a bond in US dollars from Enel
\n
Finance International to Enel Finance America, cross cur-
\n
rency interest rate swaps of \u20ac662 million were terminated
\n
early. The amount also reflects developments in the ex-
\n
change rate of the euro against the main other currencies
\n
and the effect of amortization, which caused their notional
\n
amount to increase by \u20ac714 million.
\n
The notional amount of currency forwards at December
\n
31, 2022 amounted to \u20ac9,126 million (\u20ac6,019 million at De-
\n
cember 31, 2021), an increase of \u20ac3,107 million. The expo-
\n
sure to currency risk, especially that associated with the US
\n
dollar, is mainly due to purchases of natural gas, purchases
\n
of fuel and cash flows in respect of investments. Changes
\n
in the notional amount are connected with a greater ex-
\n
posure to exchange rate risk, in particular towards the US
\n
dollar, resulting from the increase in natural gas prices and
\n
the recovery in the generation of electricity from coal.
\n

\n

\n\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss, reflecting changes in the fair
\n
value of fair value hedge derivatives and the hedged item
\n
that are attributable to currency risk for 2022 and the pre-
\n
vious year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (119) 9
\n
Hedged item 129 (8)
\n
Ineffective portion 10 1
\n
The following table shows the impact of fair value hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 1,097 (84) (87) 672 42 37
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds in foreign currencies 525 (109) 70 639 35
\n
(40)
\n
Floating-rate borrowings/bonds in foreign
\n
currencies
\n
449 (10) 13 - -
\n
-
\n
Total 974 (119) 83 639 35 (40)
\n

\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on currency
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 2,243 1,256 889 320 299 2,197
\n
-
\n
Negative fair value (1,816) (58) (53) (97) 7 (361) -
\n
The following table shows the impact of cash flow hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and at December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 27,636 371 433 20,767 80 82
\n
Currency forwards 9,126 56 56 6,019 87 89
\n
Total 36,762 427 489 26,786 167 171
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Other effects
\n
through
\n
profit or
\n
loss
\n
(1)
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
borrowings in foreign
\n
currencies
\n
(30) 30 - (11) - (69) 69 - -
\n
Fixed-rate
\n
borrowings in foreign
\n
currencies
\n
225 (225) (4) - - 15 (15) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(60) 60 - - - (37) 37 - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
(628) 509 (56) - 118 (66) 66 (2) -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with CCIRSs)
\n
50 (50) - - - 75 (75) - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(3) 3 - - - (2) 2 1 -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
(60) 59 (1) (1) - (72) 72 - -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
7 (7) 1 2 - (15) 15 (3) -
\n
Total (499) 379 (60) (10) 118 (171) 171 (4) -
\n
(1) The impact is connected with changes in spot rates between the date of inception of the CCRIS entered into to hedge bonds denominated in foreign cur-
\n
rencies and the actual disbursement of the loan.
\n

\n\n
Commodity price risk
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Commodity swaps
\n
Notional amount on electricity 653 164 143 139 132 333 1,564
\n
Average commodity swap price on power (\u20ac/MWh) 162.5 77.9 48.9 47.2 45.8 29.0
\n
Notional amount on coal/shipping 1,037 - - - - - 1,037
\n
Average commodity swap price on coal/shipping ($/t) 293.7-----
\n
Notional amount on gas 1,183 1,184 1,205 23 20 65 3,680
\n
Average commodity swap price on gas (\u20ac/MWh) 60.1 47.9 52.0 21.0 8.3 7.2
\n
Notional amount on oil 1,076 227 48---1,351
\n
Average commodity swap price on oil ($/bbl) 105.0 93.0 82.0---
\n
Commodity forwards/futures
\n
Notional amount on power 2,906 509 388 294 249 720 5,066
\n
Average commodity forward/future price on power (\u20ac/MWh) 148.1 35.2 17.4 17.8 15.8 15.6
\n
Notional amount on coal/shipping - - - ----
\n
Average commodity forward/future price on coal/shipping ($/ton) - -----
\n
Notional amount on gas 7,171 4,099 229 - - - 11,499
\n
Average commodity forward/future price on gas (\u20ac/MWh) 72.9 92.1 56.6---
\n
Notional amount on CO
\n
2
\n
1,63522650---1,911
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/ton) 81.3 94.9 94.0 - - -
\n
Notional amount on oil 1,263 58----1,321
\n
Average commodity forward/future price on oil ($/bbl) 81.7 73.9 - - - -
\n
Commodity options
\n
Notional amount on power 16 16 16 16 16 117 197
\n
Average commodity option price on power (\u20ac/MWh) 35.0 35.0 35.0 35.0 35.0 33.0
\n
Notional amount on gas -------
\n
Average commodity option price on gas (\u20ac/MWh) ------
\n
Notional amount on oil 70-----70
\n
Average commodity option price on oil ($/bbl) 133-----
\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026
\n
Beyond To ta l
\n
At Dec. 31, 2021
\n
Commodity swap
\n
Notional amount on power 124 164 168 149 146
\n
472 1,223
\n
Average commodity swap price on power (\u20ac/MWh) 51.8 53.7 47.5 46.6 46.0
\n
33.2
\n
Notional amount on gas 131 372 129 11 17 93 753
\n
Average commodity swap price on gas (\u20ac/MWh) 63.8 13.7 12.1 9.4 12.0 9.6
\n
Notional amount on oil 669 244 99 - -
\n
- 1,012
\n
Average commodity swap price on oil ($/bbl) 86.4 92.9 79.4 - -
\n
-
\n
Commodity forwards/futures
\n
Notional amount on power 319 637 302 288 248
\n
856 2,650
\n
Average commodity forward/future price on power (\u20ac/MWh) 29.7 43.3 20.0 19.7 18.7 16.6
\n
Notional amount on coal/shipping 14 - - - -
\n
- 14
\n
Average commodity forward/future price on coal/shipping ($/ton) 90.8----
\n
-
\n
Notional amount on gas 3,315 1,048 5 - - - 4,368
\n
Average commodity forward/future price on gas (\u20ac/MWh) 15.1 18.9 18.0---
\n
Notional amount on CO
\n
2
\n
47661----537
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/t) 46.1 38.4----
\n
Notional amount on oil 600 57 - - - - 657
\n
Average commodity forward/future price on oil ($/bbl) 37.7 51.6---
\n
-
\n
Commodity options
\n
Notional amount on power 10 21 21 21 21
\n
134 228
\n
Average commodity option price on power (\u20ac/MWh) 26.3 29.3 29.9 29.8 29.8
\n
32.6
\n
Notional amount on gas 99----- 99
\n
Average commodity option price gas (\u20ac/MWh) 50.5 - - - -
\n
-
\n

\n\n
The following table reports the notional amount and fair
\n
value of instruments hedging commodity price risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021, broken down by type of commodity.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives
\n
Cash flow hedges
\n
Derivatives on power:
\n
- swaps 1,213 820 982 640 352 401 (498) (263)
\n
- forwards/futures 1,535 769 89 1,073 3,510 1,881 (898) (598)
\n
- options 218 229 36 49 - - (12) (18)
\n
Total derivatives on power 2,966 1,818 1,107 1,762 3,862 2,282 (1,408) (879)
\n
Derivatives on coal/shipping:
\n
- swaps 9 - 2 - 1,028 - (373) -
\n
- forwards/futures - 14 - 3 - - - -
\n
- options - - - -----
\n
Total derivatives on coal/shipping 9 14 2 3 1,028 - (373) -
\n
Derivatives on gas and oil:
\n
- swaps 2,302 669 666 69 2,729 1,095 (765) (99)
\n
- forwards/futures 4,734 3,094 1,714 2,557 8,085 1,932 (5,182) (5,150)
\n
- options 22 30 4 3 48 70 (4) (26)
\n
Total derivatives on gas and oil 7,058 3,793 2,384 2,629 10,862 3,097 (5,951) (5,275)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps --------
\n
- forwards/futures 1,704 537 143 410 207 - (7) -
\n
- options --------
\n
Total derivatives on CO
\n
2
\n
1,704 537 143 410 207 - (7) -
\n
TOTAL COMMODITY DERIVATIVES 11,737 6,162 3,636 4,804 15,959 5,379 (7,739) (6,154)
\n
The table reports the notional amount and fair value of de-
\n
rivatives hedging commodity price risk at December 31,
\n
2022 and at December 31, 2021, broken down by type of
\n
hedge.
\n
The positive fair value of cash flow hedge derivatives on
\n
commodities regards derivatives on gas and oil commod-
\n
ities in the amount of \u20ac2,384 million, derivatives on CO
\n
2
\n
\n
(\u20ac143 million), derivatives on power (\u20ac1,107 million) and, to
\n
a lesser extent, hedges of coal purchases requested by the
\n
generation companies in the amount of \u20ac2 million.
\n
The first category primarily regards hedges of fluctuations
\n
in the price of natural gas, for both purchases and sales,
\n
carried out for oil commodities and gas products.
\n
The CO
\n
2
\n
category mainly includes hedging transactions
\n
undertaken for Enel Group compliance purposes.
\n
The power category mainly includes medium/long-term
\n
hedging transactions, especially in Spain and North Amer-
\n
ica.
\n
Cash flow hedge derivatives on commodities included in
\n
liabilities regard derivatives on gas and oil commodities in
\n
the amount of \u20ac5,951 million (mainly for derivatives hedg-
\n
ing sales), derivatives on power in the amount of \u20ac1,408
\n
million and, to a lesser extent, derivatives on coal and CO
\n
2
\n
\n
in the amount of respectively \u20ac373 million and \u20ac7 million.
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on commodity
\n
price risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on commodities
\n
Positive fair value 3,838 2,438 829 160 101 93 217
\n
Negative fair value (7,941) (4,598) (2,116) (619) (180) (153) (275)
\n

\n\n
The following table shows the impact of cash flow hedges
\n
of commodity price risk in the statement of financial posi-
\n
tion at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Power swaps 1,564 485 469 1,221 377 377
\n
Coal/shipping swaps 1,037 (371) (371) - - -
\n
Gas and oil swaps 5,031 (99) (98) 1,764 (30)
\n
(30)
\n
Power forwards/futures 5,045 (809) (938) 2,675 (223) (223)
\n
Coal/shipping forwards/futures - - - 14 3 3
\n
Gas and oil forwards/futures 12,820 (3,469) (3,673) 5,027 (2,592) (2,592)
\n
CO
\n
2
\n
forwards/futures 1,911 136 138 537 410 410
\n
Power options 218 24 24 204 7 7
\n
Gas and oil options 70 - - 99 (24)
\n
(24)
\n
Total 27,696 (4,103) (4,449) 11,541 (2,072) (2,072)
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Future transactions in power 602 (602) 15 (32) (297) 297 -
\n
(29)
\n
Future transactions in coal/shipping 371 (371) - - (3) 3 - -
\n
Future transactions in gas and oil 3,360 (3,360) - (232) 2,751 (2,751) - (2)
\n
Future transactions in CO
\n
2
\n
(133) 133 - - (410) 410 - -
\n
Total 4,200 (4,200) 15 (264) 2,041 (2,041) - (31)
\n
With regard to cash flow hedge derivatives on commodity
\n
prices, the entire commodities market continued to expe-
\n
rience major price swings in 2022. The greatest impact in
\n
terms of changes in the cash flow hedge reserve is attrib-
\n
utable to future transactions in gas, which of all commodi-
\n
ties was the one most affected by the high volatility.
\n
Finally, the ineffectiveness recognized in 2022 on future
\n
transactions in gas is mainly related to proxy hedging op-
\n
erations in Spain.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag163": { "value": "interestincome and expense are recognized using the effectiveinterest rate method.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag169": { "value": "\n
Dividends
\n
Dividends are recognized when the unconditional right to
\n
receive payment is established.
\n
Dividends and interim dividends payable to the Parent\u2019s
\n
shareholders and non-controlling interests are recognized
\n
as changes in equity in the period in which they are ap-
\n
proved by the Shareholders\u2019 Meeting and the Board of Di-
\n
rectors, respectively.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag156": { "value": "\n

\n
Income taxes
\n
Current income taxes
\n
Current income taxes for the year, which are recognized
\n
under \u201cIncome tax liabilities\u201d net of payments on account,
\n
or under \u201cTax assets\u201d where there is a credit balance, are
\n
determined using an estimate of taxable income and in
\n
conformity with the applicable regulations.
\n
Such liabilities and assets are determined using the tax
\n
rates and tax laws that are enacted or substantively en-
\n
acted by the end of the reporting period in the countries
\n
where taxable income has been generated.
\n
Current income taxes are recognized in profit or loss with
\n
the exception of current income taxes related to items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n\n
Deferred tax
\n
Deferred tax liabilities and assets are calculated on the
\n
temporary differences between the carrying amounts of
\n
liabilities and assets in the financial statements and their
\n
corresponding amounts recognized for tax purposes on
\n
the basis of tax rates in effect on the date the temporary
\n
difference will reverse, which is determined on the basis of
\n
tax rates that are enacted or substantively enacted as at
\n
the end of the reporting period.
\n
Deferred tax liabilities are recognized for all taxable tem-
\n
porary differences, except when such liability arises from
\n
the initial recognition of goodwill or in respect of taxable
\n
temporary differences associated with investments in sub-
\n
sidiaries, associates and joint ventures, when the Group
\n
can control the timing of the reversal of the temporary dif-
\n
ferences and it is probable that the temporary differences
\n
will not reverse in the foreseeable future.
\n
Deferred tax assets are recognized for all deductible tem-
\n
porary differences, the carry forward of tax losses and any
\n
unused tax credits. For more information concerning the
\n
recoverability of such assets, please see the appropriate
\n
section of the discussion of estimates.
\n
Deferred taxes and liabilities are recognized in profit or
\n
loss, with the exception of those in respect of items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n
Deferred tax assets and deferred tax liabilities are offset
\n
only if there is a legally enforceable right to offset current
\n
tax assets with current tax liabilities and when they relate
\n
to income taxes levied by the same taxation authority on
\n
either the same taxable entity or different taxable entities
\n
which intend either to settle current tax liabilities and as-
\n
sets on a net basis, or to realize the assets and settle the
\n
liabilities simultaneously, in each future period in which
\n
significant amounts of deferred tax liabilities or assets are
\n
expected to be settled or recovered.
\n

\n

\n\n
Uncertainty over income tax treatments
\n
In defining \u201cuncertainty\u201d, it shall be considered whether a
\n
particular tax treatment will be accepted by the relevant
\n
taxation authority. If it is deemed probable that the tax
\n
treatment will be accepted (where the term \u201cprobable\u201d is
\n
defined as \u201cmore likely than not\u201d), then the Group recog-
\n
nizes and measures its current/deferred tax asset or liabil-
\n
ities applying the requirements in IAS 12.
\n
Conversely, when the Group feels that it is not likely that
\n
the taxation authority will accept the tax treatment for
\n
income tax purposes, the Group reflects the uncertainty
\n
in the manner that best predicts the resolution of the un-
\n
certain tax treatment. The Group determines whether to
\n
consider each uncertain tax treatment separately or to-
\n
gether with one or more other uncertain tax treatments
\n
based on which approach provides better predictions of
\n
the resolution of the uncertainty. In assessing whether and
\n
how the uncertainty affects the tax treatment, the Group
\n
assumes that a taxation authority will accept or not an un-
\n
certain tax treatment supposing that the taxation authority
\n

\n

\n\n
will examine amounts it has a right to examine and have full
\n
knowledge of all related information when making those
\n
examinations. The Group reflects the effect of uncertainty
\n
in accounting for current and deferred tax using the ex-
\n
pected value or the most likely amount, whichever method
\n
better predicts the resolution of the uncertainty.
\n
Since uncertain income tax positions meet the definition
\n
of income taxes, the Group presents uncertain tax liabili-
\n
ties/assets as current tax liabilities/assets or deferred tax
\n
liabilities/assets.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag177": { "value": "\n
Deferred tax
\n
Deferred tax liabilities and assets are calculated on the
\n
temporary differences between the carrying amounts of
\n
liabilities and assets in the financial statements and their
\n
corresponding amounts recognized for tax purposes on
\n
the basis of tax rates in effect on the date the temporary
\n
difference will reverse, which is determined on the basis of
\n
tax rates that are enacted or substantively enacted as at
\n
the end of the reporting period.
\n
Deferred tax liabilities are recognized for all taxable tem-
\n
porary differences, except when such liability arises from
\n
the initial recognition of goodwill or in respect of taxable
\n
temporary differences associated with investments in sub-
\n
sidiaries, associates and joint ventures, when the Group
\n
can control the timing of the reversal of the temporary dif-
\n
ferences and it is probable that the temporary differences
\n
will not reverse in the foreseeable future.
\n
Deferred tax assets are recognized for all deductible tem-
\n
porary differences, the carry forward of tax losses and any
\n
unused tax credits. For more information concerning the
\n
recoverability of such assets, please see the appropriate
\n
section of the discussion of estimates.
\n
Deferred taxes and liabilities are recognized in profit or
\n
loss, with the exception of those in respect of items rec-
\n
ognized outside profit or loss that are recognized in equity.
\n
Deferred tax assets and deferred tax liabilities are offset
\n
only if there is a legally enforceable right to offset current
\n
tax assets with current tax liabilities and when they relate
\n
to income taxes levied by the same taxation authority on
\n
either the same taxable entity or different taxable entities
\n
which intend either to settle current tax liabilities and as-
\n
sets on a net basis, or to realize the assets and settle the
\n
liabilities simultaneously, in each future period in which
\n
significant amounts of deferred tax liabilities or assets are
\n
expected to be settled or recovered.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag208": { "value": "\n
3. New and amended standards and interpretations
\n
The Group has applied the following standards, interpre-
\n
tations and amendments that took effect as from January
\n
1, 2022:
\n
\u2022 \u201cAmendments to IFRS 3 - Reference to the Conceptual
\n
Framework\u201d issued in May 2020. The amendments are
\n
intended to replace a reference to the definitions of as-
\n
sets and liabilities provided by the Revised Conceptual
\n
Framework for Financial Reporting issued in March 2018
\n
(Conceptual Framework) without significantly changing
\n
its provisions.
\n
The amendments also add to IFRS 3 a requirement that,
\n
for transactions and other events within the scope of
\n
\u201cIAS 37 - Provisions, contingent liabilities and contingent
\n
assets\u201d or \u201cIFRIC 21 - Levies\u201d, an acquirer applies IAS 37
\n
or IFRIC 21 (instead of the Conceptual Framework) to
\n
identify the liabilities it has assumed in a business com-
\n
bination.
\n
Finally, the amendments clarify the existing guidelines
\n
in IFRS 3 for contingent assets acquired in a business
\n
combination, specifying that, if it is not sure that an as-
\n
set exists at the acquisition date, the contingent asset
\n
shall not be recognized.
\n
\u2022 \u201cAmendments to IAS 16 - Property, Plant and Equipment:
\n
Proceeds before Intended Use\u201d, issued in May 2020. The
\n
amendments prohibit a company from deducting from
\n
the cost of property, plant and equipment amounts re-
\n
ceived from selling items produced while the company is
\n
preparing the asset for its intended use. Instead, a com-
\n
pany will recognize such sales proceeds and related cost
\n
in profit or loss.
\n
\u2022 \u201cAmendments to IAS 37 - Onerous Contracts - Costs
\n
of Fulfilling a Contract\u201d, issued in May 2020. The amend-
\n
ments specify which costs an entity includes in deter-
\n
mining the cost of fulfilling a contract for the purpose of
\n
assessing whether the contract is onerous. To this end,
\n
the cost of fulfilling a contract comprises the costs that
\n
relate directly to the contract. These consist of the incre-
\n
mental costs of fulfilling that contract or the allotment of
\n
other costs that relate directly to fulfilling contracts.
\n
\u2022 \u201cAnnual improvements to IFRS Standards 2018-2020\u201d,
\n
issued in May 2020. The document mainly comprises
\n
amendments to the following standards:
\n
\u2013 First-Time Adoption of International Financial Report-
\n
ing Standards\u201d; the amendment simplifies the appli-
\n
cation of IFRS 1 by an investee (subsidiary, associate
\n
or joint venture) that becomes a first-time adopter of
\n
IFRS Standards after its parent has already adopted
\n
them. More specifically, if the investee adopts the IF-
\n
RSs after its parent and applies IFRS 1.D16 (a), then
\n
the investee can elect to measure the cumulative
\n
translation differences for all foreign operations at
\n
the amounts that would be included in the parent\u2019s
\n
consolidated financial statements, based on parent\u2019s
\n
date of transition to the IFRSs;
\n
\u2013 \u201cIFRS 9 - Financial Instruments\u201d; with regard to fees
\n
included in the \u201c10 per cent\u201d test for derecognition
\n
of financial liabilities, the amendment clarifies the
\n
fees that an entity includes when assessing whether
\n
the terms of a new or modified financial liability are
\n
substantially different from the terms of the original
\n
financial liability. In determining those fees paid net
\n
of fees received, the borrower shall include only fees
\n
paid or received between the borrower and the lend-
\n
er, including fees paid or received by either the bor-
\n
rower or lender on the other party\u2019s behalf;
\n
\u2013 \u201cIFRS 16 - Leases\u201d; the International Accounting Stan-
\n
dards Board amended Illustrative Example 13 accom-
\n
panying \u201cIFRS 16 - Leases\u201d. Specifically, the amend-
\n
ment eliminates the potential for confusion in the
\n
application of IFRS 16 created by the way in which
\n
Illustrative Example 13 had illustrated the require-
\n
ments for lease incentives. The example had included
\n
a reimbursement relating to leasehold improvements
\n
without explaining whether the reimbursement quali-
\n
fied as a lease incentive. The amendment removes the
\n
illustration of a reimbursement relating to leasehold
\n
improvements from the example;
\n
\u2013 \u201cIAS 41 - Agriculture\u201d; the amendment removes the
\n
requirement for entities to exclude cash flows for tax-
\n
ation when measuring fair value. Accordingly, entities
\n
shall use pre-tax cash flows and a pre-tax rate to dis-
\n
count those cash flows.
\n
The application of the amendments for 2022 did not have
\n
a material impact on these consolidated financial state-
\n
ments.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag344": { "value": "\n
4. Argentina - Hyperinflationary economy:
\n
impact of the application of IAS 29
\n
As from July 1, 2018, the Argentine economy has been con-
\n
sidered hyperinflationary based on the criteria established by
\n
\u201cIAS 29 - Financial reporting in hyperinflationary economies\u201d.
\n
This designation is determined following an assessment of a
\n
series of qualitative and quantitative circumstances, including
\n
the presence of a cumulative inflation rate of more than 100%
\n
over the previous three years.
\n
For the purposes of preparing the consolidated financial
\n
statements at December 31, 2022, and in accordance with
\n
IAS 29, certain items of the statements of financial position of
\n
the investees in Argentina have been remeasured by applying
\n
the general consumer price index to historical data in order
\n
to reflect changes in the purchasing power of the Argentine
\n
peso at the reporting date for those companies.
\n
Bearing in mind that the Enel Group acquired control of the
\n
Argentine companies on June 25, 2009, the remeasurement
\n
of the non-monetary financial statement figures was con-
\n
ducted by applying the inflation indices starting from that
\n
date. In addition to being already reflected in the opening
\n
statement of financial position, the accounting effects of that
\n
remeasurement also include changes during the period. More
\n
specifically, the effect of the remeasurement of non-mone-
\n
tary items, the equity items and the income statement items
\n
recognized in 2022 was recognized in a specific line of the
\n
income statement under financial income and expense. The
\n
associated tax effect was recognized in taxes for the year.
\n
In order to also take account of the impact of hyperinflation
\n
on the exchange rate of the local currency, the income state-
\n
ment balances expressed in the hyperinflationary currency
\n
have been translated into the Group\u2019s presentation currency
\n
(euro) applying, in accordance with IAS 21, the closing ex-
\n
change rate rather than the average rate for the year in order
\n
to adjust these amounts to present values.
\n
The cumulative changes in the general price indices from De-
\n
cember 31, 2018 until December 31, 2022 are shown in the
\n
following table:
\n
Periods
\n
Cumulative change
\n
in general consumer
\n
price index
\n
From July 1, 2009 to December 31, 2018 346.30%
\n
From January 1, 2019 to December 31, 2019 54.46%
\n
From January 1, 2020 to December 31, 2020 35.41%
\n
From January 1, 2021 to December 31, 2021 49.73%
\n
From January 1, 2022 to December 31, 2022 97.08%
\n
In 2022, the application of IAS 29 generated net financial in-
\n
come (gross of tax) of \u20ac290 million.
\n
The following tables report the effects of IAS 29 on the bal-
\n
ance at December 31, 2022 and the impact of hyperinflation
\n
on the main income statement items for 2022, differentiating
\n
between that concerning the revaluation on the basis of the
\n
general consumer price index and that due to the applica-
\n
tion of the closing exchange rate rather than the average ex-
\n
change rate for the period, in accordance with the provisions
\n
of IAS 21 for hyperinflationary economies.
\n
Millions of euro
\n
Cumulative hyperinflation
\n
effect at Dec. 31, 2021
\n
Hyperinflation effect for the
\n
period Exchange differences
\n
Cumulative hyperinflation
\n
effect at Dec. 31, 2022
\n
Total assets 1,366 1,183 (560) 1,989
\n
Total liabilities 346 359 (150)
\n
555
\n
Equity 1,020 824
\n
(1)
\n
(410) 1,434
\n
(1) The figure includes profit for year equal to \u20ac98 million.
\n
Millions of euro
\n
IAS 29 effect IAS 21 effect Total effect at Dec. 31, 2022
\n
Revenue 254 (356) (102)
\n
Costs 280
\n
(1)
\n
(449)
\n
(2)
\n
(169)
\n
Operating profit (26) 93 67
\n
Net financial income/(expense) (46) (1) (47)
\n
Net income/(expense) from hyperinflation 290 - 290
\n
Pre-tax profit/(loss) 218 92 310
\n
Income taxes 120 (3) 117
\n
Loss for the year (owners of the Parent and non-controlling interests) 98 95 193
\n
Attributable to owners of the Parent 73 51 124
\n
Attributable to non-controlling interests 25 44 69
\n
(1) Includes impact on depreciation, amortization and impairment losses of \u20ac42 million.
\n
(2) Includes impact on depreciation, amortization and impairment losses of \u20ac(169) million.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfHyperinflationaryReportingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag849": { "value": "\n
5. Climate change disclosures
\n
The move towards \u201cnet zero\u201d is under way worldwide and
\n
the processes of decarbonization and electrification of the
\n
global economy are crucial to avoiding the serious conse-
\n
quences of an increase in temperatures of over 1.5 \u00b0C.
\n
With this outlook, the Group has set its strategic guide-
\n
lines as follows:
\n
\u2022 allocate capital to support a decarbonized electricity
\n
supply;
\n
\u2022 enable the electrification of customers\u2019 energy demand;
\n
\u2022 leverage the creation of value along the value chain;
\n
\u2022 bring forward achievement of the sustainable \u201cnet-zero\u201d
\n
goals to 2040.
\n
Considering the risks related to climate change and the
\n
commitments established under the Paris Agreement, the
\n
Group has decided to achieve the carbon neutrality objec-
\n
tives in advance and reflect its impact on assets, liabilities,
\n
and profit or loss, highlighting its significant and foresee-
\n
able impacts as required under the Conceptual Frame-
\n
work of the international accounting standards.
\n
In this regard, in accordance with the provisions of the
\n
document published by the IFRS Foundation on Novem-
\n
ber 20, 2020, the Group provides explicit information in the
\n
notes to these consolidated financial statements regard-
\n
ing how climate change is reflected in our accounts.
\n
For a more effective and comprehensive communication
\n
concerning climate change disclosures prepared as part
\n
of the notes to these consolidated financial statements,
\n
we have mapped this disclosure as shown below, providing
\n
references to the various sections where issues associated
\n
with climate change are addressed.
\n
Topic Note Content
\n
Estimates and
\n
judgments
\n
concerning climate
\n
change
\n
Note 2.1 \u201cUse of estimates and
\n
management judgment\u201d
\n
\u2022 Reference to management\u2019s use of estimates and judgments with regard to
\n
climate change (taking account of their materiality within financial reporting).
\n
\u2022 Focus on estimating expected cash flows from specific assets/CGUs (section:
\n
\u201cImpairment of non-financial assets\u201d).
\n
\u2022 Focus of the effects of the Group\u2019s commitments under the Paris Agreement
\n
and their impact on the estimation of the useful life of the assets involved
\n
(section \u201cDetermining the useful life of non-financial assets\u201d).
\n
Sustainable
\n
investment
\n
Note 19 \u201cProperty, plant and equipment\u201d
\n
Note 23 \u201cIntangible assets\u201d
\n
\u2022 Focus on assets involved in renewable generation, infrastructure connected
\n
with the development of the grid and investment in expanding the e-Mobility,
\n
e-City, e-Industries, and e-Home businesses.
\n
\u2022 Focus on the development of intellectual property for achieving strategic
\n
objectives such as decarbonization, electrification and the development of
\n
platform models.
\n
Measurement of non-
\n
financial assets
\n
Note 12.e \u201cDepreciation, amortization
\n
and other impairment losses\u201d
\n
Note 19 \u201cProperty, plant and equipment\u201d
\n
Note 24 \u201cGoodwill\u201d
\n
\u2022 Focus on the effects related to the commitments of the Group in line with
\n
the Paris Agreement with regard to the measurement of non-financial as-
\n
sets, with particular regard to the residual useful life of certain assets and
\n
impairment testing.
\n
Provisions
\n
Note 40 \u201cProvisions for risks and
\n
charges\u201d
\n
\u2022 Focus on the impact of climate change on provisions for risks and charges,
\n
in particular generation plants, including those for decommissioning and re-
\n
storation of sites, and provisions for restructuring plans linked to the energy
\n
transition (which include decarbonization and digitization).
\n
Sustainable finance
\n
Note 48.3 \u201cBorrowings\u201d
\n
Note 59 \u201cEvents after the reporting
\n
period\u201d
\n
Focus on:
\n
\u2022 issues of sustainability-linked bonds connected with the achievement of su-
\n
stainability objectives in line with the SDGs issued by the United Nations;
\n
\u2022 green bonds used to finance specific sustainable Group projects and initia-
\n
tives;
\n
\u2022 sustainable loans connected with the achievement of Sustainable Develop-
\n
ment Goals (SDGs).
\n
Share-based
\n
payments
\n
Note 53 \u201cShare-based payments\u201d
\n
\u2022 Description of long-term incentive plans anchored to achievement of speci-
\n
fic climate-related targets.
\n
Environmental
\n
compliance
\n
Note 12.f \u201cOther operating expenses\u201d
\n
\u2022 Description of costs relating to environmental compliance required by natio-
\n
nal and international regulations, in particular for greenhouse gas emission
\n
quotas, green certificates and energy efficiency certificates.
\n
Note 40 \u201cProvisions for risks and
\n
charges\u201d
\n
\u2022 Description of costs generated by not having sufficient environmental certi-
\n
ficates to meet environmental compliance regulations.
\n
Note 2.2 \u201cSignificant accounting policies\u201d
\n
\u2022 Description of accounting treatment of environmental certificates (sections:
\n
\u201cEnvironmental certificates\u201d and \u201cInventories\u201d).
\n

\n", "dimensions": { "concept": "enel:DisclosureOfClimateChangeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag852": { "value": "\n

\n\n
6. Discontinued operations
\n
Within the European area, the Enel Group has decided to
\n
dispose of important business lines, particularly in Russia,
\n
Romania and Greece, leading to their assets being reclas-
\n
sified as discontinued operations for the purposes of \u201cIFRS
\n
5 - Non-current assets held for sale and discontinued op-
\n
erations\u201d.
\n
The consolidated income statement reports the profit/
\n
(loss) result from discontinued operations in a separate
\n
line.
\n
In accordance with the provisions of IFRS 5, which governs
\n
the presentation in the financial statements of profit or
\n
loss and the disclosures to be provided in the explanatory
\n
note on non-current assets held for sale and discontinued
\n
operations, the income statement below reports the re-
\n
sults of discontinued operations for 2022 and 2021.
\n
The items are shown net of intercompany transactions
\n
which have been completely eliminated.
\n
The figures for 2021, presented for comparative purposes
\n
only, pursuant to \u201cIFRS 5 - Non-current assets held for sale
\n
and discontinued operations\u201d, have been restated to en-
\n
sure they are uniform and comparable with those for 2022.
\n
Millions of euro
\n
2022 2021 Change
\n
Revenue 3,562 2,288 1,274
\n
Costs 4,858 2,166 2,692
\n
Pre-tax profit/(loss) from discontinued operations (1,296) 122 (1,418)
\n
Income taxes (52) 23 (75)
\n
Capital gains/(losses) from disposal of discontinued operations (1,054) - (1,054)
\n
Profit/(Loss) from discontinued operations (2,298) 99 (2,397)
\n
In accordance with the provisions of IFRS 5, the facts
\n
and circumstances that led to the reclassification are de-
\n
scribed below.
\n
Russia
\n
On June 16, 2022, Enel SpA signed two separate agree-
\n
ments with PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d for the sale of the
\n
entire stake held in PJSC Enel Russia, equal to 56.43% of
\n
the share capital of the latter.
\n
Following the agreements of June 16, 2022, on October 12,
\n
2022, Enel SpA finalized the sale of the entire stake held
\n
in PJSC Enel Russia, equal to 56.43% of the share capital
\n
of the latter, to PJSC Lukoil and the Closed Combined Mu-
\n
tual Investment Fund \u201cGazprombank-Frezia\u201d, for a total of
\n
about \u20ac137 million. The transaction was closed with the
\n
fulfillment of the conditions to which the sale was subject,
\n
including authorization of the operation by the President
\n
of the Russian Federation pursuant to paragraph 5 of De-
\n
cree 520 of August 5, 2022.
\n
Upon completion of the sale, Enel sold all power genera-
\n
tion assets in Russia, which include approximately 5.6 GW
\n
of conventional capacity and approximately 300 MW of
\n
wind capacity at various stages of development, ensuring
\n
continuity for its employees and customers.
\n
The overall transaction had a negative impact on the
\n
Group\u2019s profit of about \u20ac
\n
1,551 million, mainly reflecting the
\n
release of the translation reserve of \u20ac1,054 million, and the
\n
value adjustment of about \u20ac497 million.
\n
For more information, please see the section on \u201cBusiness
\n
combinations\u201d.
\n
Romania
\n
On December 14, 2022, Enel SpA entered into an Exclusiv-
\n
ity Agreement with Greek company Public Power Corpora-
\n
tion SA (PPC) in relation to the potential disposal of all the
\n
equity stakes held by Enel Group in Romania. In this regard,
\n
the value of the net assets of Enel Romania was adjusted
\n
to the expected sale price, with recognition of a value ad-
\n
justment of \u20ac696 million. On February 4, 2023, Enel SpA,
\n
following the announcement released on December 14,
\n
2022, announced that the period of exclusive negotiations
\n
with Greek company PPC in relation to the potential dis-
\n
posal of all the equity stakes held by Enel Group in Romania
\n
had been extended.
\n

\n\n

\n\n

\n\n
Greece
\n
Enel Green Power has begun the process of finding a po-
\n
tential investor interested in a partnership for the manage-
\n
ment and development of Enel Green Power Hellas within
\n
the Stewardship business model.
\n
The status of the negotiations under way suggest that a
\n
sale is highly probable. Accordingly, the requirements es-
\n
tablished by \u201cIFRS 5 - Non-current assets held for sale and
\n
discontinued operations\u201d have been met for the classifica-
\n
tion of the Greek assets as \u201cdiscontinued operations\u201d.
\n
For more details on the financial position by business line
\n
and geographical area of assets classified as discontinued
\n
operations, please see the section \u201cPerformance by prima-
\n
ry segment (Business Line) and secondary segment (Geo-
\n
graphical Area)\u201d.
\n
The details of cash flows relating to discontinued opera-
\n
tions are provided below, as already separately shown in
\n
the cash flows statement.
\n
Millions of euro
\n
2022 2021 Change
\n
Cash flows from operating activities - discontinued operations (391) 280 (671)
\n
Cash flows used in investing activities - discontinued operations (351) (453) 102
\n
Cash flows from/(used in) financing activities - discontinued operations 656 118 538
\n
Cash flows - discontinued operations (86) (55) (31)
\n

\n\n

\n\n
The 2021 consolidated income statement and statement
\n
of consolidated comprehensive income have been adjust-
\n
ed to take account of the presentation of discontinued
\n
operations as required by the \u201cIFRS 5 - Non-current assets
\n
held for sale and discontinued operations\u201d.
\n
For more details, please refer to the note \u201cDiscontinued
\n
operations\u201d.
\n
Impact on the consolidated income statement
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Revenue 88,006 (2,287) 85,719
\n
Costs 82,848 (2,157) 80,691
\n
Net results from commodity contracts 2,522 1 2,523
\n
Operating profit 7,680 (129) 7,551
\n
Financial income from derivatives 2,718 (1) 2,717
\n
Other financial income 1,882 (20) 1,862
\n
Financial expense from derivatives 1,257 (1) 1,256
\n
Other financial expense 6,114 (27) 6,087
\n
Net income from hyperinflation 20 - 20
\n
Share of profit/(loss) of equity-accounted investments 571 - 571
\n
Pre-tax profit 5,500 (122) 5,378
\n
Income taxes 1,643 (23) 1,620
\n
Profit/(Loss) from continuing operations 3,857 (99) 3,758
\n
Attributable to owners of the Parent 3,857 (760) 3,097
\n
Attributable to non-controlling interests - 661 661
\n
Profit/(Loss) from discontinued operations - 99 99
\n
Attributable to owners of the Parent - 92 92
\n
Attributable to non-controlling interests - 7 7
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling interests) 3,857 - 3,857
\n

\n\n
Impact on the consolidated comprehensive income
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Profit for the year 3,857 3,857
\n
Other comprehensive income/(expense) that may be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Effective portion of change in the fair value of cash flow hedges (725) (10) (735)
\n
Change in the fair value of hedging costs 195 (1) 194
\n
Share of the other comprehensive expense of equity-accounted
\n
investments
\n
(645) - (645)
\n
Change in the fair value of financial assets at FVOCI 11 - 11
\n
Change in translation reserve (90) 5 (85)
\n
Cumulative other comprehensive income that may be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
66
\n
Other comprehensive income/(expense) that may not be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Remeasurement of net liabilities/(assets) for defined benefit plans 30 (1) 29
\n
Change in fair value of equity investments in other companies - - -
\n
Cumulative other comprehensive income that may not be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
11
\n
Total other comprehensive expense for the year (1,224) - (1,224)
\n
Comprehensive income/(expense) for the year 2,633 - 2,633
\n
Attributable to:
\n
- owners of the Parent 2,562 2,562
\n
- non-controlling interests 71 71
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag851": { "value": "\n
6. Discontinued operations
\n
Within the European area, the Enel Group has decided to
\n
dispose of important business lines, particularly in Russia,
\n
Romania and Greece, leading to their assets being reclas-
\n
sified as discontinued operations for the purposes of \u201cIFRS
\n
5 - Non-current assets held for sale and discontinued op-
\n
erations\u201d.
\n
The consolidated income statement reports the profit/
\n
(loss) result from discontinued operations in a separate
\n
line.
\n
In accordance with the provisions of IFRS 5, which governs
\n
the presentation in the financial statements of profit or
\n
loss and the disclosures to be provided in the explanatory
\n
note on non-current assets held for sale and discontinued
\n
operations, the income statement below reports the re-
\n
sults of discontinued operations for 2022 and 2021.
\n
The items are shown net of intercompany transactions
\n
which have been completely eliminated.
\n
The figures for 2021, presented for comparative purposes
\n
only, pursuant to \u201cIFRS 5 - Non-current assets held for sale
\n
and discontinued operations\u201d, have been restated to en-
\n
sure they are uniform and comparable with those for 2022.
\n
Millions of euro
\n
2022 2021 Change
\n
Revenue 3,562 2,288 1,274
\n
Costs 4,858 2,166 2,692
\n
Pre-tax profit/(loss) from discontinued operations (1,296) 122 (1,418)
\n
Income taxes (52) 23 (75)
\n
Capital gains/(losses) from disposal of discontinued operations (1,054) - (1,054)
\n
Profit/(Loss) from discontinued operations (2,298) 99 (2,397)
\n
In accordance with the provisions of IFRS 5, the facts
\n
and circumstances that led to the reclassification are de-
\n
scribed below.
\n
Russia
\n
On June 16, 2022, Enel SpA signed two separate agree-
\n
ments with PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d for the sale of the
\n
entire stake held in PJSC Enel Russia, equal to 56.43% of
\n
the share capital of the latter.
\n
Following the agreements of June 16, 2022, on October 12,
\n
2022, Enel SpA finalized the sale of the entire stake held
\n
in PJSC Enel Russia, equal to 56.43% of the share capital
\n
of the latter, to PJSC Lukoil and the Closed Combined Mu-
\n
tual Investment Fund \u201cGazprombank-Frezia\u201d, for a total of
\n
about \u20ac137 million. The transaction was closed with the
\n
fulfillment of the conditions to which the sale was subject,
\n
including authorization of the operation by the President
\n
of the Russian Federation pursuant to paragraph 5 of De-
\n
cree 520 of August 5, 2022.
\n
Upon completion of the sale, Enel sold all power genera-
\n
tion assets in Russia, which include approximately 5.6 GW
\n
of conventional capacity and approximately 300 MW of
\n
wind capacity at various stages of development, ensuring
\n
continuity for its employees and customers.
\n
The overall transaction had a negative impact on the
\n
Group\u2019s profit of about \u20ac
\n
1,551 million, mainly reflecting the
\n
release of the translation reserve of \u20ac1,054 million, and the
\n
value adjustment of about \u20ac497 million.
\n
For more information, please see the section on \u201cBusiness
\n
combinations\u201d.
\n
Romania
\n
On December 14, 2022, Enel SpA entered into an Exclusiv-
\n
ity Agreement with Greek company Public Power Corpora-
\n
tion SA (PPC) in relation to the potential disposal of all the
\n
equity stakes held by Enel Group in Romania. In this regard,
\n
the value of the net assets of Enel Romania was adjusted
\n
to the expected sale price, with recognition of a value ad-
\n
justment of \u20ac696 million. On February 4, 2023, Enel SpA,
\n
following the announcement released on December 14,
\n
2022, announced that the period of exclusive negotiations
\n
with Greek company PPC in relation to the potential dis-
\n
posal of all the equity stakes held by Enel Group in Romania
\n
had been extended.
\n

\n\n
Greece
\n
Enel Green Power has begun the process of finding a po-
\n
tential investor interested in a partnership for the manage-
\n
ment and development of Enel Green Power Hellas within
\n
the Stewardship business model.
\n
The status of the negotiations under way suggest that a
\n
sale is highly probable. Accordingly, the requirements es-
\n
tablished by \u201cIFRS 5 - Non-current assets held for sale and
\n
discontinued operations\u201d have been met for the classifica-
\n
tion of the Greek assets as \u201cdiscontinued operations\u201d.
\n
For more details on the financial position by business line
\n
and geographical area of assets classified as discontinued
\n
operations, please see the section \u201cPerformance by prima-
\n
ry segment (Business Line) and secondary segment (Geo-
\n
graphical Area)\u201d.
\n
The details of cash flows relating to discontinued opera-
\n
tions are provided below, as already separately shown in
\n
the cash flows statement.
\n
Millions of euro
\n
2022 2021 Change
\n
Cash flows from operating activities - discontinued operations (391) 280 (671)
\n
Cash flows used in investing activities - discontinued operations (351) (453) 102
\n
Cash flows from/(used in) financing activities - discontinued operations 656 118 538
\n
Cash flows - discontinued operations (86) (55) (31)
\n

\n\n

\n\n
36. Assets and liabilities included in disposal groups classified as held for sale \u2013 \u20ac6,149
\n
million and \u20ac3,360 million
\n
Changes in assets held for sale in 2022 break down as fol-
\n
lows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-
\n
current assets
\n
Disposals and
\n
change in
\n
consolidation
\n
scope Impairment
\n
Exchange
\n
differences Investments
\n
Other
\n
changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Property, plant and equipment 899 5,231 (1,848) (1,102) 18 47 59 3,304
\n
Intangible assets 144 1,985 (1,136) (797) 23 17 98 334
\n
Goodwill 1 550 (62) (488) (42) - 41 -
\n
Deferred tax assets 16 578 (408) - - - 25 211
\n
Equity-accounted investments 4 27 (2) (1) - - (1) 27
\n
Non-current contract assets - 227 (233) - (2) 84 (76) -
\n
Other non-current assets 40 750 (639) - - - (26) 125
\n
Non-current financial assets - 208 (144) - (12) - 86 138
\n
Current financial assets and
\n
securities
\n
- 113 (65) - - - (5) 43
\n
Other current financial assets - 75 - - 8 - (74) 9
\n
Cash and cash equivalents 44 587 (287) - (4) - 85 425
\n
Inventories, trade receivables
\n
and other current assets
\n
94 2,353 (1,054) - (8) - 148 1,533
\n
Total 1,242 12,684 (5,878) (2,388) (19) 148 360 6,149
\n
Developments in liabilities break down as follows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-current
\n
liabilities
\n
Disposals and
\n
change in
\n
consolidation
\n
scope
\n
Exchange
\n
differences Other changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Long-term borrowings 782 1,160 (1,259) 33 59 775
\n
Provisions for risks and charges,
\n
non-current portion
\n
10 272 (242) 1 (8) 33
\n
Deferred tax liabilities 46 441 (207) - (40) 240
\n
Post-employment and other
\n
employee benefits
\n
-65(42)--23
\n
Non-current financial liabilities 40 123 (5) (10) (79) 69
\n
Non-current contract liabilities - 447 (5) (2) 2 442
\n
Other non-current liabilities 5 649 (597) (3) 125 179
\n
Short-term borrowings 2 651 (17) (9) 15 642
\n
Long-term borrowings, current
\n
portion
\n
- 137 (1,328) (29) 1,238 18
\n
Provisions for risks and charges,
\n
current portion
\n
-47(14) - -33
\n
Other current financial liabilities 6 28 (57) (1) 36 12
\n
Trade payables and other
\n
current liabilities
\n
71 1,663 (828) 4 (16) 894
\n
Total 962 5,683 (4,601) (16) 1,332 3,360
\n

\n\n

\n\n

\n\n
The item essentially includes assets measured at the lower
\n
of cost, understood as their net carrying amount, and the
\n
estimated realizable value, which, due to management de-
\n
cisions, meet the requirements of \u201cIFRS 5 - Non-current
\n
assets held for sale and discontinued operations\u201d for their
\n
classification in this item.
\n
The balances of assets and liabilities held for sale and
\n
discontinued operations at December 31, 2022 came to,
\n
respectively, \u20ac6,149 million and \u20ac3,360 million and mainly
\n
refer to:
\n
\u2022 Romania: on December 14, 2022, Enel SpA announced
\n
that it had entered into an Exclusivity Agreement with
\n
Greek company Public Power Corporation SA (PPC) in
\n
relation to the potential disposal of all the equity stakes
\n
held by Enel Group in Romania. The value of the net as-
\n
sets held in Romania was thus adjusted to the expected
\n
sale price, with the recognition of an impairment loss of
\n
about \u20ac696 million, and the same were classified as \u201cdis-
\n
continued operations\u201d;
\n
\u2022 Enel Green Power Hellas: the parent company Enel Green
\n
Power has started a process aimed at finding an investor
\n
interested in a partnership for the management and de-
\n
velopment of the renewable energy business in Greece.
\n
The status of negotiations suggests that the sale is high-
\n
ly probable as at December 31, 2022. Accordingly, the
\n
requirements established by \u201cIFRS 5 - Non-current as-
\n
sets held for sale and discontinued operations\u201d for the
\n
classification of Greek assets as \u201cdiscontinued opera-
\n
tions\u201d have been met;
\n
\u2022 Enel Green Power Australia: considering the status of
\n
negotiations, the two subholding companies held in
\n
Australia and their subsidiaries have been reclassified
\n
under non-current assets held for sale and discontin-
\n
ued operations, in accordance with IFRS 5, with the aim
\n
of reaching an agreement with third parties within the
\n
Stewardship business model in the next 12 months;
\n
\u2022 Central Dock Sud and Enel Generaci\u00f3n Costanera in Ar-
\n
gentina: the Enel Group, through its subsidiary Enel Ar-
\n
gentina, started negotiations for the sale of the Group\u2019s
\n
75.7% stake in the thermal generation company Enel
\n
Generaci\u00f3n Costanera. Negotiations also covered the
\n
sale of the Group\u2019s 41.2% stake in the thermal genera-
\n
tion company Central Dock Sud. The net assets of the
\n
interests were classified as available for sale and their
\n
value was adjusted to the expected sale price (\u20ac97 mil-
\n
lion), with the recognition of an impairment loss of about
\n
\u20ac290 million. The transaction was finalized in the 1st
\n
Quarter of 2023;
\n
\u2022 Avikiran Solar India Private Limited in India: following the
\n
agreements signed for the partial sale to a new share-
\n
holder, the investment satisfies the requirements of
\n
\u201cIFRS 5 - Non-current assets held for sale and discon-
\n
tinued operations\u201d, for classification of the net assets as
\n
available for sale. The disposal is expected to be finalized
\n
in the 1st Half of 2023;
\n
\u2022 3SUN in Italy: based on the negotiation process for the
\n
sale of a 50% stake in the share capital of 3SUN Srl, its
\n
net assets were reclassified at December 31, 2022 as
\n
non-current assets held for sale and discontinued oper-
\n
ations, in line with IFRS 5.
\n
Assets previously classified as held for sale disposed of in
\n
2022 include:
\n
\u2022 renewable companies in South Africa sold in the 1st Half
\n
of 2022;
\n
\u2022 CGT Fortaleza in Brazil and companies belonging to the
\n
financial sector of Enel X in Italy sold in the 3rd Quarter;
\n
\u2022 the interest held by Enel SpA in Enel Russia sold in Octo-
\n
ber 2022, thus completing the disposal of all electricity
\n
generation assets in Russia. For more information on the
\n
economic effects of the transaction, please refer to the
\n
paragraph \u201cDiscontinued operations\u201d;
\n
\u2022 the subsidiary Enel Chile SA completed the sale of the
\n
entire investment, equal to 99.09% of the share capi-
\n
tal, held in the Chilean electricity transmission company
\n
Enel Transmisi\u00f3n Chile SA, while the subsidiary Enel Bra-
\n
sil SA finalized the sale of the entire interest held in the
\n
Brazilian power distribution company Celg Distribui\u00e7\u00e3o
\n
SA - Celg-D in December 2022.
\n
For more information on the financial effects of the above
\n
transactions, please refer to the note \u201cBusiness combina-
\n
tions\u201d.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag975": { "value": "\n

\n

\n
7. Restatement of comparative disclosures
\n
Discontinued operations
\n\n
The 2021 consolidated income statement and statement
\n
of consolidated comprehensive income have been adjust-
\n
ed to take account of the presentation of discontinued
\n
operations as required by the \u201cIFRS 5 - Non-current assets
\n
held for sale and discontinued operations\u201d.
\n
For more details, please refer to the note \u201cDiscontinued
\n
operations\u201d.
\n
Impact on the consolidated income statement
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Revenue 88,006 (2,287) 85,719
\n
Costs 82,848 (2,157) 80,691
\n
Net results from commodity contracts 2,522 1 2,523
\n
Operating profit 7,680 (129) 7,551
\n
Financial income from derivatives 2,718 (1) 2,717
\n
Other financial income 1,882 (20) 1,862
\n
Financial expense from derivatives 1,257 (1) 1,256
\n
Other financial expense 6,114 (27) 6,087
\n
Net income from hyperinflation 20 - 20
\n
Share of profit/(loss) of equity-accounted investments 571 - 571
\n
Pre-tax profit 5,500 (122) 5,378
\n
Income taxes 1,643 (23) 1,620
\n
Profit/(Loss) from continuing operations 3,857 (99) 3,758
\n
Attributable to owners of the Parent 3,857 (760) 3,097
\n
Attributable to non-controlling interests - 661 661
\n
Profit/(Loss) from discontinued operations - 99 99
\n
Attributable to owners of the Parent - 92 92
\n
Attributable to non-controlling interests - 7 7
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling interests) 3,857 - 3,857
\n

\n\n

\n\n

\n\n
Impact on the consolidated comprehensive income
\n
Millions of euro
\n
2021 IFRS 5 2021 restated
\n
Profit for the year 3,857 3,857
\n
Other comprehensive income/(expense) that may be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Effective portion of change in the fair value of cash flow hedges (725) (10) (735)
\n
Change in the fair value of hedging costs 195 (1) 194
\n
Share of the other comprehensive expense of equity-accounted
\n
investments
\n
(645) - (645)
\n
Change in the fair value of financial assets at FVOCI 11 - 11
\n
Change in translation reserve (90) 5 (85)
\n
Cumulative other comprehensive income that may be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
66
\n
Other comprehensive income/(expense) that may not be subsequently
\n
reclassified to profit or loss (net of taxes)
\n
Remeasurement of net liabilities/(assets) for defined benefit plans 30 (1) 29
\n
Change in fair value of equity investments in other companies - - -
\n
Cumulative other comprehensive income that may not be subsequently
\n
reclassified to profit or loss in respect of non-current assets and disposal
\n
groups classified as held for sale/discontinued operations
\n
11
\n
Total other comprehensive expense for the year (1,224) - (1,224)
\n
Comprehensive income/(expense) for the year 2,633 - 2,633
\n
Attributable to:
\n
- owners of the Parent 2,562 2,562
\n
- non-controlling interests 71 71
\n

\n\n
The figures presented in the comments and the tables of
\n
the notes to these consolidated financial statements at
\n
December 31, 2022 are uniform and comparable with each
\n
other.
\n
Segment reporting
\n
Figures at December 31, 2021 for the Business Line Enel X
\n
have been adjusted to take account of the transfer of cer-
\n
tain net assets and related revenue and expenses to the new
\n
Business Line Enel X Way, which are shown under \u201cHolding,
\n
Services and Other\u201d. This change affected segment report-
\n
ing but did not produce any changes in the overall figures
\n
for the Group, although a number reclassifications of values
\n
were made within the various business lines.
\n
The figures presented in the comments and the tables of
\n
the notes to these consolidated financial statements at De-
\n
cember 31, 2022 are uniform and comparable with each
\n
other.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfReclassificationsOrChangesInPresentationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag976": { "value": "\n
8. Main acquisitions and disposals during the year
\n
In the two periods under review, the consolidation scope
\n
changed as a result of a number of transactions.
\n
2021
\n
\u2022 On January 8, 2021, 100% of Tynemouth Energy Storage
\n
was sold for \u20ac1 million. The sale did not have any significant
\n
impact on profit or loss.
\n
\u2022 On January 20, 2021, Enel Green Power Bulgaria was sold
\n
for a total \u20ac35 million. The sale did not have any significant
\n
impact on profit or loss.
\n
\u2022 On March 10, 2021, Enel Green Power Italia acquired 100%
\n
of e-Solar Srl, the owner of a photovoltaic project with an
\n
authorized capacity of 170.11 MW, for \u20ac2.7 million.
\n
\u2022 On March 29, 2021, Enel X Srl acquired 100% of CityPoste
\n
Payment SpA, an Italian company that offers consumers
\n
access to payment services through both physical and dig-
\n
ital channels, enabling them to carry out numerous types of
\n
transactions with private- and public-sector entities.
\n
\u2022 In the 1st Quarter of 2021, the consolidation scope
\n
changed with the global consolidation of Australian renew-
\n
able energy companies previously accounted for using the
\n
equity method due to a change in governance arrange-
\n
ments at the companies, without the acquisition of an ad-
\n
ditional interest. The purchase price allocation process was
\n
completed in December 2021 and essentially confirmed
\n
the carrying amount of the net assets acquired following
\n
an impairment loss of about \u20ac9 million.
\n
\u2022 On May 13, 2021, EGP Solar 1 LLC was sold for a total of
\n
about \u20ac4 million.
\n
\u2022 In the first nine months of 2021, Enel Green Power Espa\u00f1a
\n
acquired 100% of 30 renewables companies for a total of
\n
\u20ac86 million.
\n
\u2022 On September 8, 2021, Genability was sold by Enel X North
\n
America for about \u20ac6 million.
\n
\u2022 The purchase price allocation process for Viva Labs AS,
\n
acquired on September 17, 2020 by Enel X International,
\n
was completed in September, following which the carry-
\n
ing amounts recognized at the acquisition date were con-
\n
firmed.
\n
Other changes
\n
In addition to the above changes in the consolidation
\n
scope, the following transactions, although they do not
\n
represent transactions involving the acquisition or loss of
\n
control, gave rise to a change in the interest held by the
\n
Group in the investees:
\n
\u2022 on March 15, Enel SpA launched a partial voluntary ten-
\n
der offer for up to a maximum of 7,608,631,104 shares
\n
of Enel Am\u00e9ricas, equal to 10% of the share capital at
\n
that date. The offer period began on March 15 and end-
\n
ed on April 13, 2021.The tender offer was subject to the
\n
effectiveness of the merger of EGP Am\u00e9ricas SpA into
\n
Enel Am\u00e9ricas SA, which took place on April 1, 2021. The
\n
total price was \u20ac1,271 million. Following completion of
\n
the partial voluntary tender offer and the completion of
\n
the EGP Am\u00e9ricas merger, Enel owns about 82.3% of the
\n
outstanding share capital of Enel Am\u00e9ricas;
\n
\u2022 on November 24, Enel Green Power RSA 2 (Pty) Ltd sold
\n
a stake in the investments held in Oyster Bay Wind Farm,
\n
Garob Wind Farm, Aced Renewables Hidden Valley and
\n
Soetwater Wind Farm for a total of ZAR 340 million, cor-
\n
responding to about \u20ac19 million. Following the transac-
\n
tion, the Group\u2019s interest in those companies decreased
\n
from 60% to 55%;
\n
\u2022 on December 3, Enel SpA finalized the sale of the entire
\n
stake held in Open Fiber SpA, equal to 50% of the latter\u2019s
\n
share capital, to Macquarie Asset Management and CDP
\n
Equity SpA for a total of about \u20ac2,733 million. The capital
\n
gain realized by the Group on a consolidated basis came
\n
to about \u20ac1,763 million.
\n
2022
\n
\u2022 On January 3, 2022, Enel Produzione SpA acquired 100%
\n
of ERG Hydro Srl (subsequently renamed Enel Hydro Ap-
\n
pennino Centrale Srl and merged into Enel Produzione
\n
SpA on December 1, 2022), owner of generation plants
\n
with an installed capacity of about 527 MW and an annu-
\n
al output of approximately 1.5 TWh, for a consideration
\n
of about \u20ac1,267 million; in December 2022, the identifi-
\n
cation of the fair value of the acquired assets and liabil-
\n
ities was completed, with the recognition of goodwill of
\n
approximately \u20ac349 million.
\n
\u2022 On February 17, 2022, Enel Green Power Espa\u00f1a acquired
\n
100% of Stonewood Desarrollos SLU for about \u20ac14 mil-
\n
lion representing the licenses acquired for the devel-
\n
opment and construction of photovoltaic systems. The
\n
acquisition had no impact on profit or loss.
\n
\u2022 On March 3, 2022, Enel X Germany sold its entire stake
\n
in Cremzow KG and Cremzow Verwaltungs for about \u20ac12
\n
million.
\n
\u2022 On June 30, 2022, Enel Green Power SpA sold to Al
\n
Rayyan Holding LLC (controlled by the Qatar Investment
\n
Authority) 50% of its stake in EGP Matimba NewCo 1 Srl,
\n
indirect owner of six companies in South Africawith an
\n

\n\n
installed capacity of about 740 MW, for about \u20ac108 mil-
\n
lion, which has been paid in full.
\n
\u2022 On July 25, 2022, Enel X Srl sold to Mooney SpA, for
\n
about \u20ac140 million, settled in the form of financial re-
\n
ceivables, its entire stakes in Enel X Financial Services,
\n
CityPoste Payment, PayTipper and Junia Insurance and
\n
their subsidiaries.
\n
\u2022 On August 24, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas, closed the sale of its entire stake in CGTF -
\n
Central Geradora Termel\u00e9trica Fortaleza SA to ENEVA
\n
SA for a consideration of about \u20ac89 million. The trans-
\n
action had a negative impact on profit or loss of about
\n
\u20ac210 million, including impairment losses on assets of
\n
\u20ac73 million, a capital loss of \u20ac135 million and transaction
\n
costs connected with the sale of \u20ac2 million.
\n
\u2022 In the first nine months of 2022, Enel Green Power Ro-
\n
mania acquired 100% of Prowind Windfarm Bogdanesti,
\n
Prowind Windfarm Deleni, Prowind Windfarm Ivesti and
\n
Prowind Windfarm Viisoara for a total of about 35 mil-
\n
lion.
\n
\u2022 On October 12, 2022, Enel finalized the sale of its entire
\n
stake in PJSC Enel Russia, equal to 56.43% of the latter\u2019s
\n
share capital, to PJSC Lukoil and the Closed Combined
\n
Mutual Investment Fund \u201cGazprombank-Frezia\u201d, for a to-
\n
tal of about \u20ac137 million. The transaction had a negative
\n
impact on reported Group profit of around \u20ac1.5 billion,
\n
mainly reflecting the release of a currency translation.
\n
\u2022 On December 9, 2022, Enel Chile SA finalized the sale
\n
of its entire 99.09% stake in the share capital of listed
\n
Chilean power transmission company Enel Transmisi\u00f3n
\n
Chile SA to Sociedad Transmisora Metropolitana SpA,
\n
controlled by Inversiones Grupo Saesa Ltda, for about
\n
\u20ac1.3 billion. The transaction generated a capital gain of
\n
about \u20ac1.1 billion.
\n
\u2022 On December 22, 2022, Enel closed the sale of a 50%
\n
quota in its wholly-owned subsidiary Gridspertise Srl to
\n
the international private equity fund CVC Capital Part-
\n
ners Fund VIII for a total of approximately \u20ac300 million.
\n
The transaction had a positive impact on profit or loss of
\n
about \u20ac520 million.
\n
\u2022 On December 23, 2022, Enel Green Power India Private
\n
Limited finalized an agreement with Norfund following
\n
which the latter made an investment in Avikiran Surya
\n
India Private Limited by subscribing shares issued by the
\n
company totaling 49% of the paid-up share capital. The
\n
transaction had a negative impact of about \u20ac4 million on
\n
profit or loss, of which \u20ac2 million from the remeasure-
\n
ment at fair value of the residual interest and a capital
\n
loss of \u20ac2 million.
\n
\u2022 On December 29, 2022, Enel Brasil SA, a subsidiary of
\n
Enel Am\u00e9ricas SA, finalized the sale of its entire stake
\n
in the Brazilian power distribution company Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), equal to about 99.9%
\n
of the latter\u2019s share capital, to Equatorial Participa\u00e7\u00f5es
\n
e Investimentos SA, a subsidiary of Equatorial Energia
\n
SA, for a total of about \u20ac1.5 billion (of which about \u20ac269
\n
million for the equity portion and about \u20ac1.2 billion as
\n
repayment of intercompany loans). The transaction had
\n
a negative impact on profit or loss of about \u20ac1 billion.
\n
Other changes
\n
In addition to the above changes in the consolidation
\n
scope, the following transactions, although they do not
\n
represent transactions involving the acquisition or loss of
\n
control, gave rise to a change in the interest held by the
\n
Group in the investees:
\n
\u2022 on March 1, 2022, the merger between Emgesa SA ESP
\n
(acquiring entity), Codensa SA ESP, Enel Green Power
\n
Colombia SAS ESP and ESSA 2 (merged entities) was
\n
completed. The new name of the surviving company is
\n
Enel Colombia SA ESP. Following the transaction, the
\n
Group\u2019s stake in Emgesa SA ESP (now Enel Colombia SA
\n
ESP) increased from 39.89% to about 47.18%;
\n
\u2022 on March 24, 2022, Enel X International Srl finalized an
\n
agreement with a holding company controlled by Sixth
\n
Cinven Fund and a holding company controlled by Sev-
\n
enth Cinven Fund to indirectly acquire about 79.4% of
\n
the share capital of Ufinet Latam SLU (for \u20ac1,320 million)
\n
and at the same time sold 80.5% of the share capital of
\n
that company to Seventh Cinven Fund (for \u20ac1,186 mil-
\n
lion). Enel X International also received about \u20ac207 mil-
\n
lion from Ufinet as a distribution of available reserves.
\n
Consequently, Enel X International now holds an indirect
\n
stake of 19.5% in Ufinet, of which it had previously held
\n
20.6%. The transaction generated a positive net cash
\n
flow of about \u20ac73 million and had a positive impact on
\n
operating performance of about \u20ac220 million;
\n
\u2022 on June 15, 2022, Enel Kansas LLC sold 50% of its stake
\n
in Rocky Caney Holdings LLC for about \u20ac34 million. Fol-
\n
lowing the transaction, the interest of Enel Kansas LLC in
\n
Rocky Caney Holdings LLC decreased from 20% to 10%.
\n
The transaction generated a capital gain of about \u20ac7 mil-
\n
lion;
\n
\u2022 on June 16, 2022, EGPNA REP Holdings LLC sold 50% of its
\n
stake in EGPNA Renewable Energy Partners LLC for about
\n
\u20ac60 million. Following the transaction, EGPNA REP Hold-
\n
ings LLC holds 10% of EGPNA Renewable Energy Partners
\n
LLC. The transaction generated a capital loss of about \u20ac7
\n
million;
\n
\u2022 on July 14, 2022, Enel, acting through its wholly-owned
\n
subsidiary Enel X, acquired 50% of the share capital of
\n
Mooney SpA. Based on an enterprise value of 100% for
\n
Mooney of \u20ac1,385 million, Enel X paid a total of about
\n
\u20ac225 million (including price adjustment) for the equity
\n
portion and about \u20ac125 million for the purchase of an ex-
\n
isting claim of Schumann Investments SA against Mooney;
\n
\u2022 on December 2022, Enel Green Power Hellas SA sold the
\n
entire stake held in associated companies of the Cy-
\n

\n\n

\n
clades. The transaction did not have a significant impact
\n
on profit or loss;
\n
\u2022 on December 6, 2022, Enel X Chile SpA sold its entire
\n
stake in Sociedad de Inversiones K Cuatro SpA, Sumin-
\n
istradora de buses K Cuatro SpA and Enel X AMPCI Ebus
\n
Chile SpA for about \u20ac35 million (uncollected as of De-
\n
cember 31, 2022). The transaction did not have a signifi-
\n
cant impact on profit or loss;
\n
\u2022 on December 30, 2022, Enel Green Power Canada Inc.
\n
sold its 49% stake in Pincher Creek LP and Riverview LP
\n
for about \u20ac56 million. The transaction did not result in
\n
the loss of control in the companies.
\n\n
Acquisition of ERG Hydro Srl
\n
On January 3, 2022, Enel Produzione SpA acquired 100% of
\n
ERG Hydro Srl (subsequently renamed Enel Hydro Appen-
\n
nino Centrale Srl and merged into Enel Produzione SpA on
\n
December 1, 2022), owner of generation plants with an in-
\n
stalled capacity of about 527 MW and an annual output of
\n
approximately 1.5 TWh, for about \u20ac1,267 million.
\n
At December 2022, the identification of the fair value of
\n
the acquired assets and liabilities was completed, with the
\n
recognition of goodwill of \u20ac349 million.
\n
Millions of euro
\n
Carrying amount
\n
before January 3, 2022
\n
Adjustments for
\n
purchase price
\n
allocation
\n
Amount recognized
\n
at January 3, 2022
\n
Property, plant and equipment 605 167 772
\n
Intangible assets 1 170 171
\n
Other non-current assets 15 10 25
\n
Cash and cash equivalents 69 - 69
\n
Other current assets 94 - 94
\n
Deferred tax liabilities (4) (102) (106)
\n
Provisions for risk and charges and employee benefits (35) (7) (42)
\n
Current liabilities (65) - (65)
\n
Net assets acquired 680 238 918
\n
Cost of the acquisition 1,267 - 1,267
\n
(of which paid in cash) 1,265 - 1,265
\n
Goodwill 587 (238) 349
\n

\n\n
Sale of Ufinet
\n
On March 24, 2022 Enel X International Srl sold 1.1% of
\n
Ufinet.
\n
The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Price for acquisition of 79.4% through exercise of call option with Sixth Cinven Fund (1,320)
\n
Distribution of Ufinet reserves 207
\n
Price for sale of 80.5% to Seventh Cinven Fund 1,186
\n
Net cash flow of transaction 73
\n
Capital gain on sale of interest (1.1%) (6)
\n
Release of OCI reserve (24)
\n
Net capital gain on sale 43
\n
Fair value measurement of interest already held (19.5%) 177
\n
Total financial impact 220
\n
Following the transaction, the residual investment in Ufinet
\n
was classified under other investments measured at fair
\n
value through other comprehensive income. Previously it
\n
had been accounted for using the equity method.
\n

\n\n
Sale of EGP Matimba NewCo 1
\n
On June 30, 2022, Enel Green Power SpA sold to Al Rayyan
\n
Holding LLC (controlled by the Qatar Investment Authority)
\n
50% of its stake in EGP Matimba NewCo 1 Srl, indirect own-
\n
er of six projects in South Africa, for about \u20ac108 million,
\n
which has been paid in full.
\n
Millions of euro
\n
Total net assets held for sale with loss of control 220
\n
Interest sold (50%) 110
\n
Sale price 108
\n
Gain/(Loss) on sale (2)
\n
Fair value measurement of interest already held (2)
\n
Total financial impact (4)
\n
Following the transaction, the residual equity investment in
\n
EGP Matimba 1 and its subsidiaries was classified among
\n
equity-accounted investments and it was remeasured at
\n
fair value with a negative impact on profit or loss of about
\n
\u20ac2 million. Following this remeasurement, the value of the
\n
residual equity investment is \u20ac108 million.
\n
Sale of Enel X Financial Services, CityPoste Payment, PayTipper and Junia Insurance
\n
On July 25, 2022, Enel X Srl sold to Mooney SpA, for about
\n
\u20ac140 million, settled in the form of financial receivables, its
\n
entire stakes in Enel X Financial Services, CityPoste Pay-
\n
ment, PayTipper and Junia Insurance and their subsidiaries.
\n
Millions of euro
\n
Value of the transaction 140
\n
Net assets sold (73)
\n
Capital gain on sale 67
\n
The transaction produced a capital gain of \u20ac67 million.
\n
Sale of Central Geradora Termel\u00e9trica Fortaleza SA
\n
On August 24, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas, sold its entire stake in CGTF - Central Geradora
\n
Termel\u00e9trica Fortaleza SA to ENEVA SA for \u20ac89 million.
\n
During 2022, in line with the provisions of \u201cIFRS 5 -
\n
Non-current assets held for sale and discontinued oper-
\n
ations\u201d, the net assets of CGTF - Central Geradora Ter-
\n
mel\u00e9trica Fortaleza SA were classified as held for sale and
\n
their value was adjusted to the expected sale price in the
\n
amount of \u20ac73 million.
\n
Millions of euro
\n
Sale price 89
\n
Net assets sold 125
\n
Reversal of OCI reserve (99)
\n
Capital loss (135)
\n
Adjustment of pre-sale plant value (73)
\n
Financial impact (208)
\n
With the closing of the sale, a capital loss of about \u20ac135
\n
million was recognized, mainly due to the release of the
\n
translation reserve, plus other transaction costs of \u20ac2 mil-
\n
lion and the associated tax impact of \u20ac37 million.
\n

\n\n
Sale of PJSC Enel Russia
\n
On October 12, 2022, Enel finalized the sale of the entire stake
\n
held in PJSC Enel Russia, equal to 56.43% of the share capital
\n
of the latter, to PJSC Lukoil and the Closed Combined Mutual
\n
Investment Fund \u201cGazprombank-Frezia\u201d, for a total of about
\n
\u20ac137 million. The sale had an overall negative impact on profit
\n
or loss of about \u20ac1,551 million, mainly due to the release of the
\n
translation reserve, in the amount of about \u20ac1,054 million. The
\n
financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 137
\n
Net assets sold 137
\n
Reversal of OCI reserve (1,054)
\n
Capital loss (1,054)
\n
Adjustment of pre-sale plant value (497)
\n
Financial impact (1,551)
\n
For more information on the transaction, please see the
\n
section \u201cDiscontinued operations\u201d.
\n
Sale of Enel Transmisi\u00f3n Chile SA
\n
On December 9, 2022, Enel Chile SA finalized the sale of
\n
its entire 99.09% stake in the share capital of listed Chilean
\n
power transmission company Enel Transmisi\u00f3n Chile SA to
\n
Sociedad Transmisora Metropolitana SpA, controlled by In-
\n
versiones Grupo Saesa Ltda, for a total amount of \u20ac1,342
\n
million. The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 1,342
\n
Net assets sold 230
\n
Goodwill 61
\n
Capital gain on sale 1,051
\n
The transaction had a tax effect of \u20ac347 million.
\n
Sale of Gridspertise Srl
\n
On December 22, 2022, Enel SpA, acting through Enel
\n
Grids Srl, closed the sale of a 50% quota in its whol-
\n
ly-owned subsidiary Gridspertise Srl to the international
\n
private equity fund CVC Capital Partners Fund VIII for a to-
\n
tal of approximately \u20ac300 million. The financial effects of
\n
the transaction are as follows.
\n
Millions of euro
\n
Total net assets held for sale with loss of control 80
\n
Interest sold (50%) 40
\n
Sale price 299
\n
Release of OCI reserve 2
\n
Capital gain 261
\n
Fair value measurement of residual interest 259
\n
Total financial impact 520
\n
Following the transaction, the residual investment in in
\n
Gridspertise Srl and its subsidiaries was accounted using
\n
the equity method. After fair value measurement, the value
\n
of the residual investment is \u20ac259 million.
\n
The transaction had a tax effect of \u20ac8 million.
\n

\n\n

\n
Sale of Celg Distribui\u00e7\u00e3o SA
\n
On December 29, 2022, Enel Brasil SA, a subsidiary of Enel
\n
Am\u00e9ricas SA, finalized
\n
the sale of its entire stake in the
\n
Brazilian power distribution company Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (Enel Goi\u00e1s)
\n
, equal to about 99.9% of the latter\u2019s
\n
share capital
\n
, to Equatorial Participa\u00e7\u00f5es e Investimentos
\n
SA,
\n
a subsidiary of Equatorial Energia SA, for a total of
\n
about \u20ac1,548 million, of which \u20ac269 million for the equity
\n
portion and \u20ac1,279 million as repayment of intercompany
\n
loans. The financial effects of the transaction are as follows.
\n
Millions of euro
\n
Sale price 269
\n
Net assets sold 269
\n
Release of OCI reserve (208)
\n
Capital loss on disposal (208)
\n
Adjustment of pre-sale value (827)
\n
Financial impact (1,035)
\n
The sale had a negative impact on profit or loss of about
\n
\u20ac1,035 million, of which about \u20ac208 million mainly attrib-
\n
utable to the release of the OCI reserve and \u20ac827 million in
\n
respect of impairment losses (of which \u20ac85 million relating
\n
to goodwill).
\n
The sale generated transaction costs of \u20ac4 million and a
\n
tax effect of \u20ac8 million.
\n

\n", "dimensions": { "concept": "enel:DisclosureOfChangeInOwnershipInterestsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag977": { "value": "\n
Acquisition of ERG Hydro Srl
\n
On January 3, 2022, Enel Produzione SpA acquired 100% of
\n
ERG Hydro Srl (subsequently renamed Enel Hydro Appen-
\n
nino Centrale Srl and merged into Enel Produzione SpA on
\n
December 1, 2022), owner of generation plants with an in-
\n
stalled capacity of about 527 MW and an annual output of
\n
approximately 1.5 TWh, for about \u20ac1,267 million.
\n
At December 2022, the identification of the fair value of
\n
the acquired assets and liabilities was completed, with the
\n
recognition of goodwill of \u20ac349 million.
\n
Millions of euro
\n
Carrying amount
\n
before January 3, 2022
\n
Adjustments for
\n
purchase price
\n
allocation
\n
Amount recognized
\n
at January 3, 2022
\n
Property, plant and equipment 605 167 772
\n
Intangible assets 1 170 171
\n
Other non-current assets 15 10 25
\n
Cash and cash equivalents 69 - 69
\n
Other current assets 94 - 94
\n
Deferred tax liabilities (4) (102) (106)
\n
Provisions for risk and charges and employee benefits (35) (7) (42)
\n
Current liabilities (65) - (65)
\n
Net assets acquired 680 238 918
\n
Cost of the acquisition 1,267 - 1,267
\n
(of which paid in cash) 1,265 - 1,265
\n
Goodwill 587 (238) 349
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag979": { "value": "\n

\n
10. Performance and financial position by primary segment (Business
\n
Line) and secondary segment (Geographical Area)
\n\n
The representation of financial position and performance
\n
by business line and geographical area presented here is
\n
based on the approach used by management in monitor-
\n
ing Group performance for the two years being compared.
\n

\n

\n\n
Performance by primary segment (Business Line)
\n
Results for 2022
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-
\n
user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments To ta l
\n
Revenue and other income from third parties 53,239 6,669 19,806 58,478 2,143 182 140,517 - 140,517
\n
Revenue and other income from
\n
transactions with other segments
\n
23,096 2,498 3,226 3,674 66 2,053 34,613 (34,613) -
\n
Total revenue 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Total costs 71,189 5,873 13,918 62,517 1,544 2,503 157,544 (34,580) 122,964
\n
Net results from commodity contracts 551 183 - 1,608 (13) (5) 2,324 41 2,365
\n
Depreciation and amortization 802 1,456 2,852 498 223 255 6,086 - 6,086
\n
Impairment losses 562 53 1,047 1,177 102 17 2,958 - 2,958
\n
Impairment gains (52) (2) (117) (132) (17) 1 (319) - (319)
\n
Operating profit/(loss) 4,385 1,970 5,332 (300) 344 (546) 11,185 8 11,193
\n
Capital expenditure 990
\n
(2)
\n
6,386
\n
(3)
\n
5,547
\n
(4)
\n
721 371
\n
(5)
\n
332 14,347 - 14,347
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(3) Does not include \u20ac42 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac110 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n

\n\n
Results for 2021
\n
(1) (2) (3)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-
\n
user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments To ta l
\n
Revenue and other income from third parties 22,334 7,011 16,994 36,097 1,372 1,911 85,719 - 85,719
\n
Revenue and other income from
\n
transactions with other segments
\n
10,269 2,161 3,248 1,302 56 2,101 19,137 (19,137) -
\n
Total revenue 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
Total costs 32,327 4,547 13,142 36,372 1,102 2,649 90,139 (19,130) 71,009
\n
Net results from commodity contracts 537 (55) - 2,006 - (3) 2,485 38 2,523
\n
Depreciation and amortization 902 1,237 2,612 399 202 240 5,592 - 5,592
\n
Impairment losses 2,561 387 192 1,067 36 52 4,295 - 4,295
\n
Impairment gains (8) (5) (30) (156) (6) - (205) - (205)
\n
Operating profit/(loss) (2,642) 2,951 4,326 1,723 94 1,068 7,520 31 7,551
\n
Capital expenditure 822 5,662
\n
(4)
\n
5,296 643 285 289 12,997 - 12,997
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
(3) The figures for the Business Line Enel X have been adjusted to take account of the transfer of certain net assets and related revenue and expenses to the
\n
new Business Line Enel X Way, which are shown under \u201cHolding, Services and Other\u201d.
\n
(4) Does not include \u20ac111 million regarding units classified as held for sale or discontinued operations.
\n
Performance by secondary segment (Geographical Area)
\n
Results for 2022
\n
(1)
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments To ta l
\n
Revenue and other income from third parties 83,337 32,725 20,949 77 2,183 266 980 140,517
\n
Revenue and other income from
\n
transactions with other segments
\n
171 108 385 10 31 - (705) -
\n
Total revenue 83,508 32,833 21,334 87 2,214 266 275 140,517
\n
Total costs 81,880 25,388 14,811 66 1,126 174 (481) 122,964
\n
Net results from commodity contracts 4,679 (2,215) 56 6 (148) (9) (4) 2,365
\n
Depreciation and amortization 2,209 1,784 1,393 2 430 75 193 6,086
\n
Impairment losses 886 478 1,553 1 18 5 17 2,958
\n
Impairment gains (39) (271) (7) - - - (2) (319)
\n
Operating profit/(loss) 3,251 3,239 3,640 24 492 3 544 11,193
\n
Capital expenditure 4,640 2,316 4,289
\n
(2)
\n
224
\n
(3)
\n
2,491 164
\n
(4)
\n
223
\n
(5)
\n
14,347
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac94 million regarding units classified as held for sale.
\n
(3) Does not include \u20ac4 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac40 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac18 million regarding units classified as held for sale or discontinued operations.
\n
Results for 2021
\n
(1) (2)
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments To ta l
\n
Revenue and other income from third parties 44,282 20,800 16,956 49 1,479 240 1,913 85,719
\n
Revenue and other income from
\n
transactions with other segments
\n
1,135 252 1 (35) 34 1 (1,388) -
\n
Total revenue 45,417 21,052 16,957 14 1,513 241 525 85,719
\n
Total costs 40,751 17,412 12,867 59 748 135 (963) 71,009
\n
Net results from commodity contracts 1,967 543 53 40 (81) 4 (3) 2,523
\n
Depreciation and amortization 2,107 1,754 1,177 4 356 65 129 5,592
\n
Impairment losses 1,747 1,797 536 1 161 32 21 4,295
\n
Impairment gains (22) (170) (9) (2) - - (2) (205)
\n
Operating profit/(loss) 2,801 802 2,439 (8) 167 13 1,337 7,551
\n
Capital expenditure 3,842 2,202 3,722 456 2,293 217
\n
(3)
\n
265 12,997
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
(3) Does not include \u20ac111 million regarding units classified as held for sale or discontinued operations.
\n

\n\n
Financial position by primary segment (Business Line)
\n
At December 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 8,530 41,519 40,377 44 553 805 91,828 (3) 91,825
\n
Intangible assets 397 5,723 20,035 4,172 647 623 31,597 - 31,597
\n
Non-current and current
\n
contract assets
\n
- 50 500 - 72 53 675 (11) 664
\n
Trade receivables 7,667 3,730 5,706 8,426 618 1,304 27,451 (9,715) 17,736
\n
Other 7,928 540 2,551 2,716 480 2,535 16,750 (7,897) 8,853
\n
Operating assets 24,522
\n
(1)
\n
51,562
\n
(2)
\n
69,169
\n
(3)
\n
15,358
\n
(4)
\n
2,370
\n
(5)
\n
5,320 168,301 (17,626) 150,675
\n
Trade payables 8,034 4,173 4,297 8,647 705 1,394 27,250 (9,187) 18,063
\n
Non-current and current
\n
contract liabilities
\n
95 323 7,527 76 10 22 8,053 (89) 7,964
\n
Sundry provisions 3,979 921 3,263 380 101 1,095 9,739 (68) 9,671
\n
Other 3,475 1,802 6,691 6,740 300 4,454 23,462 (7,908) 15,554
\n
Operating liabilities 15,583
\n
(6)
\n
7, 2 1 9
\n
(7)
\n
21,778
\n
(8)
\n
15,843
\n
(9)
\n
1,116
\n
(10)
\n
6,965
\n
(11)
\n
68,504 (17,252) 51,252
\n
(1) Of which \u20ac190 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac1,951 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac1,855 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac1,160 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac80 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac87 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac185 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac390 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac476 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac11 million regarding units classified as held for sale or discontinued operations.
\n
(11) Of which \u20ac4 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2021
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 9,384 36,205 38,635 49 486 713 85,472 - 85,472
\n
Intangible assets 216 5,016 21,473 4,030 670 631 32,036 - 32,036
\n
Non-current and current
\n
contract assets
\n
1 1 525 - 60 21 608 43 651
\n
Trade receivables 4,814 2,601 6,731 6,533 559 1,347 22,585 (6,493) 16,092
\n
Other 4,319 826 2,614 3,812 345 2,287 14,203 (6,107) 8,096
\n
Operating assets 18,734
\n
(2)
\n
44,649
\n
(3)
\n
69,978 14,424 2,120
\n
(4)
\n
4,999 154,904 (12,557) 142,347
\n
Trade payables 5,730 3,701 4,390 7,129 695 1,259 22,904 (5,920) 16,984
\n
Non-current and current
\n
contract liabilities
\n
102 216 7,316 62 13 13 7,722 (75) 7,647
\n
Sundry provisions 4,586 936 3,810 466 52 1,297 11,147 (89) 11,058
\n
Other 4,125 1,901 8,104 4,575 141 3,659 22,505 (6,245) 16,260
\n
Operating liabilities 14,543 6,754
\n
(5)
\n
23,620 12,232 901
\n
(6)
\n
6,228 64,278 (12,329) 51,949
\n
(1) The figures for the Business Line Enel X have been adjusted to take account of the transfer of certain net assets and related revenue and expenses to the
\n
new Business Line Enel X Way, which are shown under \u201cHolding, Services and Other\u201d.
\n
(2) Of which \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac999 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac136 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac28 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac57 million regarding units classified as held for sale or discontinued operations.
\n

\n\n
Financial position by secondary segment (Geographical Area)
\n
At December 31, 2022
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 30,327 23,167 21,099 2,397 13,722 1,002 111 91,825
\n
Intangible assets 3,200 16,173 10,534 331 602 129 628 31,597
\n
Non-current and current contract
\n
assets
\n
73 9 493 48 19 16 6 664
\n
Trade receivables 7,086 4,369 5,037 1,127 268 66 (217) 17,736
\n
Other 4,947 2,929 1,498 294 250 63 (1,128) 8,853
\n
Operating assets 45,633
\n
(1)
\n
46,647 38,661
\n
(2)
\n
4,197
\n
(3)
\n
14,861 1,276
\n
(4)
\n
(600) 150,675
\n
Trade payables 9,595 3,220 4,813 483 1,261 119 (1,428) 18,063
\n
Non-current and current contract
\n
liabilities
\n
4,188 3,351 35 443 - 1 (54) 7,964
\n
Sundry provisions 3,008 3,458 2,378 69 97 32 629 9,671
\n
Other 4,323 3,144 4,480 637 1,893 66 1,011 15,554
\n
Operating liabilities 21,114
\n
(5)
\n
13,173 11,706
\n
(6)
\n
1,632
\n
(7)
\n
3,251 218
\n
(8)
\n
158 51,252
\n
(1) Of which \u20ac251 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac307 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac4,125 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac553 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac64 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac76 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac961 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac52 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2021
\n
Millions of euro Italy Iberia
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations
\n
and
\n
adjustments Tot al
\n
Property, plant and equipment 27,335 23,075 18,671 3,440 10,853 1,948 150 85,472
\n
Intangible assets 2,313 16,071 11,414 772 557 179 730 32,036
\n
Non-current and current contract
\n
assets
\n
94 5 517 - 18 13 4 651
\n
Trade receivables 7,372 3,886 4,414 583 215 51 (429) 16,092
\n
Other 4,555 2,474 1,398 217 259 140 (947) 8,096
\n
Operating assets 41,669
\n
(1)
\n
45,511 36,414 5,012 11,902 2,331
\n
(2)
\n
(492)
\n
(3)
\n
142,347
\n
Trade payables 9,684 2,509 4,333 481 1,208 136 (1,367) 16,984
\n
Non-current and current contract
\n
liabilities
\n
4,109 3,109 30 438 - - (39) 7,647
\n
Sundry provisions 3,395 4,211 2,426 130 120 32 744 11,058
\n
Other 5,749 3,945 4,509 328 1,482 64 183 16,260
\n
Operating liabilities 22,937
\n
(4)
\n
13,774 11,298 1,377 2,810 232
\n
(5)
\n
(479)
\n
(6)
\n
51,949
\n
(1) Of which \u20ac2 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac999 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac136 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac6 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac22 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac57 million regarding units classified as held for sale or discontinued operations.
\n

\n\n
The following table reconciles segment assets and liabili-
\n
ties and the consolidated figures.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Total assets 219,618 206,940
\n
Equity-accounted investments 1,281 704
\n
Non-current financial derivative assets 3,970 2,772
\n
Other non-current financial assets 8,359 5,704
\n
Non-current tax assets included in \u201cOther non-current assets\u201d 1,674 2,286
\n
Other current financial assets 13,753 8,645
\n
Current financial derivative assets 14,830 22,791
\n
Cash and cash equivalents 11,041 8,858
\n
Deferred tax assets 10,925 11,034
\n
Tax assets 2,159 1,694
\n
Financial and tax assets of \u201cAssets held for sale\u201d 951 105
\n
Segment assets 150,675 142,347
\n
Total liabilities 177,536 164,598
\n
Long-term borrowings 68,191 54,500
\n
Non-current financial derivative liabilities 5,895 3,339
\n
Other non-current financial liabilities -120
\n
Short-term borrowings 18,392 13,306
\n
Current portion of long-term borrowings 2,835 4,031
\n
Other current financial liabilities 853 625
\n
Current financial derivative liabilities 16,141 24,607
\n
Deferred tax liabilities 9,542 9,259
\n
Income tax liabilities 1,623 712
\n
Other tax liabilities 1,047 1,274
\n
Financial and tax liabilities of \u201cLiabilities included in disposal groups held for sale\u201d 1,765 876
\n
Segment liabilities 51,252 51,949
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag980": { "value": "\n
The representation of financial position and performance
\n
by business line and geographical area presented here is
\n
based on the approach used by management in monitor-
\n
ing Group performance for the two years being compared.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag987": { "value": "\n

\n
Revenue
\n\n
11.a Revenue from sales and services \u2013 \u20ac135,653 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Sale of electricity 69,340 45,053 24,287 53.9%
\n
Transport of electricity 11,096 10,606 490 4.6%
\n
Fees from network operators 979 800 179 22.4%
\n
Transfers from institutional market operators 1,667 833 834 -
\n
Sale of gas 8,970 4,744 4,226 89.1%
\n
Transport of gas 80 599 (519) -86.6%
\n
Sale of fuel 5,605 1,791 3,814 -
\n
Fees for connection to electricity and gas networks 826 769 57 7.4%
\n
Construction contracts
\n
(1)
\n
1,672 1,268 404 31.9%
\n
Sale of environmental certificates 111 107 4 3.7%
\n
Sale of value-added services 1,384 1,092 292 26.7%
\n
Other sales and services 918 785 133 16.9%
\n
Total IFRS 15 revenue 102,648 68,447 34,201 50.0%
\n
Sale of commodities under contracts with physical settlement 37,247 24,314 12,933 53.2%
\n
Gain/(Loss) on the measurement of commodity sales contracts with physical
\n
settlement closed during the period
\n
(4,260) (10,893) 6,633 60.9%
\n
Other revenue 18 32 (14) -43.8%
\n
Total revenue from sales and services 135,653 81,900 53,753 65.6%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Revenue from the \u201cSale of electricity\u201d amounted to \u20ac69,340
\n
million, an increase of \u20ac24,287 million compared with the
\n
previous year (+53.9%). The increase mainly reflects higher
\n
sales volumes and prices, mainly in Italy (\u20ac14,852 million)
\n
and Spain (\u20ac8,076 million).
\n
\u201cTransfers from institutional market operators\u201d increased
\n
by \u20ac834 million compared with the previous year, mainly
\n
in Iberia due to an increase in costs incurred for the pur-
\n
chase of commodities used in thermal generation plants in
\n
the Canary Islands, taking account of the rise in prices on
\n
international markets.
\n
Revenue from the \u201cSale of gas\u201d in 2022 amounted to \u20ac8,970
\n
million (\u20ac4,744 million in 2021), an increase of \u20ac4,226 million
\n
compared with the previous year. The increase is mainly attrib-
\n
utable to higher sales volumes at higher average prices espe-
\n
cially in Spain (\u20ac2,253 million) and Italy (\u20ac1,781 million).
\n
Revenue from the \u201cSale of fuel\u201d increased by \u20ac3,814 million,
\n
especially by Enel Global Trading due to the rise in gas sales.
\n
The increase in the \u201cSale of commodities under contracts
\n
with physical settlement\u201d (\u20ac12,933 million) and of perfor-
\n
mance of the measurement of contracts settled in 2022
\n
(\u20ac6,633 million) mainly involve gas contracts.
\n

\n\n

\n\n

\n\n
Revenue from contracts with customers (IFRS 15) breaks
\n
down into \u201cpoint in time\u201d and \u201cover time\u201d revenue as indi-
\n
cated in the following tables.
\n
Millions of euro 2022
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
47,650 2,068 30,984 1,425 17,686 1,227 52 4 1,109 33 214 43 10 143 97,705 4,943
\n
2021
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
(1)
\n
29,187 1,178 19,707 402 16,525 245 46 2 805 17 194 26 - 113 66,464 1,983
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The following table shows the net results on contracts for
\n
the sale or purchase of commodities with physical settle-
\n
ment measured at fair value through profit or loss within
\n
the scope of IFRS 9.
\n

\n\n

\n\n

\n\n
Millions of euro
\n
2022 2021 Change
\n
Fair value gain/(loss) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
Sales contracts
\n
Sale of electricity 5,436 4,368 1,068 24.5%
\n
Fair value gain/(loss) on closed contracts (795) (1,705) 910 53.4%
\n
Total electricity 4,641 2,663 1,978 74.3%
\n
Sale of gas 30,924 19,576 11,348 58.0%
\n
Fair value gain/(loss) on closed contracts (3,600) (9,335) 5,735 61.4%
\n
Total gas 27,324 10,241 17,083 -
\n
Sale of emissions allowances 875 366 509 -
\n
Fair value gain/(loss) on closed contracts 131 146 (15) -10.3%
\n
Total emissions allowances 1,006 512 494 96.5%
\n
Sale of guarantees of origin 12 4 8 -
\n
Fair value gain/(loss) on closed contracts 4 1 3 -
\n
Total guarantees of origin 16 5 11 -
\n
Total revenue 32,987 13,421 19,566 -
\n
Purchase contracts
\n
Purchase of electricity 6,161 3,677 2,484 67.6%
\n
Fair value gain/(loss) on closed contracts (200) (1,220) 1,020 83.6%
\n
Total electricity 5,961 2,457 3,504 -
\n
Purchase of gas 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on closed contracts (1,940) (8,057) 6,117 75.9%
\n
Total gas 31,152 11,894 19,258 -
\n
Purchase of emissions allowances 843 806 37 4.6%
\n
Fair value gain/(loss) on closed contracts 132 144 (12) -8.3%
\n
Total emissions allowances 975 950 25 2.6%
\n
Purchase of guarantees of origin 25 4 21 -
\n
Fair value gain/(loss) on closed contracts 3 1 2 -
\n
Total guarantees of origin 28 5 23 -
\n
Total costs 38,116 15,306 22,810 -
\n
Net revenue/(costs) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
(5,129) (1,885) (3,244) -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
Sales contracts
\n
Electricity (134) (1,606) 1,472 91.7%
\n
Gas 4,841 (16,285) 21,126 -
\n
Emissions allowances 490 (487) 977 -
\n
Guarantees of origin (15) (8) (7) -87.5%
\n
Tot al 5,182 (18,386) 23,568 -
\n
Purchase contracts
\n
Electricity (124) (2,169) 2,045 94.3%
\n
Gas 3,879 (13,801) 17,680 -
\n
Emissions allowances 627 (520) 1,147 -
\n
Guarantees of origin (72) 12 (84) -
\n
Tot al 4,310 (16,478) 20,788 -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
872 (1,908) 2,780 -
\n
Total net revenue/(costs) on contracts with physical settlement (within the scope of IFRS 9) (4,257) (3,793) (464) -12.2%
\n

\n\n

\n\n

\n\n
The table below gives a breakdown of revenue from sales
\n
and services by geographical segment.
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Italy 57,859 33,304
\n
Europe
\n
Iberia 30,535 18,896
\n
France 3,086 970
\n
Switzerland 6,791 2,918
\n
Germany 1,676 1,085
\n
Austria 189 245
\n
Slovenia 146 195
\n
Romania 3-
\n
Greece 15 -
\n
Bulgaria --
\n
Belgium 834 522
\n
Czech Republic 321 435
\n
Hungary 712
\n
Russia -3
\n
Netherlands 38 96
\n
United Kingdom 11,841 3,736
\n
Other European countries 1,551 1,160
\n
Americas
\n
United States 779 601
\n
Canada 53 33
\n
Mexico 313 202
\n
Brazil 9,064 9,381
\n
Chile 4,434 3,151
\n
Peru 1,449 1,111
\n
Colombia 2,725 2,188
\n
Argentina 966 887
\n
Panama 177 150
\n
Costa Rica 17 14
\n
Guatemala 83 67
\n
Other
\n
Africa 132 114
\n
Asia 521 371
\n
Oceania 48 53
\n
Tot al 135,653 81,900
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n
Performance obligations
\n
The following table provides information about the Group\u2019s
\n
performance obligations arising from contracts with cus-
\n
tomers with reference to the main revenue streams only,
\n
with a summary of the specific judgments made and the
\n
related revenue recognition policies.
\n
For information on the use of estimates with revenue from
\n
contracts with customers, please see note 2.1 \u201cUse of esti-
\n
mates and management judgment\u201d.
\n
Type of product/
\n
service Nature and timing of satisfaction of performance obligation Accounting policies
\n
Sale of electricity
\n
produced by the
\n
Group
\n
In order to determine the nature of the promise contained in these
\n
contracts with customers for the sale of electricity, the Group carefully
\n
analyzes the facts and circumstances applicable to each contract.
\n
For the sale of electricity on power exchanges, the facts and
\n
circumstances (including the intrinsic characteristics of the commodity,
\n
contractual terms, information regarding infrastructure and other
\n
delivery mechanisms) generally indicate that the performance obligation
\n
is a service in which the customer simultaneously receives and
\n
consumes the benefits of the commodity as it is delivered. Thus, the
\n
Group identifies a performance obligation satisfied over time as part of
\n
a series of distinct goods/services (i.e., each unit of commodity) that
\n
are substantially the same and have the same pattern of transfer to the
\n
customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale of electricity
\n
on power exchanges, recognized over time, so
\n
as to recognize revenue in the amount to which
\n
it has a right to invoice the customer if that
\n
amount corresponds directly with the value to the
\n
customer of the performance completed to date,
\n
i.e., at the price defined in the market (without
\n
variable consideration).
\n
Network
\n
connection
\n
services
\n
The network connection fees received from customers for connecting
\n
them to the electricity/gas distribution networks require a specific
\n
Group assessment to take into consideration all terms and conditions of
\n
the connection arrangements.
\n
This assessment is intended to determine whether the contract includes
\n
other distinct goods or services, such as for example the right to obtain
\n
ongoing access to the infrastructure in order to receive the commodity
\n
or, when the connection fee is a \u201cnon-refundable up-front fee\u201d paid
\n
at or near contract inception, a material right that gives rise to a
\n
performance obligation.
\n
In particular, in some countries in which the Group operates, it has
\n
determined that the nature of the consideration received represents
\n
a \u201cnon-refundable up-front fee\u201d whose payment provides a material
\n
right to the customer. In order to determine if the period over which
\n
this material right should be recognized extends beyond the initial
\n
contractual period, the Group takes into consideration the applicable
\n
local legal and regulatory framework applicable to the contract and
\n
affecting the parties. In such cases, if there is an implied assignment
\n
of the material right and an obligation from the initial customer to
\n
the new customer, the Group recognizes the connection fee over a
\n
period beyond the relationship with the initial customer, considering
\n
the concession terms as the period during which the initial customer
\n
and any future customer can benefit from the ongoing access without
\n
paying an additional connection fee. As a consequence, the fee is
\n
recognized over the period for which the payment creates an obligation
\n
for the Group to make the lower prices available to future customers (i.e.,
\n
the period during which the customer is expected to benefit from the
\n
ongoing access service without having to pay an \u201cup-front fee\u201d upon
\n
renewal).
\n
Revenue from monetary and in-kind fees for
\n
connection to the electricity and gas distribution
\n
network is recognized on the basis of the
\n
satisfaction of the performance obligations
\n
included in the contract. The identification of
\n
distinct goods or services requires a careful
\n
analysis of the terms and conditions of the
\n
connection arrangements, which could vary
\n
from country to country based on the local
\n
context, regulations and law. In order to finalize
\n
this assessment, the Group considers not
\n
only the characteristics of the goods/services
\n
themselves (i.e., the good or service is capable of
\n
being distinct) but also the implied promises for
\n
which the customer has a valid expectation as it
\n
views those promises as part of the negotiated
\n
exchange, that is goods/services that the
\n
customer expects to receive and has paid for (i.e.,
\n
the promise to transfer the good or service to
\n
the customer is separately identifiable from other
\n
promises in the contract).
\n
Furthermore, the Group acts as an agent in some
\n
contracts for electricity/gas network connection
\n
services and other related activities, depending
\n
on local legal and regulatory framework. In such
\n
cases, it recognizes revenue on a net basis,
\n
corresponding to any fee or commission to which
\n
it expects to be entitled.
\n
Sale/transport of
\n
electricity/gas to
\n
end users
\n
An electricity/gas supply agreement signed with an end user includes
\n
a single performance obligation (sale and transport of the commodity)
\n
because the Group has determined that the contract does not provide
\n
distinct goods/services and the promise is satisfied by transferring
\n
control over the commodity to the customer when it is delivered at
\n
the point of delivery. In order to determine the nature of the promise
\n
included in such contracts, the Group carefully analyzes the facts and
\n
circumstances applicable to each contract and commodity.
\n
However, the Group considers that the performance obligation provided
\n
for in a repetitive service contract, such as a supply or transport contract
\n
for the provision of electricity/gas to end users, is typically satisfied over
\n
time (because the customer simultaneously receives and consumes the
\n
benefits of the commodity as it is delivered) as part of a series of distinct
\n
goods/services (i.e., each unit of commodity) that are substantially the
\n
same and have the same pattern of transfer to the customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale and transport of
\n
electricity/gas to end users, so as to recognize
\n
revenue in the amount to which it has a right to
\n
invoice the customer if that amount corresponds
\n
directly with the value to the customer of
\n
the performance completed to date, i.e., the
\n
quantities provided during the period, even if
\n
these have not yet been invoiced; this revenue is
\n
determined using estimates as well as periodic
\n
meter readings. Where applicable, this revenue
\n
is based on the rates and related restrictions
\n
established by law or by the Regulatory Authority
\n
for Energy, Networks and the Environment
\n
(ARERA) and analogous foreign authorities during
\n
the applicable period.
\n

\n\n

\n\n

\n

\n\n
Construction
\n
contracts
\n
The construction contracts typically include a performance obligation
\n
satisfied over time. For these contracts, the Group generally considers
\n
it appropriate to use an input method for measuring progress, except
\n
when a specific contract analysis suggests the use of an alternative
\n
method that better depicts the Group\u2019s performance obligation fulfilled
\n
at the reporting date.
\n
For construction contracts that include a
\n
performance obligation satisfied over time,
\n
the Group recognizes revenue over time by
\n
measuring progress toward the complete
\n
satisfaction of that performance obligation. The
\n
cost-to-cost method is generally considered the
\n
best method to depict the Group\u2019s performance
\n
obligation fulfilled at the reporting date.
\n
The amount due from customers under a
\n
construction contract is presented as a contract
\n
asset; the amount due to customers under a
\n
construction contract is presented as a contract
\n
liability.
\n
Concession
\n
service
\n
arrangements
\n
(within the scope
\n
of IFRIC 12)
\n
The Group, as concession holder, provides services for the construction/
\n
upgrade of the infrastructure used for the provision of public services
\n
and/or services for the operation and maintenance of the infrastructure
\n
itself for the period of the concession.
\n
For performance obligations related to infrastructure construction and
\n
improvement, please refer to the section \u201cConstruction contracts\u201d.
\n
As far as revenue from operating services is concerned, please refer
\n
to the sections \u201cSale of electricity produced by the Group\u201d and \u201cSale/
\n
transport of electricity/gas to end users\u201d.
\n
When the Group provides construction/upgrade
\n
services, it recognizes intangible assets and/or
\n
financial assets, depending on the characteristics
\n
of the service concession arrangement.
\n
The amounts received or receivable relating
\n
to both components are initially recognized as
\n
revenue from contracts with customers. For more
\n
details on revenue recognition, please refer to the
\n
section \u201cConstruction contracts\u201d.
\n
Furthermore, the component recognized in profit
\n
or loss deriving from the remeasurement at fair
\n
value of the financial assets in respect of service
\n
concession agreements for the distribution
\n
business in Brazil is also classified as revenue, in
\n
order to adequately reflect the business model in
\n
line with the related concession agreement.
\n
Revenue from management and maintenance
\n
activities is recognized as revenue from the
\n
sale of electricity on the market or to end users
\n
(please refer to sections \u201cSale of electricity
\n
produced by the Group\u201d and \u201cSale/transport of
\n
electricity/gas to end users\u201d, respectively).
\n

\n\n\n

\n\n
11.b Other income \u2013 \u20ac4,864 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Operating grants 28 33 (5) -15.2%
\n
Grants for environmental certificates 220 249 (29) -11.6%
\n
Capital grants (electricity and gas business) 28 26 2 7.7%
\n
Sundry reimbursements 314 300 14 4.7%
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
1,876 1,781 95 5.3%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
64 59 5 8.5%
\n
Service continuity bonuses 31 48 (17) -35.4%
\n
Other income 2,303 1,323 980 74.1%
\n
Tot al 4,864 3,819 1,045 27.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
\u201cGrants for environmental certificates\u201d came to \u20ac220 mil-
\n
lion, a decrease of \u20ac29 million compared with the previ-
\n
ous year, mainly reflecting the decrease in grants for white
\n
certificates obtained from distribution operations in Italy.
\n
This effect was partially offset by the increase in grants for
\n
guarantees of origin in Spain.
\n
Gains on the disposal of entities amounted to \u20ac1,876 mil-
\n
lion in 2022, mainly reflecting the recognition gains on the
\n
disposal by Enel X International of 1.1% of the investment
\n
in Ufinet (\u20ac220 million), the sale by Enel X Srl of financial
\n
companies to Mooney (\u20ac67 million), the sale of 50% of the
\n
investment held by Enel Grids in Gridspertise (\u20ac520 million)
\n
and the sale of Enel Chile\u2019s interest in Enel Transmisi\u00f3n Chile.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
In 2021 the item included the capital gain on the sale of
\n
Enel SpA\u2019s interest in Open Fiber (\u20ac1,763 million).
\n
\u201cOther income\u201d increased by \u20ac980 million, mainly due to
\n
the increase of income in Chile (\u20ac503 million) following a
\n
modification of the existing contractual agreement with
\n
Shell, in terms of volumes committed by the supplier, and
\n
the increase in Enel Green Power North America of income
\n
from tax partnership (\u20ac319 million).
\n
The following tables show a breakdown of total revenue by
\n
business line based on the approach used by management
\n
to monitor the Group\u2019s performance during the two years
\n
being compared.
\n
Millions of euro 2022
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 61,711 1,782 2,167 131,531 (28,883) 102,648
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
42,667 - - 26 - - 42,693 (5,446) 37,247
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts with physical
\n
settlement closed during
\n
the period
\n
(4,240) - - (20) - - (4,260) - (4,260)
\n
Other revenue - 6 13 - 1 21 41 (23) 18
\n
Total revenue from sales
\n
and services
\n
75,581 7,869 20,867 61,717 1,783 2,188 170,005 (34,352) 135,653
\n
Other income 754 1,298 2,165 435 426 47 5,125 (261) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Millions of euro 2021
\n
(1)
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 16,673 8,533 19,681 36,933 1,277 2,189 85,286 (16,839) 68,447
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
26,691 - - 14 - - 26,705 (2,391) 24,314
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts
\n
(10,895) - - 1 - - (10,894) 1 (10,893)
\n
Other revenue 5 6 15 - 3 31 60 (28) 32
\n
Total revenue from sales
\n
and services
\n
32,474 8,539 19,696 36,948 1,280 2,220 101,157 (19,257) 81,900
\n
Other income 129 633 546 451 148 1,792 3,699 120 3,819
\n
TOTAL REVENUE 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag986": { "value": "\n
11.a Revenue from sales and services \u2013 \u20ac135,653 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Sale of electricity 69,340 45,053 24,287 53.9%
\n
Transport of electricity 11,096 10,606 490 4.6%
\n
Fees from network operators 979 800 179 22.4%
\n
Transfers from institutional market operators 1,667 833 834 -
\n
Sale of gas 8,970 4,744 4,226 89.1%
\n
Transport of gas 80 599 (519) -86.6%
\n
Sale of fuel 5,605 1,791 3,814 -
\n
Fees for connection to electricity and gas networks 826 769 57 7.4%
\n
Construction contracts
\n
(1)
\n
1,672 1,268 404 31.9%
\n
Sale of environmental certificates 111 107 4 3.7%
\n
Sale of value-added services 1,384 1,092 292 26.7%
\n
Other sales and services 918 785 133 16.9%
\n
Total IFRS 15 revenue 102,648 68,447 34,201 50.0%
\n
Sale of commodities under contracts with physical settlement 37,247 24,314 12,933 53.2%
\n
Gain/(Loss) on the measurement of commodity sales contracts with physical
\n
settlement closed during the period
\n
(4,260) (10,893) 6,633 60.9%
\n
Other revenue 18 32 (14) -43.8%
\n
Total revenue from sales and services 135,653 81,900 53,753 65.6%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Revenue from the \u201cSale of electricity\u201d amounted to \u20ac69,340
\n
million, an increase of \u20ac24,287 million compared with the
\n
previous year (+53.9%). The increase mainly reflects higher
\n
sales volumes and prices, mainly in Italy (\u20ac14,852 million)
\n
and Spain (\u20ac8,076 million).
\n
\u201cTransfers from institutional market operators\u201d increased
\n
by \u20ac834 million compared with the previous year, mainly
\n
in Iberia due to an increase in costs incurred for the pur-
\n
chase of commodities used in thermal generation plants in
\n
the Canary Islands, taking account of the rise in prices on
\n
international markets.
\n
Revenue from the \u201cSale of gas\u201d in 2022 amounted to \u20ac8,970
\n
million (\u20ac4,744 million in 2021), an increase of \u20ac4,226 million
\n
compared with the previous year. The increase is mainly attrib-
\n
utable to higher sales volumes at higher average prices espe-
\n
cially in Spain (\u20ac2,253 million) and Italy (\u20ac1,781 million).
\n
Revenue from the \u201cSale of fuel\u201d increased by \u20ac3,814 million,
\n
especially by Enel Global Trading due to the rise in gas sales.
\n
The increase in the \u201cSale of commodities under contracts
\n
with physical settlement\u201d (\u20ac12,933 million) and of perfor-
\n
mance of the measurement of contracts settled in 2022
\n
(\u20ac6,633 million) mainly involve gas contracts.
\n

\n\n
Revenue from contracts with customers (IFRS 15) breaks
\n
down into \u201cpoint in time\u201d and \u201cover time\u201d revenue as indi-
\n
cated in the following tables.
\n
Millions of euro 2022
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
47,650 2,068 30,984 1,425 17,686 1,227 52 4 1,109 33 214 43 10 143 97,705 4,943
\n
2021
\n
Italy Iberia Latin America Europe North America
\n
Africa, Asia
\n
and Oceania
\n
Other,
\n
eliminations and
\n
adjustments Total
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Over
\n
time
\n
Point in
\n
time
\n
Total IFRS 15
\n
revenue
\n
(1)
\n
29,187 1,178 19,707 402 16,525 245 46 2 805 17 194 26 - 113 66,464 1,983
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The following table shows the net results on contracts for
\n
the sale or purchase of commodities with physical settle-
\n
ment measured at fair value through profit or loss within
\n
the scope of IFRS 9.
\n

\n\n
Millions of euro
\n
2022 2021 Change
\n
Fair value gain/(loss) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
Sales contracts
\n
Sale of electricity 5,436 4,368 1,068 24.5%
\n
Fair value gain/(loss) on closed contracts (795) (1,705) 910 53.4%
\n
Total electricity 4,641 2,663 1,978 74.3%
\n
Sale of gas 30,924 19,576 11,348 58.0%
\n
Fair value gain/(loss) on closed contracts (3,600) (9,335) 5,735 61.4%
\n
Total gas 27,324 10,241 17,083 -
\n
Sale of emissions allowances 875 366 509 -
\n
Fair value gain/(loss) on closed contracts 131 146 (15) -10.3%
\n
Total emissions allowances 1,006 512 494 96.5%
\n
Sale of guarantees of origin 12 4 8 -
\n
Fair value gain/(loss) on closed contracts 4 1 3 -
\n
Total guarantees of origin 16 5 11 -
\n
Total revenue 32,987 13,421 19,566 -
\n
Purchase contracts
\n
Purchase of electricity 6,161 3,677 2,484 67.6%
\n
Fair value gain/(loss) on closed contracts (200) (1,220) 1,020 83.6%
\n
Total electricity 5,961 2,457 3,504 -
\n
Purchase of gas 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on closed contracts (1,940) (8,057) 6,117 75.9%
\n
Total gas 31,152 11,894 19,258 -
\n
Purchase of emissions allowances 843 806 37 4.6%
\n
Fair value gain/(loss) on closed contracts 132 144 (12) -8.3%
\n
Total emissions allowances 975 950 25 2.6%
\n
Purchase of guarantees of origin 25 4 21 -
\n
Fair value gain/(loss) on closed contracts 3 1 2 -
\n
Total guarantees of origin 28 5 23 -
\n
Total costs 38,116 15,306 22,810 -
\n
Net revenue/(costs) on contracts for energy commodities with physical settlement (within
\n
the scope of IFRS 9) closed in the period
\n
(5,129) (1,885) (3,244) -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
Sales contracts
\n
Electricity (134) (1,606) 1,472 91.7%
\n
Gas 4,841 (16,285) 21,126 -
\n
Emissions allowances 490 (487) 977 -
\n
Guarantees of origin (15) (8) (7) -87.5%
\n
Tot al 5,182 (18,386) 23,568 -
\n
Purchase contracts
\n
Electricity (124) (2,169) 2,045 94.3%
\n
Gas 3,879 (13,801) 17,680 -
\n
Emissions allowances 627 (520) 1,147 -
\n
Guarantees of origin (72) 12 (84) -
\n
Tot al 4,310 (16,478) 20,788 -
\n
Gain/(Loss) from measurement of outstanding contracts for energy commodities with
\n
physical settlement (within the scope of IFRS 9)
\n
872 (1,908) 2,780 -
\n
Total net revenue/(costs) on contracts with physical settlement (within the scope of IFRS 9) (4,257) (3,793) (464) -12.2%
\n

\n\n
The table below gives a breakdown of revenue from sales
\n
and services by geographical segment.
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Italy 57,859 33,304
\n
Europe
\n
Iberia 30,535 18,896
\n
France 3,086 970
\n
Switzerland 6,791 2,918
\n
Germany 1,676 1,085
\n
Austria 189 245
\n
Slovenia 146 195
\n
Romania 3-
\n
Greece 15 -
\n
Bulgaria --
\n
Belgium 834 522
\n
Czech Republic 321 435
\n
Hungary 712
\n
Russia -3
\n
Netherlands 38 96
\n
United Kingdom 11,841 3,736
\n
Other European countries 1,551 1,160
\n
Americas
\n
United States 779 601
\n
Canada 53 33
\n
Mexico 313 202
\n
Brazil 9,064 9,381
\n
Chile 4,434 3,151
\n
Peru 1,449 1,111
\n
Colombia 2,725 2,188
\n
Argentina 966 887
\n
Panama 177 150
\n
Costa Rica 17 14
\n
Guatemala 83 67
\n
Other
\n
Africa 132 114
\n
Asia 521 371
\n
Oceania 48 53
\n
Tot al 135,653 81,900
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n
Performance obligations
\n
The following table provides information about the Group\u2019s
\n
performance obligations arising from contracts with cus-
\n
tomers with reference to the main revenue streams only,
\n
with a summary of the specific judgments made and the
\n
related revenue recognition policies.
\n
For information on the use of estimates with revenue from
\n
contracts with customers, please see note 2.1 \u201cUse of esti-
\n
mates and management judgment\u201d.
\n
Type of product/
\n
service Nature and timing of satisfaction of performance obligation Accounting policies
\n
Sale of electricity
\n
produced by the
\n
Group
\n
In order to determine the nature of the promise contained in these
\n
contracts with customers for the sale of electricity, the Group carefully
\n
analyzes the facts and circumstances applicable to each contract.
\n
For the sale of electricity on power exchanges, the facts and
\n
circumstances (including the intrinsic characteristics of the commodity,
\n
contractual terms, information regarding infrastructure and other
\n
delivery mechanisms) generally indicate that the performance obligation
\n
is a service in which the customer simultaneously receives and
\n
consumes the benefits of the commodity as it is delivered. Thus, the
\n
Group identifies a performance obligation satisfied over time as part of
\n
a series of distinct goods/services (i.e., each unit of commodity) that
\n
are substantially the same and have the same pattern of transfer to the
\n
customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale of electricity
\n
on power exchanges, recognized over time, so
\n
as to recognize revenue in the amount to which
\n
it has a right to invoice the customer if that
\n
amount corresponds directly with the value to the
\n
customer of the performance completed to date,
\n
i.e., at the price defined in the market (without
\n
variable consideration).
\n
Network
\n
connection
\n
services
\n
The network connection fees received from customers for connecting
\n
them to the electricity/gas distribution networks require a specific
\n
Group assessment to take into consideration all terms and conditions of
\n
the connection arrangements.
\n
This assessment is intended to determine whether the contract includes
\n
other distinct goods or services, such as for example the right to obtain
\n
ongoing access to the infrastructure in order to receive the commodity
\n
or, when the connection fee is a \u201cnon-refundable up-front fee\u201d paid
\n
at or near contract inception, a material right that gives rise to a
\n
performance obligation.
\n
In particular, in some countries in which the Group operates, it has
\n
determined that the nature of the consideration received represents
\n
a \u201cnon-refundable up-front fee\u201d whose payment provides a material
\n
right to the customer. In order to determine if the period over which
\n
this material right should be recognized extends beyond the initial
\n
contractual period, the Group takes into consideration the applicable
\n
local legal and regulatory framework applicable to the contract and
\n
affecting the parties. In such cases, if there is an implied assignment
\n
of the material right and an obligation from the initial customer to
\n
the new customer, the Group recognizes the connection fee over a
\n
period beyond the relationship with the initial customer, considering
\n
the concession terms as the period during which the initial customer
\n
and any future customer can benefit from the ongoing access without
\n
paying an additional connection fee. As a consequence, the fee is
\n
recognized over the period for which the payment creates an obligation
\n
for the Group to make the lower prices available to future customers (i.e.,
\n
the period during which the customer is expected to benefit from the
\n
ongoing access service without having to pay an \u201cup-front fee\u201d upon
\n
renewal).
\n
Revenue from monetary and in-kind fees for
\n
connection to the electricity and gas distribution
\n
network is recognized on the basis of the
\n
satisfaction of the performance obligations
\n
included in the contract. The identification of
\n
distinct goods or services requires a careful
\n
analysis of the terms and conditions of the
\n
connection arrangements, which could vary
\n
from country to country based on the local
\n
context, regulations and law. In order to finalize
\n
this assessment, the Group considers not
\n
only the characteristics of the goods/services
\n
themselves (i.e., the good or service is capable of
\n
being distinct) but also the implied promises for
\n
which the customer has a valid expectation as it
\n
views those promises as part of the negotiated
\n
exchange, that is goods/services that the
\n
customer expects to receive and has paid for (i.e.,
\n
the promise to transfer the good or service to
\n
the customer is separately identifiable from other
\n
promises in the contract).
\n
Furthermore, the Group acts as an agent in some
\n
contracts for electricity/gas network connection
\n
services and other related activities, depending
\n
on local legal and regulatory framework. In such
\n
cases, it recognizes revenue on a net basis,
\n
corresponding to any fee or commission to which
\n
it expects to be entitled.
\n
Sale/transport of
\n
electricity/gas to
\n
end users
\n
An electricity/gas supply agreement signed with an end user includes
\n
a single performance obligation (sale and transport of the commodity)
\n
because the Group has determined that the contract does not provide
\n
distinct goods/services and the promise is satisfied by transferring
\n
control over the commodity to the customer when it is delivered at
\n
the point of delivery. In order to determine the nature of the promise
\n
included in such contracts, the Group carefully analyzes the facts and
\n
circumstances applicable to each contract and commodity.
\n
However, the Group considers that the performance obligation provided
\n
for in a repetitive service contract, such as a supply or transport contract
\n
for the provision of electricity/gas to end users, is typically satisfied over
\n
time (because the customer simultaneously receives and consumes the
\n
benefits of the commodity as it is delivered) as part of a series of distinct
\n
goods/services (i.e., each unit of commodity) that are substantially the
\n
same and have the same pattern of transfer to the customer.
\n
The Group applies an output method to
\n
recognize revenue from the sale and transport of
\n
electricity/gas to end users, so as to recognize
\n
revenue in the amount to which it has a right to
\n
invoice the customer if that amount corresponds
\n
directly with the value to the customer of
\n
the performance completed to date, i.e., the
\n
quantities provided during the period, even if
\n
these have not yet been invoiced; this revenue is
\n
determined using estimates as well as periodic
\n
meter readings. Where applicable, this revenue
\n
is based on the rates and related restrictions
\n
established by law or by the Regulatory Authority
\n
for Energy, Networks and the Environment
\n
(ARERA) and analogous foreign authorities during
\n
the applicable period.
\n

\n\n
Construction
\n
contracts
\n
The construction contracts typically include a performance obligation
\n
satisfied over time. For these contracts, the Group generally considers
\n
it appropriate to use an input method for measuring progress, except
\n
when a specific contract analysis suggests the use of an alternative
\n
method that better depicts the Group\u2019s performance obligation fulfilled
\n
at the reporting date.
\n
For construction contracts that include a
\n
performance obligation satisfied over time,
\n
the Group recognizes revenue over time by
\n
measuring progress toward the complete
\n
satisfaction of that performance obligation. The
\n
cost-to-cost method is generally considered the
\n
best method to depict the Group\u2019s performance
\n
obligation fulfilled at the reporting date.
\n
The amount due from customers under a
\n
construction contract is presented as a contract
\n
asset; the amount due to customers under a
\n
construction contract is presented as a contract
\n
liability.
\n
Concession
\n
service
\n
arrangements
\n
(within the scope
\n
of IFRIC 12)
\n
The Group, as concession holder, provides services for the construction/
\n
upgrade of the infrastructure used for the provision of public services
\n
and/or services for the operation and maintenance of the infrastructure
\n
itself for the period of the concession.
\n
For performance obligations related to infrastructure construction and
\n
improvement, please refer to the section \u201cConstruction contracts\u201d.
\n
As far as revenue from operating services is concerned, please refer
\n
to the sections \u201cSale of electricity produced by the Group\u201d and \u201cSale/
\n
transport of electricity/gas to end users\u201d.
\n
When the Group provides construction/upgrade
\n
services, it recognizes intangible assets and/or
\n
financial assets, depending on the characteristics
\n
of the service concession arrangement.
\n
The amounts received or receivable relating
\n
to both components are initially recognized as
\n
revenue from contracts with customers. For more
\n
details on revenue recognition, please refer to the
\n
section \u201cConstruction contracts\u201d.
\n
Furthermore, the component recognized in profit
\n
or loss deriving from the remeasurement at fair
\n
value of the financial assets in respect of service
\n
concession agreements for the distribution
\n
business in Brazil is also classified as revenue, in
\n
order to adequately reflect the business model in
\n
line with the related concession agreement.
\n
Revenue from management and maintenance
\n
activities is recognized as revenue from the
\n
sale of electricity on the market or to end users
\n
(please refer to sections \u201cSale of electricity
\n
produced by the Group\u201d and \u201cSale/transport of
\n
electricity/gas to end users\u201d, respectively).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag984": { "value": "\n

\n\n
11.b Other income \u2013 \u20ac4,864 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Operating grants 28 33 (5) -15.2%
\n
Grants for environmental certificates 220 249 (29) -11.6%
\n
Capital grants (electricity and gas business) 28 26 2 7.7%
\n
Sundry reimbursements 314 300 14 4.7%
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
1,876 1,781 95 5.3%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
64 59 5 8.5%
\n
Service continuity bonuses 31 48 (17) -35.4%
\n
Other income 2,303 1,323 980 74.1%
\n
Tot al 4,864 3,819 1,045 27.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
\u201cGrants for environmental certificates\u201d came to \u20ac220 mil-
\n
lion, a decrease of \u20ac29 million compared with the previ-
\n
ous year, mainly reflecting the decrease in grants for white
\n
certificates obtained from distribution operations in Italy.
\n
This effect was partially offset by the increase in grants for
\n
guarantees of origin in Spain.
\n
Gains on the disposal of entities amounted to \u20ac1,876 mil-
\n
lion in 2022, mainly reflecting the recognition gains on the
\n
disposal by Enel X International of 1.1% of the investment
\n
in Ufinet (\u20ac220 million), the sale by Enel X Srl of financial
\n
companies to Mooney (\u20ac67 million), the sale of 50% of the
\n
investment held by Enel Grids in Gridspertise (\u20ac520 million)
\n
and the sale of Enel Chile\u2019s interest in Enel Transmisi\u00f3n Chile.
\n

\n\n

\n\n

\n\n
In 2021 the item included the capital gain on the sale of
\n
Enel SpA\u2019s interest in Open Fiber (\u20ac1,763 million).
\n
\u201cOther income\u201d increased by \u20ac980 million, mainly due to
\n
the increase of income in Chile (\u20ac503 million) following a
\n
modification of the existing contractual agreement with
\n
Shell, in terms of volumes committed by the supplier, and
\n
the increase in Enel Green Power North America of income
\n
from tax partnership (\u20ac319 million).
\n
The following tables show a breakdown of total revenue by
\n
business line based on the approach used by management
\n
to monitor the Group\u2019s performance during the two years
\n
being compared.
\n
Millions of euro 2022
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 61,711 1,782 2,167 131,531 (28,883) 102,648
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
42,667 - - 26 - - 42,693 (5,446) 37,247
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts with physical
\n
settlement closed during
\n
the period
\n
(4,240) - - (20) - - (4,260) - (4,260)
\n
Other revenue - 6 13 - 1 21 41 (23) 18
\n
Total revenue from sales
\n
and services
\n
75,581 7,869 20,867 61,717 1,783 2,188 170,005 (34,352) 135,653
\n
Other income 754 1,298 2,165 435 426 47 5,125 (261) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Millions of euro 2021
\n
(1)
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 16,673 8,533 19,681 36,933 1,277 2,189 85,286 (16,839) 68,447
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
26,691 - - 14 - - 26,705 (2,391) 24,314
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts
\n
(10,895) - - 1 - - (10,894) 1 (10,893)
\n
Other revenue 5 6 15 - 3 31 60 (28) 32
\n
Total revenue from sales
\n
and services
\n
32,474 8,539 19,696 36,948 1,280 2,220 101,157 (19,257) 81,900
\n
Other income 129 633 546 451 148 1,792 3,699 120 3,819
\n
TOTAL REVENUE 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag985": { "value": "\n
11.b Other income \u2013 \u20ac4,864 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Operating grants 28 33 (5) -15.2%
\n
Grants for environmental certificates 220 249 (29) -11.6%
\n
Capital grants (electricity and gas business) 28 26 2 7.7%
\n
Sundry reimbursements 314 300 14 4.7%
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
1,876 1,781 95 5.3%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
64 59 5 8.5%
\n
Service continuity bonuses 31 48 (17) -35.4%
\n
Other income 2,303 1,323 980 74.1%
\n
Tot al 4,864 3,819 1,045 27.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
\u201cGrants for environmental certificates\u201d came to \u20ac220 mil-
\n
lion, a decrease of \u20ac29 million compared with the previ-
\n
ous year, mainly reflecting the decrease in grants for white
\n
certificates obtained from distribution operations in Italy.
\n
This effect was partially offset by the increase in grants for
\n
guarantees of origin in Spain.
\n
Gains on the disposal of entities amounted to \u20ac1,876 mil-
\n
lion in 2022, mainly reflecting the recognition gains on the
\n
disposal by Enel X International of 1.1% of the investment
\n
in Ufinet (\u20ac220 million), the sale by Enel X Srl of financial
\n
companies to Mooney (\u20ac67 million), the sale of 50% of the
\n
investment held by Enel Grids in Gridspertise (\u20ac520 million)
\n
and the sale of Enel Chile\u2019s interest in Enel Transmisi\u00f3n Chile.
\n

\n\n
In 2021 the item included the capital gain on the sale of
\n
Enel SpA\u2019s interest in Open Fiber (\u20ac1,763 million).
\n
\u201cOther income\u201d increased by \u20ac980 million, mainly due to
\n
the increase of income in Chile (\u20ac503 million) following a
\n
modification of the existing contractual agreement with
\n
Shell, in terms of volumes committed by the supplier, and
\n
the increase in Enel Green Power North America of income
\n
from tax partnership (\u20ac319 million).
\n
The following tables show a breakdown of total revenue by
\n
business line based on the approach used by management
\n
to monitor the Group\u2019s performance during the two years
\n
being compared.
\n
Millions of euro 2022
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 61,711 1,782 2,167 131,531 (28,883) 102,648
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
42,667 - - 26 - - 42,693 (5,446) 37,247
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts with physical
\n
settlement closed during
\n
the period
\n
(4,240) - - (20) - - (4,260) - (4,260)
\n
Other revenue - 6 13 - 1 21 41 (23) 18
\n
Total revenue from sales
\n
and services
\n
75,581 7,869 20,867 61,717 1,783 2,188 170,005 (34,352) 135,653
\n
Other income 754 1,298 2,165 435 426 47 5,125 (261) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 62,152 2,209 2,235 175,130 (34,613) 140,517
\n
Millions of euro 2021
\n
(1)
\n
Thermal
\n
Generation
\n
and Trading
\n
Enel
\n
Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services
\n
and Other
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 16,673 8,533 19,681 36,933 1,277 2,189 85,286 (16,839) 68,447
\n
Sale of commodities
\n
under contracts with
\n
physical settlement
\n
26,691 - - 14 - - 26,705 (2,391) 24,314
\n
Gain/(Loss) on the
\n
measurement of
\n
commodity sales
\n
contracts
\n
(10,895) - - 1 - - (10,894) 1 (10,893)
\n
Other revenue 5 6 15 - 3 31 60 (28) 32
\n
Total revenue from sales
\n
and services
\n
32,474 8,539 19,696 36,948 1,280 2,220 101,157 (19,257) 81,900
\n
Other income 129 633 546 451 148 1,792 3,699 120 3,819
\n
TOTAL REVENUE 32,603 9,172 20,242 37,399 1,428 4,012 104,856 (19,137) 85,719
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n
12.f Other operating costs \u2013 \u20ac4,685 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
System charges - emissions allowances 2,216 41 2,175 -
\n
System charges - energy efficiency certificates 182 239 (57) -23.8%
\n
System charges - purchases of green certificates - - - -
\n
System charges - guarantees of origin 112 26 86 -
\n
Losses on disposal of property, plant and equipment, and intangible assets 166 75 91 -
\n
Taxes and duties 1,107 1,099 8 0.7%
\n
Other 902 488 414 84.8%
\n
Tot al 4,685 1,968 2,717 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Other operating costs increased by \u20ac2,717 million com-
\n
pared with the previous year, mainly reflecting:
\n
\u2022 the increase in environmental compliance charges in It-
\n
aly and Spain (\u20ac2,178 million) reflecting the increase in
\n
the price of CO
\n
2
\n
and of thermal generation mainly attrib-
\n
utable to the need to compensate for low water levels
\n
during the period;
\n
\u2022 the capital losses recognized for the sale of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac208 million) and CGT
\n
Fortaleza in Brazil (\u20ac135 million).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag992": { "value": "\n

\n\n
Costs
\n
12.a Electricity, gas and fuel \u2013 \u20ac96,896 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Electricity 47,155 28,624 18,531 64.7%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 6,161 3,677 2,484 67.6%
\n
Gas 47,930 26,614 21,316 80.1%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on contracts for purchase of electricity and gas with
\n
physical settlement closed during the period
\n
(2,140) (9,277) 7,137 76.9%
\n
Nuclear fuel 111 107 4 3.7%
\n
Other fuels 3,840 1,634 2,206 -
\n
Total 96,896 47,702 49,194 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Costs for the purchase of \u201cElectricity\u201d mainly increased
\n
due to a rise in volumes purchased in an environment of
\n
increasing average prices compared with the previous
\n
year, mainly attributable to Italy (\u20ac15,396 million) and Spain
\n
(\u20ac3,563 million).
\n
The increase in costs for the purchase of \u201cGas\u201d mainly re-
\n
flects the increase in quantities handled, mainly due to a
\n
rise in generation, as well as the increase in the cost of
\n
purchasing gas from third parties.
\n
The gain/(loss) from the fair value measurement of closed
\n
contracts with physical settlement showed an increase of
\n
\u20ac7,137 million compared with the previous year, of which
\n
\u20ac6,117 million attributable to gas and \u20ac1,020 million to
\n
electricity.
\n
The increase in \u201cOther fuels\u201d is mainly attributable to the
\n
increase in the volume of generation and the rise in com-
\n
modity prices.
\n
12.b Services and other materials \u2013 \u20ac20,228 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wheeling 8,247 8,921 (674) -7.6%
\n
Maintenance and repairs 1,067 1,364 (297) -21.8%
\n
Telephone and postal costs 181 177 4 2.3%
\n
Communication services 117 123 (6) -4.9%
\n
IT services 872 959 (87) -9.1%
\n
Leases and rentals 503 126 377 -
\n
Other services 5,707 4,160 1,547 37.2%
\n
Purchase of environmental certificates 963 1,256 (293) -23.3%
\n
- of which relating to purchases from contracts with physical delivery (IFRS 9) 868 810 58 7.2%
\n
Fair value gain/(loss) on contracts for purchase of environmental certificates
\n
with physical settlement closed during the period
\n
135 145 (10) -6.9%
\n
Change in inventories of environmental certificates 97 32 65 -
\n
Other materials 2,533 2,041 492 24.1%
\n
Tot al 20,228 19,240 988 5.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n
Costs for services and other materials amounted to
\n
\u20ac20,228 million in 2022, an increase of \u20ac988 million com-
\n
pared with 2021. This change essentially reflected:
\n
\u2022 an increase in costs for leases and rentals, mainly re-
\n
flecting the closure, in 2021, of a dispute in Spain, which
\n
permitted the reversal of provisions previously recog-
\n
nized in the amount of about \u20ac300 million;
\n
\u2022 an increase of \u20ac1,547 million in \u201cOther services\u201d, es-
\n
sentially reflecting the increase in costs for services
\n
connected with the electricity and gas business (\u20ac720
\n
million), those related to concessions in Brazil (\u20ac281 mil-
\n
lion), those related to the value-added services business
\n
(\u20ac119 million) and expenses for professional and techni-
\n
cal services (\u20ac156 million);
\n
\u2022 an increase in \u201cOther materials\u201d mainly attributable to
\n
higher procurement costs of raw materials and higher
\n
production volumes;
\n
\u2022 a decline in costs for wheeling, mainly in Italy and Spain,
\n
attributable to a decline in the average price applied,
\n
partially offset by an increase of those in Latin America
\n
due to the increase in traded volumes;
\n
\u2022 lower provisions for costs connected with the conver-
\n
sion of plants in Italy for the purposes of the energy tran-
\n
sition;
\n
\u2022 a decrease in costs for systems assistance, computer
\n
maintenance and IT development, mainly in Italy.
\n\n
12.c Personnel expenses \u2013 \u20ac4,570 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wages and salaries 3,442 3,122 320 10.2%
\n
Social security contributions 924 844 80 9.5%
\n
Italian post-employment benefits 107 104 3 2.9%
\n
Post-employment and other long-term benefits 73 86 (13) -15.1%
\n
Early retirement incentives (20) 10 (30) -
\n
Early retirement incentives connected with restructuring agreements (151) 795 (946) -
\n
Other costs 195 179 16 8.9%
\n
Tot al 4,570 5,140 (570) -11.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Personnel expenses in 2022 amounted to \u20ac4,570 million, a
\n
decrease of \u20ac570 million.
\n
The Group\u2019s workforce decreased by 1,155 employees,
\n
mainly reflecting the positive balance between new hires
\n
and terminations (1,998 employees), more than offset by
\n
changes in the consolidation scope (-3,153 employees),
\n
essentially attributable to:
\n
\u2022 the acquisition of Enel Hydro Appennino Centrale Srl in
\n
Italy;
\n
\u2022 the acquisition of Melita Italia Srl in Italy;
\n
\u2022 the sale of PayTipper SpA in Italy;
\n
\u2022 the sale of CityPoste Payment SpA in Italy;
\n
\u2022 the sale of PayTipper Network Srl in Italy;
\n
\u2022 the sale of FlagPay Srl in Italy;
\n
\u2022 the sale of Gridspertise Srl in Italy;
\n
\u2022 the sale of Central Geradora Termel\u00e9trica Fortaleza SA,
\n
Celg Distribui\u00e7\u00e3o SA - Celg-D and Gridspertise Latam SA
\n
in Brazil;
\n
\u2022 the sale of PJSC Enel Russia and subsidiaries in Russia;
\n
\u2022 the sale of Enel Transmisi\u00f3n SA in Chile.
\n
The increase in \u201cWages and salaries\u201d substantially reflects
\n
the cost incurred as a result of new hiring at companies in
\n
Italy, the United States, Brazil, Spain and Argentina.
\n
The \u20ac13 million decrease in in \u201cPost-employment and oth-
\n
er long-term benefits\u201d is mainly attributable to Spain.
\n
The decrease in \u201cEarly retirement incentives connected
\n
with restructuring agreements\u201d is mainly attributable to an
\n
increase in costs in Italy in 2021 as a result of the signing
\n
of a new framework agreement in application of Article 4,
\n
paragraphs 1-7-ter, of Law 92/2012, for which provisions
\n
of \u20ac557 million were recognized for restructuring and dig-
\n
italization. In 2022 the provision was adjusted according to
\n
the developments of the period and changes underlying
\n
the actuarial assumptions.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
The table below shows the average number of employees
\n
by category, along with a comparison with the previous
\n
year, and the headcount as of December 31, 2022.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
2022 2021 at Dec. 31, 2022
\n
Senior managers 1,389 1,386 1,366
\n
Middle managers 12,528 11,797 12,645
\n
Office staff 35,676 35,449 34,634
\n
Blue collar 16,883 17,344 16,479
\n
Tot al 66,476 65,976 65,124
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n

\n\n\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013
\n
\u20ac1,278 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Impairment losses on trade receivables 1,375 1,285 90 7.0%
\n
Impairment losses on other financial assets 169 93 76 81.7%
\n
Total impairment losses on trade receivables and other financial assets 1,544 1,378 166 12.0%
\n
Impairment gains on trade receivables (265) (202) (63) -31.2%
\n
Impairment gains on other financial assets (1) (1) - -
\n
Total impairment gains on trade receivables and other financial assets (266) (203) (63) -31.0%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,278 1,175 103 8.8%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The item, equal to \u20ac1,278 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
increased by a total of \u20ac90 million, essentially reflecting
\n
the effect of the increase in trade receivables which led to
\n
an increase in the provision for bad debts in order to guar-
\n
antee adequate coverage of the new receivable.
\n

\n\n\n

\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac7,447 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Property, plant and equipment 4,472 4,259 213 5.0%
\n
Investment property 2 3 (1) -33.3%
\n
Intangible assets 1,612 1,330 282 21.2%
\n
Other impairment losses 1,414 2,917 (1,503) -51.5%
\n
Other reversals of impairment losses (53) (2) (51) -
\n
Tot al 7,447 8,507 (1,060) -12.5%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The decrease in \u201cDepreciation, amortization and other im-
\n
pairment losses\u201d in 2022 essentially reflected:
\n
\u2022 the effect of impairment losses recognized in 2021
\n
on certain plants or CGUs in Italy (\u20ac989 million), Spain
\n
(\u20ac1,488 million), Mexico (\u20ac155 million), Chile (\u20ac32 million)
\n
and Australia (\u20ac30 million);
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
\u2022 the effect of the impairment losses recognized in 2021 in
\n
Costa Rica (\u20ac126 million) on the hydroelectric plant op-
\n
erated under a concession arrangement by PH Chucas
\n
.
\n
These effects were partially offset by:
\n
\u2022 an increase in depreciation and amortization in Ita-
\n
ly due to an acceleration of the depreciation rates for
\n
first-generation electronic meters (1G) in order to reflect
\n
the planned installation schedule for 2G meters provided
\n
for in the Open Meter plan;
\n
\u2022 the depreciation of tangible assets due to new invest-
\n
ments made in recent years in the renewable energy
\n
sector in South America, North America and Spain;
\n
\u2022 the value adjustments of the net assets of Enel Gener-
\n
aci\u00f3n Costanera SA (\u20ac174 million) and Central Dock Sud
\n
SA (\u20ac116 million) in Argentina, and Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (\u20ac827 million) and CGT Fortaleza in Brazil (\u20ac73
\n
million).
\n

\n\n

\n\n\n

\n\n
12.f Other operating costs \u2013 \u20ac4,685 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
System charges - emissions allowances 2,216 41 2,175 -
\n
System charges - energy efficiency certificates 182 239 (57) -23.8%
\n
System charges - purchases of green certificates - - - -
\n
System charges - guarantees of origin 112 26 86 -
\n
Losses on disposal of property, plant and equipment, and intangible assets 166 75 91 -
\n
Taxes and duties 1,107 1,099 8 0.7%
\n
Other 902 488 414 84.8%
\n
Tot al 4,685 1,968 2,717 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Other operating costs increased by \u20ac2,717 million com-
\n
pared with the previous year, mainly reflecting:
\n
\u2022 the increase in environmental compliance charges in It-
\n
aly and Spain (\u20ac2,178 million) reflecting the increase in
\n
the price of CO
\n
2
\n
and of thermal generation mainly attrib-
\n
utable to the need to compensate for low water levels
\n
during the period;
\n
\u2022 the capital losses recognized for the sale of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac208 million) and CGT
\n
Fortaleza in Brazil (\u20ac135 million).
\n

\n\n

\n\n
12.g Capitalized costs \u2013 \u20ac(3,415) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Personnel (1,184) (998) (186) -18.6%
\n
Materials (1,258) (1,079) (179) -16.6%
\n
Other (973) (964) (9) -0.9%
\n
Tot al (3,415) (3,041) (374) -12.3%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Capitalized costs increased by \u20ac374 million, mainly reflect-
\n
ing:
\n
\u2022 greater investment in renewable plants in Italy, Spain and
\n
North America;
\n
\u2022 greater investment in distribution lines in Latin America;
\n
\u2022 greater investment in the distribution sector in Italy, for
\n
an increase in new customer connections and an in-
\n
crease in investment in service quality (e-grid and DSO
\n
4.0 projects).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag991": { "value": "\n
Costs
\n
12.a Electricity, gas and fuel \u2013 \u20ac96,896 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Electricity 47,155 28,624 18,531 64.7%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 6,161 3,677 2,484 67.6%
\n
Gas 47,930 26,614 21,316 80.1%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 33,092 19,951 13,141 65.9%
\n
Fair value gain/(loss) on contracts for purchase of electricity and gas with
\n
physical settlement closed during the period
\n
(2,140) (9,277) 7,137 76.9%
\n
Nuclear fuel 111 107 4 3.7%
\n
Other fuels 3,840 1,634 2,206 -
\n
Total 96,896 47,702 49,194 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Costs for the purchase of \u201cElectricity\u201d mainly increased
\n
due to a rise in volumes purchased in an environment of
\n
increasing average prices compared with the previous
\n
year, mainly attributable to Italy (\u20ac15,396 million) and Spain
\n
(\u20ac3,563 million).
\n
The increase in costs for the purchase of \u201cGas\u201d mainly re-
\n
flects the increase in quantities handled, mainly due to a
\n
rise in generation, as well as the increase in the cost of
\n
purchasing gas from third parties.
\n
The gain/(loss) from the fair value measurement of closed
\n
contracts with physical settlement showed an increase of
\n
\u20ac7,137 million compared with the previous year, of which
\n
\u20ac6,117 million attributable to gas and \u20ac1,020 million to
\n
electricity.
\n
The increase in \u201cOther fuels\u201d is mainly attributable to the
\n
increase in the volume of generation and the rise in com-
\n
modity prices.
\n
12.b Services and other materials \u2013 \u20ac20,228 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wheeling 8,247 8,921 (674) -7.6%
\n
Maintenance and repairs 1,067 1,364 (297) -21.8%
\n
Telephone and postal costs 181 177 4 2.3%
\n
Communication services 117 123 (6) -4.9%
\n
IT services 872 959 (87) -9.1%
\n
Leases and rentals 503 126 377 -
\n
Other services 5,707 4,160 1,547 37.2%
\n
Purchase of environmental certificates 963 1,256 (293) -23.3%
\n
- of which relating to purchases from contracts with physical delivery (IFRS 9) 868 810 58 7.2%
\n
Fair value gain/(loss) on contracts for purchase of environmental certificates
\n
with physical settlement closed during the period
\n
135 145 (10) -6.9%
\n
Change in inventories of environmental certificates 97 32 65 -
\n
Other materials 2,533 2,041 492 24.1%
\n
Tot al 20,228 19,240 988 5.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n
Costs for services and other materials amounted to
\n
\u20ac20,228 million in 2022, an increase of \u20ac988 million com-
\n
pared with 2021. This change essentially reflected:
\n
\u2022 an increase in costs for leases and rentals, mainly re-
\n
flecting the closure, in 2021, of a dispute in Spain, which
\n
permitted the reversal of provisions previously recog-
\n
nized in the amount of about \u20ac300 million;
\n
\u2022 an increase of \u20ac1,547 million in \u201cOther services\u201d, es-
\n
sentially reflecting the increase in costs for services
\n
connected with the electricity and gas business (\u20ac720
\n
million), those related to concessions in Brazil (\u20ac281 mil-
\n
lion), those related to the value-added services business
\n
(\u20ac119 million) and expenses for professional and techni-
\n
cal services (\u20ac156 million);
\n
\u2022 an increase in \u201cOther materials\u201d mainly attributable to
\n
higher procurement costs of raw materials and higher
\n
production volumes;
\n
\u2022 a decline in costs for wheeling, mainly in Italy and Spain,
\n
attributable to a decline in the average price applied,
\n
partially offset by an increase of those in Latin America
\n
due to the increase in traded volumes;
\n
\u2022 lower provisions for costs connected with the conver-
\n
sion of plants in Italy for the purposes of the energy tran-
\n
sition;
\n
\u2022 a decrease in costs for systems assistance, computer
\n
maintenance and IT development, mainly in Italy.
\n\n
12.c Personnel expenses \u2013 \u20ac4,570 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wages and salaries 3,442 3,122 320 10.2%
\n
Social security contributions 924 844 80 9.5%
\n
Italian post-employment benefits 107 104 3 2.9%
\n
Post-employment and other long-term benefits 73 86 (13) -15.1%
\n
Early retirement incentives (20) 10 (30) -
\n
Early retirement incentives connected with restructuring agreements (151) 795 (946) -
\n
Other costs 195 179 16 8.9%
\n
Tot al 4,570 5,140 (570) -11.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Personnel expenses in 2022 amounted to \u20ac4,570 million, a
\n
decrease of \u20ac570 million.
\n
The Group\u2019s workforce decreased by 1,155 employees,
\n
mainly reflecting the positive balance between new hires
\n
and terminations (1,998 employees), more than offset by
\n
changes in the consolidation scope (-3,153 employees),
\n
essentially attributable to:
\n
\u2022 the acquisition of Enel Hydro Appennino Centrale Srl in
\n
Italy;
\n
\u2022 the acquisition of Melita Italia Srl in Italy;
\n
\u2022 the sale of PayTipper SpA in Italy;
\n
\u2022 the sale of CityPoste Payment SpA in Italy;
\n
\u2022 the sale of PayTipper Network Srl in Italy;
\n
\u2022 the sale of FlagPay Srl in Italy;
\n
\u2022 the sale of Gridspertise Srl in Italy;
\n
\u2022 the sale of Central Geradora Termel\u00e9trica Fortaleza SA,
\n
Celg Distribui\u00e7\u00e3o SA - Celg-D and Gridspertise Latam SA
\n
in Brazil;
\n
\u2022 the sale of PJSC Enel Russia and subsidiaries in Russia;
\n
\u2022 the sale of Enel Transmisi\u00f3n SA in Chile.
\n
The increase in \u201cWages and salaries\u201d substantially reflects
\n
the cost incurred as a result of new hiring at companies in
\n
Italy, the United States, Brazil, Spain and Argentina.
\n
The \u20ac13 million decrease in in \u201cPost-employment and oth-
\n
er long-term benefits\u201d is mainly attributable to Spain.
\n
The decrease in \u201cEarly retirement incentives connected
\n
with restructuring agreements\u201d is mainly attributable to an
\n
increase in costs in Italy in 2021 as a result of the signing
\n
of a new framework agreement in application of Article 4,
\n
paragraphs 1-7-ter, of Law 92/2012, for which provisions
\n
of \u20ac557 million were recognized for restructuring and dig-
\n
italization. In 2022 the provision was adjusted according to
\n
the developments of the period and changes underlying
\n
the actuarial assumptions.
\n

\n\n

\n\n

\n

\n

\n\n
The table below shows the average number of employees
\n
by category, along with a comparison with the previous
\n
year, and the headcount as of December 31, 2022.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
2022 2021 at Dec. 31, 2022
\n
Senior managers 1,389 1,386 1,366
\n
Middle managers 12,528 11,797 12,645
\n
Office staff 35,676 35,449 34,634
\n
Blue collar 16,883 17,344 16,479
\n
Tot al 66,476 65,976 65,124
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n

\n\n\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013
\n
\u20ac1,278 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Impairment losses on trade receivables 1,375 1,285 90 7.0%
\n
Impairment losses on other financial assets 169 93 76 81.7%
\n
Total impairment losses on trade receivables and other financial assets 1,544 1,378 166 12.0%
\n
Impairment gains on trade receivables (265) (202) (63) -31.2%
\n
Impairment gains on other financial assets (1) (1) - -
\n
Total impairment gains on trade receivables and other financial assets (266) (203) (63) -31.0%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,278 1,175 103 8.8%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The item, equal to \u20ac1,278 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
increased by a total of \u20ac90 million, essentially reflecting
\n
the effect of the increase in trade receivables which led to
\n
an increase in the provision for bad debts in order to guar-
\n
antee adequate coverage of the new receivable.
\n

\n\n\n

\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac7,447 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Property, plant and equipment 4,472 4,259 213 5.0%
\n
Investment property 2 3 (1) -33.3%
\n
Intangible assets 1,612 1,330 282 21.2%
\n
Other impairment losses 1,414 2,917 (1,503) -51.5%
\n
Other reversals of impairment losses (53) (2) (51) -
\n
Tot al 7,447 8,507 (1,060) -12.5%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The decrease in \u201cDepreciation, amortization and other im-
\n
pairment losses\u201d in 2022 essentially reflected:
\n
\u2022 the effect of impairment losses recognized in 2021
\n
on certain plants or CGUs in Italy (\u20ac989 million), Spain
\n
(\u20ac1,488 million), Mexico (\u20ac155 million), Chile (\u20ac32 million)
\n
and Australia (\u20ac30 million);
\n

\n\n

\n\n

\n\n

\n

\n\n

\n\n
\u2022 the effect of the impairment losses recognized in 2021 in
\n
Costa Rica (\u20ac126 million) on the hydroelectric plant op-
\n
erated under a concession arrangement by PH Chucas
\n
.
\n
These effects were partially offset by:
\n
\u2022 an increase in depreciation and amortization in Ita-
\n
ly due to an acceleration of the depreciation rates for
\n
first-generation electronic meters (1G) in order to reflect
\n
the planned installation schedule for 2G meters provided
\n
for in the Open Meter plan;
\n
\u2022 the depreciation of tangible assets due to new invest-
\n
ments made in recent years in the renewable energy
\n
sector in South America, North America and Spain;
\n
\u2022 the value adjustments of the net assets of Enel Gener-
\n
aci\u00f3n Costanera SA (\u20ac174 million) and Central Dock Sud
\n
SA (\u20ac116 million) in Argentina, and Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (\u20ac827 million) and CGT Fortaleza in Brazil (\u20ac73
\n
million).
\n

\n\n

\n\n\n

\n\n
12.f Other operating costs \u2013 \u20ac4,685 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
System charges - emissions allowances 2,216 41 2,175 -
\n
System charges - energy efficiency certificates 182 239 (57) -23.8%
\n
System charges - purchases of green certificates - - - -
\n
System charges - guarantees of origin 112 26 86 -
\n
Losses on disposal of property, plant and equipment, and intangible assets 166 75 91 -
\n
Taxes and duties 1,107 1,099 8 0.7%
\n
Other 902 488 414 84.8%
\n
Tot al 4,685 1,968 2,717 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Other operating costs increased by \u20ac2,717 million com-
\n
pared with the previous year, mainly reflecting:
\n
\u2022 the increase in environmental compliance charges in It-
\n
aly and Spain (\u20ac2,178 million) reflecting the increase in
\n
the price of CO
\n
2
\n
and of thermal generation mainly attrib-
\n
utable to the need to compensate for low water levels
\n
during the period;
\n
\u2022 the capital losses recognized for the sale of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac208 million) and CGT
\n
Fortaleza in Brazil (\u20ac135 million).
\n

\n\n

\n\n
12.g Capitalized costs \u2013 \u20ac(3,415) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Personnel (1,184) (998) (186) -18.6%
\n
Materials (1,258) (1,079) (179) -16.6%
\n
Other (973) (964) (9) -0.9%
\n
Tot al (3,415) (3,041) (374) -12.3%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Capitalized costs increased by \u20ac374 million, mainly reflect-
\n
ing:
\n
\u2022 greater investment in renewable plants in Italy, Spain and
\n
North America;
\n
\u2022 greater investment in distribution lines in Latin America;
\n
\u2022 greater investment in the distribution sector in Italy, for
\n
an increase in new customer connections and an in-
\n
crease in investment in service quality (e-grid and DSO
\n
4.0 projects).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag994": { "value": "\n
12.c Personnel expenses \u2013 \u20ac4,570 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Wages and salaries 3,442 3,122 320 10.2%
\n
Social security contributions 924 844 80 9.5%
\n
Italian post-employment benefits 107 104 3 2.9%
\n
Post-employment and other long-term benefits 73 86 (13) -15.1%
\n
Early retirement incentives (20) 10 (30) -
\n
Early retirement incentives connected with restructuring agreements (151) 795 (946) -
\n
Other costs 195 179 16 8.9%
\n
Tot al 4,570 5,140 (570) -11.1%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Personnel expenses in 2022 amounted to \u20ac4,570 million, a
\n
decrease of \u20ac570 million.
\n
The Group\u2019s workforce decreased by 1,155 employees,
\n
mainly reflecting the positive balance between new hires
\n
and terminations (1,998 employees), more than offset by
\n
changes in the consolidation scope (-3,153 employees),
\n
essentially attributable to:
\n
\u2022 the acquisition of Enel Hydro Appennino Centrale Srl in
\n
Italy;
\n
\u2022 the acquisition of Melita Italia Srl in Italy;
\n
\u2022 the sale of PayTipper SpA in Italy;
\n
\u2022 the sale of CityPoste Payment SpA in Italy;
\n
\u2022 the sale of PayTipper Network Srl in Italy;
\n
\u2022 the sale of FlagPay Srl in Italy;
\n
\u2022 the sale of Gridspertise Srl in Italy;
\n
\u2022 the sale of Central Geradora Termel\u00e9trica Fortaleza SA,
\n
Celg Distribui\u00e7\u00e3o SA - Celg-D and Gridspertise Latam SA
\n
in Brazil;
\n
\u2022 the sale of PJSC Enel Russia and subsidiaries in Russia;
\n
\u2022 the sale of Enel Transmisi\u00f3n SA in Chile.
\n
The increase in \u201cWages and salaries\u201d substantially reflects
\n
the cost incurred as a result of new hiring at companies in
\n
Italy, the United States, Brazil, Spain and Argentina.
\n
The \u20ac13 million decrease in in \u201cPost-employment and oth-
\n
er long-term benefits\u201d is mainly attributable to Spain.
\n
The decrease in \u201cEarly retirement incentives connected
\n
with restructuring agreements\u201d is mainly attributable to an
\n
increase in costs in Italy in 2021 as a result of the signing
\n
of a new framework agreement in application of Article 4,
\n
paragraphs 1-7-ter, of Law 92/2012, for which provisions
\n
of \u20ac557 million were recognized for restructuring and dig-
\n
italization. In 2022 the provision was adjusted according to
\n
the developments of the period and changes underlying
\n
the actuarial assumptions.
\n

\n\n
The table below shows the average number of employees
\n
by category, along with a comparison with the previous
\n
year, and the headcount as of December 31, 2022.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
2022 2021 at Dec. 31, 2022
\n
Senior managers 1,389 1,386 1,366
\n
Middle managers 12,528 11,797 12,645
\n
Office staff 35,676 35,449 34,634
\n
Blue collar 16,883 17,344 16,479
\n
Tot al 66,476 65,976 65,124
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag990": { "value": "\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013
\n
\u20ac1,278 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Impairment losses on trade receivables 1,375 1,285 90 7.0%
\n
Impairment losses on other financial assets 169 93 76 81.7%
\n
Total impairment losses on trade receivables and other financial assets 1,544 1,378 166 12.0%
\n
Impairment gains on trade receivables (265) (202) (63) -31.2%
\n
Impairment gains on other financial assets (1) (1) - -
\n
Total impairment gains on trade receivables and other financial assets (266) (203) (63) -31.0%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,278 1,175 103 8.8%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The item, equal to \u20ac1,278 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
increased by a total of \u20ac90 million, essentially reflecting
\n
the effect of the increase in trade receivables which led to
\n
an increase in the provision for bad debts in order to guar-
\n
antee adequate coverage of the new receivable.
\n

\n\n

\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac7,447 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Property, plant and equipment 4,472 4,259 213 5.0%
\n
Investment property 2 3 (1) -33.3%
\n
Intangible assets 1,612 1,330 282 21.2%
\n
Other impairment losses 1,414 2,917 (1,503) -51.5%
\n
Other reversals of impairment losses (53) (2) (51) -
\n
Tot al 7,447 8,507 (1,060) -12.5%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The decrease in \u201cDepreciation, amortization and other im-
\n
pairment losses\u201d in 2022 essentially reflected:
\n
\u2022 the effect of impairment losses recognized in 2021
\n
on certain plants or CGUs in Italy (\u20ac989 million), Spain
\n
(\u20ac1,488 million), Mexico (\u20ac155 million), Chile (\u20ac32 million)
\n
and Australia (\u20ac30 million);
\n

\n\n

\n\n

\n\n
\u2022 the effect of the impairment losses recognized in 2021 in
\n
Costa Rica (\u20ac126 million) on the hydroelectric plant op-
\n
erated under a concession arrangement by PH Chucas
\n
.
\n
These effects were partially offset by:
\n
\u2022 an increase in depreciation and amortization in Ita-
\n
ly due to an acceleration of the depreciation rates for
\n
first-generation electronic meters (1G) in order to reflect
\n
the planned installation schedule for 2G meters provided
\n
for in the Open Meter plan;
\n
\u2022 the depreciation of tangible assets due to new invest-
\n
ments made in recent years in the renewable energy
\n
sector in South America, North America and Spain;
\n
\u2022 the value adjustments of the net assets of Enel Gener-
\n
aci\u00f3n Costanera SA (\u20ac174 million) and Central Dock Sud
\n
SA (\u20ac116 million) in Argentina, and Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (\u20ac827 million) and CGT Fortaleza in Brazil (\u20ac73
\n
million).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag995": { "value": "\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac7,447 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Property, plant and equipment 4,472 4,259 213 5.0%
\n
Investment property 2 3 (1) -33.3%
\n
Intangible assets 1,612 1,330 282 21.2%
\n
Other impairment losses 1,414 2,917 (1,503) -51.5%
\n
Other reversals of impairment losses (53) (2) (51) -
\n
Tot al 7,447 8,507 (1,060) -12.5%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The decrease in \u201cDepreciation, amortization and other im-
\n
pairment losses\u201d in 2022 essentially reflected:
\n
\u2022 the effect of impairment losses recognized in 2021
\n
on certain plants or CGUs in Italy (\u20ac989 million), Spain
\n
(\u20ac1,488 million), Mexico (\u20ac155 million), Chile (\u20ac32 million)
\n
and Australia (\u20ac30 million);
\n

\n\n
\u2022 the effect of the impairment losses recognized in 2021 in
\n
Costa Rica (\u20ac126 million) on the hydroelectric plant op-
\n
erated under a concession arrangement by PH Chucas
\n
.
\n
These effects were partially offset by:
\n
\u2022 an increase in depreciation and amortization in Ita-
\n
ly due to an acceleration of the depreciation rates for
\n
first-generation electronic meters (1G) in order to reflect
\n
the planned installation schedule for 2G meters provided
\n
for in the Open Meter plan;
\n
\u2022 the depreciation of tangible assets due to new invest-
\n
ments made in recent years in the renewable energy
\n
sector in South America, North America and Spain;
\n
\u2022 the value adjustments of the net assets of Enel Gener-
\n
aci\u00f3n Costanera SA (\u20ac174 million) and Central Dock Sud
\n
SA (\u20ac116 million) in Argentina, and Celg Distribui\u00e7\u00e3o SA
\n
- Celg-D (\u20ac827 million) and CGT Fortaleza in Brazil (\u20ac73
\n
million).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag993": { "value": "\n

\n\n
12.f Other operating costs \u2013 \u20ac4,685 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
System charges - emissions allowances 2,216 41 2,175 -
\n
System charges - energy efficiency certificates 182 239 (57) -23.8%
\n
System charges - purchases of green certificates - - - -
\n
System charges - guarantees of origin 112 26 86 -
\n
Losses on disposal of property, plant and equipment, and intangible assets 166 75 91 -
\n
Taxes and duties 1,107 1,099 8 0.7%
\n
Other 902 488 414 84.8%
\n
Tot al 4,685 1,968 2,717 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Other operating costs increased by \u20ac2,717 million com-
\n
pared with the previous year, mainly reflecting:
\n
\u2022 the increase in environmental compliance charges in It-
\n
aly and Spain (\u20ac2,178 million) reflecting the increase in
\n
the price of CO
\n
2
\n
and of thermal generation mainly attrib-
\n
utable to the need to compensate for low water levels
\n
during the period;
\n
\u2022 the capital losses recognized for the sale of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac208 million) and CGT
\n
Fortaleza in Brazil (\u20ac135 million).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1000": { "value": "\n
13. Net results from commodity contracts \u2013 \u20ac2,365 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Commodity derivatives:
\n
- income from settled derivatives 23,124 11,456 11,668 -
\n
- expense from settled derivatives 18,929 9,331 9,598 -
\n
Net income/(expense) from settled commodity derivatives: 4,195 2,125 2,070 97.4%
\n
- income from outstanding derivatives (2,479) 4,572 (7,051) -
\n
- expense from outstanding derivatives 223 2,266 (2,043) -90.2%
\n
Net income/(expense) from outstanding commodity derivatives (2,702) 2,306 (5,008) -
\n
Outstanding contracts for energy commodities with physical settlement:
\n
- results from outstanding contracts to sell energy commodities with
\n
physical settlement
\n
5,182 (18,386) 23,568 -
\n
- results from outstanding contracts to purchase energy commodities with
\n
physical settlement
\n
(4,310) 16,478 (20,788) -
\n
Net results from outstanding contracts for energy commodities with
\n
physical settlement
\n
872 (1,908) 2,780 -
\n
NET RESULTS FROM COMMODITY CONTRACTS 2,365 2,523 (158) -6.3%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Net results from commodity contracts showed net income
\n
of \u20ac2,365 million in 2022 (net income of \u20ac2,523 million in
\n
2021), and break down as follows:
\n
\u2022 net income from commodity derivatives totaling \u20ac1,493
\n
million (net income of \u20ac4,431 million in 2021), including
\n
derivatives designated as cash flow hedges and de-
\n
rivatives measured at fair value through profit or loss.
\n
More specifically, net income from derivatives settled in
\n
the period amounted to \u20ac4,195 million (net income of
\n
\u20ac2,125 million in 2021) and net expense from the fair
\n
value measurement of outstanding derivatives came to
\n
\u20ac2,702 million (net income of \u20ac2,306 million in 2021);
\n
\u2022 net income from the fair value measurement through
\n
profit or loss of energy commodity contracts with phys-
\n
ical settlement still outstanding at the reporting date
\n
amounting to \u20ac872 million (net expense of \u20ac1,908 mil-
\n
lion in 2021).
\n
For more information on derivatives, please see note 51
\n
\u201cDerivatives and hedge accounting\u201d.
\n

\n", "dimensions": { "concept": "enel:DisclosureOfNetResultsFromCommodityContracts", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag999": { "value": "\n

\n\n

\n\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(296) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 1,442 2,097 (655) -31.2%
\n
- income from derivatives at fair value through profit or loss 1,676 620 1,056 -
\n
Total income 3,118 2,717 401 14.8%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,744) (599) (1,145) -
\n
- expense from derivatives at fair value through profit or loss (1,670) (657) (1,013) -
\n
Total expense (3,414) (1,256) (2,158) -
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (296) 1,461 (1,757) -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
In 2022, net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac296 million (net income of
\n
\u20ac1,461 million in 2021) and break down as follows:
\n
\u2022 net expense from derivatives designated as hedging deriv-
\n
atives in the amount of \u20ac302 million (net income of \u20ac1,498
\n
million in 2021) mainly in regard of cash flow hedges;
\n
\u2022 net income from derivatives at fair value through profit
\n
or loss in the amount of \u20ac6 million (net expense of \u20ac37
\n
million in 2021).
\n
The net balances recognized in 2022 and 2021 on both
\n
hedging derivatives and those at fair value through profit or
\n
loss mainly referred to the hedging of exchange rate risk.
\n
For more information on derivatives, see note 51 \u201cDeriva-
\n
tives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n

\n\n

\n
15. Net other financial income/(expense) \u2013 \u20ac(2,160) million
\n
Other financial income
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest income from financial assets
\n
(current and non-current):
\n
- interest income at effective rate on non-current securities and financial assets 158 117 41 35.0%
\n
- interest income at effective rate on current financial investments 201 80 121 -
\n
Total interest income at the effective interest rate 359 197 162 82.2%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
--- -
\n
Exchange gains 2,289 1,212 1,077 88.9%
\n
Income on equity investments 1 6 (5) -83.3%
\n
Income from hyperinflation 1,739 824 915 -
\n
Other income 781 447 334 74.7%
\n
TOTAL OTHER FINANCIAL INCOME 5,169 2,686 2,483 92.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial income amounted to \u20ac5,169 million, an in-
\n
crease of \u20ac2,483 million compared with the previous year.
\n
The increase mainly reflects the following factors:
\n
\u2022 an increase in income from exchange gains (\u20ac1,077 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac728
\n
million) and Enel Am\u00e9ricas (\u20ac222 million);
\n
\u2022 an increase in income from hyperinflation (\u20ac915 million),
\n
recognized by the Argentine companies as a result of
\n
the application of IAS 29 on financial reporting in hyper-
\n
inflationary economies; for more information, see note
\n
4 of these consolidated financial statements at 31 De-
\n
cember, 2022;
\n
\u2022 an increase in interest income at the effective rate (\u20ac162
\n
million), mainly relating to short-term financial invest-
\n
ments;
\n
\u2022 an increase in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value hedge
\n
relationships (\u20ac123 million).
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n
Other financial expense
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest expense on financial debt
\n
(current and non-current):
\n
- interest on bank borrowings 509 322 187 58.1%
\n
- interest expense on bonds 1,884 1,877 7 0.4%
\n
- interest expense on other borrowings 235 134 101 75.4%
\n
Total interest expense 2,628 2,333 295 12.6%
\n
Financial expense on debt management transactions - 702 (702) -
\n
Exchange losses 2,179 2,551 (372) -14.6%
\n
Adjustment to post-employment and other employee benefits 145 105 40 38.1%
\n
Adjustment to other provisions 201 126 75 59.5%
\n
Expense from equity investments ----
\n
Expense from hyperinflation 1,449 804 645 80.2%
\n
Other expenses 727 270 457 -
\n
TOTAL OTHER FINANCIAL EXPENSE 7,329 6,891 438 6.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial expense amounted to \u20ac7,329 million, an
\n
overall increase of \u20ac438 million compared with 2021, es-
\n
sentially reflecting the following factors:
\n
\u2022 an increase in expense from hyperinflation of \u20ac645 mil-
\n
lion, recognized by the Argentine companies as a result
\n
of the application of IAS 29 on financial reporting in hy-
\n
perinflationary economies; for more information, see
\n
note 4 of these consolidated financial statements at 31
\n
December 2022;
\n
\u2022 an increase in interest expense of \u20ac295 million, mainly
\n
attributable to the increase in interest rates due to the
\n
restrictive monetary policies implemented to face grow-
\n
ing inflationary pressures;
\n
\u2022 an increase in other expenses, in the amount of \u20ac63 mil-
\n
lion, in Argentina, mainly attributable to the increase in
\n
financial expense in respect of CAMMESA (\u20ac65 million),
\n
in Brazil, for higher costs deriving from the PIS/COFINS
\n
dispute, as well as \u20ac43 million at Enel Produzione for
\n
greater financial expense connected with the impair-
\n
ment loss on the receivable in respect of the sale of Slo-
\n
vak Power Holding.
\n
These effects were substantially offset by the reduction in
\n
financial expense associated with the recognition of ex-
\n
pense on debt management operations (\u20ac702 million) in
\n
2021.
\n

\n\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag997": { "value": "\n

\n\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(296) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 1,442 2,097 (655) -31.2%
\n
- income from derivatives at fair value through profit or loss 1,676 620 1,056 -
\n
Total income 3,118 2,717 401 14.8%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,744) (599) (1,145) -
\n
- expense from derivatives at fair value through profit or loss (1,670) (657) (1,013) -
\n
Total expense (3,414) (1,256) (2,158) -
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (296) 1,461 (1,757) -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n

\n\n

\n\n
In 2022, net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac296 million (net income of
\n
\u20ac1,461 million in 2021) and break down as follows:
\n
\u2022 net expense from derivatives designated as hedging deriv-
\n
atives in the amount of \u20ac302 million (net income of \u20ac1,498
\n
million in 2021) mainly in regard of cash flow hedges;
\n
\u2022 net income from derivatives at fair value through profit
\n
or loss in the amount of \u20ac6 million (net expense of \u20ac37
\n
million in 2021).
\n
The net balances recognized in 2022 and 2021 on both
\n
hedging derivatives and those at fair value through profit or
\n
loss mainly referred to the hedging of exchange rate risk.
\n
For more information on derivatives, see note 51 \u201cDeriva-
\n
tives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n
Other financial expense amounted to \u20ac7,329 million, an
\n
overall increase of \u20ac438 million compared with 2021, es-
\n
sentially reflecting the following factors:
\n
\u2022 an increase in expense from hyperinflation of \u20ac645 mil-
\n
lion, recognized by the Argentine companies as a result
\n
of the application of IAS 29 on financial reporting in hy-
\n
perinflationary economies; for more information, see
\n
note 4 of these consolidated financial statements at 31
\n
December 2022;
\n
\u2022 an increase in interest expense of \u20ac295 million, mainly
\n
attributable to the increase in interest rates due to the
\n
restrictive monetary policies implemented to face grow-
\n
ing inflationary pressures;
\n
\u2022 an increase in other expenses, in the amount of \u20ac63 mil-
\n
lion, in Argentina, mainly attributable to the increase in
\n
financial expense in respect of CAMMESA (\u20ac65 million),
\n
in Brazil, for higher costs deriving from the PIS/COFINS
\n
dispute, as well as \u20ac43 million at Enel Produzione for
\n
greater financial expense connected with the impair-
\n
ment loss on the receivable in respect of the sale of Slo-
\n
vak Power Holding.
\n
These effects were substantially offset by the reduction in
\n
financial expense associated with the recognition of ex-
\n
pense on debt management operations (\u20ac702 million) in
\n
2021.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag998": { "value": "\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(296) million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 1,442 2,097 (655) -31.2%
\n
- income from derivatives at fair value through profit or loss 1,676 620 1,056 -
\n
Total income 3,118 2,717 401 14.8%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,744) (599) (1,145) -
\n
- expense from derivatives at fair value through profit or loss (1,670) (657) (1,013) -
\n
Total expense (3,414) (1,256) (2,158) -
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (296) 1,461 (1,757) -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n\n
In 2022, net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac296 million (net income of
\n
\u20ac1,461 million in 2021) and break down as follows:
\n
\u2022 net expense from derivatives designated as hedging deriv-
\n
atives in the amount of \u20ac302 million (net income of \u20ac1,498
\n
million in 2021) mainly in regard of cash flow hedges;
\n
\u2022 net income from derivatives at fair value through profit
\n
or loss in the amount of \u20ac6 million (net expense of \u20ac37
\n
million in 2021).
\n
The net balances recognized in 2022 and 2021 on both
\n
hedging derivatives and those at fair value through profit or
\n
loss mainly referred to the hedging of exchange rate risk.
\n
For more information on derivatives, see note 51 \u201cDeriva-
\n
tives and hedge accounting\u201d.
\n

\n\n

\n\n
Other financial income amounted to \u20ac5,169 million, an in-
\n
crease of \u20ac2,483 million compared with the previous year.
\n
The increase mainly reflects the following factors:
\n
\u2022 an increase in income from exchange gains (\u20ac1,077 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac728
\n
million) and Enel Am\u00e9ricas (\u20ac222 million);
\n
\u2022 an increase in income from hyperinflation (\u20ac915 million),
\n
recognized by the Argentine companies as a result of
\n
the application of IAS 29 on financial reporting in hyper-
\n
inflationary economies; for more information, see note
\n
4 of these consolidated financial statements at 31 De-
\n
cember, 2022;
\n
\u2022 an increase in interest income at the effective rate (\u20ac162
\n
million), mainly relating to short-term financial invest-
\n
ments;
\n
\u2022 an increase in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value hedge
\n
relationships (\u20ac123 million).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1005": { "value": "\n

\n
15. Net other financial income/(expense) \u2013 \u20ac(2,160) million
\n
Other financial income
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest income from financial assets
\n
(current and non-current):
\n
- interest income at effective rate on non-current securities and financial assets 158 117 41 35.0%
\n
- interest income at effective rate on current financial investments 201 80 121 -
\n
Total interest income at the effective interest rate 359 197 162 82.2%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
--- -
\n
Exchange gains 2,289 1,212 1,077 88.9%
\n
Income on equity investments 1 6 (5) -83.3%
\n
Income from hyperinflation 1,739 824 915 -
\n
Other income 781 447 334 74.7%
\n
TOTAL OTHER FINANCIAL INCOME 5,169 2,686 2,483 92.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial income amounted to \u20ac5,169 million, an in-
\n
crease of \u20ac2,483 million compared with the previous year.
\n
The increase mainly reflects the following factors:
\n
\u2022 an increase in income from exchange gains (\u20ac1,077 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac728
\n
million) and Enel Am\u00e9ricas (\u20ac222 million);
\n
\u2022 an increase in income from hyperinflation (\u20ac915 million),
\n
recognized by the Argentine companies as a result of
\n
the application of IAS 29 on financial reporting in hyper-
\n
inflationary economies; for more information, see note
\n
4 of these consolidated financial statements at 31 De-
\n
cember, 2022;
\n
\u2022 an increase in interest income at the effective rate (\u20ac162
\n
million), mainly relating to short-term financial invest-
\n
ments;
\n
\u2022 an increase in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value hedge
\n
relationships (\u20ac123 million).
\n

\n\n

\n\n

\n\n

\n
Other financial expense
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Interest expense on financial debt
\n
(current and non-current):
\n
- interest on bank borrowings 509 322 187 58.1%
\n
- interest expense on bonds 1,884 1,877 7 0.4%
\n
- interest expense on other borrowings 235 134 101 75.4%
\n
Total interest expense 2,628 2,333 295 12.6%
\n
Financial expense on debt management transactions - 702 (702) -
\n
Exchange losses 2,179 2,551 (372) -14.6%
\n
Adjustment to post-employment and other employee benefits 145 105 40 38.1%
\n
Adjustment to other provisions 201 126 75 59.5%
\n
Expense from equity investments ----
\n
Expense from hyperinflation 1,449 804 645 80.2%
\n
Other expenses 727 270 457 -
\n
TOTAL OTHER FINANCIAL EXPENSE 7,329 6,891 438 6.4%
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n\n

\n\n
Other financial expense amounted to \u20ac7,329 million, an
\n
overall increase of \u20ac438 million compared with 2021, es-
\n
sentially reflecting the following factors:
\n
\u2022 an increase in expense from hyperinflation of \u20ac645 mil-
\n
lion, recognized by the Argentine companies as a result
\n
of the application of IAS 29 on financial reporting in hy-
\n
perinflationary economies; for more information, see
\n
note 4 of these consolidated financial statements at 31
\n
December 2022;
\n
\u2022 an increase in interest expense of \u20ac295 million, mainly
\n
attributable to the increase in interest rates due to the
\n
restrictive monetary policies implemented to face grow-
\n
ing inflationary pressures;
\n
\u2022 an increase in other expenses, in the amount of \u20ac63 mil-
\n
lion, in Argentina, mainly attributable to the increase in
\n
financial expense in respect of CAMMESA (\u20ac65 million),
\n
in Brazil, for higher costs deriving from the PIS/COFINS
\n
dispute, as well as \u20ac43 million at Enel Produzione for
\n
greater financial expense connected with the impair-
\n
ment loss on the receivable in respect of the sale of Slo-
\n
vak Power Holding.
\n
These effects were substantially offset by the reduction in
\n
financial expense associated with the recognition of ex-
\n
pense on debt management operations (\u20ac702 million) in
\n
2021.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1003": { "value": "\n
Other financial income amounted to \u20ac5,169 million, an in-
\n
crease of \u20ac2,483 million compared with the previous year.
\n
The increase mainly reflects the following factors:
\n
\u2022 an increase in income from exchange gains (\u20ac1,077 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac728
\n
million) and Enel Am\u00e9ricas (\u20ac222 million);
\n
\u2022 an increase in income from hyperinflation (\u20ac915 million),
\n
recognized by the Argentine companies as a result of
\n
the application of IAS 29 on financial reporting in hyper-
\n
inflationary economies; for more information, see note
\n
4 of these consolidated financial statements at 31 De-
\n
cember, 2022;
\n
\u2022 an increase in interest income at the effective rate (\u20ac162
\n
million), mainly relating to short-term financial invest-
\n
ments;
\n
\u2022 an increase in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value hedge
\n
relationships (\u20ac123 million).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1008": { "value": "\n
Other financial expense amounted to \u20ac7,329 million, an
\n
overall increase of \u20ac438 million compared with 2021, es-
\n
sentially reflecting the following factors:
\n
\u2022 an increase in expense from hyperinflation of \u20ac645 mil-
\n
lion, recognized by the Argentine companies as a result
\n
of the application of IAS 29 on financial reporting in hy-
\n
perinflationary economies; for more information, see
\n
note 4 of these consolidated financial statements at 31
\n
December 2022;
\n
\u2022 an increase in interest expense of \u20ac295 million, mainly
\n
attributable to the increase in interest rates due to the
\n
restrictive monetary policies implemented to face grow-
\n
ing inflationary pressures;
\n
\u2022 an increase in other expenses, in the amount of \u20ac63 mil-
\n
lion, in Argentina, mainly attributable to the increase in
\n
financial expense in respect of CAMMESA (\u20ac65 million),
\n
in Brazil, for higher costs deriving from the PIS/COFINS
\n
dispute, as well as \u20ac43 million at Enel Produzione for
\n
greater financial expense connected with the impair-
\n
ment loss on the receivable in respect of the sale of Slo-
\n
vak Power Holding.
\n
These effects were substantially offset by the reduction in
\n
financial expense associated with the recognition of ex-
\n
pense on debt management operations (\u20ac702 million) in
\n
2021.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1002": { "value": "\n

\n\n

\n\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac4 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share of profit of associates 145 624 (479) -76.8%
\n
Share of loss of associates (141) (53) (88) -
\n
Tot al 4 571 (567) -99.3%
\n
The share of profit/(loss) of equity-accounted investments
\n
in 2022 came to \u20ac4 million, a decrease of \u20ac567 million
\n
compared with the previous year.
\n
The change was essentially due to a decrease in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac587 million), heavily penalized by the sharp rise in
\n
electricity prices on the spot market, slightly offset by the
\n
increase in the share of profit/(loss) of the Spanish compa-
\n
nies (\u20ac20 million) and Rusenergosbyt (\u20ac19 million).
\n

\n\n

\n\n

\n\n

\n", "dimensions": { "concept": "enel:DisclosureOfIncomeExpenseOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1004": { "value": "\n

\n\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac4 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share of profit of associates 145 624 (479) -76.8%
\n
Share of loss of associates (141) (53) (88) -
\n
Tot al 4 571 (567) -99.3%
\n
The share of profit/(loss) of equity-accounted investments
\n
in 2022 came to \u20ac4 million, a decrease of \u20ac567 million
\n
compared with the previous year.
\n
The change was essentially due to a decrease in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac587 million), heavily penalized by the sharp rise in
\n
electricity prices on the spot market, slightly offset by the
\n
increase in the share of profit/(loss) of the Spanish compa-
\n
nies (\u20ac20 million) and Rusenergosbyt (\u20ac19 million).
\n

\n\n

\n\n

\n\n

\n\n

\n\n
26. Equity-accounted investments - \u20ac1,281 million
\n
The following table shows changes in the main investments
\n
in joint ventures and associated companies accounted for
\n
using the equity method.
\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl - - - 299 - - - 299 50.0%
\n
Mooney Group SpA - - (17) 305 - - (69) 219 50.0%
\n
Slovak Power Holding - 50.0% (65) - - - 155 90 50.0%
\n
Zacapa Topco S\u00e0rl 114 20.6% 1 (114) - - (1) - -
\n
Matimba project
\n
companies
\n
- - (3) 108 - - 3 108 50.0%
\n
Kino project companies 21 20.0% (18) - - - 13 16 20.0%
\n
Tejo Energia Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica
\n
12 43.8% - - (7) - - 5 43.8%
\n
Ewiva Srl 22 50.0% (2) - - - - 20 50.0%
\n
Drift Sand Wind Project 40 50.0% 2 - - - 3 45 50.0%
\n
Front Mar\u00edtim del Bes\u00f2s 33 61.4% (2) - - - - 31 61.4%
\n
Rusenergosbyt 51 49.5% 64 - (11) - (13) 91 49.5%
\n
Energie Electrique de
\n
Tahaddart
\n
18 32.0% 2 - (2) - (7) 11 32.0%
\n
PowerCrop - 50.0% 16 - - - (2) 14 50.0%
\n
Total joint ventures 311 (22) 598 (20) - 82 949
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Associates
\n
CESI 59 42.7% (3) - - - 2 58 42.7%
\n
Elecgas SA 15 50.0% 7 - (15) - 23 30 50.0%
\n
GNL Chile SA 6 33.3% 7 - - - 1 14 33.3%
\n
Energ\u00edas Especiales del
\n
Bierzo
\n
4 50.0% 3 - (2) - 7 12 50.0%
\n
Tecnatom 27 45.0% - - - (27) - - -
\n
Gorona del Viento El
\n
Hierro SA
\n
13 23.2% 1 - (1) - - 13 23.2%
\n
Suministradora El\u00e9ctrica
\n
de C\u00e1diz
\n
10 33.5% 4 - (5) - - 9 33.5%
\n
Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas
\n
8 37.5 % 3 - (3) - (1) 7 37.5 %
\n
Cogenio Srl 12 20.0% (1) - (4) - 2 9 20.0%
\n
Avikiran Surya India - - - 28 - - (1) 27 51.0%
\n
Sociedad de Inversiones
\n
K Cuatro SpA
\n
- - - (30) - - 30 - -
\n
Enel X AMPCI Ebus Chile
\n
SpA
\n
4 20.0% - (5) - - 1 - -
\n
EGPNA Renewable
\n
Energy Partners
\n
121 20.0% 5 (59) - - 10 77 10.0%
\n
Rocky Caney Holding 50 20.0% 5 (30) - - (3) 22 10.0%
\n
Other 64 (5) (12) (7) - 14 54
\n
Total associates 393 26 (108) (37) (27) 85 332
\n
TOTAL 704 4 490 (57) (27) 167 1,281
\n
The increase in equity-accounted investments in 2022
\n
mainly reflected:
\n
\u2022 the positive impact of changes in the consolidation
\n
scope, mainly regarding:
\n
- the acquisition of a stake in Mooney; more specifical-
\n
ly, with the closing of the transaction between Enel
\n
X Srl and Banca 5 both companies have acquired a
\n
50% stake in Mooney putting it under the joint control
\n
of both parties. Subsequently, all the activities related
\n
to Enel X\u2019s financial service business in Italy, marketed
\n
under the brand Enel X Pay, were sold to Mooney, cre-
\n
ating a European-based fintech company;
\n
- the recognition of the interest in Gridspertise Srl fol-
\n
lowing the disposal of a 50% stake in the company,
\n
previously wholly owned, to the international private
\n
equity fund CVC Capital Partners Fund VIII (CVC);
\n
- the recognition of the interest in the joint venture
\n
holding the companies of the Matimba project, previ-
\n
ously controlled by the Enel Group;
\n
- the recognition of the interest in the previously con-
\n
trolled Indian company Avikiran Surya India Private
\n
Limited;
\n
- the reclassification of the investment in Zacapa Top-
\n
co (\u20ac114 million) under \u201cInvestments in other entities\u201d,
\n
following the sale by Enel X International of 1.1% of
\n
the interest in Ufinet. Following the transaction, Enel X
\n
International retains an indirect stake of 19.5% in the
\n
share capital of Ufinet;
\n
- the sale by Enel X Chile SpA of the entire stake held in
\n
the associates Sociedad de Inversiones K Cuatro SpA
\n
and Enel X AMPCI Ebus Chile SpA;
\n
- the sale of 50% of the stakes held in EGPNA Renew-
\n
able Energy Partners and in Rocky Caney Holding
\n
(which, following the transaction, go from 20% to
\n
10%);
\n
\u2022 the profits attributable to the Group of equity-account-
\n
ed companies (\u20ac4 million), mainly accounted for by the
\n
profit contributed by Rusenergosbyt, PowerCrop and
\n
Spanish companies;
\n
\u2022 changes in the OCI reserves mainly relating to Slovak
\n
Power Holding, following the positive developments in
\n
the fair value of cash flow hedge derivatives, and the
\n
Spanish companies.
\n
These positive effects were mainly offset by:
\n
\u2022 dividends distributed in the period in the amount of \u20ac57
\n
million, mainly by Rusenergosbyt and certain Spanish
\n
companies;
\n

\n\n

\n\n

\n\n

\n\n

\n\n
\u2022 the reclassification of the investment in Tecnatom (\u20ac27
\n
million) as held for sale.
\n
The following tables provide a summary of financial infor-
\n
mation for the main joint ventures and associates of the
\n
Group not classified as held for sale in accordance with
\n
IFRS 5.
\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2022 2021 2022 2021 2022 2021
\n
Joint ventures
\n
Slovak Power Holding 5,184 3,417 (320) 190 (223) 137
\n
Gridspertise Srl 334 - 12 - 8 -
\n
Rusenergosbyt 2,919 2,288 170 112 137 90
\n
Matimba project
\n
companies
\n
34 - (22) - (15) -
\n
Mooney Group SpA 224 - (33) - (33) -
\n
Ewiva Srl - - (4) - (4) -
\n
Associates
\n
CESI 155 140 (4) (7) (1) (8)
\n
Elecgas SA 26 25 20 15 14 11
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1006": { "value": "\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac4 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share of profit of associates 145 624 (479) -76.8%
\n
Share of loss of associates (141) (53) (88) -
\n
Tot al 4 571 (567) -99.3%
\n
The share of profit/(loss) of equity-accounted investments
\n
in 2022 came to \u20ac4 million, a decrease of \u20ac567 million
\n
compared with the previous year.
\n
The change was essentially due to a decrease in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac587 million), heavily penalized by the sharp rise in
\n
electricity prices on the spot market, slightly offset by the
\n
increase in the share of profit/(loss) of the Spanish compa-
\n
nies (\u20ac20 million) and Rusenergosbyt (\u20ac19 million).
\n

\n\n

\n\n

\n\n
26. Equity-accounted investments - \u20ac1,281 million
\n
The following table shows changes in the main investments
\n
in joint ventures and associated companies accounted for
\n
using the equity method.
\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl - - - 299 - - - 299 50.0%
\n
Mooney Group SpA - - (17) 305 - - (69) 219 50.0%
\n
Slovak Power Holding - 50.0% (65) - - - 155 90 50.0%
\n
Zacapa Topco S\u00e0rl 114 20.6% 1 (114) - - (1) - -
\n
Matimba project
\n
companies
\n
- - (3) 108 - - 3 108 50.0%
\n
Kino project companies 21 20.0% (18) - - - 13 16 20.0%
\n
Tejo Energia Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica
\n
12 43.8% - - (7) - - 5 43.8%
\n
Ewiva Srl 22 50.0% (2) - - - - 20 50.0%
\n
Drift Sand Wind Project 40 50.0% 2 - - - 3 45 50.0%
\n
Front Mar\u00edtim del Bes\u00f2s 33 61.4% (2) - - - - 31 61.4%
\n
Rusenergosbyt 51 49.5% 64 - (11) - (13) 91 49.5%
\n
Energie Electrique de
\n
Tahaddart
\n
18 32.0% 2 - (2) - (7) 11 32.0%
\n
PowerCrop - 50.0% 16 - - - (2) 14 50.0%
\n
Total joint ventures 311 (22) 598 (20) - 82 949
\n

\n\n

\n\n

\n\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Associates
\n
CESI 59 42.7% (3) - - - 2 58 42.7%
\n
Elecgas SA 15 50.0% 7 - (15) - 23 30 50.0%
\n
GNL Chile SA 6 33.3% 7 - - - 1 14 33.3%
\n
Energ\u00edas Especiales del
\n
Bierzo
\n
4 50.0% 3 - (2) - 7 12 50.0%
\n
Tecnatom 27 45.0% - - - (27) - - -
\n
Gorona del Viento El
\n
Hierro SA
\n
13 23.2% 1 - (1) - - 13 23.2%
\n
Suministradora El\u00e9ctrica
\n
de C\u00e1diz
\n
10 33.5% 4 - (5) - - 9 33.5%
\n
Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas
\n
8 37.5 % 3 - (3) - (1) 7 37.5 %
\n
Cogenio Srl 12 20.0% (1) - (4) - 2 9 20.0%
\n
Avikiran Surya India - - - 28 - - (1) 27 51.0%
\n
Sociedad de Inversiones
\n
K Cuatro SpA
\n
- - - (30) - - 30 - -
\n
Enel X AMPCI Ebus Chile
\n
SpA
\n
4 20.0% - (5) - - 1 - -
\n
EGPNA Renewable
\n
Energy Partners
\n
121 20.0% 5 (59) - - 10 77 10.0%
\n
Rocky Caney Holding 50 20.0% 5 (30) - - (3) 22 10.0%
\n
Other 64 (5) (12) (7) - 14 54
\n
Total associates 393 26 (108) (37) (27) 85 332
\n
TOTAL 704 4 490 (57) (27) 167 1,281
\n
The increase in equity-accounted investments in 2022
\n
mainly reflected:
\n
\u2022 the positive impact of changes in the consolidation
\n
scope, mainly regarding:
\n
- the acquisition of a stake in Mooney; more specifical-
\n
ly, with the closing of the transaction between Enel
\n
X Srl and Banca 5 both companies have acquired a
\n
50% stake in Mooney putting it under the joint control
\n
of both parties. Subsequently, all the activities related
\n
to Enel X\u2019s financial service business in Italy, marketed
\n
under the brand Enel X Pay, were sold to Mooney, cre-
\n
ating a European-based fintech company;
\n
- the recognition of the interest in Gridspertise Srl fol-
\n
lowing the disposal of a 50% stake in the company,
\n
previously wholly owned, to the international private
\n
equity fund CVC Capital Partners Fund VIII (CVC);
\n
- the recognition of the interest in the joint venture
\n
holding the companies of the Matimba project, previ-
\n
ously controlled by the Enel Group;
\n
- the recognition of the interest in the previously con-
\n
trolled Indian company Avikiran Surya India Private
\n
Limited;
\n
- the reclassification of the investment in Zacapa Top-
\n
co (\u20ac114 million) under \u201cInvestments in other entities\u201d,
\n
following the sale by Enel X International of 1.1% of
\n
the interest in Ufinet. Following the transaction, Enel X
\n
International retains an indirect stake of 19.5% in the
\n
share capital of Ufinet;
\n
- the sale by Enel X Chile SpA of the entire stake held in
\n
the associates Sociedad de Inversiones K Cuatro SpA
\n
and Enel X AMPCI Ebus Chile SpA;
\n
- the sale of 50% of the stakes held in EGPNA Renew-
\n
able Energy Partners and in Rocky Caney Holding
\n
(which, following the transaction, go from 20% to
\n
10%);
\n
\u2022 the profits attributable to the Group of equity-account-
\n
ed companies (\u20ac4 million), mainly accounted for by the
\n
profit contributed by Rusenergosbyt, PowerCrop and
\n
Spanish companies;
\n
\u2022 changes in the OCI reserves mainly relating to Slovak
\n
Power Holding, following the positive developments in
\n
the fair value of cash flow hedge derivatives, and the
\n
Spanish companies.
\n
These positive effects were mainly offset by:
\n
\u2022 dividends distributed in the period in the amount of \u20ac57
\n
million, mainly by Rusenergosbyt and certain Spanish
\n
companies;
\n

\n\n

\n\n

\n\n
\u2022 the reclassification of the investment in Tecnatom (\u20ac27
\n
million) as held for sale.
\n
The following tables provide a summary of financial infor-
\n
mation for the main joint ventures and associates of the
\n
Group not classified as held for sale in accordance with
\n
IFRS 5.
\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2022 2021 2022 2021 2022 2021
\n
Joint ventures
\n
Slovak Power Holding 5,184 3,417 (320) 190 (223) 137
\n
Gridspertise Srl 334 - 12 - 8 -
\n
Rusenergosbyt 2,919 2,288 170 112 137 90
\n
Matimba project
\n
companies
\n
34 - (22) - (15) -
\n
Mooney Group SpA 224 - (33) - (33) -
\n
Ewiva Srl - - (4) - (4) -
\n
Associates
\n
CESI 155 140 (4) (7) (1) (8)
\n
Elecgas SA 26 25 20 15 14 11
\n

\n\n

\n\n

\n\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1007": { "value": "\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac4 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share of profit of associates 145 624 (479) -76.8%
\n
Share of loss of associates (141) (53) (88) -
\n
Tot al 4 571 (567) -99.3%
\n
The share of profit/(loss) of equity-accounted investments
\n
in 2022 came to \u20ac4 million, a decrease of \u20ac567 million
\n
compared with the previous year.
\n
The change was essentially due to a decrease in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac587 million), heavily penalized by the sharp rise in
\n
electricity prices on the spot market, slightly offset by the
\n
increase in the share of profit/(loss) of the Spanish compa-
\n
nies (\u20ac20 million) and Rusenergosbyt (\u20ac19 million).
\n

\n\n
26. Equity-accounted investments - \u20ac1,281 million
\n
The following table shows changes in the main investments
\n
in joint ventures and associated companies accounted for
\n
using the equity method.
\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl - - - 299 - - - 299 50.0%
\n
Mooney Group SpA - - (17) 305 - - (69) 219 50.0%
\n
Slovak Power Holding - 50.0% (65) - - - 155 90 50.0%
\n
Zacapa Topco S\u00e0rl 114 20.6% 1 (114) - - (1) - -
\n
Matimba project
\n
companies
\n
- - (3) 108 - - 3 108 50.0%
\n
Kino project companies 21 20.0% (18) - - - 13 16 20.0%
\n
Tejo Energia Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica
\n
12 43.8% - - (7) - - 5 43.8%
\n
Ewiva Srl 22 50.0% (2) - - - - 20 50.0%
\n
Drift Sand Wind Project 40 50.0% 2 - - - 3 45 50.0%
\n
Front Mar\u00edtim del Bes\u00f2s 33 61.4% (2) - - - - 31 61.4%
\n
Rusenergosbyt 51 49.5% 64 - (11) - (13) 91 49.5%
\n
Energie Electrique de
\n
Tahaddart
\n
18 32.0% 2 - (2) - (7) 11 32.0%
\n
PowerCrop - 50.0% 16 - - - (2) 14 50.0%
\n
Total joint ventures 311 (22) 598 (20) - 82 949
\n

\n\n
Millions of euro % held
\n
Impact on
\n
profit or
\n
loss
\n
Change in
\n
consolidation
\n
scope Dividends
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes % held
\n
at Dec. 31, 2021 at Dec. 31, 2022
\n
Associates
\n
CESI 59 42.7% (3) - - - 2 58 42.7%
\n
Elecgas SA 15 50.0% 7 - (15) - 23 30 50.0%
\n
GNL Chile SA 6 33.3% 7 - - - 1 14 33.3%
\n
Energ\u00edas Especiales del
\n
Bierzo
\n
4 50.0% 3 - (2) - 7 12 50.0%
\n
Tecnatom 27 45.0% - - - (27) - - -
\n
Gorona del Viento El
\n
Hierro SA
\n
13 23.2% 1 - (1) - - 13 23.2%
\n
Suministradora El\u00e9ctrica
\n
de C\u00e1diz
\n
10 33.5% 4 - (5) - - 9 33.5%
\n
Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas
\n
8 37.5 % 3 - (3) - (1) 7 37.5 %
\n
Cogenio Srl 12 20.0% (1) - (4) - 2 9 20.0%
\n
Avikiran Surya India - - - 28 - - (1) 27 51.0%
\n
Sociedad de Inversiones
\n
K Cuatro SpA
\n
- - - (30) - - 30 - -
\n
Enel X AMPCI Ebus Chile
\n
SpA
\n
4 20.0% - (5) - - 1 - -
\n
EGPNA Renewable
\n
Energy Partners
\n
121 20.0% 5 (59) - - 10 77 10.0%
\n
Rocky Caney Holding 50 20.0% 5 (30) - - (3) 22 10.0%
\n
Other 64 (5) (12) (7) - 14 54
\n
Total associates 393 26 (108) (37) (27) 85 332
\n
TOTAL 704 4 490 (57) (27) 167 1,281
\n
The increase in equity-accounted investments in 2022
\n
mainly reflected:
\n
\u2022 the positive impact of changes in the consolidation
\n
scope, mainly regarding:
\n
- the acquisition of a stake in Mooney; more specifical-
\n
ly, with the closing of the transaction between Enel
\n
X Srl and Banca 5 both companies have acquired a
\n
50% stake in Mooney putting it under the joint control
\n
of both parties. Subsequently, all the activities related
\n
to Enel X\u2019s financial service business in Italy, marketed
\n
under the brand Enel X Pay, were sold to Mooney, cre-
\n
ating a European-based fintech company;
\n
- the recognition of the interest in Gridspertise Srl fol-
\n
lowing the disposal of a 50% stake in the company,
\n
previously wholly owned, to the international private
\n
equity fund CVC Capital Partners Fund VIII (CVC);
\n
- the recognition of the interest in the joint venture
\n
holding the companies of the Matimba project, previ-
\n
ously controlled by the Enel Group;
\n
- the recognition of the interest in the previously con-
\n
trolled Indian company Avikiran Surya India Private
\n
Limited;
\n
- the reclassification of the investment in Zacapa Top-
\n
co (\u20ac114 million) under \u201cInvestments in other entities\u201d,
\n
following the sale by Enel X International of 1.1% of
\n
the interest in Ufinet. Following the transaction, Enel X
\n
International retains an indirect stake of 19.5% in the
\n
share capital of Ufinet;
\n
- the sale by Enel X Chile SpA of the entire stake held in
\n
the associates Sociedad de Inversiones K Cuatro SpA
\n
and Enel X AMPCI Ebus Chile SpA;
\n
- the sale of 50% of the stakes held in EGPNA Renew-
\n
able Energy Partners and in Rocky Caney Holding
\n
(which, following the transaction, go from 20% to
\n
10%);
\n
\u2022 the profits attributable to the Group of equity-account-
\n
ed companies (\u20ac4 million), mainly accounted for by the
\n
profit contributed by Rusenergosbyt, PowerCrop and
\n
Spanish companies;
\n
\u2022 changes in the OCI reserves mainly relating to Slovak
\n
Power Holding, following the positive developments in
\n
the fair value of cash flow hedge derivatives, and the
\n
Spanish companies.
\n
These positive effects were mainly offset by:
\n
\u2022 dividends distributed in the period in the amount of \u20ac57
\n
million, mainly by Rusenergosbyt and certain Spanish
\n
companies;
\n

\n\n
\u2022 the reclassification of the investment in Tecnatom (\u20ac27
\n
million) as held for sale.
\n
The following tables provide a summary of financial infor-
\n
mation for the main joint ventures and associates of the
\n
Group not classified as held for sale in accordance with
\n
IFRS 5.
\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2022 2021 2022 2021 2022 2021
\n
Joint ventures
\n
Slovak Power Holding 5,184 3,417 (320) 190 (223) 137
\n
Gridspertise Srl 334 - 12 - 8 -
\n
Rusenergosbyt 2,919 2,288 170 112 137 90
\n
Matimba project
\n
companies
\n
34 - (22) - (15) -
\n
Mooney Group SpA 224 - (33) - (33) -
\n
Ewiva Srl - - (4) - (4) -
\n
Associates
\n
CESI 155 140 (4) (7) (1) (8)
\n
Elecgas SA 26 25 20 15 14 11
\n

\n\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Joint ventures
\n
Slovak Power Holding 12,376 12,194 1,444 1,854 13,820 14,048 4,950 6,762 6,620 5,369 11,570 12,131 2,250 1,917
\n
Gridspertise Srl 94 - 192 - 286 - 9 - 198 - 207 - 79 -
\n
Rusenergosbyt 3 3 285 141 288 144 - - 165 120 165 120 123 24
\n
Matimba project
\n
companies
\n
114 - - - 114 - - - - - - - 114 -
\n
Mooney Group SpA 880 - 449 - 1,329 - 1,086 - 575 - 1,661 - (332) -
\n
Ewiva Srl 40 44 - - 40 44 - - - - - - 40 44
\n
Associates
\n
CESI 191 198 25 28 216 226 24 25 90 - 114 25 102 201
\n
Elecgas SA 332 370 222 188 554 558 327 408 167 120 494 528 60 30
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInAssociatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1009": { "value": "\n
17. Income taxes \u2013 \u20ac3,523 million
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Change
\n
Current taxes 3,025 2,007 1,018 50.7%
\n
Adjustments for income taxes relating to prior years (233) 145 (378) -
\n
Total current taxes 2,792 2,152 640 29.7%
\n
Deferred tax expense 342 304 38 12.5%
\n
Deferred tax income 389 (836) 1,225 -
\n
TOTAL 3,523 1,620 1,903 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
The tax rate for 2022 came to 40%, compared with 30% in
\n
2021. The increase essentially reflects the following factors:
\n
\u2022 the change in the tax impact of impairment losses and
\n
gains and losses on mergers and acquisitions in the pe-
\n
riod compared with the previous year;
\n
\u2022 higher costs incurred in Italy for the extraordinary tax fund-
\n
ing program to shield users from higher energy costs envis-
\n
aged under Law 51/2022 (about \u20ac121 million) and the soli-
\n
darity tax provided for by Law 197/2022 (about \u20ac599 million);
\n
\u2022 the effect of foreign tax rates exceeding the theoretical
\n
Italian rate;
\n
\u2022 a decrease in the tax credit to eliminate dual taxation of
\n
dividends at Enel Iberia (\u20ac60 million);
\n
\u2022 the tax effect of the application of hyperinflation ac-
\n
counting in Argentina (\u20ac30 million).
\n
These adverse factors were partly offset by:
\n
\u2022 the tax impact of the disposal of the interest in Ufinet, Grid-
\n
spertise and Mooney (\u20ac190 million);
\n
\u2022 the tax impact of the regime di Patent Box in Italy (\u20ac65 mil-
\n
lion);
\n
\u2022 deferred tax assets recognized on the carve-out of Enel
\n
X Way in North America (\u20ac60 million).
\n
For more information on changes in deferred tax assets
\n
and liabilities, see note 25.
\n
The following table provides a reconciliation of the theo-
\n
retical tax rate and the effective tax rate.
\n
Millions of euro
\n
2022 2021
\n
(1)
\n
Pre-tax profit 8,741 5,378
\n
Theoretical taxes 2,098 24% 1,291 24%
\n
Change in tax effect on impairment losses, capital gains and negative goodwill 399 (229)
\n
Net effect on deferred taxation recognized with timing mismatch - 70
\n
Tax reforms in Argentina and Colombia - 166
\n
Adjustment of tax credit of Enel Iberia - 211
\n
Preferential tax treatment of Open Fiber capital gain - (401)
\n
Preferential tax treatment of Ufinet, Gridspertise and Mooney capital gain (190) -
\n
Deferred tax assets recognized on the carve-out of Enel X Way (60) -
\n
Patent Box in Italy (65) -
\n
Deferred tax assets not recognized on tax losses - 75
\n
Sundry tax effects of hyperinflation accounting in Argentina 30 49
\n
Tax effect for non-deductible Matimba capital loss 20 -
\n
Reversal of tax credit for Astrid operation - 25
\n
Tax effect of provisions for non-deductible risks in Spain 30 -
\n
IRAP 260 276
\n
Extraordinary energy cost tax 121 -
\n
Solidarity tax 599 -
\n
Other differences, effect of different tax rates abroad compared with the
\n
theoretical rate in Italy, and other minor items
\n
281 81
\n
Effect of restatement of comparative figures of discontinued operations - 6
\n
Tot al 3,523 1,620
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1013": { "value": "\n

\n
18. Basic and diluted earnings per share
\n\n
Both of these indicators are calculated on the basis of the
\n
average number of ordinary shares for the year, equal to
\n
10,166,679,946, adjusted by the average number of trea-
\n
sury shares held.
\n

\n\n
The number of treasury shares, with a par value of \u20ac1
\n
each, held at December 31, 2022 was equal to 7,153,795
\n
(4,889,152 at December 31, 2021).
\n
Millions of euro
\n
2022 2021
\n
Profit for the year attributable to owners of the Parent (basic) 1,682 3,189
\n
of which from:
\n
- continuing operations 3,637 3,097
\n
- discontinued operations (1,955) 92
\n
Effect of preference rights on dividends (e.g., preference shares) - -
\n
Dividends on equity instruments (e.g., hybrid bonds) (123) (71)
\n
Other --
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 1,559 3,118
\n
of which from:
\n
- continuing operations 3,514 3,026
\n
- discontinued operations (1,955) 92
\n
Number of shares (units)
\n
Number of ordinary shares issued at 1 January 10,166,679,946 10,166,679,946
\n
Effect of treasury shares held (6,287,027) (4,111,452)
\n
Effect of share options exercised 145,119 -
\n
Other --
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 1,559 3,118
\n
Effect of dilution:
\n
- interest on convertible bonds --
\n
- other --
\n
Profit for the year attributable to ordinary owners of the Parent (diluted) 1,559 3,118
\n
of which:
\n
- continuing operations 3,514 3,026
\n
- discontinued operations (1,955) 92
\n
Number of shares (units)
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Effect of conversion of convertible notes - -
\n
Other --
\n
Weighted average number of ordinary shares outstanding (total) for diluted
\n
earnings per share
\n
10,160,538,038 10,162,568,494
\n
Basic earnings per share
\n
Basic earnings per share 0.15 0.31
\n
Basic earnings per share from continuing operations 0.35 0.30
\n
Basic earnings per share from discontinued operations (0.20) 0.01
\n
Diluted earnings per share
\n
Diluted earnings per share 0.15 0.31
\n
Diluted earnings per share from continuing operations 0.35 0.30
\n
Diluted earnings per share from discontinued operations (0.20) 0.01
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1012": { "value": "\n
Both of these indicators are calculated on the basis of the
\n
average number of ordinary shares for the year, equal to
\n
10,166,679,946, adjusted by the average number of trea-
\n
sury shares held.
\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEarningsPerShareExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1016": { "value": "\n
19. Property, plant and equipment \u2013 \u20ac88,521 million
\n
The breakdown of and changes in property, plant and
\n
equipment for 2022 is given below.
\n
Millions of euro Land Buildings
\n
Plant and
\n
machinery
\n
Industrial and
\n
commercial
\n
equipment
\n
Other
\n
assets
\n
Leased
\n
assets
\n
Leasehold
\n
improvements
\n
Assets under
\n
construction
\n
and advances Tot al
\n
Cost net of accumulated
\n
impairment losses
\n
643 11,115 163,443 547 1,551 3,722 482 11,819 193,322
\n
Accumulated depreciation - 5,650 100,069 396 1,188 1,093 354 - 108,750
\n
Balance at Dec. 31, 2021 643 5,465 63,374 151 363 2,629 128 11,819 84,572
\n
Capital expenditure 3 43 2,125 32 115 - 7 8,905 11,230
\n
Assets entering service 27 804 5,078 7 22 27 49 (6,014) -
\n
Exchange differences (2) 163 322 1 (20) 86 1 133 684
\n
Change in the
\n
consolidation scope
\n
4 46 700 - 2 (9) - (122) 621
\n
Disposals (1) (12) (89) (1) (8) (96) - (63) (270)
\n
Depreciation - (215) (3,893) (24) (90) (336) (43) - (4,601)
\n
Impairment losses 1 - (153) - (1) - - (49) (202)
\n
Impairment gains (1) - 47 - - - - - 46
\n
Other changes 1 23 714 2 38 552 (3) 345 1,672
\n
Reclassifications from/to
\n
assets held for sale
\n
(46) (430) (3,540) (5) (129) (91) - (990) (5,231)
\n
Total changes (14) 422 1,311 12 (71) 133 11 2,145 3,949
\n
Cost net of accumulated
\n
impairment losses
\n
629 11,606 165,370 572 1,439 4,021 547 13,964 198,148
\n
Accumulated depreciation - 5,719 100,685 409 1,147 1,259 408 - 109,627
\n
Balance at Dec. 31, 2022 629 5,887 64,685 163 292 2,762 139 13,964 88,521
\n
Plant and machinery included assets to be relinquished free
\n
of charge with a carrying amount of \u20ac8,409 million (\u20ac7,946
\n
million at December 31, 2021), largely regarding power plants
\n
in Iberia and Latin America amounting to \u20ac3,456 million
\n
(\u20ac3,672 million at December 31, 2021), and the electricity dis-
\n
tribution grid in Latin America totaling \u20ac4,228 million (\u20ac3,506
\n
million at December 31, 2021).
\n
For more information on \u201cLeased assets\u201d, please see note 21
\n
below.
\n
The types of capital expenditure made during 2022 are sum-
\n
marized below by class of asset. These expenditures, totaling
\n
\u20ac13,329 million, increased by \u20ac1,128 million on 2021, increas-
\n
es that were particularly concentrated in solar power plants.
\n
Millions of euro
\n
2022 2021 Change
\n
Power plants:
\n
- thermal 661 550 111 20.2%
\n
- hydroelectric 435 402 33 8.2%
\n
- geothermal 121 120 1 0.8%
\n
- nuclear 134 157 (23) -14.6%
\n
- alternative energy sources 5,189 4,947 242 4.9%
\n
Total power plants 6,540 6,176 364 5.9%
\n
Electricity distribution grids
\n
(1)
\n
4,483 4,389 94 2.1%
\n
Enel X (e-City, e-Industries, e-Home) 373 285 88 30.9%
\n
Enel X Way (e-Mobility) 113 82 31 37.8%
\n
Retail customers 721 643 78 12.1%
\n
Other 1,099 626 473 75.6%
\n
TOTAL
\n
(2)
\n
13,329 12,201 1,128 9.2%
\n
(1) The figure for 2022 does not include \u20ac1,174 million in respect of infrastructure investments within the scope of IFRIC 12 (\u20ac907 million in 2021).
\n
(2) The figure for 2022 includes \u20ac156 million regarding units classified as held for sale (\u20ac111 million in 2021).
\n
\n\n
The Enel Group, in line with the Paris Agreement on CO
\n
2
\n
emissions reductions and guided by energy efficiency and
\n
energy transition objectives, has invested above all in gen-
\n
eration plants that exploit alternative energy sources. Cap-
\n
ital expenditure on generation plants mainly regard solar
\n
plants in the United States, Italy, Spain, Colombia, Peru,
\n
Chile, Brazil, South Africa and Australia.
\n
In order to respond to ever more variable climate develop-
\n
ments and, therefore, enhance the resilience of grids, the
\n
Group continued to invest in the distribution business line
\n
(\u20ac4,483 million). The \u20ac94 million increase is mainly attribut-
\n
able to greater investments in Italy, Brazil and Peru, mainly
\n
for corrective maintenance and grid reliability.
\n
Capital expenditure of Enel X increased mainly in Italy, in
\n
the e-City and e-Home businesses, in North America and
\n
Australia, reflecting higher industrial capex of the Battery
\n
Energy Storage business for the implementation of new
\n
projects, in Brazil due to higher expenditure in the Smart
\n
Lighting, e-Home and Distributed Energy businesses
\n
(launch of new PV-Photovoltaic projects), in Peru in the
\n
Public Lighting business, in Colombia with the launch of
\n
new projects in the Distributed Energy business (PV-Pho-
\n
tovoltaic) and in Spain, in the e-Home business.
\n
The growth of capital expenditure of Enel X Way refers to
\n
deployment of new charging points for electric mobility
\n
mainly in Spain.
\n
The change in \u201cOther\u201d mainly includes investments in the
\n
period in Battery Energy Storage Systems (BESS) in Italy
\n
and North America.
\n
Exchange gains amounted to \u20ac684 million.
\n
The \u201cChange in the consolidation scope\u201d in 2022 mainly
\n
refers to the acquisition of ERG Hydro Srl (now merged in
\n
Enel Produzione) in Italy and the sale of Thar Surya 1 Private
\n
Limited in India.
\n
\u201cImpairment losses\u201d amounted to \u20ac202 million and are
\n
mainly attributable to the value adjustment of the Spanish
\n
generation plants of Baleares, Canarias, Ceuta Melilla and
\n
Terminal Portuario de Los Barrios, and in Colombia to So-
\n
ciedad Portuaria Central Cartagena SA, controlled by Enel
\n
Colombia, which will terminate commercial operations
\n
from November 2023. For that reason, at December 31,
\n
2022, the carrying amount of \u201cPlant and machinery\u201d was
\n
written down.
\n
This item was also affected by impairment losses on Enel
\n
Produzione\u2019s assets of coal-fired power plants in Torreval-
\n
daliga Nord, Fusina and Brindisi Sud.
\n
\u201cReclassifications from/to assets held for sale\u201d refer mainly
\n
to all the assets of the Romanian, Greek companies and of
\n
Enel Russia, which was sold during the 4th Quarter of 2022.
\n
It also refers to the reclassification to assets held for sale
\n
of Enel Generaci\u00f3n Costanera SA and Central Dock Sud SA
\n
in Argentina, 3SUN Srl in Italy, Avikiran Solar India Private
\n
Limited in India and Bungala in Australia.
\n
\u201cOther changes\u201d include the provision for plant retiring and
\n
site restoration costs in the amount of a negative \u20ac302
\n
million, mainly in Spain and North America, new leases of
\n
\u20ac585 million, impairment losses on the property, plant and
\n
equipment of the Argentine companies operating in a hy-
\n
perinflationary economy in the amount of \u20ac1,081 million
\n
and the effect of capitalizing interest on loans specifical-
\n
ly dedicated to capital expenditure on property, plant and
\n
equipment of \u20ac260 million (\u20ac182 million in 2021) breaking
\n
down as follows.
\n
Millions of euro
\n
2022 Rate % 2021 Rate % Change
\n
EGP North America 83 0.5% 17 0.2% 66 -
\n
EGP M\u00e9xico 14 7.0% 10 4.3% 4 40.0%
\n
EGP South Africa 22 6.3% 61 6.3% (39) -63.9%
\n
Enel Am\u00e9ricas Group 50 3.2% 23 3.7% 27 -
\n
Enel Chile Group 91 6.1% 80 7.0% 11 13.8%
\n
Endesa Group 5 1.4% 4 1.5% 1 25.0%
\n
Enel Russia Group - 18 8.5% (18) -
\n
EGP India Group 7 9.9% 8 8.3% (1) -12.5%
\n
EGP Australia Group - 1 0.2% (1) -
\n
Enel Produzione 1 2.1% 2 2.1% (1) -50.0%
\n
C&C Uno Energy Srl 1 3.1% - 1 -
\n
Nuove Energie 21.6% 10.5% 1 -
\n
Enel Green Power Italia 6 3.6% 5 3.3% 1 20.0%
\n
Enel Finance International - 12 1.8% (12) -
\n
Total
\n
(1)
\n
282 242 40 16.5%
\n
(1) The total for 2022 also includes \u20ac22 million pertaining to assets held for sale (the total for 2021 includes -\u20ac5 million in capitalized financial expense in respect
\n
of intangible assets, \u20ac4 million in other non-current assets and \u20ac61 million pertaining to assets held for sale).
\n
\n\n
At December 31, 2022, contractual commitments to pur-
\n
chase property, plant and equipment amounted to \u20ac2,926
\n
million.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag982": { "value": "\n
20. Infrastructure within the scope of \u201cIFRIC 12 - Service concession arrangements\u201d
\n
Service concession arrangements, which are recognized
\n
in accordance with IFRIC 12, regard certain infrastructure
\n
serving concessions for electricity distribution in Brazil and
\n
Costa Rica.
\n
The following table summarizes the salient details of those
\n
concessions.
\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
Amount
\n
recognized
\n
among
\n
contract
\n
assets at
\n
Dec. 31,
\n
2022
\n
Amount
\n
recognized
\n
among
\n
financial
\n
assets at
\n
Dec. 31,
\n
2022
\n
Amount
\n
recognized
\n
among
\n
intangible
\n
assets at
\n
Dec. 31,
\n
2022
\n
Enel Distribui\u00e7\u00e3o
\n
Rio de Janeiro
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1996-2026 4 years Yes 116 1,138 453
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 6 years Yes 86 876 459
\n
Enel Green
\n
Power Mour\u00e3o
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 24 years No - 5 -
\n
Enel Green
\n
Power
\n
Paranapanema
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 24 years No - 26 -
\n
Enel Green
\n
Power Volta
\n
Grande
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2017-2047 25 years No - 276 -
\n
Enel Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 6 years Yes 290 1,318 544
\n
PH Chucas
\n
Costa Rican
\n
Electricity
\n
Institute
\n
Hydroelectric
\n
plant
\n
Costa
\n
Rica
\n
2012-2031 9 years No - 103 44
\n
Total 492 3,742 1,500
\n
The assets classified under financial assets are measured
\n
at fair value at the end of the concessions. For more infor-
\n
mation, see note 52 \u201cAssets and liabilities measured at fair
\n
value\u201d.
\n

\n\n
The following table reports service concession arrange-
\n
ments that do not fall within the scope of IFRIC 12 and had
\n
a balance as at December 31, 2022.
\n

\n\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2022
\n
Initial fair
\n
value
\n
Endesa Distribuci\u00f3n
\n
El\u00e9ctrica
\n
-
\n
Electricity
\n
distribution
\n
Spain Indefinite Indefinite - 5,678 5,673
\n
Enel Colombia (formerly
\n
Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,047 1,839
\n
Enel Distribuci\u00f3n Chile
\n
(formerly Chilectra)
\n
Republic of
\n
Chile
\n
Electricity
\n
distribution
\n
Chile Indefinite Indefinite - 1,331 1,667
\n
Enel Distribuci\u00f3n Per\u00fa
\n
(formerly Empresa de
\n
Distribuci\u00f3n El\u00e9ctrica de
\n
Lima Norte)
\n
Republic of
\n
Peru
\n
Electricity
\n
distribution
\n
Peru Indefinite Indefinite - 584 548
\n
Assets with an indefinite useful life amounted to \u20ac8,640
\n
million (\u20ac8,633 million at December 31, 2021) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,678 million), Colombia (\u20ac1,047 million), Chile
\n
(\u20ac1,331 million) and Peru (\u20ac584 million), for which there
\n
was no statutory or currently predictable expiration date.
\n
On the basis of the forecasts developed, cash flows for
\n
each CGU, with which the various concessions are asso-
\n
ciated, were sufficient to recover the carrying amount.
\n
The change during the year was essentially attributable to
\n
changes in exchange rates. For more information on ser-
\n
vice concession arrangements, see note 20.
\n

\n\n
Millions of euro Non-current Current
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Contract assets 508 530 106 121
\n
Contract liabilities 5,747 6,214 1,775 1,433
\n

\n\n
Non-current assets deriving from contracts with custom-
\n
ers (contract assets) refer mainly to assets under develop-
\n
ment resulting from public-to-private service concession
\n
arrangements recognized in accordance with IFRIC 12 and
\n
which have an expiration of beyond 12 months (\u20ac492 mil-
\n
lion). These cases arise when the concession holder has
\n
not yet obtained full right to recognize the asset from the
\n
grantor, in that there remains a contractual obligation to
\n
ensure that the asset is completed and can be remuner-
\n
ated through rates. The figure at December 31, 2022 in-
\n
cludes investments for the year in the amount of \u20ac1,174
\n
million.
\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Equity investments in other companies measured at fair value 366 72 294 -
\n
Financial assets and securities included in net financial debt (see note 29.1) 4,213 2,692 1,521 56.5%
\n
Service concession arrangements 3,732 2,890 842 29.1%
\n
Non-current financial prepayments 48 50 (2) -4.0%
\n
Tot al 8,359 5,704 2,655 46.5%
\n
\n\n
\u201cOther non-current financial assets\u201d increased by \u20ac2,655
\n
million mainly reflecting:
\n
\u2022 the increase in financial assets included in net financial
\n
debt, as detailed in note 29.1;
\n
\u2022 the increase in financial assets in respect of service con-
\n
cession arrangements, mainly in Brazil;
\n
\u2022 the recognition of the investment in Zacapa Topco, fol-
\n
lowing the sale by Enel X International of a 1.1% share
\n
in Ufinet which resulted in the loss of joint control over
\n
Zacapa Topco.
\n

\n

\n\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Cash and cash equivalents - - 35 10,169 8,759
\n
Trade receivables 34 1,388 1,301 34 15,217 14,775
\n
Current portion of long-term loan assets - - 30.1 2,838 1,538
\n
Cash collateral - - 30.1 8,319 6,485
\n
Other financial assets 29.1 3,766 2,289 30.1 2,090 315
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 295 260 29 12 64
\n
Other financial assets at amortized cost 282 242 1,412 2,735
\n
Tot al 5,731 4,092 40,057 34,671
\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2022
\n
Equity investments in other
\n
companies at FVOCI
\n
29 360 14 43 303 - - - -
\n
Securities at FVOCI 29.1, 30.1 447 447 - - 78 78 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
94 - 94 - 201 - 201 -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 7--7 ----
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 3,436 - 3,436 - - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
8--8 176176--
\n
Other cash investments at
\n
FVTPL
\n
---- 87242-830
\n
Non-monetary grants in
\n
respect of environmental
\n
certificates
\n
16--16 ----
\n
Fair value hedge derivatives:
\n
- on interest rates 51 22 - 22 - - - - -
\n
- on exchange rates 51 15 - 15 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 336 - 336 - - - - -
\n
- on exchange rates 51 1,854 - 1,854 - 389 - 389 -
\n
- on commodities 51 1,270 314 300 656 2,366 496 1,597 273
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 74 - 74 -
\n
- on commodities 51 472 109 362 1 12,001 10,640 1,360 1
\n
Inventories measured at fair
\n
value
\n
51 15 15 - - 18 - 18 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n
\u201cFinancial assets from service concession arrangements
\n
at FVTPL\u201d concern electricity distribution operations in
\n
Brazil, mainly by Enel Distribui\u00e7\u00e3o Rio de Janeiro, Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1, and Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, as well as
\n
the generation plant of PH Chucas in Costa Rica, and are
\n
accounted for in accordance with IFRIC 12.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfServiceConcessionArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag981": { "value": "\n
21. Leases
\n
The table below shows changes in right-of-use assets in
\n
2022.
\n
Millions of euro Leased land
\n
Leased
\n
buildings Leased plants
\n
Other leased
\n
assets To ta l
\n
Total at Dec. 31, 2021 1,147 517 441 524 2,629
\n
Increases 289 172 (1) 138 598
\n
Exchange differences 63 6 11 6 86
\n
Depreciation (48) (120) (36) (132) (336)
\n
Other changes (139) (62) 9 (23) (215)
\n
Total at Dec. 31, 2022 1,312 513 424 513 2,762
\n

\n\n
Lease liabilities and changes during the year are shown in
\n
the table below.
\n
Millions of euro
\n
Total at Dec. 31, 2021 2,547
\n
Increases 445
\n
Payments (310)
\n
Other changes (10)
\n
Total at Dec. 31, 2022 2,672
\n
of which medium to long term 2,409
\n
of which short term 263
\n
Millions of euro
\n
2022
\n
Depreciation of right-of-use assets 327
\n
Interest expense on lease liabilities 96
\n
Expense relating to short-term leases (included in costs for services and other materials) 59
\n
Expense relating to leases of low-value assets (included in costs for services and other materials) -
\n
Variable lease payments (included in costs for services and other materials) 32
\n
Tot al 514
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag983": { "value": "\n
22. Investment property \u2013 \u20ac94 million
\n
Millions of euro
\n
Cost net of accumulated impairment losses 129
\n
Accumulated depreciation 38
\n
Balance at Dec. 31, 2021 91
\n
Exchange differences 1
\n
Depreciation (2)
\n
Impairment losses -
\n
Other changes 4
\n
Total changes 3
\n
Cost net of accumulated impairment losses 116
\n
Accumulated depreciation 22
\n
Balance at Dec. 31, 2022 94
\n
Investment property at December 31, 2022 amounted to
\n
\u20ac94 million, an increase of \u20ac3 million on 2021.
\n
The Group\u2019s investment property consists of properties in
\n
Italy, Spain, Brazil and Chile, which are free of restrictions
\n
on their sale or the remittance of income and proceeds of
\n
disposal. In addition, the Group has no contractual obliga-
\n
tions to purchase, construct or develop investment prop-
\n
erty or for repairs, maintenance or enhancements.
\n
The change in 2021 was mainly due to impairment losses
\n
recognized on a number of assets in Spain and accumu-
\n
lated depreciation.
\n
For more information on the valuation of investment prop-
\n
erty, see notes 52 \u201cAssets and liabilities measured at fair
\n
value\u201d, and 52.2 \u201cAssets not measured at fair value in the
\n
statement of financial position\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentPropertyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag988": { "value": "\n

\n\n
23. Intangible assets \u2013 \u20ac17,520 million
\n
A breakdown of and changes in intangible assets for 2022
\n
are shown below.
\n
Millions of euro
\n
Development
\n
expenditure
\n
Industrial
\n
patents &
\n
intellectual
\n
property
\n
rights
\n
Concessions,
\n
licenses,
\n
trademarks
\n
and similar
\n
rights
\n
Service
\n
concession
\n
arrangements Other
\n
Leasehold
\n
improvements
\n
Assets under
\n
development
\n
and
\n
advances
\n
Contract
\n
costs To t a l
\n
Cost net of accumulated
\n
impairment losses
\n
43 3,512 12,842 5,781 5,092 - 1,760 2,063 31,093
\n
Accumulated amortization 23 2,771 1,721 3,683 3,708 - - 1,117 13,023
\n
Balance at Dec. 31, 2021 20 741 11,121 2,098 1,384 - 1,760 946 18,070
\n
Capital expenditure 49 82 151 - 131 - 784 746 1,943
\n
Assets entering service 19 263 14 - 396 - (694) 2 -
\n
Exchange differences - (7) 250 234 14 - (3) - 488
\n
Change in the
\n
consolidation scope
\n
-1171---2-174
\n
Disposals - (1) - (15) (1) - (50) - (67)
\n
Amortization (4) (326) (216) (381) (356) - - (375) (1,658)
\n
Impairment losses - - (1) - (6) - (6) - (13)
\n
Impairment gains - - - - - - - - -
\n
Other changes 3 (23) 10 481 44 - 42 11 568
\n
Reclassifications from/to
\n
assets held for sale
\n
(8) (67) (705) (917) (174) - (88) (26) (1,985)
\n
Total changes 59 (78) (326) (598) 48 - (13) 358 (550)
\n
Cost net of accumulated
\n
impairment losses
\n
101 3,697 12,646 5,261 5,279 - 1,747 2,831 31,562
\n
Accumulated amortization 22 3,034 1,851 3,761 3,847 - - 1,527 14,042
\n
Balance at Dec. 31, 2022 79 663 10,795 1,500 1,432 - 1,747 1,304 17,520
\n
Enel\u2019s intellectual property (IP) portfolio comprises a set of
\n
critical information for sustainable growth. The Open In-
\n
novability
\n
\u00ae
\n
ecosystem generates innovation through the
\n
creation and sharing of internal and external solutions that
\n
give life to a stream of inventions that are protected and
\n
monetized with the support of intellectual property pro-
\n
tection mechanisms.
\n
At December 31, 2022 the Group had applied for 883
\n
patents for industrial inventions, in 163 patent families; of
\n
these, 711 have been granted and 172 are pending. The
\n
portfolio ensures protection in all the markets in which the
\n
Group is present. Enel\u2019s portfolio also includes 23 utility
\n
models and 194 design registrations. Together with pat-
\n
ents, utility models and designs, IP rights also include in-
\n
dustrial secrets of both a technical and commercial nature
\n
which are constantly codified and maintained in line with
\n
the provisions of the Trade Secrets Management proce-
\n
dure. The Group also owns 2,027 trademarks, of which
\n
1,642 have already been registered with 385 applications
\n
pending.
\n
Enel has consolidated the processes for managing the
\n
generation and exploitation of intellectual property rights
\n
within the Intellectual Property Management and Trade Se-
\n
crets Management organizational procedures. Both pro-
\n
cedures look at human capital as an essential element in
\n
the creation of IP and seek to encourage employee partic-
\n
ipation in the inventive process, emphasizing the strategic
\n
importance of all inventions.
\n
During 2022, the activity of coding and protection of in-
\n
tellectual property continued in all global business lines.
\n
More specifically:
\n
\u2022 Enel X Global Retail focused its activity on strategic plat-
\n
forms, coding copyrights on the Big Data Platform, a
\n
container of strategic data for all Enel X and X Custom-
\n
er business units, and global management system for
\n
Enel X customers. With regard to the circular economy,
\n
Enel X has protected its circularity schemes under copy-
\n
right law together with the related scores and operating
\n
mechanisms. In the field of telemedicine, a multiple de-
\n
sign has been registered in the European Union for the
\n
graphic interfaces of the \u201cSmart Axistance eWell\u201d app,
\n
which offers users a complete wellness package.
\n
\u2022 Enel Green Power and Thermal Generation report the
\n
following developments for the year:
\n
\u2013 in the photovoltaic sector, (i) a patent application for
\n
an industrial invention and a design application for
\n
a solution that automates the process of installing
\n
photovoltaic panels in the field, reducing installation
\n
times and costs and increasing operator safety; (ii) a
\n
patent application jointly owned with the Commissar-
\n

\n\n

\n\n

\n\n

\n

\n

\n
iat \u00e0 l\u2019\u00c9nergie Atomique et aux \u00c9nergies Alternatives
\n
(CEA) concerning a system for optimizing the removal
\n
and automatic insertion of the wafer bar holder of the
\n
cassette used to process wafers in fume cupboards.
\n
Furthermore, the generation and protection of the
\n
technological know-how necessary for the Gigafac-
\n
tory project continues at the 3SUN factory, mainly in
\n
the form of trade secrets;
\n
\u2013 in hydroelectric generation, a patent application for a
\n
utility model for a robotic solution that facilitates plant
\n
control, allowing the inspection of difficult-to-access
\n
locations, such as hydroelectric spirals, distributor
\n
vanes or small-diameter hydroelectric pipelines.
\n
\u2022 Enel Grids filed two patent applications for inventions in
\n
2022: one in the field of asset recognition and anomaly
\n
detection for grids and grid events (Project ODIN) and
\n
the other in the field of safety devices for workers work-
\n
ing at height. We also note (i) the registration of a design
\n
for a new sustainable road cab, which will be implement-
\n
ed using recycled materials to reduce the environmental
\n
impact and (ii) the filing of a patent application for a utility
\n
model in the safety field, consisting of a method for the
\n
delimitation of road construction sites. Also during the
\n
year, Gridspertise consolidated its IP portfolio by filing a
\n
patent application relating to the Quantum Edge - Qed
\n
\u00ae
\n
device, which exploits edge computing to digitalize the
\n
physical components of secondary substations, reduc-
\n
es installation, training and operating and maintenance
\n
costs and increases network reliability.
\n
\u2022 Global e-Mobility has protected the JuiceBox DC and
\n
JuiceBox 4.0 smart home charging devices respectively
\n
using: (i) an international design registered in the Euro-
\n
pean Union, the United Kingdom and the United States
\n
and (ii) an international design registered in Canada,
\n
Mexico and the United States. Intellectual property pro-
\n
tection for electric vehicle charging stations has also
\n
been extended to the registration in the European Union
\n
and in the United States of the designs of the JuiceMedia
\n
2.0 and JuiceMod products.
\n
\u2022 Enel Global Services filed a patent application in Italy for
\n
an industrial invention on the innovation management
\n
method, also protected as the trademark ENEL OOPS\u2026!
\n
INNOVATION
\n
\u00ae
\n
. This method is based on the improvement
\n
of industrial processes using Open Innovability
\n
\u00ae
\n
tools.
\n
More generally, the Group continues to invest resourc-
\n
es in the development of solutions with a high IP density,
\n
which is mainly expressed in the forms of copyright pro-
\n
tection and trade secrets for databases and forecasting
\n
algorithms for the electricity and gas markets, advanced
\n
quantitative models that use scenario data to evaluate the
\n
impact of climate change on specific assets/production
\n
activities. In particular, this activity includes development
\n
models designed to: (i) characterize the ability of an as-
\n
set to \u201cresist\u201d the possible effects of climate change; (ii)
\n
quantify the probability that an event or a combination of
\n
climate events will damage a plant; and (iii) provide an index
\n
of \u201cweakness\u201d for the asset, including in distributed form,
\n
with a specific technical approach to prioritize actions/
\n
fields for improvement.
\n\n
The following table reports service concession arrange-
\n
ments that do not fall within the scope of IFRIC 12 and had
\n
a balance as at December 31, 2022.
\n

\n\n\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2022
\n
Initial fair
\n
value
\n
Endesa Distribuci\u00f3n
\n
El\u00e9ctrica
\n
-
\n
Electricity
\n
distribution
\n
Spain Indefinite Indefinite - 5,678 5,673
\n
Enel Colombia (formerly
\n
Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,047 1,839
\n
Enel Distribuci\u00f3n Chile
\n
(formerly Chilectra)
\n
Republic of
\n
Chile
\n
Electricity
\n
distribution
\n
Chile Indefinite Indefinite - 1,331 1,667
\n
Enel Distribuci\u00f3n Per\u00fa
\n
(formerly Empresa de
\n
Distribuci\u00f3n El\u00e9ctrica de
\n
Lima Norte)
\n
Republic of
\n
Peru
\n
Electricity
\n
distribution
\n
Peru Indefinite Indefinite - 584 548
\n
Assets with an indefinite useful life amounted to \u20ac8,640
\n
million (\u20ac8,633 million at December 31, 2021) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,678 million), Colombia (\u20ac1,047 million), Chile
\n
(\u20ac1,331 million) and Peru (\u20ac584 million), for which there
\n
was no statutory or currently predictable expiration date.
\n
On the basis of the forecasts developed, cash flows for
\n
each CGU, with which the various concessions are asso-
\n
ciated, were sufficient to recover the carrying amount.
\n
The change during the year was essentially attributable to
\n
changes in exchange rates. For more information on ser-
\n
vice concession arrangements, see note 20.
\n

\n\n

\n\n

\n\n

\n\n
The change in the consolidation scope for 2022 mainly re-
\n
flected the acquisition by Enel Produzione of ERG Hydro Srl
\n
(now merged in Enel Produzione) in Italy, with an increase
\n
in the value of hydroelectric concessions of \u20ac170 million.
\n
Impairment losses amounted to \u20ac13 million in 2022, and
\n
mainly regarded projects for assets under development
\n
that management has decided to abandon. For more in-
\n
formation, see note 12.e.
\n
\u201cOther changes\u201d mainly reported the design costs connect-
\n
ed with the acquisition of a number of Brazilian vehicle com-
\n
panies and impairment losses on intangible assets of Argen-
\n
tine companies operating in a hyperinflationary economy.
\n

\n\n

\n\n

\n\n
24. Goodwill \u2013 \u20ac13,742 million
\n
Millions of euro at Dec. 31, 2021
\n
Change
\n
in
\n
consol.
\n
scope
\n
Exchange
\n
differences
\n
Impairment
\n
losses
\n
Offsetting
\n
cost with
\n
accum.
\n
impairment
\n
losses
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes
\n
at Dec. 31, 2022
\n
Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount
\n
Iberian
\n
Peninsula
\n
11,177 (2,392) 8,785 - - - - - 11,177 (2,392) 8,785
\n
Chile 1,209 - 1,209 - 42 - - (61) (42) 1,148 - 1,148
\n
Argentina 275 (253) 22 - (1) - - - - 274 (253) 21
\n
Peru 566 - 566 - 4 - - - 1 571 - 571
\n
Colombia 527 - 527 - (9) - - - - 518 - 518
\n
Brazil 1,303 - 1,303 - 95 - - (85) - 1,313 - 1,313
\n
Central
\n
America
\n
25 - 25 - 2 - - - (1) 26 - 26
\n
Mexico 18 (18) - - - - - - - - - -
\n
Enel Green
\n
Power North
\n
America
\n
70 - 70 - - - - - - 70 - 70
\n
Enel X North
\n
America
\n
199-199-13-- -(70)142-142
\n
Enel X
\n
Way North
\n
America
\n
------- 7070-70
\n
Enel X Asia
\n
Pacific
\n
84 - 84 - - - - - - 84 - 84
\n
Enel X Rest
\n
of Europe
\n
(1)
\n
46 (3) 43 - - - - - - 43 - 43
\n
Enel X Italy - - - - - - - - - - - -
\n
Market Italy
\n
(2)
\n
580 - 580 1 - - - - - 581 - 581
\n
Enel Green
\n
Power Italy
\n
21 - 21 - - - - - - 21 - 21
\n
Enel
\n
Produzione
\n
Italy
\n
- - - 349 - - - - - 349 - 349
\n
Romania 400 (13) 387 17 1 - - (404) (1) - - -
\n
Total 16,500 (2,679) 13,821 367 147 - - (550) (43) 16,387 (2,645) 13,742
\n
(1) Includes Viva Labs.
\n
(2) Includes Enel Energia.
\n

\n\n

\n\n

\n\n
Goodwill matrix at Dec. 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other To ta l
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 581 - - 581
\n
Enel Produzione Italy - 349 - - - - 349
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 2 19 - - - 21
\n
Brazil - 478 835 - - - 1,313
\n
Chile - 996 152 - - - 1,148
\n
Colombia - 295 223 - - - 518
\n
Peru 44 207 320 - - - 571
\n
Central America - 26 - - - - 26
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----142-142
\n
Enel X Way North
\n
America
\n
-----7070
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,634 7,337 2,388 269 70 13,742
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n
Goodwill matrix at Dec. 31, 2021
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other Tot al
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 580 - - 580
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 3 19 - - - 22
\n
Brazil - 423 880 - - - 1,303
\n
Chile - 996 213 - - - 1,209
\n
Colombia - 304 223 - - - 527
\n
Peru 44 202 320 - - - 566
\n
Central America - 25 - - - - 25
\n
Romania - - 330 57 - - 387
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----199-199
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,234 7,773 2,444 326 - 13,821
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n

\n\n

\n\n

\n\n
The decrease of \u20ac79 million in goodwill was mainly attrib-
\n
utable to \u201creclassifications from/to assets classified as held
\n
for sale\u201d (-\u20ac550 million), regarding Romania (-\u20ac404 million)
\n
for classification as discontinued operations, Brazil (-\u20ac85
\n
million) and Chile (-\u20ac61 million) for reclassification as assets
\n
held for sale of Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s)
\n
and Enel Transmisi\u00f3n Chile, respectively (which were sold in
\n
2022). The negative effect was partially offset by the increase
\n
in the consolidation scope mainly reflecting the acquisition
\n
of Enel Hydro Appennino Centrale Srl (\u20ac349 million) and \u201cEx-
\n
change differences\u201d (a positive \u20ac147 million) mainly regarding
\n
Brazil, Chile and the United States.
\n
The criteria used to identify the cash generating units (CGUs)
\n
are based on revenue separation, which is considered the
\n
main criterion in view of the nature of our business, taking
\n
due account of the operational rules and regulations of the
\n
markets in which they operate and the corporate organi-
\n
zation. For the purposes of impairment testing of goodwill,
\n
the CGUs are grouped on the basis of expected synergies,
\n
consistent with management\u2019s strategic and operational vi-
\n
sion, within the operating segments identified for segment
\n
reporting purposes.
\n
Note also that in 2022 the existing CGUs underwent exten-
\n
sive analysis to assess the possible presence of significant
\n
changes pursuant to IAS 36, paragraph 72.
\n
This analysis led to the modification of the existing CGUs
\n
only for Enel X Way, a new global business established from
\n
the spin-off of electric mobility operations from Enel X.
\n
In particular, the new Enel X North America CGU was iden-
\n
tified.
\n
The recoverable amount of the goodwill recognized was es-
\n
timated by calculating the value in use of the CGUs or groups
\n
of CGUs using discounted cash flow models, which involve
\n
estimating expected future cash flows and applying an ap-
\n
propriate discount rate, selected on the basis of market in-
\n
puts such as risk-free rates, betas and market-risk premi-
\n
ums.
\n
Cash flows were determined on the basis of the best infor-
\n
mation available at the time of the estimate, taking account
\n
of the specific risks of individual CGU or groups of CGUs, and
\n
drawn:
\n
\u2022 for the explicit period, from the Business Plan approved
\n
by the Board of Directors of the Parent on November 21,
\n
2022, containing forecasts for volumes, revenue, operat-
\n
ing costs, capital expenditure, industrial and commercial
\n
organization and developments in the main macroeco-
\n
nomic variables (inflation, nominal interest rates and ex-
\n
change rates) and commodity prices. The explicit period
\n
of cash flows considered in impairment testing was three
\n
years;
\n
\u2022 for subsequent years, from assumptions concerning long-
\n
term developments in the main variables that determine
\n
cash flows, the average residual useful life of assets or the
\n
duration of the concessions.
\n
More specifically, the terminal value is calculated based on
\n
the specific characteristics of the businesses related to the
\n
various CGUs or groups of CGUs subject to impairment test-
\n
ing:
\n
\u2022 perpetuity, for the businesses of large-hydro (LH) power
\n
generation and of distribution, in which the licenses and
\n
public concessions are of a long-term nature and are eas-
\n
ily renewable; as well as for the Enel X and Enel X Way busi-
\n
nesses, as they feature the development of specific know-
\n
how that is sustainable over the long term;
\n
\u2022 annuity, for CGUs or groups of CGUs that are predomi-
\n
nantly characterized by retail business, for which the re-
\n
sidual life is, therefore, essentially correlated with the av-
\n
erage duration of the customer relationships; as well as
\n
for businesses of conventional thermal power generation
\n
(Generation and Trading). This method is also used for the
\n
renewable energy (Enel Green Power) businesses to take
\n
account of: (i) the value resulting from the remaining useful
\n
lives of the plants; and (ii) the residual value, in the event of
\n
plant decommissioning, associated with licensing rights,
\n
the competitiveness of the production facilities (in terms
\n
of natural resources), and network interconnectivity.
\n
The nominal growth rate (g-rate) is equal to the long-term
\n
rate of growth in electricity and/or inflation (depending on
\n
the country and business involved) and in any case no high-
\n
er than the average long-term growth rate of the reference
\n
market.
\n
The Group therefore confirmed its strategic direction based
\n
on the trends associated with the energy transition. The use
\n
of capital has been focused on:
\n
\u2022 decarbonization through the gradual development of
\n
generation assets that use renewable sources and the
\n
simultaneous exit from coal and gas-fired electricity pro-
\n
duction (by 2040);
\n
\u2022 electrification of energy consumption, with the incentive
\n
of new products and services for end users and the simul-
\n
taneous gradual exit from gas sales to end users (by 2040);
\n
\u2022 digitization and upgrading of distribution networks, to
\n
cope with the energy transition under way and guarantee
\n
quality of service to customers.
\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope 1 GHG
\n
emission
\n
intensity
\n
related
\n
to power
\n
generation
\n
Electricity
\n
generation
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n
(2)
\n
Short term
\n
(2025)
\n
130 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Gradual phase out of coal-fired capacity in
\n
2023-2025 (percentage weight of coal capacity
\n
out of total consolidated capacity reduced from
\n
about 7% in 2022 to below 0.5% in 2025).
\n
\u2022 Invest \u20ac15 billion to accelerate the development
\n
of renewable energy by installing 17 GW of new
\n
renewables capacity (13 GW of which at the
\n
consolidated level) and 4 GW in BESS in 2023-
\n
2025, reaching 75 GW of renewables capacity
\n
(including 4 GW of BESS) by 2025.
\n
Medium
\n
term (2030)
\n
72 gCO
\n
2eq
\n
/kWh
\n
(-80% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, implementing a Group-
\n
wide investment plan that will remain at the
\n
annual levels of the 2023-2025 plan, reaching
\n
a managed capacity of over 130 GW by 2030,
\n
thereby bringing total generation capacity to be
\n
made up of around 85% renewables.
\n
\u2022 Exit from coal-fired generation, which is
\n
expected to take place by 2027 globally.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n

\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Exit from the business of thermal electricity
\n
generation, achieving a 100% renewable energy
\n
mix.
\n
\u2022 No use of carbon-removal technologies.
\n
Scope 1
\n
and 3 GHG
\n
emission
\n
intensity
\n
related to
\n
integrated
\n
power
\n
Sale
\n
of electricity
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n

\n
73.4%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Short term
\n
(2025)
\n
135 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Increase the percentage of renewable energy
\n
sold to customers, while increasing Group\u2019s
\n
renewables production.
\n
\u2022 Increase the share of fixed-price energy
\n
sales covered by carbon-free sources in core
\n
countries from around 70% in 2022 to about
\n
90% by 2025, while increasing volumes of
\n
electricity sold at a fixed price from about 185
\n
TWh in 2022 to around 200 TWh by 2025.
\n
Medium
\n
term (2030)
\n
73 gCO
\n
2eq
\n
/kWh
\n
(-78% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Increase the share of renewable energy sold to
\n
customers by increasing the Group\u2019s renewables
\n
generation, reaching a managed capacity of
\n
over 130 GW by 2030, thereby bringing total
\n
generation capacity to be made up of around
\n
85% renewables.
\n
\u2022 Continue the strategy of balancing supply and
\n
demand and increase the share of electricity
\n
sold at a fixed price covered by carbon-free
\n
generation.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 By 2040, reach 100% of the energy sales
\n
covered by renewables.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope
\n
3 GHG
\n
emissions
\n
related
\n
to sale of
\n
natural gas
\n
on end-user
\n
market
\n
Sale of gas to
\n
end users
\n
100%
\n
of Scope 3 GHG
\n
emissions -
\n
category 11 (Use
\n
of sold products)
\n
Short term
\n
(2025)
\n
20.9 MtCO
\n
2eq
\n
n/a
\n
(4)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 20% by 2025.
\n
\u2022 Promote services to customers that enable
\n
electrification: increase in behind-the-meter
\n
storage capacity from around 99 MW in 2022 to
\n
about 352 MW by 2025; increase in the capacity
\n
of photovoltaic panels installed at end users
\n
from around 100 MW in 2022 to roughly 300
\n
MW by 2025; and increase in demand response
\n
capacity from around 8.4 GW in 2022 to about
\n
12.4 GW by 2025.
\n
\u2022 Reduce the volumes of gas sold to customers
\n
from around 10.2 bcm in 2022 to about 4.3 bcm
\n
by 2025.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), reducing
\n
customers of the retail gas business from
\n
around 6.5 million in 2022 to roughly 4.4 million
\n
by 2025.
\n
Medium
\n
term (2030)
\n
11.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 30% by 2030.
\n
\u2022 Continue with the short-term strategic actions,
\n
while continuing to promote services to
\n
customers that enable the electrification of
\n
consumption and reaching a demand response
\n
capacity of over 20 GW by 2030.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), continuing to
\n
reduce the volumes of gas sold to around 3 bcm
\n
by 2030.
\n
Long term
\n
(2040)
\n
0 MtCO
\n
2eq
\n

\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Aim to achieve sale of 100% renewable energy
\n
to end users by 2040.
\n
\u2022 Exit from the sale of gas to retail customers by
\n
2040.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n

\n\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Additional
\n
emissions
\n
Scopes
\n
1-2-3
\n
\u2022 Electricity
\n
distribution
\n
(Scopes 1
\n
and 2)
\n
\u2022 Management
\n
of vehicle fleet,
\n
buildings and
\n
other assets
\n
(Scopes 1
\n
and 2)
\n
\u2022 Supply chain
\n
management
\n
(Scope 3)
\n
\u2022 Purchasing of
\n
fuels (Scope 3)
\n
0.4%
\n
of Scope 1 GHG
\n
emissions
\n
100%
\n
of Scope 2 GHG
\n
emissions
\n
28.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 1
\n
(Purchase of
\n
goods and
\n
services) for the
\n
2030 target and
\n
43% for the 2040
\n
target
\n
(5)
\n
26.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Medium
\n
term (2030)
\n
10.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Invest a total of \u20ac15 billion in grids over the
\n
period 2023-2025, of which 11% to increase
\n
digitalization and 47% to improve grid resilience
\n
and quality, thereby helping to reduce grid
\n
losses and related greenhouse gas emissions.
\n
Replace existing distribution network
\n
infrastructure components with SF
\n
6
\n
-free
\n
solutions.
\n
\u2022 Electrify fleet and buildings by 2030.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Phase out coal-fired generation by 2027,
\n
mitigating all GHG emissions related to coal
\n
supply.
\n
Long term
\n
(2040)
\n
<2.5 MtCO
\n
2eq
\n

\n
(-90% compared
\n
to 2017 base
\n
year)
\n
Net-zero
\n
emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Promote grid digitalization and replace existing
\n
distribution network infrastructure components
\n
with SF
\n
6
\n
-free solutions.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Zero out emissions associated with gas
\n
extraction, as the Group will have completely
\n
exited both the gas-fired generation of
\n
electricity and the sale of gas to end users.
\n
(1) Percentages based on total GHG emissions in 2022.
\n
(2) Excludes marginal Scope 1 GHG emissions not directly related to the combustion of fossil fuels in electricity generation at thermal plants, which accounted
\n
for 1.4% of total Scope 1 emissions in 2022. In any event, GHG emissions covered by all of the above targets are equal, on the whole, to 98.7% of total Scope
\n
1 and 2 emissions in 2022, and therefore exceed the threshold of 95% required under the Science Based Target initiative.
\n
(3) The target is in line with the path to 1.5 \u00b0C set by the SBTi for the electrical services industry (Sectoral Decarbonization Approach, or SDA), although it could
\n
not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date.
\n
(4) The target could not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date. In
\n
addition, the SBTi has not defined a Sectoral Decarbonization Approach for these types of emissions, so the ambition level cannot be verified.
\n
(5) Two different percentage limits have been set for the target for Scope 3 GHG emissions by the supply chain, as allowed under the SBTi approach, which
\n
required coverage of at least 67% of Scope 3 emissions for the 2030 target, and at least 90% for the 2040 target.
\n
Total coverage of Scopes 1-2-3
\n
emissions in 2022
\n
\u2022 98.6% of Scope 1 GHG emissions (2025, 2030 and 2040 targets)
\n
\u2022 100% of Scope 2 GHG emissions (2030 and 2040 targets)
\n
\u2022 87% (2030 target) and 90% (2040 target) of Scope 3 GHG emissions
\n
(5)
\n

\n\n

\n\n

\n\n
Regarding the assumptions for commodity price develop-
\n
ments, the use of Paris reference scenarios is confirmed.
\n
More specifically, the price of CO
\n
2
\n
is assumed to rise rapidly
\n
through 2030, driven by the gradual reduction in the sup-
\n
ply of allowances in the face of growing demand, while coal
\n
prices are projected to stabilize due to falling demand. Gas
\n
price tensions are expected to ease in the coming years in
\n
light of a realignment between supply and demand at the
\n
global level. Finally, the price of oil is expected to stabilize,
\n
with peak demand coming around 2030.
\n
Note also that the Group has used sensitivity analyses to
\n
take account of the impacts of climate change in the long
\n
term. More specifically:
\n
\u2022 we consider a long-term growth rate in the estimation of
\n
the terminal value that is in line with the change in elec-
\n
tricity demand over the 2026-2050 period, based on the
\n
specific features of the businesses concerned, adopting
\n
certain assumptions concerning the increase in tempera-
\n
ture due to climate change and trends connected with
\n
the energy transition;
\n
\u2022 we consider changes in the hydroelectric, wind and pho-
\n
tovoltaic generation levels of our portfolio assets, asso-
\n
ciated with each projection of underlying climate and
\n
weather variables (for example, temperature, irradiance,
\n
wind speed and precipitation);
\n
\u2022 we assume that the Group will incur the costs provisioned
\n
for decommissioning fossil fuel generation plants in line
\n
with the goal of zero direct (Scope 1) and indirect emis-
\n
sions from retail activities (Scope 3).
\n
In order to verify the robustness of the value in use of the
\n
CGUs, sensitivity analyses were conducted for the main val-
\n
ue drivers, in particular WACC, the long-term growth rate.
\n
In these circumstances as well, the results were consistent
\n
with the evidence described above, finding that the value of
\n
all the CGUs analyzed exceeded the carrying amount, thus
\n
ensuring the full recoverability of their carrying amount in
\n
the consolidated financial statements of the Enel Group at
\n
December 31, 2022.
\n

\n\n

\n\n

\n\n
The table below reports the composition of the main
\n
goodwill values for the companies within each CGU, along
\n
with the discount rates applied and the time horizon over
\n
which the expected cash flows have been discounted.
\n
Millions of euro
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Iberian Peninsula 8,785 2.47% 6.10% 3 years
\n
Perpetuity/25
\n
years EGP/13
\n
years G&T
\n
8,785 1.64% 3.93% 3 years
\n
Perpetuity/25
\n
years EGP/14
\n
years G&T
\n
Chile 1,148 2.00% 8.45% 3 years
\n
Perpetuity/26
\n
years EGP/5
\n
years G&T
\n
1,209 2.02% 6.58% 3 years
\n
Perpetuity/25
\n
years EGP/6
\n
years G&T
\n
Argentina 21 45.70% 71.78% 3 years Perpetuity 22 24.11% 46.75% 3 years
\n
Perpetuity/8
\n
years G&T
\n
Peru 571 2.25% 8.75% 3 years
\n
Perpetuity/25
\n
years EGP/8
\n
years G&T
\n
566 2.31% 6.64% 3 years
\n
Perpetuity/23
\n
years EGP/9
\n
years G&T
\n
Colombia 518 3.20% 11.79% 3 years
\n
Perpetuity/26
\n
years EGP/15
\n
years G&T
\n
527 3.11% 8.82% 3 years
\n
Perpetuity/28
\n
years EGP/16
\n
years G&T
\n
Brazil 1,313 3.58% 11.22% 3 years
\n
Perpetuity/25
\n
years EGP
\n
1,303 3.30% 9.09% 3 years
\n
Perpetuity/26
\n
years EGP/7
\n
years G&T
\n
Central America 26 2.02% 9.66% 3 years 18 years 25 2.03% 7.85% 3 years 19 years
\n
Enel Green Power North
\n
America
\n
70 2.02% 6.48% 3 years 25 years 70 2.03% 5.01% 3 years 26 years
\n
Enel X North America 142 2.02% 9.71% 3 years Perpetuity 199 2.03% 7.62% 3 years Perpetuity
\n
Enel X Way North America 70 2.02% 11.53% 3 years Perpetuity n.a. n.a. n.a. n.a. n.a.
\n
Enel X Asia Pacific 84 2.02% 10.39% 3 years Perpetuity 84 2.03% 8.81% 3 years Perpetuity
\n
Enel X Rest of Europe 43 1.62% 8.82% 3 years Perpetuity 43 1.70% 8.24% 3 years Perpetuity
\n
Enel Green Power Italy 21 1.62% 6.39% 3 years
\n
Perpetuity/24
\n
years
\n
21 1.52% 4.94% 3 years
\n
Perpetuity/23
\n
years
\n
Market Italy 581 2.38% 10.88% 3 years 15 years 580 1.48% 9.14% 3 years 15 years
\n
Enel Produzione Italy 349 1.64% 7.70% 3 years
\n
Perpetuity/15
\n
years
\n
n.a. n.a. n.a. n.a. n.a.
\n
Romania n.a. n.a. n.a. n.a. n.a. 387 2.06% 7.56% 3 years
\n
Perpetuity/25
\n
years
\n
CGUs with no recognized
\n
goodwill but that underwent
\n
impairment testing given the
\n
presence of the indicators
\n
provided for in IAS 36
\n
Iberia - NPT (Non-Peninsular
\n
Territories)
\n
n.a. n.a. n.a. n.a. n.a. - - 3.42% 5 years 5 years
\n
Australia n.a. n.a. n.a. n.a. n.a. - 0.91% 5.50% 3 years 25 years
\n
Mexico n.a. n.a. n.a. n.a. n.a. - 3.36% 8.77% 3 years 24 years
\n
(1) Perpetual growth rate for cash flows after the explicit forecast period.
\n
(2) Pre-tax WACC calculated using the iterative method: the discount rate that ensures that the value in use calculated with pre-tax cash flows is equal to that
\n
calculated with post-tax cash flows discounted with the post-tax WACC.
\n
(3) The terminal value has been estimated on the basis of a perpetuity or an annuity with a rising yield for the years indicated in the column (G&T = Generation
\n
& Trading, EGP = Enel Green Power, LH = Large Hydro).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag989": { "value": "\n
23. Intangible assets \u2013 \u20ac17,520 million
\n
A breakdown of and changes in intangible assets for 2022
\n
are shown below.
\n
Millions of euro
\n
Development
\n
expenditure
\n
Industrial
\n
patents &
\n
intellectual
\n
property
\n
rights
\n
Concessions,
\n
licenses,
\n
trademarks
\n
and similar
\n
rights
\n
Service
\n
concession
\n
arrangements Other
\n
Leasehold
\n
improvements
\n
Assets under
\n
development
\n
and
\n
advances
\n
Contract
\n
costs To t a l
\n
Cost net of accumulated
\n
impairment losses
\n
43 3,512 12,842 5,781 5,092 - 1,760 2,063 31,093
\n
Accumulated amortization 23 2,771 1,721 3,683 3,708 - - 1,117 13,023
\n
Balance at Dec. 31, 2021 20 741 11,121 2,098 1,384 - 1,760 946 18,070
\n
Capital expenditure 49 82 151 - 131 - 784 746 1,943
\n
Assets entering service 19 263 14 - 396 - (694) 2 -
\n
Exchange differences - (7) 250 234 14 - (3) - 488
\n
Change in the
\n
consolidation scope
\n
-1171---2-174
\n
Disposals - (1) - (15) (1) - (50) - (67)
\n
Amortization (4) (326) (216) (381) (356) - - (375) (1,658)
\n
Impairment losses - - (1) - (6) - (6) - (13)
\n
Impairment gains - - - - - - - - -
\n
Other changes 3 (23) 10 481 44 - 42 11 568
\n
Reclassifications from/to
\n
assets held for sale
\n
(8) (67) (705) (917) (174) - (88) (26) (1,985)
\n
Total changes 59 (78) (326) (598) 48 - (13) 358 (550)
\n
Cost net of accumulated
\n
impairment losses
\n
101 3,697 12,646 5,261 5,279 - 1,747 2,831 31,562
\n
Accumulated amortization 22 3,034 1,851 3,761 3,847 - - 1,527 14,042
\n
Balance at Dec. 31, 2022 79 663 10,795 1,500 1,432 - 1,747 1,304 17,520
\n
Enel\u2019s intellectual property (IP) portfolio comprises a set of
\n
critical information for sustainable growth. The Open In-
\n
novability
\n
\u00ae
\n
ecosystem generates innovation through the
\n
creation and sharing of internal and external solutions that
\n
give life to a stream of inventions that are protected and
\n
monetized with the support of intellectual property pro-
\n
tection mechanisms.
\n
At December 31, 2022 the Group had applied for 883
\n
patents for industrial inventions, in 163 patent families; of
\n
these, 711 have been granted and 172 are pending. The
\n
portfolio ensures protection in all the markets in which the
\n
Group is present. Enel\u2019s portfolio also includes 23 utility
\n
models and 194 design registrations. Together with pat-
\n
ents, utility models and designs, IP rights also include in-
\n
dustrial secrets of both a technical and commercial nature
\n
which are constantly codified and maintained in line with
\n
the provisions of the Trade Secrets Management proce-
\n
dure. The Group also owns 2,027 trademarks, of which
\n
1,642 have already been registered with 385 applications
\n
pending.
\n
Enel has consolidated the processes for managing the
\n
generation and exploitation of intellectual property rights
\n
within the Intellectual Property Management and Trade Se-
\n
crets Management organizational procedures. Both pro-
\n
cedures look at human capital as an essential element in
\n
the creation of IP and seek to encourage employee partic-
\n
ipation in the inventive process, emphasizing the strategic
\n
importance of all inventions.
\n
During 2022, the activity of coding and protection of in-
\n
tellectual property continued in all global business lines.
\n
More specifically:
\n
\u2022 Enel X Global Retail focused its activity on strategic plat-
\n
forms, coding copyrights on the Big Data Platform, a
\n
container of strategic data for all Enel X and X Custom-
\n
er business units, and global management system for
\n
Enel X customers. With regard to the circular economy,
\n
Enel X has protected its circularity schemes under copy-
\n
right law together with the related scores and operating
\n
mechanisms. In the field of telemedicine, a multiple de-
\n
sign has been registered in the European Union for the
\n
graphic interfaces of the \u201cSmart Axistance eWell\u201d app,
\n
which offers users a complete wellness package.
\n
\u2022 Enel Green Power and Thermal Generation report the
\n
following developments for the year:
\n
\u2013 in the photovoltaic sector, (i) a patent application for
\n
an industrial invention and a design application for
\n
a solution that automates the process of installing
\n
photovoltaic panels in the field, reducing installation
\n
times and costs and increasing operator safety; (ii) a
\n
patent application jointly owned with the Commissar-
\n

\n\n

\n

\n

\n
iat \u00e0 l\u2019\u00c9nergie Atomique et aux \u00c9nergies Alternatives
\n
(CEA) concerning a system for optimizing the removal
\n
and automatic insertion of the wafer bar holder of the
\n
cassette used to process wafers in fume cupboards.
\n
Furthermore, the generation and protection of the
\n
technological know-how necessary for the Gigafac-
\n
tory project continues at the 3SUN factory, mainly in
\n
the form of trade secrets;
\n
\u2013 in hydroelectric generation, a patent application for a
\n
utility model for a robotic solution that facilitates plant
\n
control, allowing the inspection of difficult-to-access
\n
locations, such as hydroelectric spirals, distributor
\n
vanes or small-diameter hydroelectric pipelines.
\n
\u2022 Enel Grids filed two patent applications for inventions in
\n
2022: one in the field of asset recognition and anomaly
\n
detection for grids and grid events (Project ODIN) and
\n
the other in the field of safety devices for workers work-
\n
ing at height. We also note (i) the registration of a design
\n
for a new sustainable road cab, which will be implement-
\n
ed using recycled materials to reduce the environmental
\n
impact and (ii) the filing of a patent application for a utility
\n
model in the safety field, consisting of a method for the
\n
delimitation of road construction sites. Also during the
\n
year, Gridspertise consolidated its IP portfolio by filing a
\n
patent application relating to the Quantum Edge - Qed
\n
\u00ae
\n
device, which exploits edge computing to digitalize the
\n
physical components of secondary substations, reduc-
\n
es installation, training and operating and maintenance
\n
costs and increases network reliability.
\n
\u2022 Global e-Mobility has protected the JuiceBox DC and
\n
JuiceBox 4.0 smart home charging devices respectively
\n
using: (i) an international design registered in the Euro-
\n
pean Union, the United Kingdom and the United States
\n
and (ii) an international design registered in Canada,
\n
Mexico and the United States. Intellectual property pro-
\n
tection for electric vehicle charging stations has also
\n
been extended to the registration in the European Union
\n
and in the United States of the designs of the JuiceMedia
\n
2.0 and JuiceMod products.
\n
\u2022 Enel Global Services filed a patent application in Italy for
\n
an industrial invention on the innovation management
\n
method, also protected as the trademark ENEL OOPS\u2026!
\n
INNOVATION
\n
\u00ae
\n
. This method is based on the improvement
\n
of industrial processes using Open Innovability
\n
\u00ae
\n
tools.
\n
More generally, the Group continues to invest resourc-
\n
es in the development of solutions with a high IP density,
\n
which is mainly expressed in the forms of copyright pro-
\n
tection and trade secrets for databases and forecasting
\n
algorithms for the electricity and gas markets, advanced
\n
quantitative models that use scenario data to evaluate the
\n
impact of climate change on specific assets/production
\n
activities. In particular, this activity includes development
\n
models designed to: (i) characterize the ability of an as-
\n
set to \u201cresist\u201d the possible effects of climate change; (ii)
\n
quantify the probability that an event or a combination of
\n
climate events will damage a plant; and (iii) provide an index
\n
of \u201cweakness\u201d for the asset, including in distributed form,
\n
with a specific technical approach to prioritize actions/
\n
fields for improvement.
\n\n
The following table reports service concession arrange-
\n
ments that do not fall within the scope of IFRIC 12 and had
\n
a balance as at December 31, 2022.
\n

\n\n\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period
\n
remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2022
\n
Initial fair
\n
value
\n
Endesa Distribuci\u00f3n
\n
El\u00e9ctrica
\n
-
\n
Electricity
\n
distribution
\n
Spain Indefinite Indefinite - 5,678 5,673
\n
Enel Colombia (formerly
\n
Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,047 1,839
\n
Enel Distribuci\u00f3n Chile
\n
(formerly Chilectra)
\n
Republic of
\n
Chile
\n
Electricity
\n
distribution
\n
Chile Indefinite Indefinite - 1,331 1,667
\n
Enel Distribuci\u00f3n Per\u00fa
\n
(formerly Empresa de
\n
Distribuci\u00f3n El\u00e9ctrica de
\n
Lima Norte)
\n
Republic of
\n
Peru
\n
Electricity
\n
distribution
\n
Peru Indefinite Indefinite - 584 548
\n
Assets with an indefinite useful life amounted to \u20ac8,640
\n
million (\u20ac8,633 million at December 31, 2021) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,678 million), Colombia (\u20ac1,047 million), Chile
\n
(\u20ac1,331 million) and Peru (\u20ac584 million), for which there
\n
was no statutory or currently predictable expiration date.
\n
On the basis of the forecasts developed, cash flows for
\n
each CGU, with which the various concessions are asso-
\n
ciated, were sufficient to recover the carrying amount.
\n
The change during the year was essentially attributable to
\n
changes in exchange rates. For more information on ser-
\n
vice concession arrangements, see note 20.
\n

\n\n

\n\n
The change in the consolidation scope for 2022 mainly re-
\n
flected the acquisition by Enel Produzione of ERG Hydro Srl
\n
(now merged in Enel Produzione) in Italy, with an increase
\n
in the value of hydroelectric concessions of \u20ac170 million.
\n
Impairment losses amounted to \u20ac13 million in 2022, and
\n
mainly regarded projects for assets under development
\n
that management has decided to abandon. For more in-
\n
formation, see note 12.e.
\n
\u201cOther changes\u201d mainly reported the design costs connect-
\n
ed with the acquisition of a number of Brazilian vehicle com-
\n
panies and impairment losses on intangible assets of Argen-
\n
tine companies operating in a hyperinflationary economy.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag996": { "value": "\n
24. Goodwill \u2013 \u20ac13,742 million
\n
Millions of euro at Dec. 31, 2021
\n
Change
\n
in
\n
consol.
\n
scope
\n
Exchange
\n
differences
\n
Impairment
\n
losses
\n
Offsetting
\n
cost with
\n
accum.
\n
impairment
\n
losses
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes
\n
at Dec. 31, 2022
\n
Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount Cost
\n
Cumulative
\n
impairment
\n
Net
\n
carrying
\n
amount
\n
Iberian
\n
Peninsula
\n
11,177 (2,392) 8,785 - - - - - 11,177 (2,392) 8,785
\n
Chile 1,209 - 1,209 - 42 - - (61) (42) 1,148 - 1,148
\n
Argentina 275 (253) 22 - (1) - - - - 274 (253) 21
\n
Peru 566 - 566 - 4 - - - 1 571 - 571
\n
Colombia 527 - 527 - (9) - - - - 518 - 518
\n
Brazil 1,303 - 1,303 - 95 - - (85) - 1,313 - 1,313
\n
Central
\n
America
\n
25 - 25 - 2 - - - (1) 26 - 26
\n
Mexico 18 (18) - - - - - - - - - -
\n
Enel Green
\n
Power North
\n
America
\n
70 - 70 - - - - - - 70 - 70
\n
Enel X North
\n
America
\n
199-199-13-- -(70)142-142
\n
Enel X
\n
Way North
\n
America
\n
------- 7070-70
\n
Enel X Asia
\n
Pacific
\n
84 - 84 - - - - - - 84 - 84
\n
Enel X Rest
\n
of Europe
\n
(1)
\n
46 (3) 43 - - - - - - 43 - 43
\n
Enel X Italy - - - - - - - - - - - -
\n
Market Italy
\n
(2)
\n
580 - 580 1 - - - - - 581 - 581
\n
Enel Green
\n
Power Italy
\n
21 - 21 - - - - - - 21 - 21
\n
Enel
\n
Produzione
\n
Italy
\n
- - - 349 - - - - - 349 - 349
\n
Romania 400 (13) 387 17 1 - - (404) (1) - - -
\n
Total 16,500 (2,679) 13,821 367 147 - - (550) (43) 16,387 (2,645) 13,742
\n
(1) Includes Viva Labs.
\n
(2) Includes Enel Energia.
\n

\n\n
Goodwill matrix at Dec. 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other To ta l
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 581 - - 581
\n
Enel Produzione Italy - 349 - - - - 349
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 2 19 - - - 21
\n
Brazil - 478 835 - - - 1,313
\n
Chile - 996 152 - - - 1,148
\n
Colombia - 295 223 - - - 518
\n
Peru 44 207 320 - - - 571
\n
Central America - 26 - - - - 26
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----142-142
\n
Enel X Way North
\n
America
\n
-----7070
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,634 7,337 2,388 269 70 13,742
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n
Goodwill matrix at Dec. 31, 2021
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets Enel X
\n
Holding,
\n
Services and
\n
Other Tot al
\n
Enel Green Power Italy - 21 - - - - 21
\n
Market Italy
\n
(1)
\n
- - - 580 - - 580
\n
Iberian Peninsula - 1,190 5,788 1,807 - - 8,785
\n
Argentina - 3 19 - - - 22
\n
Brazil - 423 880 - - - 1,303
\n
Chile - 996 213 - - - 1,209
\n
Colombia - 304 223 - - - 527
\n
Peru 44 202 320 - - - 566
\n
Central America - 25 - - - - 25
\n
Romania - - 330 57 - - 387
\n
Enel Green Power
\n
North America
\n
-70----70
\n
Enel X North America ----199-199
\n
Enel X Asia Pacific ----84-84
\n
Enel X Rest of Europe
\n
(2)
\n
----43-43
\n
Total 44 3,234 7,773 2,444 326 - 13,821
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\n

\n\n
The decrease of \u20ac79 million in goodwill was mainly attrib-
\n
utable to \u201creclassifications from/to assets classified as held
\n
for sale\u201d (-\u20ac550 million), regarding Romania (-\u20ac404 million)
\n
for classification as discontinued operations, Brazil (-\u20ac85
\n
million) and Chile (-\u20ac61 million) for reclassification as assets
\n
held for sale of Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s)
\n
and Enel Transmisi\u00f3n Chile, respectively (which were sold in
\n
2022). The negative effect was partially offset by the increase
\n
in the consolidation scope mainly reflecting the acquisition
\n
of Enel Hydro Appennino Centrale Srl (\u20ac349 million) and \u201cEx-
\n
change differences\u201d (a positive \u20ac147 million) mainly regarding
\n
Brazil, Chile and the United States.
\n
The criteria used to identify the cash generating units (CGUs)
\n
are based on revenue separation, which is considered the
\n
main criterion in view of the nature of our business, taking
\n
due account of the operational rules and regulations of the
\n
markets in which they operate and the corporate organi-
\n
zation. For the purposes of impairment testing of goodwill,
\n
the CGUs are grouped on the basis of expected synergies,
\n
consistent with management\u2019s strategic and operational vi-
\n
sion, within the operating segments identified for segment
\n
reporting purposes.
\n
Note also that in 2022 the existing CGUs underwent exten-
\n
sive analysis to assess the possible presence of significant
\n
changes pursuant to IAS 36, paragraph 72.
\n
This analysis led to the modification of the existing CGUs
\n
only for Enel X Way, a new global business established from
\n
the spin-off of electric mobility operations from Enel X.
\n
In particular, the new Enel X North America CGU was iden-
\n
tified.
\n
The recoverable amount of the goodwill recognized was es-
\n
timated by calculating the value in use of the CGUs or groups
\n
of CGUs using discounted cash flow models, which involve
\n
estimating expected future cash flows and applying an ap-
\n
propriate discount rate, selected on the basis of market in-
\n
puts such as risk-free rates, betas and market-risk premi-
\n
ums.
\n
Cash flows were determined on the basis of the best infor-
\n
mation available at the time of the estimate, taking account
\n
of the specific risks of individual CGU or groups of CGUs, and
\n
drawn:
\n
\u2022 for the explicit period, from the Business Plan approved
\n
by the Board of Directors of the Parent on November 21,
\n
2022, containing forecasts for volumes, revenue, operat-
\n
ing costs, capital expenditure, industrial and commercial
\n
organization and developments in the main macroeco-
\n
nomic variables (inflation, nominal interest rates and ex-
\n
change rates) and commodity prices. The explicit period
\n
of cash flows considered in impairment testing was three
\n
years;
\n
\u2022 for subsequent years, from assumptions concerning long-
\n
term developments in the main variables that determine
\n
cash flows, the average residual useful life of assets or the
\n
duration of the concessions.
\n
More specifically, the terminal value is calculated based on
\n
the specific characteristics of the businesses related to the
\n
various CGUs or groups of CGUs subject to impairment test-
\n
ing:
\n
\u2022 perpetuity, for the businesses of large-hydro (LH) power
\n
generation and of distribution, in which the licenses and
\n
public concessions are of a long-term nature and are eas-
\n
ily renewable; as well as for the Enel X and Enel X Way busi-
\n
nesses, as they feature the development of specific know-
\n
how that is sustainable over the long term;
\n
\u2022 annuity, for CGUs or groups of CGUs that are predomi-
\n
nantly characterized by retail business, for which the re-
\n
sidual life is, therefore, essentially correlated with the av-
\n
erage duration of the customer relationships; as well as
\n
for businesses of conventional thermal power generation
\n
(Generation and Trading). This method is also used for the
\n
renewable energy (Enel Green Power) businesses to take
\n
account of: (i) the value resulting from the remaining useful
\n
lives of the plants; and (ii) the residual value, in the event of
\n
plant decommissioning, associated with licensing rights,
\n
the competitiveness of the production facilities (in terms
\n
of natural resources), and network interconnectivity.
\n
The nominal growth rate (g-rate) is equal to the long-term
\n
rate of growth in electricity and/or inflation (depending on
\n
the country and business involved) and in any case no high-
\n
er than the average long-term growth rate of the reference
\n
market.
\n
The Group therefore confirmed its strategic direction based
\n
on the trends associated with the energy transition. The use
\n
of capital has been focused on:
\n
\u2022 decarbonization through the gradual development of
\n
generation assets that use renewable sources and the
\n
simultaneous exit from coal and gas-fired electricity pro-
\n
duction (by 2040);
\n
\u2022 electrification of energy consumption, with the incentive
\n
of new products and services for end users and the simul-
\n
taneous gradual exit from gas sales to end users (by 2040);
\n
\u2022 digitization and upgrading of distribution networks, to
\n
cope with the energy transition under way and guarantee
\n
quality of service to customers.
\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope 1 GHG
\n
emission
\n
intensity
\n
related
\n
to power
\n
generation
\n
Electricity
\n
generation
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n
(2)
\n
Short term
\n
(2025)
\n
130 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Gradual phase out of coal-fired capacity in
\n
2023-2025 (percentage weight of coal capacity
\n
out of total consolidated capacity reduced from
\n
about 7% in 2022 to below 0.5% in 2025).
\n
\u2022 Invest \u20ac15 billion to accelerate the development
\n
of renewable energy by installing 17 GW of new
\n
renewables capacity (13 GW of which at the
\n
consolidated level) and 4 GW in BESS in 2023-
\n
2025, reaching 75 GW of renewables capacity
\n
(including 4 GW of BESS) by 2025.
\n
Medium
\n
term (2030)
\n
72 gCO
\n
2eq
\n
/kWh
\n
(-80% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, implementing a Group-
\n
wide investment plan that will remain at the
\n
annual levels of the 2023-2025 plan, reaching
\n
a managed capacity of over 130 GW by 2030,
\n
thereby bringing total generation capacity to be
\n
made up of around 85% renewables.
\n
\u2022 Exit from coal-fired generation, which is
\n
expected to take place by 2027 globally.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n

\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Exit from the business of thermal electricity
\n
generation, achieving a 100% renewable energy
\n
mix.
\n
\u2022 No use of carbon-removal technologies.
\n
Scope 1
\n
and 3 GHG
\n
emission
\n
intensity
\n
related to
\n
integrated
\n
power
\n
Sale
\n
of electricity
\n
98.2%
\n
of Scope 1 GHG
\n
emissions
\n

\n
73.4%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Short term
\n
(2025)
\n
135 gCO
\n
2eq
\n
/kWh 1.5 \u00b0C
\n
(3)
\n
\u2022 Increase the percentage of renewable energy
\n
sold to customers, while increasing Group\u2019s
\n
renewables production.
\n
\u2022 Increase the share of fixed-price energy
\n
sales covered by carbon-free sources in core
\n
countries from around 70% in 2022 to about
\n
90% by 2025, while increasing volumes of
\n
electricity sold at a fixed price from about 185
\n
TWh in 2022 to around 200 TWh by 2025.
\n
Medium
\n
term (2030)
\n
73 gCO
\n
2eq
\n
/kWh
\n
(-78% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Increase the share of renewable energy sold to
\n
customers by increasing the Group\u2019s renewables
\n
generation, reaching a managed capacity of
\n
over 130 GW by 2030, thereby bringing total
\n
generation capacity to be made up of around
\n
85% renewables.
\n
\u2022 Continue the strategy of balancing supply and
\n
demand and increase the share of electricity
\n
sold at a fixed price covered by carbon-free
\n
generation.
\n
Long term
\n
(2040)
\n
0 gCO
\n
2eq
\n
/kWh
\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 By 2040, reach 100% of the energy sales
\n
covered by renewables.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Scope
\n
3 GHG
\n
emissions
\n
related
\n
to sale of
\n
natural gas
\n
on end-user
\n
market
\n
Sale of gas to
\n
end users
\n
100%
\n
of Scope 3 GHG
\n
emissions -
\n
category 11 (Use
\n
of sold products)
\n
Short term
\n
(2025)
\n
20.9 MtCO
\n
2eq
\n
n/a
\n
(4)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 20% by 2025.
\n
\u2022 Promote services to customers that enable
\n
electrification: increase in behind-the-meter
\n
storage capacity from around 99 MW in 2022 to
\n
about 352 MW by 2025; increase in the capacity
\n
of photovoltaic panels installed at end users
\n
from around 100 MW in 2022 to roughly 300
\n
MW by 2025; and increase in demand response
\n
capacity from around 8.4 GW in 2022 to about
\n
12.4 GW by 2025.
\n
\u2022 Reduce the volumes of gas sold to customers
\n
from around 10.2 bcm in 2022 to about 4.3 bcm
\n
by 2025.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), reducing
\n
customers of the retail gas business from
\n
around 6.5 million in 2022 to roughly 4.4 million
\n
by 2025.
\n
Medium
\n
term (2030)
\n
11.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Encourage customers (especially residential
\n
customers) to switch from gas to electricity
\n
by promoting efficient electricity technologies
\n
(e.g., heat pumps for home heating or
\n
induction cooktops in kitchens), increasing the
\n
electrification rate of our customers in Italy and
\n
Spain from 17% in 2022 to over 30% by 2030.
\n
\u2022 Continue with the short-term strategic actions,
\n
while continuing to promote services to
\n
customers that enable the electrification of
\n
consumption and reaching a demand response
\n
capacity of over 20 GW by 2030.
\n
\u2022 Optimize the gas portfolio of customers
\n
(especially industrial customers), continuing to
\n
reduce the volumes of gas sold to around 3 bcm
\n
by 2030.
\n
Long term
\n
(2040)
\n
0 MtCO
\n
2eq
\n

\n
(-100%
\n
compared to
\n
2017 base year)
\n
Zero emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Aim to achieve sale of 100% renewable energy
\n
to end users by 2040.
\n
\u2022 Exit from the sale of gas to retail customers by
\n
2040.
\n
\u2022 No use of carbon-removal technologies.
\n

\n\n
GHG target
\n
Primary
\n
business activity
\n
Sources of
\n
covered GHG
\n
(GHG Protocol)
\n
(1)
\n
Time frame GHG target
\n
Climate
\n
scenario Primary drivers and actions
\n
Additional
\n
emissions
\n
Scopes
\n
1-2-3
\n
\u2022 Electricity
\n
distribution
\n
(Scopes 1
\n
and 2)
\n
\u2022 Management
\n
of vehicle fleet,
\n
buildings and
\n
other assets
\n
(Scopes 1
\n
and 2)
\n
\u2022 Supply chain
\n
management
\n
(Scope 3)
\n
\u2022 Purchasing of
\n
fuels (Scope 3)
\n
0.4%
\n
of Scope 1 GHG
\n
emissions
\n
100%
\n
of Scope 2 GHG
\n
emissions
\n
28.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 1
\n
(Purchase of
\n
goods and
\n
services) for the
\n
2030 target and
\n
43% for the 2040
\n
target
\n
(5)
\n
26.6%
\n
of Scope 3 GHG
\n
emissions -
\n
category 3 (Fuel
\n
and energy-
\n
related activities)
\n
Medium
\n
term (2030)
\n
10.4 MtCO
\n
2eq
\n

\n
(-55% compared
\n
to 2017 base
\n
year)
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Invest a total of \u20ac15 billion in grids over the
\n
period 2023-2025, of which 11% to increase
\n
digitalization and 47% to improve grid resilience
\n
and quality, thereby helping to reduce grid
\n
losses and related greenhouse gas emissions.
\n
Replace existing distribution network
\n
infrastructure components with SF
\n
6
\n
-free
\n
solutions.
\n
\u2022 Electrify fleet and buildings by 2030.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Phase out coal-fired generation by 2027,
\n
mitigating all GHG emissions related to coal
\n
supply.
\n
Long term
\n
(2040)
\n
<2.5 MtCO
\n
2eq
\n

\n
(-90% compared
\n
to 2017 base
\n
year)
\n
Net-zero
\n
emissions
\n
1.5 \u00baC
\n
(SBTi
\n
certified)
\n
\u2022 Promote grid digitalization and replace existing
\n
distribution network infrastructure components
\n
with SF
\n
6
\n
-free solutions.
\n
\u2022 Implement a circular procurement approach;
\n
increase the number of contracts that include
\n
the measurement of the carbon footprint of
\n
the products and services purchased by Enel,
\n
encouraging their reduction in a collaborative
\n
decarbonization process with our suppliers.
\n
Strengthen dialogue with raw material
\n
producers and other utilities to define shared
\n
and effective long-term decarbonization
\n
strategies.
\n
\u2022 Zero out emissions associated with gas
\n
extraction, as the Group will have completely
\n
exited both the gas-fired generation of
\n
electricity and the sale of gas to end users.
\n
(1) Percentages based on total GHG emissions in 2022.
\n
(2) Excludes marginal Scope 1 GHG emissions not directly related to the combustion of fossil fuels in electricity generation at thermal plants, which accounted
\n
for 1.4% of total Scope 1 emissions in 2022. In any event, GHG emissions covered by all of the above targets are equal, on the whole, to 98.7% of total Scope
\n
1 and 2 emissions in 2022, and therefore exceed the threshold of 95% required under the Science Based Target initiative.
\n
(3) The target is in line with the path to 1.5 \u00b0C set by the SBTi for the electrical services industry (Sectoral Decarbonization Approach, or SDA), although it could
\n
not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date.
\n
(4) The target could not be officially validated because the SBTi does not certify targets over a time frame of less than five years from the presentation date. In
\n
addition, the SBTi has not defined a Sectoral Decarbonization Approach for these types of emissions, so the ambition level cannot be verified.
\n
(5) Two different percentage limits have been set for the target for Scope 3 GHG emissions by the supply chain, as allowed under the SBTi approach, which
\n
required coverage of at least 67% of Scope 3 emissions for the 2030 target, and at least 90% for the 2040 target.
\n
Total coverage of Scopes 1-2-3
\n
emissions in 2022
\n
\u2022 98.6% of Scope 1 GHG emissions (2025, 2030 and 2040 targets)
\n
\u2022 100% of Scope 2 GHG emissions (2030 and 2040 targets)
\n
\u2022 87% (2030 target) and 90% (2040 target) of Scope 3 GHG emissions
\n
(5)
\n

\n\n
Regarding the assumptions for commodity price develop-
\n
ments, the use of Paris reference scenarios is confirmed.
\n
More specifically, the price of CO
\n
2
\n
is assumed to rise rapidly
\n
through 2030, driven by the gradual reduction in the sup-
\n
ply of allowances in the face of growing demand, while coal
\n
prices are projected to stabilize due to falling demand. Gas
\n
price tensions are expected to ease in the coming years in
\n
light of a realignment between supply and demand at the
\n
global level. Finally, the price of oil is expected to stabilize,
\n
with peak demand coming around 2030.
\n
Note also that the Group has used sensitivity analyses to
\n
take account of the impacts of climate change in the long
\n
term. More specifically:
\n
\u2022 we consider a long-term growth rate in the estimation of
\n
the terminal value that is in line with the change in elec-
\n
tricity demand over the 2026-2050 period, based on the
\n
specific features of the businesses concerned, adopting
\n
certain assumptions concerning the increase in tempera-
\n
ture due to climate change and trends connected with
\n
the energy transition;
\n
\u2022 we consider changes in the hydroelectric, wind and pho-
\n
tovoltaic generation levels of our portfolio assets, asso-
\n
ciated with each projection of underlying climate and
\n
weather variables (for example, temperature, irradiance,
\n
wind speed and precipitation);
\n
\u2022 we assume that the Group will incur the costs provisioned
\n
for decommissioning fossil fuel generation plants in line
\n
with the goal of zero direct (Scope 1) and indirect emis-
\n
sions from retail activities (Scope 3).
\n
In order to verify the robustness of the value in use of the
\n
CGUs, sensitivity analyses were conducted for the main val-
\n
ue drivers, in particular WACC, the long-term growth rate.
\n
In these circumstances as well, the results were consistent
\n
with the evidence described above, finding that the value of
\n
all the CGUs analyzed exceeded the carrying amount, thus
\n
ensuring the full recoverability of their carrying amount in
\n
the consolidated financial statements of the Enel Group at
\n
December 31, 2022.
\n

\n\n
The table below reports the composition of the main
\n
goodwill values for the companies within each CGU, along
\n
with the discount rates applied and the time horizon over
\n
which the expected cash flows have been discounted.
\n
Millions of euro
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
Amount
\n
of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WAC C
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period
\n
of cash
\n
flows
\n
Terminal
\n
value
\n
(3)
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Iberian Peninsula 8,785 2.47% 6.10% 3 years
\n
Perpetuity/25
\n
years EGP/13
\n
years G&T
\n
8,785 1.64% 3.93% 3 years
\n
Perpetuity/25
\n
years EGP/14
\n
years G&T
\n
Chile 1,148 2.00% 8.45% 3 years
\n
Perpetuity/26
\n
years EGP/5
\n
years G&T
\n
1,209 2.02% 6.58% 3 years
\n
Perpetuity/25
\n
years EGP/6
\n
years G&T
\n
Argentina 21 45.70% 71.78% 3 years Perpetuity 22 24.11% 46.75% 3 years
\n
Perpetuity/8
\n
years G&T
\n
Peru 571 2.25% 8.75% 3 years
\n
Perpetuity/25
\n
years EGP/8
\n
years G&T
\n
566 2.31% 6.64% 3 years
\n
Perpetuity/23
\n
years EGP/9
\n
years G&T
\n
Colombia 518 3.20% 11.79% 3 years
\n
Perpetuity/26
\n
years EGP/15
\n
years G&T
\n
527 3.11% 8.82% 3 years
\n
Perpetuity/28
\n
years EGP/16
\n
years G&T
\n
Brazil 1,313 3.58% 11.22% 3 years
\n
Perpetuity/25
\n
years EGP
\n
1,303 3.30% 9.09% 3 years
\n
Perpetuity/26
\n
years EGP/7
\n
years G&T
\n
Central America 26 2.02% 9.66% 3 years 18 years 25 2.03% 7.85% 3 years 19 years
\n
Enel Green Power North
\n
America
\n
70 2.02% 6.48% 3 years 25 years 70 2.03% 5.01% 3 years 26 years
\n
Enel X North America 142 2.02% 9.71% 3 years Perpetuity 199 2.03% 7.62% 3 years Perpetuity
\n
Enel X Way North America 70 2.02% 11.53% 3 years Perpetuity n.a. n.a. n.a. n.a. n.a.
\n
Enel X Asia Pacific 84 2.02% 10.39% 3 years Perpetuity 84 2.03% 8.81% 3 years Perpetuity
\n
Enel X Rest of Europe 43 1.62% 8.82% 3 years Perpetuity 43 1.70% 8.24% 3 years Perpetuity
\n
Enel Green Power Italy 21 1.62% 6.39% 3 years
\n
Perpetuity/24
\n
years
\n
21 1.52% 4.94% 3 years
\n
Perpetuity/23
\n
years
\n
Market Italy 581 2.38% 10.88% 3 years 15 years 580 1.48% 9.14% 3 years 15 years
\n
Enel Produzione Italy 349 1.64% 7.70% 3 years
\n
Perpetuity/15
\n
years
\n
n.a. n.a. n.a. n.a. n.a.
\n
Romania n.a. n.a. n.a. n.a. n.a. 387 2.06% 7.56% 3 years
\n
Perpetuity/25
\n
years
\n
CGUs with no recognized
\n
goodwill but that underwent
\n
impairment testing given the
\n
presence of the indicators
\n
provided for in IAS 36
\n
Iberia - NPT (Non-Peninsular
\n
Territories)
\n
n.a. n.a. n.a. n.a. n.a. - - 3.42% 5 years 5 years
\n
Australia n.a. n.a. n.a. n.a. n.a. - 0.91% 5.50% 3 years 25 years
\n
Mexico n.a. n.a. n.a. n.a. n.a. - 3.36% 8.77% 3 years 24 years
\n
(1) Perpetual growth rate for cash flows after the explicit forecast period.
\n
(2) Pre-tax WACC calculated using the iterative method: the discount rate that ensures that the value in use calculated with pre-tax cash flows is equal to that
\n
calculated with post-tax cash flows discounted with the post-tax WACC.
\n
(3) The terminal value has been estimated on the basis of a perpetuity or an annuity with a rising yield for the years indicated in the column (G&T = Generation
\n
& Trading, EGP = Enel Green Power, LH = Large Hydro).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1001": { "value": "\n
25. Deferred tax assets and liabilities \u2013 \u20ac10,925 million and \u20ac9,542 million
\n
The following tables detail changes in deferred tax assets
\n
and liabilities by type of timing difference and calculated
\n
based on the tax rates established by applicable regula-
\n
tions, as well as the amount of deferred tax assets offset-
\n
table, where permitted, with deferred tax liabilities.
\n
Millions of euro
\n
Increase/
\n
(Decrease)
\n
taken to
\n
profit or loss
\n
Increase/
\n
(Decrease)
\n
taken to
\n
equity
\n
Change in the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
Reclassifications
\n
of assets held
\n
for sale
\n
at Dec. 31, 2021
\n
at Dec. 31, 2022
\n
Deferred tax assets:
\n
- differences in the
\n
carrying amount of
\n
intangible assets,
\n
property, plant and
\n
equipment
\n
2,469 (90) 1 5 12 (10) (74) 2,313
\n
- accruals to provisions
\n
for risks and charges
\n
and impairment
\n
losses with deferred
\n
deductibility
\n
2,035 13 - 10 45 (19) (128) 1,956
\n
- tax loss carried
\n
forward
\n
785 158 - - 46 3 (206) 786
\n
- measurement of
\n
financial instruments
\n
2,248 91 522 4 2 67 (20) 2,914
\n
- employee benefits 871 (70) (78) - 45 40 (10) 798
\n
- other items 2,626 (464) 6 1 (7) 136 (140) 2,158
\n
Total 11,034 (362) 451 20 143 217 (578) 10,925
\n
Deferred tax liabilities:
\n
- differences on non-
\n
current and financial
\n
assets
\n
5,538 148 2 110 (97) 273 (255) 5,719
\n
- measurement of
\n
financial instruments
\n
1,527 28 (159) - 2 110 (2) 1,506
\n
- other items 2,194 188 6 (3) 38 78 (184) 2,317
\n
Total 9,259 364 (151) 107 (57) 461 (441) 9,542
\n
Non-offsettable
\n
deferred tax assets
\n
6,194
\n
Non-offsettable
\n
deferred tax liabilities
\n
4,612
\n
Excess net deferred
\n
tax liabilities after any
\n
offsetting
\n
199
\n
Deferred tax assets recognized at December 31, 2022, as the
\n
recovery of such assets is considered reasonably certain, to-
\n
taled \u20ac10,925 million (\u20ac11,034 million at December 31, 2021).
\n
Deferred tax assets decreased by \u20ac109 million during the
\n
year, essentially due to:
\n
\u2022 the reversal of deferred tax assets by Enel Iberia, the par-
\n
ent company of the tax consolidation group in Spain;
\n
\u2022 reversals of deferred tax assets on the differences in
\n
the value of non-current assets mainly in Italy and Latin
\n
America;
\n
\u2022 the reclassification of deferred tax assets relating to
\n
companies classified as available for sale and discontin-
\n
ued operations in the period.
\n
These factors were partly offset by the effect of deferred
\n
tax assets connected with developments in the fair value
\n
of cash flow hedge derivatives, the impact of exchange
\n
differences in Latin America and deferred tax assets rec-
\n
ognized following the corporate reorganization of the new
\n
e-Mobility Business Line in North America and Spain.
\n

\n\n
Note that deferred tax assets have not been assessed on
\n
tax losses carried forward and for the year (\u20ac1,129 million)
\n
in the amount of \u20ac352 million because, as based on cur-
\n
rent estimates of future taxable income, their recoverabili-
\n
ty is not considered probable.
\n
Deferred tax liabilities amounted to \u20ac9,542 million at De-
\n
cember 31, 2022 (\u20ac9,259 million at December 31, 2021).
\n
They essentially include the determination of the tax ef-
\n
fects of the adjustments to assets acquired as part of the
\n
final allocation of the cost of acquisitions made in the
\n
various years and the deferred taxation in respect of the
\n
differences between depreciation charged for tax purpos-
\n
es, including accelerated depreciation, and depreciation
\n
based on the estimated useful lives of assets.
\n
Deferred tax liabilities increased by a total of \u20ac283 million,
\n
due, in particular, to:
\n
\u2022 the impact of tax reforms and hyperinflation in Argen-
\n
tina;
\n
\u2022 the tax effect of the allocation of the goodwill on the
\n
merger of Enel Hydro Appennino Centrale Srl.
\n
These effects were partially offset by the effect of deferred
\n
tax assets connected with developments in the fair value
\n
of cash flow hedge derivatives, the impact of exchange
\n
differences in Latin America and the reclassification of
\n
deferred tax liabilities relating to companies classified as
\n
available for sale and discontinued operations during the
\n
year.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1011": { "value": "\n
27. Derivatives
\n
Millions of euro Non-current Current
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Derivative financial assets 3,970 2,772 14,830 22,791
\n
Derivative financial liabilities 5,895 3,339 16,141 24,607
\n
For more information on derivatives classified as non-cur-
\n
rent financial assets, please see note 51 for hedging deriv-
\n
atives and trading derivatives.
\n

\n\n
51. Derivatives and hedge accounting
\n
The following tables show the notional amount and the fair
\n
value of derivative financial assets and derivative financial
\n
liabilities eligible for hedge accounting or measured at
\n
FVTPL, classified on the basis of the type of hedge rela-
\n
tionship and the hedged risk, broken down into current
\n
and non-current instruments.
\n
The notional amount of a derivative contract is the amount
\n
on the basis of which cash flows are exchanged. This
\n
amount can be expressed as a value or a quantity (for ex-
\n
ample tons, converted into euros by multiplying the no-
\n
tional amount by the agreed price). Amounts denominated
\n
in currencies other than the euro are translated at the offi-
\n
cial closing exchange rates provided by the World Markets
\n
Refinitiv (WMR) Company.
\n
Millions of euro Non-current Current
\n
Notional Fair value Notional Fair value
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
DERIVATIVE ASSETS
\n
Fair value hedge derivatives:
\n
- on interest rates 1541392219----
\n
- on exchange rates 99 672 15 42 - - -
\n
-
\n
- of which associated with borrowings 70 672 14 42----
\n
Total 2538113761----
\n
Cash flow hedge derivatives:
\n
- on interest rates 4,949404336199---
\n
- on exchange rates 16,955 14,980 1,854 1,356 4,053 2,690 389
\n
104
\n
- of which associated with borrowings 15,402 13,130 1,786 1,303 1,244 77 236 14
\n
- on commodities 4,321 2,693 1,270 1,059 7,416 3,469 2,366 3,023
\n
Total 26,225 18,077 3,460 2,434 11,478 6,159 2,755 3,127
\n
Trading derivatives:
\n
- on interest rates -----50-1
\n
- on exchange rates 19 26 1 - 3,640 2,154 74 23
\n
- on commodities 1,774 1,147 472 277 49,253 48,304 12,001
\n
19,640
\n
Total 1,793 1,173 473 277 52,893 50,508 12,075 19,664
\n
TOTAL DERIVATIVE ASSETS 28,271 20,061 3,970 2,772 64,371 56,667 14,830
\n
22,791
\n

\n\n

\n
Millions of euro Non-current Current
\n
Notional Fair value Notional Fair value
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
DERIVATIVE LIABILITIES
\n
Fair value hedge derivatives:
\n
- on interest rates 1,603660925----
\n
- on exchange rates 813 - 99 - 185 - - -
\n
- of which associated with borrowings 750 - 91-----
\n
Total 2,4166601915185---
\n
Cash flow hedge derivatives:
\n
- on interest rates 890 6,807 59 620 150 653 1 9
\n
- on exchange rates 11,956 7,224 1,640 1,244 3,798 1,892 176 49
\n
- of which associated with borrowings 8,388 5,034 1,348 1,099 67 21 2 1
\n
- on commodities 6,403 3,312 3,417 1,301 9,556 2,067 4,322 4,853
\n
Total 19,249 17,343 5,116 3,165 13,504 4,612 4,499 4,911
\n
Trading derivatives:
\n
- on interest rates ----1001502373
\n
- on exchange rates 52 73 1 2 2,096 3,555 34 60
\n
- on commodities 1,281 884 587 167 45,899 41,595 11,585 19,563
\n
Total 1,333 957 588 169 48,095 45,300 11,642 19,696
\n
TOTAL DERIVATIVE LIABILITIES 22,998 18,960 5,895 3,339 61,784 49,912 16,141 24,607
\n
Exchange rate derivatives associated with borrowings re-
\n
fer to the fair value and notional amount of cross currency
\n
swaps entered into to hedge foreign currency loans to third
\n
parties; the net fair value of these derivatives is included in
\n
the representation of the Group\u2019s net financial debt.
\n\n
51.1 Derivatives designated as hedging
\n
instruments
\n
Derivatives are initially recognized at fair value, on the trade
\n
date of the contract, and are subsequently re-measured at
\n
their fair value. The method of recognizing the resulting
\n
gain or loss depends on whether the derivative is desig-
\n
nated as a hedging instrument, and if so, the nature of the
\n
item being hedged.
\n
Hedge accounting is applied to derivatives entered into in
\n
order to reduce risks such as interest rate risk, currency
\n
risk, commodity price risk (including Virtual PPAs) and net
\n
investments in foreign operations when all the criteria pro-
\n
vided by IFRS 9 are met.
\n
At the inception of the transaction, the Group docu-
\n
ments the relationship between hedging instruments and
\n
hedged items, as well as its risk management objectives
\n
and strategy. The Group also documents its assessment,
\n
both at hedge inception and on an ongoing basis, of
\n
whether hedging instruments are highly effective in offset-
\n
ting changes in fair values or cash flows of hedged items.
\n
For cash flow hedges of forecast transactions designat-
\n
ed as hedged items, the Group assesses and documents
\n
that they are highly probable and present an exposure to
\n
changes in cash flows that affect profit or loss.
\n
Depending on the nature of the risk exposure, the Group
\n
designates derivatives as either:
\n
\u2022 fair value hedges;
\n
\u2022 cash flow hedges.
\n
For more details about the nature and the extent of risks
\n
arising from financial instruments to which the Group is
\n
exposed, please see note 49 \u201cRisk management\u201d.
\n
To be effective a hedge relationship shall meet all of the
\n
following criteria:
\n
\u2022 existence of an economic relationship between hedging
\n
instrument and hedged item;
\n
\u2022 the effect of credit risk does not dominate the value
\n
changes resulting from the economic relationship;
\n
\u2022 the hedge ratio defined at initial designation shall be
\n
equal to the one used for risk management purposes
\n
(i.e., same quantity of the hedged item that the entity
\n
actually hedges and the quantity of the hedging instru-
\n
ment that the entity actually uses to hedge the quantity
\n
of the hedged item).
\n
Based on the IFRS 9 requirements, the existence of an
\n
economic relationship is evaluated by the Group through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n

\n\n

\n\n

\n\n

\n
\u2022 if the underlying risk of the hedging instrument and the
\n
hedged item is the same, the existence of an economic
\n
relationship will be provided through a qualitative anal-
\n
ysis;
\n
\u2022 on the other hand, if the underling risk of the hedging
\n
instrument and the hedged item is not the same, the
\n
existence of the economic relationship will be demon-
\n
strated through a quantitative method in addition to a
\n
qualitative analysis of the nature of the economic rela-
\n
tionship (i.e., linear regression).
\n
In order to demonstrate that the behavior of the hedging
\n
instrument is in line with those of the hedged item, differ-
\n
ent scenarios will be analyzed.
\n
For hedging of commodity price risk, the existence of an
\n
economic relationship is deduced from a ranking matrix
\n
that defines, for each possible risk component, a set of all
\n
standard derivatives available in the market whose ranking
\n
is based on their effectiveness in hedging the considered
\n
risk.
\n
In order to evaluate the credit risk effects, the Group con-
\n
siders the existence of risk mitigating measures (collateral,
\n
mutual break-up clauses, netting agreements, etc.).
\n
The Group has established a hedge ratio of 1:1 for all the
\n
hedge relationships (including commodity price risk hedg-
\n
ing) as the underlying risk of the hedging derivative is
\n
identical to the hedged risk, in order to minimize hedging
\n
ineffectiveness.
\n
The hedge ineffectiveness will be evaluated through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the following circumstances:
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument match and there are no other sources of inef-
\n
fectiveness including the credit risk adjustment on the
\n
hedging derivative, the hedge relationship will be con-
\n
sidered fully effective on the basis of a qualitative as-
\n
sessment;
\n
\u2022 if the critical terms of the hedged item and hedging in-
\n
strument do not match or there is at least one source of
\n
ineffectiveness, the hedge ineffectiveness will be quan-
\n
tified applying the dollar offset cumulative method with
\n
hypothetical derivative. This method compares changes
\n
in fair value of the hedging instrument and the hypo-
\n
thetical derivative between the reporting date and the
\n
inception date.
\n
The main causes of hedge ineffectiveness can be the fol-
\n
lowing:
\n
\u2022 basis differences (i.e., the fair value or cash flows of the
\n
hedged item depend on a variable that is different from
\n
the variable that causes the fair value or cash flows of
\n
the hedging instrument to change);
\n
\u2022 timing differences (i.e., the hedged item and hedging in-
\n
strument occur or are settled at different dates);
\n
\u2022 quantity or notional amount differences (i.e., the hedged
\n
item and hedging instrument are based on different
\n
quantities or notional amounts);
\n
\u2022 other risks (i.e., changes in the fair value or cash flows of
\n
a derivative hedging instrument or hedged item relate to
\n
risks other than the specific risk being hedged);
\n
\u2022 credit risk (i.e., the counterparty credit risk differently im-
\n
pact the changes in the fair value of the hedging instru-
\n
ments and hedged items).
\n
The macroeconomic context became particularly unstable
\n
in 2022, due to the conflict between Russia and Ukraine,
\n
impacting raw material supply chains and causing high
\n
price volatility, especially in the energy sector. In this con-
\n
text, the commodity risk was managed effectively and did
\n
not have a significant impact on the soundness of hedging
\n
relationships, also thanks to the solidity of the integrated
\n
portfolio models used in the main European areas in which
\n
the Group operates and the geographical diversification of
\n
our sources of supply. Even credit risk was essentially un-
\n
affected, as the Group\u2019s main trading counterparties have
\n
a high credit rating or are adequately secured by bank or
\n
insurance guarantees.
\n
The conflict and the difficult macroeconomic conditions
\n
had only a limited impact on the management of interest
\n
rate and exchange rate risk, being insufficient to direct-
\n
ly and significantly influence the valuation of derivative
\n
instruments and the outcome of effectiveness checks of
\n
hedges. The volatility that buffeted financial markets was
\n
offset by risk mitigation actions using derivative financial
\n
instruments.
\n
Fair value hedges
\n
Fair value hedges are used to protect the Group against
\n
exposures to changes in the fair value of assets, liabilities
\n
or firm commitment attributable to a particular risk that
\n
could affect profit or loss.
\n
Changes in the fair value of derivatives that qualify and are
\n
designated as hedging instruments are recognized in the
\n
income statement, together with changes in the fair value
\n
of the hedged item that are attributable to the hedged risk.
\n
If the hedge no longer meets the criteria for hedge ac-
\n
counting, the adjustment to the carrying amount of a
\n
hedged item for which the effective interest rate method
\n
is used is amortized to profit or loss over the period to ma-
\n
turity.
\n

\n\n

\n\n

\n\n

\n

\n
Cash flow hedges
\n
Cash flow hedges are applied in order to hedge the Group
\n
exposure to changes in future cash flows that are attribut-
\n
able to a particular risk associated with a recognized asset
\n
or liability or a highly probable transaction that could affect
\n
profit or loss.
\n
The effective portion of changes in the fair value of deriv-
\n
atives that are designated and qualify as cash flow hedges
\n
is recognized in other comprehensive income. The gain or
\n
loss relating to the ineffective portion is recognized imme-
\n
diately in the income statement.
\n
Amounts accumulated in equity are reclassified to profit
\n
or loss in the periods when the hedged item affects profit
\n
or loss (for example, when the hedged forecast sale takes
\n
place).
\n
If the hedged item results in the recognition of a non-fi-
\n
nancial asset (i.e., property, plant and equipment or inven-
\n
tories, etc.) or a non-financial liability, or a hedged forecast
\n
transaction for a non-financial asset or a non-financial
\n
liability becomes a firm commitment for which fair value
\n
hedge accounting is applied, the amount accumulated in
\n
equity (i.e., hedging reserve) shall be removed and included
\n
in the initial amount (cost or other carrying amount) of the
\n
asset or the liability hedged (i.e., \u201cbasis adjustment\u201d).
\n
When a hedging instrument expires or is sold, or when a
\n
hedge no longer meets the criteria for hedge accounting,
\n
any cumulative gain or loss existing in equity at that time
\n
remains in equity and is recognized when the forecast
\n
transaction is ultimately recognized in the income state-
\n
ment. When a forecast transaction is no longer expected
\n
to occur, the cumulative gain or loss that was reported in
\n
equity is immediately transferred to the income statement.
\n
For hedge relationships using forwards as a hedging in-
\n
strument, where only the change in the value of the spot
\n
element is designated as the hedging instrument, ac-
\n
counting for the forward element (profit or loss vs OCI) is
\n
defined case by case. This approach is actually applied by
\n
the Group for hedging of currency risk on renewables as-
\n
sets.
\n
Conversely, for hedge relationships using cross currency
\n
interest rate swaps as hedging instruments, the Group
\n
separates foreign currency basis spread, in designating
\n
the hedging derivative, and present them in other com-
\n
prehensive income (OCI) as hedging costs.
\n
With specific regard to cash flow hedges of commodity
\n
risk, in order to improve their consistency with the risk
\n
management strategy, the Enel Group applies a dynamic
\n
hedge accounting approach based on specific liquidity re-
\n
quirements (the so-called liquidity-based approach).
\n
This approach requires the designation of hedges through
\n
the use of the most liquid derivatives available on the mar-
\n
ket and replacing them with others that are more effective
\n
in covering the risk in question.
\n
Consistent with the risk management strategy, the liquid-
\n
ity-based approach allows the roll-over of a derivative by
\n
replacing it with a new derivative, not only in the event of
\n
expiry but also during the hedge relationship, if and only
\n
if the new derivative meets both of the following require-
\n
ments:
\n
\u2022 it represents a best proxy of the old derivative in terms
\n
of ranking;
\n
\u2022 it meets specific liquidity requirements.
\n
Satisfaction of these requirements is verified quarterly.
\n
At the roll-over date, the hedge relationship is not discon-
\n
tinued. Accordingly, starting from that date, changes in the
\n
effective fair value of the new derivative will be recognized
\n
in equity (the hedging reserve), while changes in the fair
\n
value of the old derivative are recognized through profit
\n
or loss.
\n\n
Reform of benchmarks for the determination of interest
\n
rates \u2013 IBOR reform
\n
Overview
\n
Interbank Offered Rates (\u201cIBORs\u201d) are benchmark rates at
\n
which banks can borrow funds on the interbank market on
\n
an unsecured basis for a given period ranging from over-
\n
night to 12 months, in a specific currency.
\n
In recent years there have been a number of cases of ma-
\n
nipulation of these rates by the banks contributing to their
\n
calculation. For this reason, regulators around the world
\n
have begun a sweeping reform of interest rate bench-
\n
marks that includes the replacement of some benchmarks
\n
with alternative risk-free rates (the IBOR reform).
\n
The Group\u2019s main exposure is based on Euribor and USD
\n
LIBOR.
\n
Euribor is still considered compliant with the European
\n
Benchmarks Regulation (BMR) and this permits market
\n
participants to continue to use it for both existing and new
\n
contracts.
\n
In line with the most recent guidance issued by the major
\n
regulatory bodies:
\n
\u2022 the 1-month, 3-month and 6-month USD LIBOR bench-
\n
marks will become unrepresentative after June 30, 2023
\n
and the alternative reference rate will be the Secured
\n
Overnight Financing Rate (SOFR);
\n
\u2022 the 1-month, 3-month and 6-month GBP LIBOR bench-
\n
marks will become unrepresentative after December 31,
\n
2021 and the alternative reference rate will be the Ster-
\n
ling Overnight Index Average (SONIA).
\n
As a result of the IBOR reform, a number of temporary ex-
\n
ceptions to the rules on hedge relationships have been al-
\n
lowed in implementation of the amendments to IFRS 9 is-
\n
sued in September 2019 (Phase 1) and August 2020 (Phase
\n
2) to address, respectively:
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n\n
\u2022 pre-replacement issues that impact financial reporting
\n
in the period preceding the replacement of an existing
\n
interest rate benchmark with an alternative risk-free rate
\n
(Phase 1); and
\n
\u2022 post-replacement issues that could impact financial
\n
reporting when an existing interest rate benchmark is
\n
reformed or replaced and there is no longer any initial
\n
uncertainty, but hedge contracts and relationships still
\n
need to be updated to reflect the new benchmark rates
\n
(Phase 2).
\n
Impact of the IBOR reform on the Group
\n
In a context of uncertainty regarding the IBOR transition in
\n
the various countries, the Group has determined the over-
\n
all number and nominal value of the contracts impacted by
\n
the reform. In addition, a number of contractual amend-
\n
ments have already been implemented in contracts pre-
\n
viously indexed to GBP LIBOR in 2021 and others will be
\n
amended in 2023 on the basis of the evolution of the IBOR
\n
reform and market practice.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and USD LIBOR and is almost entirely
\n
hedged using financial derivatives.
\n
At the reporting date, the Group is planning to take no
\n
action with regard to Euribor since, as stated above, this
\n
benchmark has been comprehensively reformed to com-
\n
ply with the European Benchmarks Regulation. Despite the
\n
continuity with Euribor, replacement clauses may be re-
\n
quired and could therefore be implemented by the Group
\n
in the new contracts in accordance with the evolution of
\n
accepted market practice.
\n
During 2022, the Group obtained new US dollar loans in-
\n
dexed to SOFR. The main focus over the coming months
\n
will be how to change existing USD LIBOR to USD SOFR ex-
\n
posures and how to use the new, alternative risk-free rates
\n
for new financial transactions.
\n
The Group\u2019s derivative instruments are managed through
\n
contracts that are mainly based on framework agreements
\n
defined by the International Swaps and Derivatives Associ-
\n
ation (ISDA).
\n
The ISDA has revised its standardized contracts in light of
\n
the IBOR reform and amended the choices for floating rates
\n
within the 2006 ISDA definitions to include replacement
\n
clauses that would apply upon the permanent discontinu-
\n
ation of specific key benchmarks. These changes took ef-
\n
fect on January 25, 2021. Transactions represented in the
\n
2006 ISDA definitions carried out on January 25, 2021 or
\n
later include adjusted floating-rate options (e.g., the choice
\n
of floating rate with replacement clause), while transactions
\n
completed before that date (previous derivative contracts)
\n
continue to be based on the 2006 ISDA definitions.
\n
For this reason, the ISDA published an IBOR Fallback Pro-
\n
tocol to facilitate multilateral amendments to include the
\n
amended definitions.
\n
The Group is assessing whether to: (i) adopt that protocol
\n
in the light of its exposure and developments in the IBOR
\n
reform or (ii) adjust in advance any contracts impacted bi-
\n
laterally by the reform.
\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, USD LIBOR and
\n
SONIA.
\n
The Group has assessed the impact of uncertainty engen-
\n
dered by the IBOR reform on hedge relationships at De-
\n
cember 31, 2022 with reference to both hedging instru-
\n
ments and hedged items. Both the hedged items and the
\n
hedging instruments will change their parameterization
\n
from interbank market-based benchmarks (IBORs) to al-
\n
ternative risk-free rates (RFRs) as a result of the contrac-
\n
tual amendments that will take effect in the coming years.
\n
In particular, uncertainty remains as to how the replacement
\n
will take place with regard to both hedging instruments and
\n
hedged items indexed to USD LIBOR. The Group manages
\n
the uncertainty associated with these hedge relationships
\n
by continuing to apply the temporary exceptions provided
\n
for in the amendments to IFRS 9 issued in September 2019
\n
(Phase 1). It was therefore felt that the benchmark indices
\n
for determining the interest rates on which the cash flows
\n
of the hedged items or the hedging instruments are based
\n
would not change as a consequence of the IBOR reform.
\n
The exception was applied for the following hedge rela-
\n
tionship requirements:
\n
\u2022 determine if a forecast transaction is highly probable;
\n
\u2022 establish whether the future hedged cash flows will arise
\n
in a discontinued cash flow hedge relationship;
\n
\u2022 assess the economic relationship between the hedged
\n
item and the hedging instrument.
\n
The hedge relationships impacted may become ineffective
\n
attributable to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In any case,
\n
the Group will seek to implement the replacements at the
\n
same time.
\n
In addition, the Group changed the reference to GBP LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically equiv-
\n
alent, SONIA benchmark at the end of 2021. Consequently,
\n
the Group no longer applies the amendments to IFRS 9
\n
issued in September 2019 (Phase 1) to these hedge rela-
\n
tionships and, consequently, is applying the amendments
\n
to IFRS 9 issued in August 2020 (Phase 2), modifying the
\n
formal designation of the hedge relationship as required
\n
by the IBOR reform and without considering this event as a
\n
termination of the hedge relationship.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n

\n

\n

\n\n
Furthermore, for cash flow hedge relationships, in modify-
\n
ing the description of the hedged item in the hedge rela-
\n
tionship, the amounts accumulated in the cash flow hedge
\n
reserve were considered on the basis of the alternative
\n
benchmark index in relation to which the future hedged
\n
cash flows are determined.
\n
The following table provides details of the notional amounts
\n
of the hedging instruments for which the amendments to
\n
IFRS 9 (both Phase 1 and Phase 2) were applied as at De-
\n
cember 31, 2022, broken down by the alternative bench-
\n
mark index used for determining the interest rate.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022
\n
Hedging instruments Phase 1 Phase 2
\n
USD LIBOR/SOFR 977 -
\n
GBP LIBOR/SONIA - 1,240
\n
Tot al 977
\n
1,240
\n

\n\n\n
Unamended contracts including those with specific
\n
replacement clauses
\n
The Group is monitoring the evolution of the transition
\n
from the old interest rate benchmarks to the new rates,
\n
reviewing the overall value of contracts that have not yet
\n
been indexed to the new benchmark rates and, among
\n
these, the value of contracts which already include specific
\n
replacement clauses. The Group considers a contract to
\n
have not yet incorporated an alternative benchmark rate
\n
when the interest rate of the contract is indexed to an in-
\n
terest rate benchmark still involved in the IBOR reform and,
\n
therefore, when uncertainties still exist as to how and when
\n
replacement with the new benchmark will take place.
\n

\n

\n\n
51.1.1 Hedge relationships by type of risk hedged
\n
Interest rate risk
\n
The following table shows the notional amount and the
\n
average interest rate of instruments hedging the interest
\n
rate risk on transactions outstanding at December 31,
\n
2022 and December 31, 2021, broken down by maturity.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Interest rate swaps
\n
Total notional amount 159 722 573 902 2,017 3,382 7,755
\n
Notional amount related to IRS in euro 159 623 573 682 1,558 2,724 6,319
\n
Average IRS rate in euro 4.41 2.24 1.91 2.20 1.84 1.61
\n
Notional amount related to IRS in US dollars - 47 - - 459 237 743
\n
Average IRS rate in US dollars 0.70 3.23 3.84
\n

\n\n

\n\n

\n\n

\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the interest rate risk
\n
of transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument
\n
Hedged item
\n
Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Fair value hedges
\n
Interest rate swaps Floating-rate borrowings/bonds 20 (2) 518 13 (1) 241
\n
Interest rate swaps Fixed-rate borrowings/bonds 2 (90) 1,239 6 (4)
\n
558
\n
Cash flow hedges
\n
Interest rate swaps Floating-rate bonds 29 (44)
\n
1,190 - (167) 1,190
\n
Interest rate swaps Floating-rate loan assets - (9) 162 13 (1) 164
\n
Interest rate swaps Floating-rate borrowings 307 (7) 4,646 6 (461)
\n
6,510
\n
Tot al 358 (152) 7,755 38 (634) 8,663
\n
The following table shows the notional amount and the fair
\n
value of hedging derivatives on interest rate risk as at De-
\n
cember 31, 2022 and December 31, 2021 broken down by
\n
type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
Interest rate swaps 154 139 22 19 1,603 660 (92) (5)
\n
Total 154 139 22 19 1,603 660 (92) (5)
\n
Cash flow hedges
\n
Interest rate swaps 4,958 404 336 19 1,040 7,460 (60) (629)
\n
Total 4,958 404 336 19 1,040 7,460 (60) (629)
\n
TOTAL INTEREST RATE
\n
DERIVATIVES
\n
5,112 543 358 38 2,643 8,120 (152) (634)
\n
The notional amount of derivatives classified as hedging
\n
instruments at December 31, 2022 came to \u20ac7,755 million,
\n
with a corresponding positive fair value of \u20ac206 million.
\n
Compared with December 31, 2021, the notional amount
\n
decreased by \u20ac908 million, mainly reflecting:
\n
\u2022 the expiry of interest rate swaps amounting to \u20ac481 mil-
\n
lion;
\n
\u2022 the classification as assets held for sale of Australian
\n
companies holding interest rate financial derivatives in
\n
the amount of \u20ac340 million;
\n
\u2022 new interest rate swaps amounting to \u20ac1,174 million;
\n
\u2022 the reduction in the notional amount of amortizing inter-
\n
est rate swaps in the amount of \u20ac211 million.
\n
We also note the early closure of interest rate swaps for
\n
an amount of \u20ac1,050 million. The improvement in the fair
\n
value of \u20ac802 million mainly reflects developments in the
\n
yield curve.
\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss in respect of fair value hedge
\n
derivatives and the hedged item that are attributable to in-
\n
terest rate risk both in 2022 and the previous year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (84) (10)
\n
Hedged item 75 3
\n
Ineffective portion (9) (7)
\n

\n\n

\n\n

\n\n
The following table shows the impact of fair value hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 1,757 (70) (70) 799 14 14
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds 1,152 (87) (81) 562 4 (8)
\n
Floating-rate borrowings/bonds 576 (16) (18) 262 (9) 12
\n
Total 1,728 (103) (99) 824 (5) 4
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on interest rate
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on interest
\n
rates
\n
Positive fair value 336 80 98 60 48 64 -
\n
Negative fair value (60) (15) (10) (10) (8) (24) -
\n
The following table shows the impact of cash flow hedges
\n
of interest rate risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness in
\n
the year
\n
Interest rate swaps 5,998 276 276 7,864 (610)
\n
(610)
\n

\n\n

\n\n

\n\n

\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through P&L of
\n
CFH derivatives
\n
designated after
\n
initial recognition
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
bonds
\n
15 - (15) - - 167 - (167) - -
\n
Floating-rate
\n
loan assets
\n
9 - (9) - - (12) - 12 - -
\n
Floating-rate
\n
borrowings
\n
(327) (28) 326 - 2 417 (32) (417) - (6)
\n
Total (303) (28) 302 - 2 572 (32) (572) - (6)
\n\n
Currency risk
\n
The following table reports the maturity profile of the no-
\n
tional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRS)
\n
Total notional amount of CCIRS 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRS EUR/USD 1,171 2,290 2,107 1,171 1,615 11,529 19,883
\n
Average exchange rate EUR/USD 1.33 1.13 1.07 1.18 1.10 1.15
\n
Notional amount for CCIRS EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount for CCIRS EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 140 288 239 94 - - 761
\n
Average exchange rate USD/BRL 5.22 5.50 5.22 5.29
\n
Notional amount for CCIRS EUR/BRL 597 438 181 - 70 - 1,286
\n
Average exchange rate EUR/BRL 6.09 6.25 6.16 3.92
\n
Currency forwards
\n
Total notional amount of forwards 6,127 2,374 625 - - - 9,126
\n
Notional amount - currency forwards EUR/USD 4,713 2,345 625 - - - 7,683
\n
Average currency forward rate - EUR/USD 1.09 1.10 1.11
\n
Notional amount - currency forwards USD/BRL 333 -----333
\n
Average currency forward rate - USD/BRL 5.61
\n
Notional amount - currency forwards EUR/CNH 311 -----311
\n
Average currency forward rate - EUR/CNH 7.41
\n
Notional amount - currency forwards USD/CLP 199 20----219
\n
Average currency forward rate - USD/CLP 906.90 921.05
\n
Notional amount - currency forwards USD/COP 156 2----158
\n
Average currency forward rate - USD/COP 4,720.74 4,444.96
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026 Beyond Total
\n
At Dec. 31, 2021
\n
Cross currency interest rate swap (CCIRS)
\n
Total notional amount of CCIRS 258 1,574 4,638 1,002 1,153 12,814 21,439
\n
Notional amount for CCIRS EUR/USD - 1,104 2,158 661 1,104 8,632 13,659
\n
Average exchange rate EUR/USD 1.33 1.13 1.17 1.18 1.21
\n
Notional amount for CCIRS EUR/GBP - - 1,012 - - 3,678 4,690
\n
Average exchange rate EUR/GBP 0.88 0.82
\n
Notional amount for CCIRS EUR/CHF - - 218 - - 126 344
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 98 132 295 155 49 244 973
\n
Average exchange rate USD/BRL 4.81 5.22 5.55 5.29 5.39 3.57
\n
Notional amount for CCIRS EUR/BRL 160 339 402 79 - 77 1,057
\n
Average exchange rate EUR/BRL 6.41 6.44 6.25 6.71 3.92
\n
Currency forward
\n
Total notional amount of forwards 4,324 1,320 371 4 - - 6,019
\n
Notional amount - currency forwards EUR/USD 3,064 1,268 371 4 - - 4,707
\n
Average currency forward rate - EUR/USD 1.16 1.19 1.18 1.18
\n
Notional amount - currency forwards USD/BRL 311 -----311
\n
Average currency forward rate - USD/BRL 5.65
\n
Notional amount - currency forwards USD/COP 284-----284
\n
Average currency forward rate - USD/COP 3,963.3
\n
Notional amount - currency forwards USD/CLP 145-----145
\n
Average currency forward rate - USD/CLP 818.94
\n
Notional amount - currency forwards USD/CAD 107-----107
\n
Average currency forward rate - USD/CAD 1.24
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the currency risk of
\n
transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument Hedged item Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
15 (99) 1,097 12 - 595
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings in foreign
\n
currencies
\n
-- -30-77
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings/financial
\n
assets in foreign currencies
\n
95 (76) 1,061 88 (19) 953
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
4 (233) 2,445 43 (58) 2,553
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate bonds in foreign
\n
currencies
\n
60 - 414 37 - 344
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
1,864 (1,293) 23,381 1,159 (1,095) 16,601
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Future cash flows denominated in
\n
foreign currencies
\n
- (50) 335 - (75) 316
\n
Currency forwards
\n
Future cash flows denominated in
\n
foreign currencies
\n
9 (6) 326 7 (3) 378
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign currencies
\n
192 (135) 7,508 106 (36) 4,802
\n
Currency forwards
\n
Purchases of investment goods and
\n
other in foreign currencies
\n
19 (23) 1,292 20 (7) 839
\n
Tot al 2,258 (1,915) 37,859 1,502 (1,293) 27,458
\n
Cash flow hedges and fair value hedges include:
\n
\u2022 CCIRSs with a notional amount of \u20ac26,923 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac258 million;
\n
\u2022 CCIRSs with a notional amount of \u20ac1,810 million used to
\n
hedge the currency risk on floating-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac29 million;
\n
\u2022 currency forwards with a notional amount of \u20ac7,834
\n
million used to hedge the currency risk associated with
\n
purchases of natural gas, purchases of fuel and expect-
\n
ed cash flows in currencies other than the euro, with a
\n
total positive fair value of \u20ac60 million;
\n
\u2022 currency forwards with a notional amount of \u20ac1,292
\n
million and a negative fair value of \u20ac4 million, in respect
\n
of OTC transactions to mitigate the currency risk on ex-
\n
pected cash flows in currencies other than the presen-
\n
tation currency connected with the purchase of invest-
\n
ment goods in the renewables and infrastructure and
\n
networks sectors (new generation digital meters), on
\n
operating costs for the supply of cloud services and on
\n
revenue from the sale of renewable energy.
\n
The following table reports the notional amount and fair
\n
value of foreign exchange derivatives at December 31,
\n
2022 and December 31, 2021, broken down by type of
\n
hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
CCIRS 99 672 15 42 998 - (99) -
\n
Total 99 672 15 42 998 - (99) -
\n
Cash flow hedges
\n
Currency forwards 4,313 4,117 220 133 4,813 1,902 (164) (46)
\n
CCIRS 16,695 13,553 2,023 1,327 10,941 7,214 (1,652) (1,247)
\n
Total 21,008 17,670 2,243 1,460 15,754 9,116 (1,816) (1,293)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
21,107 18,342 2,258 1,502 16,752 9,116 (1,915) (1,293)
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The notional amount of CCIRS at December 31, 2022
\n
amounted to \u20ac28,733 million (\u20ac21,439 million at Decem-
\n
ber 31, 2021), an increase of \u20ac7,294 million. Cross curren-
\n
cy interest rate swaps with a total amount of \u20ac258 million
\n
expired, while new derivatives amounted to \u20ac7,500 million,
\n
of which \u20ac6,936 million in respect of bond issues denomi-
\n
nated in British pounds and US dollars in 2022. In addition,
\n
following the novation of a bond in US dollars from Enel
\n
Finance International to Enel Finance America, cross cur-
\n
rency interest rate swaps of \u20ac662 million were terminated
\n
early. The amount also reflects developments in the ex-
\n
change rate of the euro against the main other currencies
\n
and the effect of amortization, which caused their notional
\n
amount to increase by \u20ac714 million.
\n
The notional amount of currency forwards at December
\n
31, 2022 amounted to \u20ac9,126 million (\u20ac6,019 million at De-
\n
cember 31, 2021), an increase of \u20ac3,107 million. The expo-
\n
sure to currency risk, especially that associated with the US
\n
dollar, is mainly due to purchases of natural gas, purchases
\n
of fuel and cash flows in respect of investments. Changes
\n
in the notional amount are connected with a greater ex-
\n
posure to exchange rate risk, in particular towards the US
\n
dollar, resulting from the increase in natural gas prices and
\n
the recovery in the generation of electricity from coal.
\n

\n

\n\n
Fair value hedge derivatives
\n
The following table reports net gains and losses recog-
\n
nized through profit or loss, reflecting changes in the fair
\n
value of fair value hedge derivatives and the hedged item
\n
that are attributable to currency risk for 2022 and the pre-
\n
vious year.
\n
Millions of euro 2022 2021
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments (119) 9
\n
Hedged item 129 (8)
\n
Ineffective portion 10 1
\n
The following table shows the impact of fair value hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 1,097 (84) (87) 672 42 37
\n
The following table shows the impact of the hedged item
\n
of fair value hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Carrying
\n
amount
\n
Cumulative
\n
adjustment of
\n
fair value of
\n
hedged item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings/bonds in foreign currencies 525 (109) 70 639 35
\n
(40)
\n
Floating-rate borrowings/bonds in foreign
\n
currencies
\n
449 (10) 13 - -
\n
-
\n
Total 974 (119) 83 639 35 (40)
\n

\n\n

\n\n

\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on currency
\n
risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 2,243 1,256 889 320 299 2,197
\n
-
\n
Negative fair value (1,816) (58) (53) (97) 7 (361) -
\n
The following table shows the impact of cash flow hedges
\n
of currency risk in the statement of financial position at
\n
December 31, 2022 and at December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Cross currency interest rate swaps (CCIRS) 27,636 371 433 20,767 80 82
\n
Currency forwards 9,126 56 56 6,019 87 89
\n
Total 36,762 427 489 26,786 167 171
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Other effects
\n
through
\n
profit or
\n
loss
\n
(1)
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Floating-rate
\n
borrowings in foreign
\n
currencies
\n
(30) 30 - (11) - (69) 69 - -
\n
Fixed-rate
\n
borrowings in foreign
\n
currencies
\n
225 (225) (4) - - 15 (15) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(60) 60 - - - (37) 37 - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
(628) 509 (56) - 118 (66) 66 (2) -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with CCIRSs)
\n
50 (50) - - - 75 (75) - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(3) 3 - - - (2) 2 1 -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
(60) 59 (1) (1) - (72) 72 - -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
7 (7) 1 2 - (15) 15 (3) -
\n
Total (499) 379 (60) (10) 118 (171) 171 (4) -
\n
(1) The impact is connected with changes in spot rates between the date of inception of the CCRIS entered into to hedge bonds denominated in foreign cur-
\n
rencies and the actual disbursement of the loan.
\n

\n\n

\n\n

\n\n
Commodity price risk
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Commodity swaps
\n
Notional amount on electricity 653 164 143 139 132 333 1,564
\n
Average commodity swap price on power (\u20ac/MWh) 162.5 77.9 48.9 47.2 45.8 29.0
\n
Notional amount on coal/shipping 1,037 - - - - - 1,037
\n
Average commodity swap price on coal/shipping ($/t) 293.7-----
\n
Notional amount on gas 1,183 1,184 1,205 23 20 65 3,680
\n
Average commodity swap price on gas (\u20ac/MWh) 60.1 47.9 52.0 21.0 8.3 7.2
\n
Notional amount on oil 1,076 227 48---1,351
\n
Average commodity swap price on oil ($/bbl) 105.0 93.0 82.0---
\n
Commodity forwards/futures
\n
Notional amount on power 2,906 509 388 294 249 720 5,066
\n
Average commodity forward/future price on power (\u20ac/MWh) 148.1 35.2 17.4 17.8 15.8 15.6
\n
Notional amount on coal/shipping - - - ----
\n
Average commodity forward/future price on coal/shipping ($/ton) - -----
\n
Notional amount on gas 7,171 4,099 229 - - - 11,499
\n
Average commodity forward/future price on gas (\u20ac/MWh) 72.9 92.1 56.6---
\n
Notional amount on CO
\n
2
\n
1,63522650---1,911
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/ton) 81.3 94.9 94.0 - - -
\n
Notional amount on oil 1,263 58----1,321
\n
Average commodity forward/future price on oil ($/bbl) 81.7 73.9 - - - -
\n
Commodity options
\n
Notional amount on power 16 16 16 16 16 117 197
\n
Average commodity option price on power (\u20ac/MWh) 35.0 35.0 35.0 35.0 35.0 33.0
\n
Notional amount on gas -------
\n
Average commodity option price on gas (\u20ac/MWh) ------
\n
Notional amount on oil 70-----70
\n
Average commodity option price on oil ($/bbl) 133-----
\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026
\n
Beyond To ta l
\n
At Dec. 31, 2021
\n
Commodity swap
\n
Notional amount on power 124 164 168 149 146
\n
472 1,223
\n
Average commodity swap price on power (\u20ac/MWh) 51.8 53.7 47.5 46.6 46.0
\n
33.2
\n
Notional amount on gas 131 372 129 11 17 93 753
\n
Average commodity swap price on gas (\u20ac/MWh) 63.8 13.7 12.1 9.4 12.0 9.6
\n
Notional amount on oil 669 244 99 - -
\n
- 1,012
\n
Average commodity swap price on oil ($/bbl) 86.4 92.9 79.4 - -
\n
-
\n
Commodity forwards/futures
\n
Notional amount on power 319 637 302 288 248
\n
856 2,650
\n
Average commodity forward/future price on power (\u20ac/MWh) 29.7 43.3 20.0 19.7 18.7 16.6
\n
Notional amount on coal/shipping 14 - - - -
\n
- 14
\n
Average commodity forward/future price on coal/shipping ($/ton) 90.8----
\n
-
\n
Notional amount on gas 3,315 1,048 5 - - - 4,368
\n
Average commodity forward/future price on gas (\u20ac/MWh) 15.1 18.9 18.0---
\n
Notional amount on CO
\n
2
\n
47661----537
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/t) 46.1 38.4----
\n
Notional amount on oil 600 57 - - - - 657
\n
Average commodity forward/future price on oil ($/bbl) 37.7 51.6---
\n
-
\n
Commodity options
\n
Notional amount on power 10 21 21 21 21
\n
134 228
\n
Average commodity option price on power (\u20ac/MWh) 26.3 29.3 29.9 29.8 29.8
\n
32.6
\n
Notional amount on gas 99----- 99
\n
Average commodity option price gas (\u20ac/MWh) 50.5 - - - -
\n
-
\n

\n\n

\n\n

\n\n
The following table reports the notional amount and fair
\n
value of instruments hedging commodity price risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021, broken down by type of commodity.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives
\n
Cash flow hedges
\n
Derivatives on power:
\n
- swaps 1,213 820 982 640 352 401 (498) (263)
\n
- forwards/futures 1,535 769 89 1,073 3,510 1,881 (898) (598)
\n
- options 218 229 36 49 - - (12) (18)
\n
Total derivatives on power 2,966 1,818 1,107 1,762 3,862 2,282 (1,408) (879)
\n
Derivatives on coal/shipping:
\n
- swaps 9 - 2 - 1,028 - (373) -
\n
- forwards/futures - 14 - 3 - - - -
\n
- options - - - -----
\n
Total derivatives on coal/shipping 9 14 2 3 1,028 - (373) -
\n
Derivatives on gas and oil:
\n
- swaps 2,302 669 666 69 2,729 1,095 (765) (99)
\n
- forwards/futures 4,734 3,094 1,714 2,557 8,085 1,932 (5,182) (5,150)
\n
- options 22 30 4 3 48 70 (4) (26)
\n
Total derivatives on gas and oil 7,058 3,793 2,384 2,629 10,862 3,097 (5,951) (5,275)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps --------
\n
- forwards/futures 1,704 537 143 410 207 - (7) -
\n
- options --------
\n
Total derivatives on CO
\n
2
\n
1,704 537 143 410 207 - (7) -
\n
TOTAL COMMODITY DERIVATIVES 11,737 6,162 3,636 4,804 15,959 5,379 (7,739) (6,154)
\n
The table reports the notional amount and fair value of de-
\n
rivatives hedging commodity price risk at December 31,
\n
2022 and at December 31, 2021, broken down by type of
\n
hedge.
\n
The positive fair value of cash flow hedge derivatives on
\n
commodities regards derivatives on gas and oil commod-
\n
ities in the amount of \u20ac2,384 million, derivatives on CO
\n
2
\n
\n
(\u20ac143 million), derivatives on power (\u20ac1,107 million) and, to
\n
a lesser extent, hedges of coal purchases requested by the
\n
generation companies in the amount of \u20ac2 million.
\n
The first category primarily regards hedges of fluctuations
\n
in the price of natural gas, for both purchases and sales,
\n
carried out for oil commodities and gas products.
\n
The CO
\n
2
\n
category mainly includes hedging transactions
\n
undertaken for Enel Group compliance purposes.
\n
The power category mainly includes medium/long-term
\n
hedging transactions, especially in Spain and North Amer-
\n
ica.
\n
Cash flow hedge derivatives on commodities included in
\n
liabilities regard derivatives on gas and oil commodities in
\n
the amount of \u20ac5,951 million (mainly for derivatives hedg-
\n
ing sales), derivatives on power in the amount of \u20ac1,408
\n
million and, to a lesser extent, derivatives on coal and CO
\n
2
\n
\n
in the amount of respectively \u20ac373 million and \u20ac7 million.
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in com-
\n
ing years from cash flow hedge derivatives on commodity
\n
price risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2022 2023 2024 2025 2026 2027 Beyond
\n
Cash flow hedge derivatives on commodities
\n
Positive fair value 3,838 2,438 829 160 101 93 217
\n
Negative fair value (7,941) (4,598) (2,116) (619) (180) (153) (275)
\n

\n\n

\n\n

\n\n
The following table shows the impact of cash flow hedges
\n
of commodity price risk in the statement of financial posi-
\n
tion at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Notional
\n
amount
\n
Carrying
\n
amount
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Power swaps 1,564 485 469 1,221 377 377
\n
Coal/shipping swaps 1,037 (371) (371) - - -
\n
Gas and oil swaps 5,031 (99) (98) 1,764 (30)
\n
(30)
\n
Power forwards/futures 5,045 (809) (938) 2,675 (223) (223)
\n
Coal/shipping forwards/futures - - - 14 3 3
\n
Gas and oil forwards/futures 12,820 (3,469) (3,673) 5,027 (2,592) (2,592)
\n
CO
\n
2
\n
forwards/futures 1,911 136 138 537 410 410
\n
Power options 218 24 24 204 7 7
\n
Gas and oil options 70 - - 99 (24)
\n
(24)
\n
Total 27,696 (4,103) (4,449) 11,541 (2,072) (2,072)
\n
The following table shows the impact of the hedged item
\n
of cash flow hedges in the statement of financial position
\n
at December 31, 2022 and December 31, 2021.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Hedging
\n
reserve
\n
Hedging
\n
costs
\n
reserve
\n
Ineffective
\n
portion of
\n
carrying
\n
amount
\n
of CFH
\n
derivatives
\n
Future transactions in power 602 (602) 15 (32) (297) 297 -
\n
(29)
\n
Future transactions in coal/shipping 371 (371) - - (3) 3 - -
\n
Future transactions in gas and oil 3,360 (3,360) - (232) 2,751 (2,751) - (2)
\n
Future transactions in CO
\n
2
\n
(133) 133 - - (410) 410 - -
\n
Total 4,200 (4,200) 15 (264) 2,041 (2,041) - (31)
\n
With regard to cash flow hedge derivatives on commodity
\n
prices, the entire commodities market continued to expe-
\n
rience major price swings in 2022. The greatest impact in
\n
terms of changes in the cash flow hedge reserve is attrib-
\n
utable to future transactions in gas, which of all commodi-
\n
ties was the one most affected by the high volatility.
\n
Finally, the ineffectiveness recognized in 2022 on future
\n
transactions in gas is mainly related to proxy hedging op-
\n
erations in Spain.
\n

\n\n

\n\n
51.2 Derivatives at fair value through profit or loss
\n
The following table shows the notional amount and the fair
\n
value of derivatives at FVTPL as at December 31, 2022 and
\n
December 31, 2021.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL
\n
on interest rates:
\n
- interest rate swaps - 50 - 1 100 100 (23) (71)
\n
- interest rate options -----50-(2)
\n
on exchange rates:
\n
- currency forwards 3,659 2,180 75 23 2,102 3,628 (34) (62)
\n
- CCIRS ----46-(1)-
\n
- on commodities
\n
Derivatives on power:
\n
- swaps 595 777 106 (78) 245 1,088 (180) (198)
\n
- forwards/futures 6,903 23,207 872 3,368 5,620 17,970 (908) (2,927)
\n
- options 7 3 15 78 140 113 (172) (16)
\n
Total derivatives on power 7,505 23,987 993 3,368 6,005 19,171 (1,260) (3,141)
\n
Derivatives on coal:
\n
- swaps - 35 - 4 - 133 - 23
\n
- forwards/futures 115 213 21 63 1,291 455 (9) (148)
\n
- options - -------
\n
Total derivatives on coal 115 248 21 67 1,291 588 (9) (125)
\n
Derivatives on gas and oil:
\n
- swaps 1,964 2,904 806 (1,049) 834 4,199 (550) 1,843
\n
- forwards/futures 40,669 19,001 10,456 16,706 38,651 16,755 (10,280) (17,374)
\n
- options 34 232 8 268 33 399 (22) (402)
\n
Total derivatives on gas and oil 42,667 22,137 11,270 15,925 39,518 21,353 (10,852) (15,933)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps --------
\n
- forwards/futures 725 3,079 115 557 361 1,366 (35) (530)
\n
- options 2 - 2 -----
\n
Total derivatives on CO
\n
2
\n
727 3,079 117 557 361 1,366 (35) (530)
\n
Derivatives on other:
\n
- swaps -----1-(1)
\n
- forwards/futures 13 - 72 - 5 - (16) -
\n
- options --------
\n
Total derivatives on other 13 - 72 - 5 1 (16) (1)
\n
Embedded derivatives --------
\n
TOTAL 54,686 51,681 12,548 19,941 49,428 46,257 (12,230) (19,865)
\n
At December 31, 2022 the notional amount of trading de-
\n
rivatives on interest rates came to \u20ac100 million. The neg-
\n
ative fair value of \u20ac23 million improved by \u20ac48 million on
\n
the previous year, mainly due to developments in the yield
\n
curve.
\n
At December 31, 2022, the notional amount of derivatives
\n
on exchange rates was \u20ac5,761 million. The overall decrease
\n
in their notional value of \u20ac47 million and the increase in
\n
the associated net fair value of \u20ac80 million mainly reflected
\n
normal operations and developments in exchange rates.
\n

\n\n
At December 31, 2022, the notional amount of derivatives
\n
on commodities came to \u20ac98,207 million. The fair value
\n
of trading derivatives on commodities classified as as-
\n
sets mainly reflects the market valuation of hedges of gas
\n
and oil amounting to \u20ac11,270 million, derivatives on power
\n
amounting to \u20ac993 million, derivatives on CO
\n
2
\n
amounting
\n
to \u20ac117 million and, to a lesser extent, derivatives on coal
\n
and other commodities totaling \u20ac21 million and \u20ac72 mil-
\n
lion, respectively.
\n
The fair value of trading derivatives on commodities
\n
classified as liabilities mainly regards hedges of gas and
\n
oil amounting to \u20ac10,852 million, derivatives on power
\n
amounting to \u20ac1,260 million and derivatives on CO
\n
2
\n
, coal
\n
and other commodities in the amount of \u20ac35 million, \u20ac9
\n
million and \u20ac16 million, respectively.
\n
These amounts include transactions managed within the
\n
trading portfolios and transactions that, although estab-
\n
lished for hedging purposes, did not meet the require-
\n
ments for hedge accounting.
\n
The \u201cother\u201d category includes hedges using carried out
\n
on guarantees of origin and green certificates, i.e., incen-
\n
tive mechanisms for the production of electricity from re-
\n
newable sources. In addition to commodity price risk, the
\n
Group companies have to manage the risk of fluctuations
\n
in the price of these certificates which were recently af-
\n
fected by greater market volatility compared with the past,
\n
due to the increasing market attention to environmental
\n
sustainability issues.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1010": { "value": "\n

\n

\n
28. Current/Non-current contract assets/(liabilities)
\n\n
Millions of euro Non-current Current
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Contract assets 508 530 106 121
\n
Contract liabilities 5,747 6,214 1,775 1,433
\n

\n\n\n
Non-current assets deriving from contracts with custom-
\n
ers (contract assets) refer mainly to assets under develop-
\n
ment resulting from public-to-private service concession
\n
arrangements recognized in accordance with IFRIC 12 and
\n
which have an expiration of beyond 12 months (\u20ac492 mil-
\n
lion). These cases arise when the concession holder has
\n
not yet obtained full right to recognize the asset from the
\n
grantor, in that there remains a contractual obligation to
\n
ensure that the asset is completed and can be remuner-
\n
ated through rates. The figure at December 31, 2022 in-
\n
cludes investments for the year in the amount of \u20ac1,174
\n
million.
\n

\n\n
Current contract assets mainly concern construction con-
\n
tracts in progress (\u20ac80 million to be invoiced, payments
\n
on which are subject to the fulfillment of a performance
\n
obligation).
\n
The value at December 31, 2022 of non-current contract
\n
liabilities is mainly attributable to distribution operations in
\n
Italy (\u20ac3,127 million) and Spain (\u20ac2,620 million) as a result of
\n
the accounting treatment of revenue from connections of
\n
new customers, which are deferred over the average dura-
\n
tion of the associated contracts.
\n
Current contract liabilities include the contractual liabilities
\n
related to revenue from connections to the electricity grid
\n
expiring within 12 months in the amount of \u20ac1,234 million,
\n
mainly recognized in Italy and Spain, as well as liabilities for
\n
construction contracts in progress (\u20ac509 million).
\n
As required under IFRS 15, the following table reports the
\n
reversal to profit or loss of contract liabilities by time band.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Within 1 year 1,775 1,433
\n
Within 2 years 516 498
\n
Within 3 years 517 480
\n
Within 4 years 516 479
\n
Within 5 years 515 477
\n
More than 5 years 3,683 4,280
\n
Tot al 7,5 2 2 7, 6 4 7
\n

\n", "dimensions": { "concept": "enel:DisclosureOfContractAssetsLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1014": { "value": "\n

\n

\n

\n
29. Other non-current financial assets - \u20ac8,359 million
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Equity investments in other companies measured at fair value 366 72 294 -
\n
Financial assets and securities included in net financial debt (see note 29.1) 4,213 2,692 1,521 56.5%
\n
Service concession arrangements 3,732 2,890 842 29.1%
\n
Non-current financial prepayments 48 50 (2) -4.0%
\n
Tot al 8,359 5,704 2,655 46.5%
\n
\n\n

\n\n\n
\u201cOther non-current financial assets\u201d increased by \u20ac2,655
\n
million mainly reflecting:
\n
\u2022 the increase in financial assets included in net financial
\n
debt, as detailed in note 29.1;
\n
\u2022 the increase in financial assets in respect of service con-
\n
cession arrangements, mainly in Brazil;
\n
\u2022 the recognition of the investment in Zacapa Topco, fol-
\n
lowing the sale by Enel X International of a 1.1% share
\n
in Ufinet which resulted in the loss of joint control over
\n
Zacapa Topco.
\n

\n

\n\n
The following is a breakdown of equity investments in oth-
\n
er companies measured at fair value.
\n
Millions of euro
\n
at Dec. 31,
\n
2022 % held
\n
at Dec. 31,
\n
2021 % held Change
\n
Empresa Propietaria de la Red SA 7 11.1% 5 11.1% 2
\n
European Energy Exchange AG 22 2.4% 13 2.4% 9
\n
Athonet Srl 7 16.0% 7 16.0% -
\n
Korea Line Corporation 1 0.3% 1 0.3% -
\n
Hubject GmbH 11 12.5% 10 12.5% 1
\n
Termoel\u00e9ctrica Jos\u00e9 de San Mart\u00edn SA 11 4.2% 11 4.2% -
\n
Termoel\u00e9ctrica Manuel Belgrano SA 9 4.7% 12 4.7% (3)
\n
Zacapa Topco S\u00e0rl 288 19.5% - - 288
\n
Other 10 13 (3)
\n
Tot al 366 72 294
\n
29.1 Other non-current financial assets included in net financial debt \u2013 \u20ac4,213 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Securities 447 403 44 10.9%
\n
Other financial assets 3,766 2,289 1,477 64.5%
\n
Tot al 4,213 2,692 1,521 56.5%
\n
\u201cSecurities\u201d are represented by financial instruments in
\n
which the Dutch insurance companies invest a portion of
\n
their liquidity. The increase in \u201cOther financial assets\u201d is
\n
mainly attributable to an increase in financial assets for se-
\n
curity deposits.
\n

\n\n
30. Other current financial assets \u2013 \u20ac13,753 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Current financial assets included in net financial debt (see note 30.1) 13,501 8,467 5,034 59.5%
\n
Other 252 178 74 41.6%
\n
Tot al 13,753 8,645 5,108 59.1%
\n
\u201cOther current financial assets\u201d increased by \u20ac5,108 mil-
\n
lion, mainly reflecting the increase in current financial as-
\n
sets included in net financial debt, as detailed in note 30.1.
\n
30.1 Other current financial assets included in net financial debt \u2013 \u20ac13,501 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Current portion of long-term financial assets 2,838 1,538 1,300 84.5%
\n
Securities at FVTPL - 1 (1) -
\n
Securities at FVOCI 78 87 (9) -10.3%
\n
Financial assets and cash collateral 8,319 6,485 1,834 28.3%
\n
Other 2,266 356 1,910 -
\n
Tot al 13,501 8,467 5,034 59.5%
\n
The increase in the item is mainly attributable to:
\n
\u2022 \u20ac1,300 million in respect of an increase in the current
\n
portion of long-term financial assets, which essentially
\n
reflects the increase in financial assets relating to the
\n
deficit of the Spanish electricity system;
\n
\u2022 \u20ac1,834 million in respect of an increase in cash collateral
\n
paid to counterparties for derivatives transactions;
\n
\u2022 an increase in \u201cOther\u201d, mainly reflecting the increase in
\n
short-term financial assets of Enel X Italia in respect of
\n
the assignment of tax credits for building renovations
\n
under the \u201ceco-sisma bonus\u201d program (\u20ac557 million) and
\n
the increase in financial assets in Brazil (\u20ac1,210 million)
\n
essentially relating to the sale of Celg Distribui\u00e7\u00e3o SA -
\n
Celg-D (Enel Goi\u00e1s).
\n

\n\n
48.1 Financial assets by category
\n
The following table reports the carrying amount for each
\n
category of financial asset provided for under IFRS 9, bro-
\n
ken down into current and non-current financial assets,
\n
showing hedging derivatives and derivatives measured at
\n
fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Financial assets at amortized cost 48.1.1 5,731 4,092 40,057 34,671
\n
Financial assets at FVOCI 48.1.2 901 706 279 144
\n
Financial assets at fair value through profit or loss
\n
Derivative financial assets at FVTPL 48.1.3 473 277 12,075 19,664
\n
Other financial assets at FVTPL 48.1.3 3,442 2,662 1,049 141
\n
Total financial assets at fair value through profit or loss 3,915 2,939 13,124 19,805
\n
Derivative financial assets designated as hedging instruments
\n
Fair value hedge derivatives 48.1.4 37 61 - -
\n
Cash flow hedge derivatives 48.1.4 3,460 2,434 2,755 3,127
\n
Total derivative financial assets designated as hedging instruments 3,497 2,495 2,755 3,127
\n
TOTAL 14,044 10,232 56,215 57,747
\n
For more information on the recognition and classification
\n
of current and non-current derivative assets, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n
For more information on fair value measurement, see note
\n
52 \u201cAssets and liabilities measured at fair value\u201d.
\n

\n\n

\n\n

\n

\n
48.1.1 Financial assets measured at amortized cost
\n
The following table reports financial assets measured at
\n
amortized cost by nature, broken down into current and
\n
non-current financial assets.
\n\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Cash and cash equivalents - - 35 10,169 8,759
\n
Trade receivables 34 1,388 1,301 34 15,217 14,775
\n
Current portion of long-term loan assets - - 30.1 2,838 1,538
\n
Cash collateral - - 30.1 8,319 6,485
\n
Other financial assets 29.1 3,766 2,289 30.1 2,090 315
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 295 260 29 12 64
\n
Other financial assets at amortized cost 282 242 1,412 2,735
\n
Tot al 5,731 4,092 40,057 34,671
\n

\n\n
Impairment of financial assets at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac45,788 million at December 31, 2022 (\u20ac38,763 million at
\n
December 31, 2021) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,087 million at De-
\n
cember 31, 2022 (\u20ac4,051 million at the end of the previous
\n
year).
\n
The Group mainly has the following types of financial as-
\n
sets measured at amortized cost subject to impairment
\n
testing:
\n
\u2022 cash and cash equivalents;
\n
\u2022 trade receivables and contract assets;
\n
\u2022 loan assets;
\n
\u2022 other financial assets.
\n
While cash and cash equivalents are also subject to the
\n
impairment requirements of IFRS 9, the identified impair-
\n
ment loss was immaterial.
\n\n
The expected credit loss (ECL) \u2013 determined using proba-
\n
bility of default (PD), loss given default (LGD) and exposure
\n
at default (EAD) \u2013 is the difference between all contractual
\n
cash flows that are due in accordance with the contract
\n
and all cash flows that are expected to be received (i.e., all
\n
shortfalls) discounted at the original effective interest rate
\n
(EIR).
\n
For calculating ECL, the Group applies two different ap-
\n
proaches:
\n
\u2022 the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receivables.
\n
This approach, based on an assessment of any signif-
\n
icant increase in credit risk since initial recognition, is
\n
performed comparing the PD at origination with PD at
\n
the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss al-
\n
lowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e., staging):
\n
\u2013 12-month ECL, for financial assets for which there has
\n
not been a significant increase in credit risk since ini-
\n
tial recognition;
\n
\u2013 lifetime ECL, for financial assets for which there has
\n
been a significant increase in credit risk or which are
\n
credit impaired (i.e., defaulted based on past due in-
\n
formation);
\n
\u2022 the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a significant
\n
financing component, based on lifetime ECL without
\n
tracking changes in credit risk.
\n
A forward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
future events and macroeconomic developments that
\n
could impact the risk associated with the portfolio or fi-
\n
nancial instrument.
\n
Depending on the nature of the financial assets and the
\n
credit risk information available, the assessment of the in-
\n
crease in credit risk can be performed on:
\n
\u2022 an individual basis, if the receivables are individually sig-
\n
nificant and for all receivables which have been individ-
\n
ually identified for impairment based on reasonable and
\n
supportable information;
\n
\u2022 a collective basis, if no reasonable and supportable in-
\n
formation is available without undue cost or effort to
\n
measure expected credit losses on an individual instru-
\n
ment basis.
\n
When there is no reasonable expectation of recovering a
\n
financial asset in its entirety or a portion thereof, the gross
\n
carrying amount of the financial asset shall be reduced.
\n
A write-off represents a derecognition event (e.g., the right
\n
to cash flows is legally or contractually extinguished, trans-
\n
ferred or expired).
\n

\n

\n\n

\n\n

\n\n

\n\n
The following table reports expected credit losses on fi-
\n
nancial assets measured at amortized cost on the basis of
\n
the general simplified approach.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Gross amount
\n
Expected
\n
credit loss
\n
allowance Total Gross amount
\n
Expected
\n
credit loss
\n
allowance Total
\n
Cash and cash equivalents 10,169 - 10,169 8,759 - 8,759
\n
Trade receivables 20,388 3,783 16,605 19,739 3,663 16,076
\n
Loan assets 17,261 248 17,013 10,861 234 10,627
\n
Other financial assets at amortized cost 2,057 56 2,001 3,455 154 3,301
\n
Total 49,875 4,087 45,788 42,814 4,051 38,763
\n
To measure expected losses, the Group assesses trade re-
\n
ceivables and contract assets with the simplified approach,
\n
both on an individual basis (e.g., government entities, au-
\n
thorities, financial counterparties, wholesale sellers, traders
\n
and large companies, etc.) and a collective basis (e.g., retail
\n
customers).
\n
In the case of individual assessments, PD is generally ob-
\n
tained from external providers.
\n
Otherwise, in the case of collective assessments, trade re-
\n
ceivables are grouped on the basis of their shared credit risk
\n
characteristics and information on past due positions, con-
\n
sidering a specific definition of default.
\n
Based on each business and local regulatory framework, as
\n
well as differences between customer portfolios, including
\n
their default and recovery rates (comprising expectations
\n
for recovery beyond 90 days):
\n
\u2022 the Group mainly defines a defaulted position as one that
\n
is 180 days past due. Accordingly, beyond this time lim-
\n
it, trade receivables are presumed to be credit impaired);
\n
and
\n
\u2022 specific clusters are defined on the basis of specific mar-
\n
kets, business and risk characteristics.
\n
Contract assets substantially have the same risk character-
\n
istics as trade receivables for the same types of contracts.
\n
In order to measure the ECL for trade receivables on a col-
\n
lective basis, as well as for contract assets, the Group uses
\n
the following assumptions regarding the ECL parameters:
\n
\u2022 PD, assumed equal to the average default rate, is calculat-
\n
ed by cluster and considering historical data from at least
\n
24 months;
\n
\u2022 LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022 EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices is-
\n
sued but not past due and invoices to be issued.
\n
Despite the deterioration in the collection status of certain
\n
customer segments, which was taken into consideration in
\n
determining impairment of trade receivables, the Group\u2019s
\n
portfolio has so far demonstrated resilience to the mac-
\n
roeconomic context and the current price scenario. This
\n
reflects the expansion of digital collection channels and a
\n
solid diversification of commercial customers.
\n
The following table reports changes in the allowance for ex-
\n
pected credit losses on loan assets in accordance with the
\n
general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 65 143
\n
Accruals -9
\n
Uses --
\n
Reversals to profit or loss (25) (9)
\n
Other changes 25 26
\n
Closing balance at Dec. 31, 2021 65 169
\n
Opening balance at Jan. 1, 2022 65 169
\n
Accruals 22 5
\n
Uses --
\n
Reversals to profit or loss - (11)
\n
Other changes (58) 56
\n
Closing balance at Dec. 31, 2022 29 219
\n

\n\n

\n\n

\n

\n\n
The following table reports changes in the allowance for
\n
expected credit losses on trade receivables in accordance
\n
with the simplified approach.
\n
Millions of euro
\n
Opening balance at Jan. 1, 2021 3,287
\n
Accruals 1,285
\n
Uses 709
\n
Reversals to profit or loss (202)
\n
Other changes (1,416)
\n
Closing balance at Dec. 31, 2021 3,663
\n
Opening balance at Jan. 1, 2022 3,663
\n
Accruals 1,375
\n
Uses (766)
\n
Reversals to profit or loss (265)
\n
Other changes (224)
\n
Closing balance at Dec. 31, 2022 3,783
\n
The following table reports changes in the allowance for
\n
expected credit losses on other financial assets at amor-
\n
tized cost in accordance with the simplified approach.
\n
Millions of euro ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 129
\n
Accruals 94
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (68)
\n
Closing balance at Dec. 31, 2021 154
\n
Opening balance at Jan. 1, 2022 154
\n
Accruals 180
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (277)
\n
Closing balance at Dec. 31, 2022 56
\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\n\n\n
48.1.2 Financial assets at fair value through other
\n
comprehensive income
\n
The following table shows financial assets at fair value
\n
through other comprehensive income by nature, broken
\n
down into current and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Investments in other companies at FVOCI 29 360
\n
40 --
\n
Securities 29.1 447 403 30.1 78 87
\n
Receivables and other financial assets at FVOCI 94
\n
263 201 57
\n
Tot al 901 706 279 144
\n

\n\n

\n\n

\n

\n\n
Changes in financial assets at FVOCI
\n
Investments in other companies
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 40 -
\n
Purchases 2-
\n
Sales -
\n
-
\n
Changes in fair value through OCI --
\n
Other changes (2)
\n
-
\n
Closing balance at Dec. 31, 2021 40 -
\n
Opening balance at Jan. 1, 2022 40
\n
-
\n
Purchases 149 -
\n
Sales -
\n
-
\n
Changes in fair value through OCI 11 -
\n
Other changes 160
\n
-
\n
Closing balance at Dec. 31, 2022 360 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 551 102
\n
Purchases 165 -
\n
Sales (87)
\n
-
\n
Changes in fair value through OCI 2-
\n
Reclassifications (85) 85
\n
Other changes 120
\n
(43)
\n
Closing balance at Dec. 31, 2021 666 144
\n
Opening balance at Jan. 1, 2022 666
\n
144
\n
Purchases 225 -
\n
Sales (41)
\n
(14)
\n
Changes in fair value through OCI (38) -
\n
Reclassifications (102) 102
\n
Other changes (168)
\n
47
\n
Closing balance at Dec. 31, 2022 541 279
\n

\n\n\n

\n\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n

\n\n

\n\n
48.1.4 Derivative financial assets designated as hedging
\n
instruments
\n
For more information on derivative financial assets, please
\n
see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1015": { "value": "\n
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Equity investments in other companies measured at fair value 366 72 294 -
\n
Financial assets and securities included in net financial debt (see note 29.1) 4,213 2,692 1,521 56.5%
\n
Service concession arrangements 3,732 2,890 842 29.1%
\n
Non-current financial prepayments 48 50 (2) -4.0%
\n
Tot al 8,359 5,704 2,655 46.5%
\n
\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsOtherThanInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1018": { "value": "\n

\n\n

\n
31. Other non-current assets \u2013 \u20ac2,486 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 282 242 40 16.5%
\n
Net assets of personnel programs 8 - 8 -
\n
Other 2,196 3,026 (830) -27.4%
\n
Tot al 2,486 3,268 (782) -23.9%
\n

\n\n
Amounts due from institutional market operators in-
\n
creased by \u20ac40 million, mainly in Spain as a result of the
\n
remuneration of distribution operations.
\n
Other assets at December 31, 2022 included tax assets in
\n
the amount of \u20ac1,674 million (\u20ac2,286 million at December
\n
31, 2021) and security deposits in the amount of \u20ac301 mil-
\n
lion (\u20ac340 million at the end of 2021).
\n
The change for the year mainly reflected the decline in tax
\n
assets previously recognized in Brazil, connected with the
\n
PIS/COFINS dispute in the amount of \u20ac253 million, and a
\n
decrease in assets connected with the sale of a number
\n
of Brazilian companies in the amount of \u20ac976 million, only
\n
partially offset by positive exchange rate developments in
\n
the amount of \u20ac543 million.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1017": { "value": "\n

\n
31. Other non-current assets \u2013 \u20ac2,486 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 282 242 40 16.5%
\n
Net assets of personnel programs 8 - 8 -
\n
Other 2,196 3,026 (830) -27.4%
\n
Tot al 2,486 3,268 (782) -23.9%
\n

\n\n
Amounts due from institutional market operators in-
\n
creased by \u20ac40 million, mainly in Spain as a result of the
\n
remuneration of distribution operations.
\n
Other assets at December 31, 2022 included tax assets in
\n
the amount of \u20ac1,674 million (\u20ac2,286 million at December
\n
31, 2021) and security deposits in the amount of \u20ac301 mil-
\n
lion (\u20ac340 million at the end of 2021).
\n
The change for the year mainly reflected the decline in tax
\n
assets previously recognized in Brazil, connected with the
\n
PIS/COFINS dispute in the amount of \u20ac253 million, and a
\n
decrease in assets connected with the sale of a number
\n
of Brazilian companies in the amount of \u20ac976 million, only
\n
partially offset by positive exchange rate developments in
\n
the amount of \u20ac543 million.
\n

\n\n

\n

\n

\n
32. Other current assets \u2013 \u20ac4,314 million
\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 1,033 2,205 (1,172) -53.2%
\n
Advances to suppliers 332 326 6 1.8%
\n
Amounts due from employees 30 29 1 3.4%
\n
Amounts due from others 1,056 1,071 (15) -1.4%
\n
Sundry tax assets 1,598 1,164 434 37.3%
\n
Current accrued income and prepayments 265 207 58 28.0%
\n
Tot al 4,314 5,002 (688) -13.8%
\n

\n\n

\n\n
Amounts due from institutional market operators main-
\n
ly include amounts due in respect of the Italian system in
\n
the amount of \u20ac617 million (\u20ac1,519 million at December
\n
31, 2021) and the Spanish system in the amount of \u20ac388
\n
million (\u20ac667 million at December 31, 2021). The decrease
\n
was essentially attributable to the decrease in amounts re-
\n
ceivable in Italy in respect of the Energy and Environmental
\n
Services Fund, mainly held by e-distribuzione (\u20ac429 mil-
\n
lion) and Servizio Elettrico Nazionale (\u20ac106 million), primar-
\n
ily connected with equalization mechanisms.
\n\n
The increase of \u20ac434 million in sundry tax assets is mainly
\n
attributable to an increase in credits for indirect taxes and
\n
duties in Italy (\u20ac216 million), Latin America (\u20ac100 million)
\n
and in the parent company Enel SpA (\u20ac282 million), partially
\n
offset by a decline in such items in Spain (\u20ac115 million) and
\n
North America (\u20ac93 million).
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1019": { "value": "\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 282 242 40 16.5%
\n
Net assets of personnel programs 8 - 8 -
\n
Other 2,196 3,026 (830) -27.4%
\n
Tot al 2,486 3,268 (782) -23.9%
\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 1,033 2,205 (1,172) -53.2%
\n
Advances to suppliers 332 326 6 1.8%
\n
Amounts due from employees 30 29 1 3.4%
\n
Amounts due from others 1,056 1,071 (15) -1.4%
\n
Sundry tax assets 1,598 1,164 434 37.3%
\n
Current accrued income and prepayments 265 207 58 28.0%
\n
Tot al 4,314 5,002 (688) -13.8%
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1022": { "value": "\n

\n\n

\n

\n

\n
32. Other current assets \u2013 \u20ac4,314 million
\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 1,033 2,205 (1,172) -53.2%
\n
Advances to suppliers 332 326 6 1.8%
\n
Amounts due from employees 30 29 1 3.4%
\n
Amounts due from others 1,056 1,071 (15) -1.4%
\n
Sundry tax assets 1,598 1,164 434 37.3%
\n
Current accrued income and prepayments 265 207 58 28.0%
\n
Tot al 4,314 5,002 (688) -13.8%
\n

\n\n

\n\n
Amounts due from institutional market operators main-
\n
ly include amounts due in respect of the Italian system in
\n
the amount of \u20ac617 million (\u20ac1,519 million at December
\n
31, 2021) and the Spanish system in the amount of \u20ac388
\n
million (\u20ac667 million at December 31, 2021). The decrease
\n
was essentially attributable to the decrease in amounts re-
\n
ceivable in Italy in respect of the Energy and Environmental
\n
Services Fund, mainly held by e-distribuzione (\u20ac429 mil-
\n
lion) and Servizio Elettrico Nazionale (\u20ac106 million), primar-
\n
ily connected with equalization mechanisms.
\n\n
The increase of \u20ac434 million in sundry tax assets is mainly
\n
attributable to an increase in credits for indirect taxes and
\n
duties in Italy (\u20ac216 million), Latin America (\u20ac100 million)
\n
and in the parent company Enel SpA (\u20ac282 million), partially
\n
offset by a decline in such items in Spain (\u20ac115 million) and
\n
North America (\u20ac93 million).
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1020": { "value": "\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due from institutional market operators 1,033 2,205 (1,172) -53.2%
\n
Advances to suppliers 332 326 6 1.8%
\n
Amounts due from employees 30 29 1 3.4%
\n
Amounts due from others 1,056 1,071 (15) -1.4%
\n
Sundry tax assets 1,598 1,164 434 37.3%
\n
Current accrued income and prepayments 265 207 58 28.0%
\n
Tot al 4,314 5,002 (688) -13.8%
\n

\n\n
The increase of \u20ac434 million in sundry tax assets is mainly
\n
attributable to an increase in credits for indirect taxes and
\n
duties in Italy (\u20ac216 million), Latin America (\u20ac100 million)
\n
and in the parent company Enel SpA (\u20ac282 million), partially
\n
offset by a decline in such items in Spain (\u20ac115 million) and
\n
North America (\u20ac93 million).
\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n
\u2022 the decrease in \u201cOther tax liabilities\u201d, mainly attributable
\n
to Italy following the start in 2021 of the Group settlement
\n
mechanism for VAT obligations by the Parent, Enel SpA;
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1021": { "value": "\n
33. Inventories \u2013 \u20ac4,853 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Raw and ancillary materials, and consumables:
\n
- fuels 2,396 1,023 1,373 -
\n
- materials, equipment and other inventories 2,155 1,793 362 20.2%
\n
Tot al 4,551 2,816 1,735 61.6%
\n
Environmental certificates:
\n
- CO
\n
2
\n
emissions allowances 152 139 13 9.4%
\n
- green certificates - 3 (3) -
\n
- energy efficiency certificates 6 16 (10) -62.5%
\n
Tot al 158 158--
\n
Buildings held for sale 47 49 (2) -4.1%
\n
Payments on account 97 86 11 12.8%
\n
TOTAL 4,853 3,109 1,744 56.1%
\n
Raw and ancillary materials, and consumables consist of
\n
materials and equipment used to operate, maintain, and
\n
construct power plants and distribution networks, as well
\n
as fuel inventories to cover the Group\u2019s requirements for
\n
generation and trading activities.
\n
The overall increase in inventories in 2022 (\u20ac1,744 million) is
\n
mainly attributable to an increase in inventories of fuel and
\n
materials, devices and other inventories recorded above all
\n
in Italy (\u20ac1,221 million), Spain (\u20ac506 million) and Latin Amer-
\n
ica (\u20ac69 million), notably gas inventories to meet the needs
\n
of the Group plants and an increase in stocks of low- and
\n
medium-voltage materials, partially offset by the decrease
\n
in inventories in Russia and Romania (\u20ac100 million).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1024": { "value": "\n
34. Trade receivables \u2013 \u20ac16,605 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Customers:
\n
- electricity sales and transport 10,216 10,111 105 1.0%
\n
- distribution and sale of gas 3,026 2,658 368 13.8%
\n
- other assets 3,118 3,158 (40) -1.3%
\n
Total trade receivables due from customers 16,360 15,927 433 2.7%
\n
Trade receivables due from associates and joint ventures 245 149 96 64.4%
\n
TOTAL 16,605 16,076 529 3.3%
\n
Trade receivables due from customers are recognized net
\n
of loss allowances, which totaled \u20ac3,783 million at the end
\n
of the year, compared with a balance of \u20ac3,663 million at
\n
the end of the previous year.
\n
Specifically, the increase in 2022, totaling \u20ac529 million,
\n
mainly recognized in Spain (\u20ac530 million) and Latin Amer-
\n
ica (\u20ac554 million), was partially offset by the decrease rec-
\n
ognized in Italy (\u20ac106 million) and Romania (\u20ac500 million),
\n
which, in line with the provisions of \u201cIFRS 5 - Non-current
\n
assets held for sale and discontinued operations\u201d, was
\n
classified as held for sale.
\n
The change in the period is attributable to receivables for
\n
electricity and gas sales and transport recognized in the
\n
year, as well as the increase in allocations net of releases in
\n
respect of bad debt provisions in Italy and Latin America.
\n
For more information on trade receivables, see note 48
\n
\u201cFinancial instruments by category\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1025": { "value": "\n
35. Cash and cash equivalents \u2013 \u20ac11,041 million
\n
Cash and cash equivalents, detailed in the following table,
\n
increased by \u20ac2,183 million due to proceeds from the sale
\n
in December 2022 of Enel Transmisi\u00f3n Chile, Gridspertise
\n
and Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Bank and postal deposits 8,968 8,118 850 10.5%
\n
Cash and cash equivalents on hand 35 8 27 -
\n
Other investments of liquidity 2,038 732 1,306 -
\n
Tot al 11,041 8,858 2,183 24.6%
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1039": { "value": "\n
36. Assets and liabilities included in disposal groups classified as held for sale \u2013 \u20ac6,149
\n
million and \u20ac3,360 million
\n
Changes in assets held for sale in 2022 break down as fol-
\n
lows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-
\n
current assets
\n
Disposals and
\n
change in
\n
consolidation
\n
scope Impairment
\n
Exchange
\n
differences Investments
\n
Other
\n
changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Property, plant and equipment 899 5,231 (1,848) (1,102) 18 47 59 3,304
\n
Intangible assets 144 1,985 (1,136) (797) 23 17 98 334
\n
Goodwill 1 550 (62) (488) (42) - 41 -
\n
Deferred tax assets 16 578 (408) - - - 25 211
\n
Equity-accounted investments 4 27 (2) (1) - - (1) 27
\n
Non-current contract assets - 227 (233) - (2) 84 (76) -
\n
Other non-current assets 40 750 (639) - - - (26) 125
\n
Non-current financial assets - 208 (144) - (12) - 86 138
\n
Current financial assets and
\n
securities
\n
- 113 (65) - - - (5) 43
\n
Other current financial assets - 75 - - 8 - (74) 9
\n
Cash and cash equivalents 44 587 (287) - (4) - 85 425
\n
Inventories, trade receivables
\n
and other current assets
\n
94 2,353 (1,054) - (8) - 148 1,533
\n
Total 1,242 12,684 (5,878) (2,388) (19) 148 360 6,149
\n
Developments in liabilities break down as follows.
\n
Millions of euro
\n
Reclassification
\n
from/to current
\n
and non-current
\n
liabilities
\n
Disposals and
\n
change in
\n
consolidation
\n
scope
\n
Exchange
\n
differences Other changes
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Long-term borrowings 782 1,160 (1,259) 33 59 775
\n
Provisions for risks and charges,
\n
non-current portion
\n
10 272 (242) 1 (8) 33
\n
Deferred tax liabilities 46 441 (207) - (40) 240
\n
Post-employment and other
\n
employee benefits
\n
-65(42)--23
\n
Non-current financial liabilities 40 123 (5) (10) (79) 69
\n
Non-current contract liabilities - 447 (5) (2) 2 442
\n
Other non-current liabilities 5 649 (597) (3) 125 179
\n
Short-term borrowings 2 651 (17) (9) 15 642
\n
Long-term borrowings, current
\n
portion
\n
- 137 (1,328) (29) 1,238 18
\n
Provisions for risks and charges,
\n
current portion
\n
-47(14) - -33
\n
Other current financial liabilities 6 28 (57) (1) 36 12
\n
Trade payables and other
\n
current liabilities
\n
71 1,663 (828) 4 (16) 894
\n
Total 962 5,683 (4,601) (16) 1,332 3,360
\n

\n\n
The item essentially includes assets measured at the lower
\n
of cost, understood as their net carrying amount, and the
\n
estimated realizable value, which, due to management de-
\n
cisions, meet the requirements of \u201cIFRS 5 - Non-current
\n
assets held for sale and discontinued operations\u201d for their
\n
classification in this item.
\n
The balances of assets and liabilities held for sale and
\n
discontinued operations at December 31, 2022 came to,
\n
respectively, \u20ac6,149 million and \u20ac3,360 million and mainly
\n
refer to:
\n
\u2022 Romania: on December 14, 2022, Enel SpA announced
\n
that it had entered into an Exclusivity Agreement with
\n
Greek company Public Power Corporation SA (PPC) in
\n
relation to the potential disposal of all the equity stakes
\n
held by Enel Group in Romania. The value of the net as-
\n
sets held in Romania was thus adjusted to the expected
\n
sale price, with the recognition of an impairment loss of
\n
about \u20ac696 million, and the same were classified as \u201cdis-
\n
continued operations\u201d;
\n
\u2022 Enel Green Power Hellas: the parent company Enel Green
\n
Power has started a process aimed at finding an investor
\n
interested in a partnership for the management and de-
\n
velopment of the renewable energy business in Greece.
\n
The status of negotiations suggests that the sale is high-
\n
ly probable as at December 31, 2022. Accordingly, the
\n
requirements established by \u201cIFRS 5 - Non-current as-
\n
sets held for sale and discontinued operations\u201d for the
\n
classification of Greek assets as \u201cdiscontinued opera-
\n
tions\u201d have been met;
\n
\u2022 Enel Green Power Australia: considering the status of
\n
negotiations, the two subholding companies held in
\n
Australia and their subsidiaries have been reclassified
\n
under non-current assets held for sale and discontin-
\n
ued operations, in accordance with IFRS 5, with the aim
\n
of reaching an agreement with third parties within the
\n
Stewardship business model in the next 12 months;
\n
\u2022 Central Dock Sud and Enel Generaci\u00f3n Costanera in Ar-
\n
gentina: the Enel Group, through its subsidiary Enel Ar-
\n
gentina, started negotiations for the sale of the Group\u2019s
\n
75.7% stake in the thermal generation company Enel
\n
Generaci\u00f3n Costanera. Negotiations also covered the
\n
sale of the Group\u2019s 41.2% stake in the thermal genera-
\n
tion company Central Dock Sud. The net assets of the
\n
interests were classified as available for sale and their
\n
value was adjusted to the expected sale price (\u20ac97 mil-
\n
lion), with the recognition of an impairment loss of about
\n
\u20ac290 million. The transaction was finalized in the 1st
\n
Quarter of 2023;
\n
\u2022 Avikiran Solar India Private Limited in India: following the
\n
agreements signed for the partial sale to a new share-
\n
holder, the investment satisfies the requirements of
\n
\u201cIFRS 5 - Non-current assets held for sale and discon-
\n
tinued operations\u201d, for classification of the net assets as
\n
available for sale. The disposal is expected to be finalized
\n
in the 1st Half of 2023;
\n
\u2022 3SUN in Italy: based on the negotiation process for the
\n
sale of a 50% stake in the share capital of 3SUN Srl, its
\n
net assets were reclassified at December 31, 2022 as
\n
non-current assets held for sale and discontinued oper-
\n
ations, in line with IFRS 5.
\n
Assets previously classified as held for sale disposed of in
\n
2022 include:
\n
\u2022 renewable companies in South Africa sold in the 1st Half
\n
of 2022;
\n
\u2022 CGT Fortaleza in Brazil and companies belonging to the
\n
financial sector of Enel X in Italy sold in the 3rd Quarter;
\n
\u2022 the interest held by Enel SpA in Enel Russia sold in Octo-
\n
ber 2022, thus completing the disposal of all electricity
\n
generation assets in Russia. For more information on the
\n
economic effects of the transaction, please refer to the
\n
paragraph \u201cDiscontinued operations\u201d;
\n
\u2022 the subsidiary Enel Chile SA completed the sale of the
\n
entire investment, equal to 99.09% of the share capi-
\n
tal, held in the Chilean electricity transmission company
\n
Enel Transmisi\u00f3n Chile SA, while the subsidiary Enel Bra-
\n
sil SA finalized the sale of the entire interest held in the
\n
Brazilian power distribution company Celg Distribui\u00e7\u00e3o
\n
SA - Celg-D in December 2022.
\n
For more information on the financial effects of the above
\n
transactions, please refer to the note \u201cBusiness combina-
\n
tions\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1026": { "value": "\n

\n

\n

\n
37. Equity \u2013 \u20ac42,082 million
\n
37.1 Equity attributable to owners of the Parent \u2013 \u20ac28,657 million
\n
Millions of euro
\n
2022 2021 Change
\n
Share capital 10,167 10,167 -
\n
Treasury share reserve (47) (36) (11)
\n
Other reserves 2,740 1,721 1,019
\n
Share premium reserve 7,496 7,496 -
\n
Reserve for equity instruments - perpetual hybrid bonds 5,567 5,567 -
\n
Legal reserve 2,034 2,034 -
\n
Other reserves 2,332 2,313 19
\n
Translation reserve (5,912) (8,125) 2,213
\n
Hedging reserve (3,553) (2,268) (1,285)
\n
Hedging costs reserve (81) (39) (42)
\n
Reserve from measurement of financial instruments at FVOCI (22) 10 (32)
\n
Reserve from equity-accounted investments (476) (721) 245
\n
Actuarial reserve (1,063) (1,325) 262
\n
Reserve from disposal of equity interests without loss of control (2,390) (2,378) (12)
\n
Reserve from acquisitions of non-controlling interests (1,192) (843) (349)
\n
Retained earnings 15,797 17,801 (2,004)
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n\n
Share capital \u2013 \u20ac10,167 million
\n
At December 31, 2022, the fully subscribed and paid-up
\n
share capital of Enel SpA totaled \u20ac10,166,679,946, rep-
\n
resented by the same number of ordinary shares with a
\n
par value of \u20ac1.00 each. Enel SpA\u2019s share capital was un-
\n
changed compared with the amount reported at Decem-
\n
ber 31, 2021.
\n
At December 31, 2022, based on the shareholders register
\n
and the notices submitted to CONSOB and received by the
\n
Parent pursuant to Article 120 of Legislative Decree 58 of
\n
February 24, 1998, as well as other available information,
\n
shareholders with interests of greater than 3% in the Par-
\n
ent\u2019s share capital were the Ministry for the Economy and
\n
Finance (with a 23.585% stake) and BlackRock Inc. (with a
\n
5.114% stake held for asset management purposes).
\n

\n\n\n
Treasury share reserve - \u20ac(47) million
\n
At December 31, 2022, treasury shares are represented by
\n
7,153,795 ordinary shares of Enel SpA with a par value of
\n
\u20ac1.00 each (4,889,152 at December 31, 2021), purchased
\n
through an authorized intermediary for a total of \u20ac47 mil-
\n
lion.
\n

\n\n\n
Other reserves - \u20ac2,740 million
\n
Share premium reserve - \u20ac7,496 million
\n
Pursuant to Article 2431 of the Italian Civil Code, the share
\n
premium reserve contains, in the case of the issue of
\n
shares at a price above par, the difference between the is-
\n
sue price of the shares and their par value, including those
\n
resulting from conversion from bonds. The reserve, which
\n
is a capital reserve, may not be distributed until the legal
\n
reserve has reached the threshold established under Arti-
\n
cle 2430 of the Italian Civil Code.
\n
Reserve for equity instruments - perpetual hybrid bonds
\n
- \u20ac5,567 million
\n
This reserve reports the nominal value, net of transaction
\n
costs, of the non-convertible subordinated perpetual hy-
\n
brid bonds denominated in euros for international inves-
\n
tors.
\n
In 2022, the Group paid \u20ac123 million in coupons to holders
\n
of perpetual hybrid bonds.
\n
Legal reserve - \u20ac2,034 million
\n
The legal reserve is formed of the part of profits that, pur-
\n
suant to Article 2430 of the Italian Civil Code, cannot be
\n
distributed as dividends.
\n

\n\n

\n\n

\n\n
Other reserves - \u20ac2,332 million
\n
These include \u20ac2,215 million related to the remaining por-
\n
tion of the adjustments carried out when Enel was trans-
\n
formed from a public entity to a joint-stock company.
\n
Pursuant to Article 47 of the Consolidated Income Tax
\n
Code (Testo Unico Imposte sul Reddito, or \u201cTUIR\u201d), this
\n
amount does not constitute taxable income when distrib-
\n
uted.
\n
Translation reserve - \u20ac(5,912) million
\n
The increase for the year, of \u20ac2,213 million, was mainly due
\n
to the change in the consolidation scope connected with
\n
the sale of PJSC Enel Russia, Central Geradora Termel\u00e9trica
\n
Fortaleza and Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s),
\n
and the net appreciation of the functional currencies used
\n
by the foreign subsidiaries, mainly in Latin America and the
\n
United States, against the Group presentation currency
\n
(the euro).
\n
Hedging reserve - \u20ac(3,553) million
\n
This includes the net expense recognized in equity from
\n
the measurement of cash flow hedge derivatives. The
\n
change in 2022 is mainly attributable to developments in
\n
commodity prices.
\n
Hedging costs reserve - \u20ac(81) million
\n
In application of IFRS 9, this reserve includes the fair val-
\n
ue gains and losses on currency basis points and forward
\n
points. The change in 2022 is mainly attributable to devel-
\n
opments in commodity prices.
\n
Reserve from measurement of financial instruments at
\n
FVOCI - \u20ac(22) million
\n
This includes net unrealized fair value losses on financial
\n
assets.
\n
Reserve from equity-accounted investments - \u20ac(476)
\n
million
\n
The reserve reports the share of comprehensive income to
\n
be recognized directly in equity of equity-accounted in-
\n
vestees. The change in 2022 is mainly attributable to the
\n
change in the hedging reserve of Slovak Power Holding.
\n
Actuarial reserve - \u20ac(1,063) million
\n
This reserve includes actuarial gains and losses in respect
\n
of employee benefit liabilities, net of tax effects.
\n
Reserve from disposal of equity interests without loss of
\n
control - \u20ac(2,390) million
\n
This item mainly reports:
\n
\u2022 the gain posted on the public offering of Enel Green
\n
Power shares, net of expenses associated with the dis-
\n
posal and the related taxation;
\n
\u2022 the sale of non-controlling interests recognized as a re-
\n
sult of the Enersis (now Enel Am\u00e9ricas and Enel Chile)
\n
capital increase;
\n
\u2022 the capital loss, net of expenses associated with the dis-
\n
posal and the related taxation, from the public offering
\n
of 21.92% of Endesa;
\n
\u2022 the disposal to third parties of the non-controlling inter-
\n
est in Enel Green Power North America Renewable Ener-
\n
gy Partners;
\n
\u2022 the effects of the merger into Enel Am\u00e9ricas of Endesa
\n
Am\u00e9ricas and Chilectra Am\u00e9ricas.
\n
The change in the reserve in 2022 is associated with the
\n
sale of the 49% stake held by Enel Green Power Canada in
\n
Pincher Creek LP and Riverview LP.
\n
Reserve from acquisitions of non-controlling interests -
\n
\u20ac(1,192) million
\n
This reserve mainly includes the surplus of acquisition
\n
prices with respect to the carrying amount of the equi-
\n
ty acquired following the acquisition from third parties of
\n
further interests in companies already controlled in Latin
\n
America.
\n
The change for the year (-\u20ac349 million) mainly reflects the
\n
effects of the merger between Emgesa SA ESP (acquir-
\n
ing entity), Codensa SA ESP, Enel Green Power Colombia
\n
SAS ESP and ESSA 2 (merged entities), following which the
\n
Group\u2019s interest in Emgesa SA ESP (now Enel Colombia
\n
SA ESP) increased from 39.89% to 47.18%, and the sale by
\n
Endesa X Servicios SLU to Enel X Way Srl of 51% of Endesa
\n
X Way SL increasing the interest held by the Group in the
\n
latter from 70.11% to 85.35%.
\n

\n

\n\n
Retained earnings - \u20ac15,797 million
\n
This reserve reports earnings from previous years that
\n
have not been distributed or allocated to other reserves.
\n
The table below shows the changes in gains and losses
\n
recognized directly in other comprehensive income, in-
\n
cluding non-controlling interests, with specific reporting
\n
of the related tax effects.
\n

\n\n

\n
Millions of euro
\n
at Dec. 31, 2021 Change
\n
at Dec. 31, 2022
\n
Tot al
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests
\n
Gains/
\n
(Losses)
\n
recognized
\n
in equity
\n
during the
\n
year
\n
Released
\n
to profit
\n
or loss Taxes Total
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests Tot al
\n
Of
\n
which
\n
owners
\n
of the
\n
Parent
\n
Of which
\n
non-
\n
controlling
\n
interests
\n
Translation
\n
reserve
\n
(11,790) (6,303) (5,487) 890 - - 890 879 11 (10,900) (5,424) (5,476)
\n
Hedging reserve (2,961) (2,280) (681) (3,605) 1,323 587 (1,695) (1,293) (402) (4,656) (3,573) (1,083)
\n
Hedging costs
\n
reserve
\n
(49) (39) (10) (40) (31) 9 (62) (52) (10) (111) (91) (20)
\n
Reserve from
\n
measurement
\n
of financial
\n
instruments at
\n
FVOCI
\n
11 12 (1) (51) - 7 (44) (44) - (33) (32) (1)
\n
Share of OCI
\n
of equity-
\n
accounted
\n
associates
\n
(820) (825) 5 256 - (22) 234 224 10 (586) (601) 15
\n
Reserve from
\n
measurement
\n
of equity
\n
investments
\n
in other
\n
companies
\n
(32) (32) - 13 - - 13 13 - (19) (19) -
\n
Actuarial reserve (1,798) (1,265) (533) 403 - (79) 324 249 75 (1,474) (1,016) (458)
\n
Total gains/
\n
(losses)
\n
recognized in
\n
equity
\n
(17,439) (10,732) (6,707) (2,134) 1,292 502 (340) (24) (316) (17,779) (10,756) (7,023)
\n\n
37.2 Dividends
\n
Amount distributed
\n
(millions of euro) Dividend per share (euro)
\n
Dividends distributed in 2021
\n
Dividends for 2020 3,638 0.358
\n
Interim dividends for 2021
\n
(1)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2021 3,638 0.358
\n
Dividends distributed in 2021
\n
Dividends for 2022 3,861 0.380
\n
Interim dividends for 2022
\n
(2)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2022 3,861 0.380
\n
(1) Approved by the Board of Directors on November 4, 2021 and paid as from January 26, 2022 (interim dividend of \u20ac0.19 per share for a total of \u20ac1,932 million).
\n
(2) Approved by the Board of Directors on November 3, 2022 and paid as from January 25, 2023 (interim dividend of \u20ac0.20 per share for a total of \u20ac2,033 million).
\n
Dividends distributed are shown net of amounts due to
\n
treasury shares at the respective \u201crecord dates\u201d. These
\n
shares were waived for collection and allocated to \u201cre-
\n
tained earnings\u201d.
\n
The dividend for 2022 is equal to \u20ac0.40 per share, for a
\n
total of \u20ac4,067 million (of which \u20ac0.20 per share for a total
\n
of \u20ac2,033 million already paid as an interim dividend). It will
\n
be proposed to the Shareholders\u2019 Meeting of May 10, 2023
\n
at single call.
\n
These consolidated financial statements do not take ac-
\n
count of the effects of the distribution to shareholders of
\n
the dividend for 2022, except for the liability in respect
\n
of shareholders for the interim dividend for 2022, which
\n
was approved by the Board of Directors on November 3,
\n
2022 for a potential maximum of \u20ac2,033 million, and paid
\n
as from January 25, 2023 net of the portion pertaining to
\n
the 7,153,795 treasury shares held as at the record date of
\n
January 24, 2023.
\n

\n\n

\n\n

\n

\n\n

\n

\n
In 2022, the Group also paid \u20ac123 million in coupons to
\n
holders of perpetual hybrid bonds.
\n\n
Capital management
\n
The Group\u2019s objectives for managing capital comprise
\n
safeguarding the business as a going concern, creating
\n
value for stakeholders and supporting the development of
\n
the Group. In particular, the Group seeks to maintain an ad-
\n
equate capitalization that enables it to achieve a satisfac-
\n
tory return for shareholders and ensure access to external
\n
sources of financing, in part by maintaining an adequate
\n
rating.
\n
In this context, the Group manages its capital structure
\n
and adjusts that structure when changes in economic
\n
conditions so require. There were no substantive changes
\n
in objectives, policies or processes in 2022.
\n
To this end, the Group constantly monitors developments
\n
in the level of its debt in relation to equity. The situation at
\n
December 31, 2022 and 2021 is summarized in the follow-
\n
ing table.
\n

\n

\n\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Non-current financial debt 68,191 54,620 13,571
\n
Net current financial position (3,315) 24 (3,339)
\n
Non-current financial assets and long-term securities (4,213) (2,692) (1,521)
\n
Net exchange rate derivatives associated with borrowings
\n
(1)
\n
(595) (259) (336)
\n
Net financial debt
\n
(1)
\n
60,068 51,693 8,375
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n
Non-controlling interests 13,425 12,689 736
\n
Equity 42,082 42,342 (260)
\n
Debt/equity ratio 1.43 1.22 0.21
\n
(1) In order to improve the reporting of net financial debt, so as to take account of exchange risk hedging, in its determination the Group has decided to include
\n
the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on borrowings. Accordingly, in order to improve
\n
the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021.
\n
The increase in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in net financial debt, mainly reflecting the funding require-
\n
ments of investments in the year, the payment of divi-
\n
dends, and the acquisition of ERG Hydro.
\n
See note 47 for a breakdown of the individual items in the
\n
table.
\n

\n\n

\n\n\n

\n\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,425 million
\n
The following table presents the composition of non-con-
\n
trolling interests by geographical area.
\n
Millions of euro Non-controlling interests
\n
Profit for the year attributable to non-
\n
controlling interests
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Italy 1 1 - -
\n
Iberia 5,321 5,238 713 193
\n
Latin America 7,422 6,511 857 467
\n
Europe 328 635 (342) 5
\n
North America 218 151 10 6
\n
Africa, Asia and Oceania 135 153 - (3)
\n
Total 13,425 12,689 1,238 668
\n
The change in non-controlling interests mainly reflects the
\n
appreciation of the functional currencies of the foreign
\n
subsidiaries against the euro (especially in Latin America),
\n
the results for the period, the effect of the corporate trans-
\n
action in Colombia and the impact of hyperinflation. These
\n
effects were partly offset by the dividends distributed and
\n
the value adjustment of cash flow hedge instruments.
\n
The financial disclosure requirements of IFRS 12 for sub-
\n
sidiaries with significant non-controlling interests are re-
\n
ported below.
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of
\n
euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
29,600 28,959 5,430 4,711 35,030 33,670
\n
Enel Chile
\n
10,985 9,887 1,541 (642) 12,526 9,245
\n
Endesa
\n
45,018 43,217 11,166 3,853 56,184 47,070
\n
Millions of
\n
euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable to
\n
owners of the Parent
\n
Non-controlling
\n
interests
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
11,534 11,320 6,208 6,073 17,742 17,393 17,288 16,277 12,136 11,556 5,152 4,721
\n
Enel Chile
\n
4,113 3,356 2,460 1,178 6,573 4,534 5,953 4,711 3,683 2,921 2,270 1,790
\n
Endesa
\n
18,414 15,196 17,372 11,449 35,786 26,645 20,398 20,425 15,083 15,187 5,315 5,238
\n
Millions of
\n
euro Total revenue Pre-tax profit
\n
Profit from continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable to non-
\n
controlling interests
\n
2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
14,696 13,581 1,015 1,516 221 757 (90) 337 311 420
\n
Enel Chile
\n
6,450 3,114 1,971 128 1,458 104 913 57 545 47
\n
Endesa
\n
32,714 20,217 3,055 769 2,244 589 1,534 396 710 193
\n

\n\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1033": { "value": "\n
Share capital \u2013 \u20ac10,167 million
\n
At December 31, 2022, the fully subscribed and paid-up
\n
share capital of Enel SpA totaled \u20ac10,166,679,946, rep-
\n
resented by the same number of ordinary shares with a
\n
par value of \u20ac1.00 each. Enel SpA\u2019s share capital was un-
\n
changed compared with the amount reported at Decem-
\n
ber 31, 2021.
\n
At December 31, 2022, based on the shareholders register
\n
and the notices submitted to CONSOB and received by the
\n
Parent pursuant to Article 120 of Legislative Decree 58 of
\n
February 24, 1998, as well as other available information,
\n
shareholders with interests of greater than 3% in the Par-
\n
ent\u2019s share capital were the Ministry for the Economy and
\n
Finance (with a 23.585% stake) and BlackRock Inc. (with a
\n
5.114% stake held for asset management purposes).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1030": { "value": "\n
Treasury share reserve - \u20ac(47) million
\n
At December 31, 2022, treasury shares are represented by
\n
7,153,795 ordinary shares of Enel SpA with a par value of
\n
\u20ac1.00 each (4,889,152 at December 31, 2021), purchased
\n
through an authorized intermediary for a total of \u20ac47 mil-
\n
lion.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1027": { "value": "\n
Other reserves - \u20ac2,740 million
\n
Share premium reserve - \u20ac7,496 million
\n
Pursuant to Article 2431 of the Italian Civil Code, the share
\n
premium reserve contains, in the case of the issue of
\n
shares at a price above par, the difference between the is-
\n
sue price of the shares and their par value, including those
\n
resulting from conversion from bonds. The reserve, which
\n
is a capital reserve, may not be distributed until the legal
\n
reserve has reached the threshold established under Arti-
\n
cle 2430 of the Italian Civil Code.
\n
Reserve for equity instruments - perpetual hybrid bonds
\n
- \u20ac5,567 million
\n
This reserve reports the nominal value, net of transaction
\n
costs, of the non-convertible subordinated perpetual hy-
\n
brid bonds denominated in euros for international inves-
\n
tors.
\n
In 2022, the Group paid \u20ac123 million in coupons to holders
\n
of perpetual hybrid bonds.
\n
Legal reserve - \u20ac2,034 million
\n
The legal reserve is formed of the part of profits that, pur-
\n
suant to Article 2430 of the Italian Civil Code, cannot be
\n
distributed as dividends.
\n

\n\n
Other reserves - \u20ac2,332 million
\n
These include \u20ac2,215 million related to the remaining por-
\n
tion of the adjustments carried out when Enel was trans-
\n
formed from a public entity to a joint-stock company.
\n
Pursuant to Article 47 of the Consolidated Income Tax
\n
Code (Testo Unico Imposte sul Reddito, or \u201cTUIR\u201d), this
\n
amount does not constitute taxable income when distrib-
\n
uted.
\n
Translation reserve - \u20ac(5,912) million
\n
The increase for the year, of \u20ac2,213 million, was mainly due
\n
to the change in the consolidation scope connected with
\n
the sale of PJSC Enel Russia, Central Geradora Termel\u00e9trica
\n
Fortaleza and Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s),
\n
and the net appreciation of the functional currencies used
\n
by the foreign subsidiaries, mainly in Latin America and the
\n
United States, against the Group presentation currency
\n
(the euro).
\n
Hedging reserve - \u20ac(3,553) million
\n
This includes the net expense recognized in equity from
\n
the measurement of cash flow hedge derivatives. The
\n
change in 2022 is mainly attributable to developments in
\n
commodity prices.
\n
Hedging costs reserve - \u20ac(81) million
\n
In application of IFRS 9, this reserve includes the fair val-
\n
ue gains and losses on currency basis points and forward
\n
points. The change in 2022 is mainly attributable to devel-
\n
opments in commodity prices.
\n
Reserve from measurement of financial instruments at
\n
FVOCI - \u20ac(22) million
\n
This includes net unrealized fair value losses on financial
\n
assets.
\n
Reserve from equity-accounted investments - \u20ac(476)
\n
million
\n
The reserve reports the share of comprehensive income to
\n
be recognized directly in equity of equity-accounted in-
\n
vestees. The change in 2022 is mainly attributable to the
\n
change in the hedging reserve of Slovak Power Holding.
\n
Actuarial reserve - \u20ac(1,063) million
\n
This reserve includes actuarial gains and losses in respect
\n
of employee benefit liabilities, net of tax effects.
\n
Reserve from disposal of equity interests without loss of
\n
control - \u20ac(2,390) million
\n
This item mainly reports:
\n
\u2022 the gain posted on the public offering of Enel Green
\n
Power shares, net of expenses associated with the dis-
\n
posal and the related taxation;
\n
\u2022 the sale of non-controlling interests recognized as a re-
\n
sult of the Enersis (now Enel Am\u00e9ricas and Enel Chile)
\n
capital increase;
\n
\u2022 the capital loss, net of expenses associated with the dis-
\n
posal and the related taxation, from the public offering
\n
of 21.92% of Endesa;
\n
\u2022 the disposal to third parties of the non-controlling inter-
\n
est in Enel Green Power North America Renewable Ener-
\n
gy Partners;
\n
\u2022 the effects of the merger into Enel Am\u00e9ricas of Endesa
\n
Am\u00e9ricas and Chilectra Am\u00e9ricas.
\n
The change in the reserve in 2022 is associated with the
\n
sale of the 49% stake held by Enel Green Power Canada in
\n
Pincher Creek LP and Riverview LP.
\n
Reserve from acquisitions of non-controlling interests -
\n
\u20ac(1,192) million
\n
This reserve mainly includes the surplus of acquisition
\n
prices with respect to the carrying amount of the equi-
\n
ty acquired following the acquisition from third parties of
\n
further interests in companies already controlled in Latin
\n
America.
\n
The change for the year (-\u20ac349 million) mainly reflects the
\n
effects of the merger between Emgesa SA ESP (acquir-
\n
ing entity), Codensa SA ESP, Enel Green Power Colombia
\n
SAS ESP and ESSA 2 (merged entities), following which the
\n
Group\u2019s interest in Emgesa SA ESP (now Enel Colombia
\n
SA ESP) increased from 39.89% to 47.18%, and the sale by
\n
Endesa X Servicios SLU to Enel X Way Srl of 51% of Endesa
\n
X Way SL increasing the interest held by the Group in the
\n
latter from 70.11% to 85.35%.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1029": { "value": "\n
37.2 Dividends
\n
Amount distributed
\n
(millions of euro) Dividend per share (euro)
\n
Dividends distributed in 2021
\n
Dividends for 2020 3,638 0.358
\n
Interim dividends for 2021
\n
(1)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2021 3,638 0.358
\n
Dividends distributed in 2021
\n
Dividends for 2022 3,861 0.380
\n
Interim dividends for 2022
\n
(2)
\n
--
\n
Special dividends --
\n
Total dividend distributed in 2022 3,861 0.380
\n
(1) Approved by the Board of Directors on November 4, 2021 and paid as from January 26, 2022 (interim dividend of \u20ac0.19 per share for a total of \u20ac1,932 million).
\n
(2) Approved by the Board of Directors on November 3, 2022 and paid as from January 25, 2023 (interim dividend of \u20ac0.20 per share for a total of \u20ac2,033 million).
\n
Dividends distributed are shown net of amounts due to
\n
treasury shares at the respective \u201crecord dates\u201d. These
\n
shares were waived for collection and allocated to \u201cre-
\n
tained earnings\u201d.
\n
The dividend for 2022 is equal to \u20ac0.40 per share, for a
\n
total of \u20ac4,067 million (of which \u20ac0.20 per share for a total
\n
of \u20ac2,033 million already paid as an interim dividend). It will
\n
be proposed to the Shareholders\u2019 Meeting of May 10, 2023
\n
at single call.
\n
These consolidated financial statements do not take ac-
\n
count of the effects of the distribution to shareholders of
\n
the dividend for 2022, except for the liability in respect
\n
of shareholders for the interim dividend for 2022, which
\n
was approved by the Board of Directors on November 3,
\n
2022 for a potential maximum of \u20ac2,033 million, and paid
\n
as from January 25, 2023 net of the portion pertaining to
\n
the 7,153,795 treasury shares held as at the record date of
\n
January 24, 2023.
\n

\n\n

\n

\n
In 2022, the Group also paid \u20ac123 million in coupons to
\n
holders of perpetual hybrid bonds.
\n\n
Capital management
\n
The Group\u2019s objectives for managing capital comprise
\n
safeguarding the business as a going concern, creating
\n
value for stakeholders and supporting the development of
\n
the Group. In particular, the Group seeks to maintain an ad-
\n
equate capitalization that enables it to achieve a satisfac-
\n
tory return for shareholders and ensure access to external
\n
sources of financing, in part by maintaining an adequate
\n
rating.
\n
In this context, the Group manages its capital structure
\n
and adjusts that structure when changes in economic
\n
conditions so require. There were no substantive changes
\n
in objectives, policies or processes in 2022.
\n
To this end, the Group constantly monitors developments
\n
in the level of its debt in relation to equity. The situation at
\n
December 31, 2022 and 2021 is summarized in the follow-
\n
ing table.
\n

\n

\n\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Non-current financial debt 68,191 54,620 13,571
\n
Net current financial position (3,315) 24 (3,339)
\n
Non-current financial assets and long-term securities (4,213) (2,692) (1,521)
\n
Net exchange rate derivatives associated with borrowings
\n
(1)
\n
(595) (259) (336)
\n
Net financial debt
\n
(1)
\n
60,068 51,693 8,375
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n
Non-controlling interests 13,425 12,689 736
\n
Equity 42,082 42,342 (260)
\n
Debt/equity ratio 1.43 1.22 0.21
\n
(1) In order to improve the reporting of net financial debt, so as to take account of exchange risk hedging, in its determination the Group has decided to include
\n
the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on borrowings. Accordingly, in order to improve
\n
the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021.
\n
The increase in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in net financial debt, mainly reflecting the funding require-
\n
ments of investments in the year, the payment of divi-
\n
dends, and the acquisition of ERG Hydro.
\n
See note 47 for a breakdown of the individual items in the
\n
table.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1031": { "value": "0.38", "decimals": 3, "dimensions": { "concept": "ifrs-full:DividendsRecognisedAsDistributionsToOwnersPerShare", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00", "unit": "iso4217:EUR/xbrli:shares" } }, "Tag1035": { "value": "0.4", "decimals": 2, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwnersPerShare", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00", "unit": "iso4217:EUR/xbrli:shares" } }, "Tag1037": { "value": "4067000000", "decimals": -6, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag1038": { "value": "\n
Capital management
\n
The Group\u2019s objectives for managing capital comprise
\n
safeguarding the business as a going concern, creating
\n
value for stakeholders and supporting the development of
\n
the Group. In particular, the Group seeks to maintain an ad-
\n
equate capitalization that enables it to achieve a satisfac-
\n
tory return for shareholders and ensure access to external
\n
sources of financing, in part by maintaining an adequate
\n
rating.
\n
In this context, the Group manages its capital structure
\n
and adjusts that structure when changes in economic
\n
conditions so require. There were no substantive changes
\n
in objectives, policies or processes in 2022.
\n
To this end, the Group constantly monitors developments
\n
in the level of its debt in relation to equity. The situation at
\n
December 31, 2022 and 2021 is summarized in the follow-
\n
ing table.
\n

\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Non-current financial debt 68,191 54,620 13,571
\n
Net current financial position (3,315) 24 (3,339)
\n
Non-current financial assets and long-term securities (4,213) (2,692) (1,521)
\n
Net exchange rate derivatives associated with borrowings
\n
(1)
\n
(595) (259) (336)
\n
Net financial debt
\n
(1)
\n
60,068 51,693 8,375
\n
Equity attributable to owners of the Parent 28,657 29,653 (996)
\n
Non-controlling interests 13,425 12,689 736
\n
Equity 42,082 42,342 (260)
\n
Debt/equity ratio 1.43 1.22 0.21
\n
(1) In order to improve the reporting of net financial debt, so as to take account of exchange risk hedging, in its determination the Group has decided to include
\n
the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on borrowings. Accordingly, in order to improve
\n
the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021.
\n
The increase in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in net financial debt, mainly reflecting the funding require-
\n
ments of investments in the year, the payment of divi-
\n
dends, and the acquisition of ERG Hydro.
\n
See note 47 for a breakdown of the individual items in the
\n
table.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1032": { "value": "\n

\n\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,425 million
\n
The following table presents the composition of non-con-
\n
trolling interests by geographical area.
\n
Millions of euro Non-controlling interests
\n
Profit for the year attributable to non-
\n
controlling interests
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Italy 1 1 - -
\n
Iberia 5,321 5,238 713 193
\n
Latin America 7,422 6,511 857 467
\n
Europe 328 635 (342) 5
\n
North America 218 151 10 6
\n
Africa, Asia and Oceania 135 153 - (3)
\n
Total 13,425 12,689 1,238 668
\n
The change in non-controlling interests mainly reflects the
\n
appreciation of the functional currencies of the foreign
\n
subsidiaries against the euro (especially in Latin America),
\n
the results for the period, the effect of the corporate trans-
\n
action in Colombia and the impact of hyperinflation. These
\n
effects were partly offset by the dividends distributed and
\n
the value adjustment of cash flow hedge instruments.
\n
The financial disclosure requirements of IFRS 12 for sub-
\n
sidiaries with significant non-controlling interests are re-
\n
ported below.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Millions of
\n
euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
29,600 28,959 5,430 4,711 35,030 33,670
\n
Enel Chile
\n
10,985 9,887 1,541 (642) 12,526 9,245
\n
Endesa
\n
45,018 43,217 11,166 3,853 56,184 47,070
\n
Millions of
\n
euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable to
\n
owners of the Parent
\n
Non-controlling
\n
interests
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
11,534 11,320 6,208 6,073 17,742 17,393 17,288 16,277 12,136 11,556 5,152 4,721
\n
Enel Chile
\n
4,113 3,356 2,460 1,178 6,573 4,534 5,953 4,711 3,683 2,921 2,270 1,790
\n
Endesa
\n
18,414 15,196 17,372 11,449 35,786 26,645 20,398 20,425 15,083 15,187 5,315 5,238
\n
Millions of
\n
euro Total revenue Pre-tax profit
\n
Profit from continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable to non-
\n
controlling interests
\n
2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
14,696 13,581 1,015 1,516 221 757 (90) 337 311 420
\n
Enel Chile
\n
6,450 3,114 1,971 128 1,458 104 913 57 545 47
\n
Endesa
\n
32,714 20,217 3,055 769 2,244 589 1,534 396 710 193
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1028": { "value": "\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,425 million
\n
The following table presents the composition of non-con-
\n
trolling interests by geographical area.
\n
Millions of euro Non-controlling interests
\n
Profit for the year attributable to non-
\n
controlling interests
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Italy 1 1 - -
\n
Iberia 5,321 5,238 713 193
\n
Latin America 7,422 6,511 857 467
\n
Europe 328 635 (342) 5
\n
North America 218 151 10 6
\n
Africa, Asia and Oceania 135 153 - (3)
\n
Total 13,425 12,689 1,238 668
\n
The change in non-controlling interests mainly reflects the
\n
appreciation of the functional currencies of the foreign
\n
subsidiaries against the euro (especially in Latin America),
\n
the results for the period, the effect of the corporate trans-
\n
action in Colombia and the impact of hyperinflation. These
\n
effects were partly offset by the dividends distributed and
\n
the value adjustment of cash flow hedge instruments.
\n
The financial disclosure requirements of IFRS 12 for sub-
\n
sidiaries with significant non-controlling interests are re-
\n
ported below.
\n

\n\n

\n\n

\n\n
Millions of
\n
euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
29,600 28,959 5,430 4,711 35,030 33,670
\n
Enel Chile
\n
10,985 9,887 1,541 (642) 12,526 9,245
\n
Endesa
\n
45,018 43,217 11,166 3,853 56,184 47,070
\n
Millions of
\n
euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable to
\n
owners of the Parent
\n
Non-controlling
\n
interests
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
11,534 11,320 6,208 6,073 17,742 17,393 17,288 16,277 12,136 11,556 5,152 4,721
\n
Enel Chile
\n
4,113 3,356 2,460 1,178 6,573 4,534 5,953 4,711 3,683 2,921 2,270 1,790
\n
Endesa
\n
18,414 15,196 17,372 11,449 35,786 26,645 20,398 20,425 15,083 15,187 5,315 5,238
\n
Millions of
\n
euro Total revenue Pre-tax profit
\n
Profit from continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable to non-
\n
controlling interests
\n
2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
14,696 13,581 1,015 1,516 221 757 (90) 337 311 420
\n
Enel Chile
\n
6,450 3,114 1,971 128 1,458 104 913 57 545 47
\n
Endesa
\n
32,714 20,217 3,055 769 2,244 589 1,534 396 710 193
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1034": { "value": "\n
37.3 Non-controlling interests \u2013 \u20ac13,425 million
\n
The following table presents the composition of non-con-
\n
trolling interests by geographical area.
\n
Millions of euro Non-controlling interests
\n
Profit for the year attributable to non-
\n
controlling interests
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Italy 1 1 - -
\n
Iberia 5,321 5,238 713 193
\n
Latin America 7,422 6,511 857 467
\n
Europe 328 635 (342) 5
\n
North America 218 151 10 6
\n
Africa, Asia and Oceania 135 153 - (3)
\n
Total 13,425 12,689 1,238 668
\n
The change in non-controlling interests mainly reflects the
\n
appreciation of the functional currencies of the foreign
\n
subsidiaries against the euro (especially in Latin America),
\n
the results for the period, the effect of the corporate trans-
\n
action in Colombia and the impact of hyperinflation. These
\n
effects were partly offset by the dividends distributed and
\n
the value adjustment of cash flow hedge instruments.
\n
The financial disclosure requirements of IFRS 12 for sub-
\n
sidiaries with significant non-controlling interests are re-
\n
ported below.
\n

\n\n
Millions of
\n
euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
29,600 28,959 5,430 4,711 35,030 33,670
\n
Enel Chile
\n
10,985 9,887 1,541 (642) 12,526 9,245
\n
Endesa
\n
45,018 43,217 11,166 3,853 56,184 47,070
\n
Millions of
\n
euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable to
\n
owners of the Parent
\n
Non-controlling
\n
interests
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
11,534 11,320 6,208 6,073 17,742 17,393 17,288 16,277 12,136 11,556 5,152 4,721
\n
Enel Chile
\n
4,113 3,356 2,460 1,178 6,573 4,534 5,953 4,711 3,683 2,921 2,270 1,790
\n
Endesa
\n
18,414 15,196 17,372 11,449 35,786 26,645 20,398 20,425 15,083 15,187 5,315 5,238
\n
Millions of
\n
euro Total revenue Pre-tax profit
\n
Profit from continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable to non-
\n
controlling interests
\n
2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
\n
Subsidiaries
\n
Enel
\n
Am\u00e9ricas
\n
14,696 13,581 1,015 1,516 221 757 (90) 337 311 420
\n
Enel Chile
\n
6,450 3,114 1,971 128 1,458 104 913 57 545 47
\n
Endesa
\n
32,714 20,217 3,055 769 2,244 589 1,534 396 710 193
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1036": { "value": "\n
38. Borrowings
\n
Millions of euro Non-current Current
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Long-term borrowings 68,191 54,500 2,835 4,031
\n
Short-term borrowings - - 18,392 13,306
\n
Tot al 68,191 54,500 21,227 17,337
\n
For more information on the nature of borrowings, see
\n
note 48 \u201cFinancial instruments by category\u201d.
\n

\n\n

\n\n
48.3 Borrowings
\n
48.3.1 Long-term borrowings (including the portion
\n
falling due within 12 months) \u2013 \u20ac71,026 million
\n
The following table reports the nominal value, carrying
\n
amount, and fair value of long-term borrowings including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
(1)
\n
Millions of euro
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Changes
\n
in carrying
\n
amount
\n
2022-
\n
2021
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Bonds:
\n
- listed, fixed rate 30,355 29,892 978 28,914 27,468 27,857 27,413 2,119 25,294 30,279 2,479
\n
- listed, floating rate 2,569 2,547 537 2,010 2,473 2,574 2,557 434 2,123 2,545 (10)
\n
- unlisted, fixed rate 18,959 18,727 - 18,727 17,249 11,293 11,207 50 11,157 12,670 7,520
\n
- unlisted, floating rate 525 525 97 428 600 622 622 97 525 728
\n
(97)
\n
Total bonds 52,408 51,691 1,612 50,079 47,790 42,346 41,799 2,700 39,099 46,222 9,892
\n
Bank borrowings:
\n
- fixed rate 3,367 3,273 211 3,062 3,021 2,414 2,405 238 2,167 2,298 868
\n
- floating rate 12,884 12,848 677 12,171 12,570 10,139 10,109 751 9,358 10,037
\n
2,739
\n
- use of revolving credit
\n
lines
\n
30 30 2 28 26 1,054 1,054 - 1,054 1,054
\n
(1,024)
\n
Total bank borrowings 16,281 16,151 890 15,261 15,617 13,607 13,568 989 12,579 13,389 2,583
\n
Leases:
\n
- fixed rate 2,630 2,630 251 2,379 2,630 2,477 2,477 242 2,235 2,477 153
\n
- floating rate 42 42 10 32 42 70 70 17 53 70
\n
(28)
\n
Total leases 2,672 2,672 261 2,411 2,672 2,547 2,547 259 2,288 2,547 125
\n
Other non-bank
\n
borrowings:
\n
- fixed rate 504 504 70 434 504 571 595 69 526 569 (91)
\n
- floating rate 8 8 2 6 12 34 22 14 8 25
\n
(14)
\n
Total other non-bank
\n
borrowings
\n
512 512 72 440 516 605 617 83 534 594
\n
(105)
\n
Total fixed-rate
\n
borrowings
\n
55,815 55,026 1,510 53,516 50,872 44,612 44,097 2,718 41,379 48,293
\n
10,929
\n
Total floating-rate
\n
borrowings
\n
16,058 16,000 1,325 14,675 15,723 14,493 14,434 1,313 13,121 14,459 1,566
\n
TOTAL 71,873 71,026 2,835 68,191 66,595 59,105 58,531 4,031 54,500 62,752
\n
12,495
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position that
\n
are included in long-term financial debt.
\n

\n\n

\n\n

\n\n
The following table reports long-term financial debt by
\n
currency and interest rate.
\n
Long-term financial debt by currency and interest rate
\n
(1)
\n
Millions of euro
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Euro 34,993 35,383 32,041 32,387 1.9% 2.1% 1.6% 1.9%
\n
US dollar 26,930 27,209 17,518 17,629 4.8% 5.1% 4.2% 4.3%
\n
Pound sterling 4,470 4,610 3,901 3,976 4.6% 4.8% 5.0% 5.2%
\n
Colombian peso 1,310 1,310 1,341 1,341 10.3% 10.3% 6.5% 6.5%
\n
Brazilian real 1,899 1,926 1,720 1,753 10.0% 10.2% 8.8% 8.9%
\n
Swiss franc 359 360 343 344 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 526 531 423 428 5.1% 5.2% 5.2% 5.2%
\n
Peruvian sol 429 429 415 415 5.3% 5.3% 5.2% 5.2%
\n
Russian ruble - - 427 427 6.8% 7.3%
\n
Other currencies 110 115 402 405
\n
Total non-euro currencies 36,033 36,490 26,490 26,718
\n
TOTAL 71,026 71,873 58,531 59,105
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
Long-term financial debt denominated in currencies other
\n
than the euro increased by \u20ac9,543 million, largely attrib-
\n
utable to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term debt
\n
(1)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope
\n
New
\n
borrowings Other changes
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Bonds 42,346 (2,788) (37) 12,390 - 497 52,408
\n
Borrowings 16,759 (6,571) (1,016)
\n
10,009 -28419,465
\n
- of which leases 2,547 (310) (88) 445 -782,672
\n
Total financial debt 59,105 (9,359) (1,053) 22,399 - 781 71,873
\n
(1) Does not include changes in the nominal value of other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the
\n
statement of financial position.
\n
The nominal value of long-term debt amounted to \u20ac71,873
\n
million at December 31, 2022, an increase of \u20ac12,768 mil-
\n
lion compared with December 31, 2021. The increase in
\n
debt reflected new borrowing of \u20ac22,399 million and ex-
\n
change losses of \u20ac781 million, only partially offset by re-
\n
payments of \u20ac9,359 million and the deconsolidation of
\n
debt of various companies, in particular that resulting from
\n
the sale of the equity investment in Enel Russia, equal to
\n
\u20ac1,053 million.
\n
Repayments in 2022 involved bonds in the amount of
\n
\u20ac2,788 million and loans in the amount of \u20ac6,571 million.
\n
Specifically, repayments of bonds in 2022 included:
\n
\u2022 \u20ac50 million in respect of a fixed-rate bond issued by Enel
\n
Finance International, maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n

\n\n

\n\n

\n\n
\u2022 270,000 million Colombian pesos (equivalent to \u20ac52
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2022;
\n
\u2022 \u20ac1,949 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in September 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in September
\n
2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in November 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in December
\n
2022.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022 \u20ac5,250 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022 \u20ac264 million in respect of Endesa loans, of which \u20ac132
\n
million in sustainable loans;
\n
\u2022 \u20ac504 million in respect of sustainable loans of Group\u2019s
\n
Italian companies;
\n
\u2022 the equivalent of \u20ac354 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2022 involved \u20ac12,390 million in bonds
\n
and \u20ac10,009 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2022 and translated into euros
\n
at the exchange rate prevailing at December 31, 2022.
\n

\n\n

\n\n

\n\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of
\n
euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance International 17.01.2022 1,250 EUR 0.25% Fixed rate 17.11.2025
\n
Enel Finance International 17.01.2022 750 EUR 0.88% Fixed rate 17.01.2031
\n
Enel Finance International 17.01.2022 750 EUR 1.25% Fixed rate 17.01.2035
\n
Enel Finance International 11.04.2022 845 GBP 2.88% Fixed rate 11.04.2029
\n
Enel Finance International 15.06.2022 703 USD 4.25% Fixed rate 15.06.2025
\n
Enel Finance International 15.06.2022 703 USD 4.63% Fixed rate 15.06.2027
\n
Enel Finance International 15.06.2022 937 USD 5.00% Fixed rate 15.06.2032
\n
Enel Finance International 15.06.2022 937 USD 5.50% Fixed rate 15.06.2052
\n
Enel Finance International 09.09.2022 1,000 EUR 3.88% Fixed rate 09.03.2029
\n
Enel Finance International 14.10.2022 703 USD 6.80% Fixed rate 14.10.2025
\n
Enel Finance International 14.10.2022 1,171 USD 7.50% Fixed rate 14.10.2032
\n
Enel Finance International 14.10.2022 937 USD 7.75% Fixed rate 14.10.2052
\n
Enel Finance America 14.10.2022 937 USD 7.10% Fixed rate 14.10.2027
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 12.05.2022 142 BRL IPCA + 6.14% Floating rate 15.04.2032
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 30.05.2022 106 BRL IPCA + 6.21% Floating rate 17.05.2032
\n
Total bonds 11,871
\n
Bank borrowings
\n
Enel SpA 07.03.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 14.09.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 30.09.2022 350 EUR Euribor + 0.45% Floating rate 26.07.2025
\n
Enel SpA 30.09.2022 648 EUR Euribor + 0.40% Floating rate 12.05.2025
\n
Enel SpA 30.09.2022 1,852 EUR Euribor + 0.40% Floating rate 05.03.2026
\n
Enel SpA 30.09.2022 1,000 EUR Euribor + 0.52% Floating rate 02.10.2024
\n
e-distibuzione 05.08.2022 300 EUR Euribor + 0.473% Floating rate 05.08.2037
\n
Enel Italia 29.07.2022 60 EUR Euribor 6M + 0.462% Floating rate 29.07.2037
\n
Enel Finance America 06.10.2022 403 USD USD SOFR 6M CMP + 1.22% Floating rate 15.05.2034
\n
Enel Finance America 03.11.2022 187 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 13.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 21.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Endesa 17.01.2022 300 EUR Euribor 6M + 0.53% Floating rate 20.12.2033
\n
Endesa 25.03.2022 400 EUR Euribor 3M + 0.72% Floating rate 31.07.2024
\n
Endesa 28.03.2022 250 EUR Euribor 6M + 0.368% Floating rate 30.03.2037
\n
Endesa 30.03.2022 50 EUR Euribor 6M + 0.45% Floating rate 31.07.2024
\n
Endesa 31.03.2022 250 EUR Euribor 3M + 0.85% Floating rate 31.07.2024
\n
Endesa 31.03.2022 275 EUR Euribor 3M + 1.20% Floating rate 31.07.2024
\n
Endesa 31.03.2022 75 EUR 1.405% Fixed rate 01.04.2027
\n
Endesa 08.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 29.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 10.05.2022 100 EUR Euribor 3M + 0.65% Floating rate 31.07.2024
\n
Endesa 25.05.2022 500 EUR 1.895% Fixed rate 13.05.2027
\n
Endesa 19.10.2022 200 EUR Euribor 3M + 1.30% Floating rate 31.07.2024
\n
Endesa 18.11.2022 250 EUR Euribor 6M + 0.582% Floating rate 18.11.2037
\n
Enel Colombia 05.04.2022 93 COP COP IBR 3M + 2.05% Floating rate 05.04.2028
\n
Enel Colombia 28.07.2022 79 COP COP IBR 3M + 1.6% Floating rate 28.07.2028
\n
Enel Colombia 30.11.2022 70 COP COP IBR 3M + 2.98% Floating rate 30.11.2029
\n
Enel Distribuci\u00f3n Per\u00fa 04.04.2022 52 PEN 6.96% Fixed rate 19.03.2025
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 24.03.2022 51 USD USD SOFR CMP + 0.91% Floating rate 21.03.2025
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 01.09.2022 88 USD 3.61% Fixed rate 01.09.2037
\n
Total bank borrowings 8,665
\n

\n\n

\n\n

\n\n
The following table reports the impact on gross long-term
\n
debt of hedges to mitigate currency risk.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
(1)
\n
Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Euro 34,993 35,383 49.2% 23,473 58,856 81.9% 32,041 32,387 54.8% 16,657 49,044 83.0%
\n
US dollar 26,930 27,209 37.9% (19,741) 7,468 10.4% 17,518 17,629 29.8% (13,423) 4,206 7.1%
\n
Pound sterling 4,470 4,610 6.4% (4,610) - - 3,901 3,976 6.7% (3,976) - -
\n
Colombian peso 1,310 1,310 1.8% - 1,310 1.8% 1,341 1,341 2.3% - 1,341 2.3%
\n
Brazilian real 1,899 1,926 2.7% 1,187 3,113 4.4% 1,720 1,753 3.0% 1,028 2,781 4.7%
\n
Swiss franc 359 360 0.5% (360) - - 343 344 0.6% (344) - -
\n
Chilean peso/UF 526 531 0.7% - 531 0.7% 423 428 0.7% - 428 0.7%
\n
Peruvian sol 429 429 0.6% - 429 0.6% 415 415 0.7% - 415 0.7%
\n
Russian ruble - - - - - - 427 427 0.7% - 427 0.7%
\n
Other currencies 110 115 0.2% 51 166 0.2% 402 405 0.7% 58 463
\n
0.8%
\n
Total non-euro
\n
currencies 36,033 36,490 50.8% (23,473) 13,017 18.1% 26,490 26,718 45.2% (16,657) 10,061 17.0%
\n
TOTAL 71,026 71,873 100.0% - 71,873 100.0% 58,531 59,105 100.0% - 59,105
\n
100.0%
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
The amount of floating-rate debt that is not hedged
\n
against interest rate risk is the main risk factor that could
\n
adversely impact profit or loss (raising borrowing costs) in
\n
the event of an increase in market interest rates.
\n
Millions of euro 2022 2021
\n
Pre-hedge % Post-hedge
\n
% Pre-hedge % Post-hedge %
\n
Floating rate 34,450 38.2% 31,353 34.7% 27,811 38.4% 22,478 31.0%
\n
Fixed rate 55,815 61.8% 58,912 65.3% 44,612 61.6% 49,945 69.0%
\n
Total 90,265 90,265 72,423 72,423
\n
At December 31, 2022, 38.2% of long and medium-term
\n
financial debt was floating rate (38.4% at December 31,
\n
2021). Taking account of hedges of interest rates consid-
\n
ered effective pursuant to the IFRS-EU, 34.7% of long and
\n
medium-term net financial debt at December 31, 2022
\n
was exposed to interest rate risk (31% at December 31,
\n
2021). These figures are in line with the limits established in
\n
the risk management policy.
\n
The following table shows the impact of the IBOR reform
\n
on long-term financial debt for the main indices (for more
\n
details, please see the section \u201cReform of benchmarks for
\n
the determination of interest rates - IBOR reform\u201d in note
\n
51.1).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional amount Phase 1 Phase 2 Phase 1 Phase 2
\n
USD LIBOR/SOFR 1,310 - 888 -
\n
GBP LIBOR/SONIA ---
\n
-
\n
Tot al 1,310 - 888 -
\n

\n\n

\n\n

\n\n
Long-term debt \u2013 Main covenants
\n
The Group\u2019s main long-term financial liabilities are gov-
\n
erned by covenants that are commonly adopted in inter-
\n
national business practice. They include in particular bond
\n
issues carried out within the framework of the Global/Euro
\n
Medium Term Notes program, issues of subordinated un-
\n
convertible hybrid bonds (so-called \u201chybrid bonds\u201d) and
\n
loans granted by banks and other financial institutions (in-
\n
cluding the European Investment Bank and Cassa Depositi
\n
e Prestiti SpA).
\n
The main covenants regarding bond issues carried out
\n
within the framework of the Global/Euro Medium Term
\n
Notes program of Enel and Enel Finance International NV
\n
(including the green bonds of Enel Finance International
\n
NV guaranteed by Enel SpA, which are used to finance the
\n
Group\u2019s so-called eligible green projects) and those re-
\n
garding bonds issued by Enel Finance International NV on
\n
the US market guaranteed by Enel SpA can be summarized
\n
as follows:
\n
\u2022 negative pledge clauses under which the issuer and the
\n
guarantor may not establish or maintain mortgages, liens
\n
or other encumbrances on all or part of their assets or
\n
revenue to secure certain financial liabilities, unless the
\n
same encumbrances are extended equally or pro rata to
\n
the bonds in question;
\n
\u2022 pari passu clauses, under which the bonds and the as-
\n
sociated security constitute a direct, unconditional and
\n
unsecured obligation of the issuer and the guarantor,
\n
are issued without preferential rights among them and
\n
have at least the same seniority as other present and fu-
\n
ture unsubordinated and unsecured bonds of the issuer
\n
and the guarantor;
\n
\u2022 cross-default clauses, under which the occurrence of
\n
a default event in respect of a specified financial liabil-
\n
ity (above a threshold level) of the issuer, the guarantor
\n
or, in some cases, \u201csignificant\u201d subsidiaries constitutes
\n
a default in respect of the liabilities in question, which
\n
become immediately repayable.
\n
Since 2019, Enel Finance International NV has issued a
\n
number of \u201csustainable\u201d bonds on the European market (as
\n
part of the Euro Medium Term Notes - EMTN bond issue
\n
program) and on the American market, both guaranteed
\n
by Enel SpA, linked to the achievement of a number of the
\n
Sustainable Development Goals (SDGs) of the United Na-
\n
tions that contain the same covenants as other bonds of
\n
the same type.
\n
In 2022, Enel Finance America LLC issued a \u201csustainable\u201d
\n
bond of the same type, guaranteed by Enel SpA, on the
\n
US market.
\n
The main covenants covering Enel\u2019s hybrid bonds, includ-
\n
ing the perpetual hybrid bond issues, which will only be
\n
repaid in the event of the dissolution or liquidation of the
\n
Company, can be summarized as follows:
\n
\u2022 subordination clauses, under which each hybrid bond is
\n
subordinate to all other bonds issued by the company
\n
and has the same seniority with all other hybrid financial
\n
instruments issued, being senior only to equity instru-
\n
ments;
\n
\u2022 prohibition on mergers with other companies, the sale
\n
or leasing of all or a substantial part of the company\u2019s
\n
assets to another company, unless the latter succeeds
\n
in all obligations of the issuer.
\n
The main covenants envisaged in the loan contracts
\n
of Enel and Enel Finance International NV and the other
\n
Group companies, including the sustainability-linked loan
\n
facility agreements obtained by Enel SpA, can be summa-
\n
rized as follows:
\n
\u2022 negative pledge clauses, under which the borrower and,
\n
in some cases, the guarantor are subject to limitations
\n
on the establishment of mortgages, liens or other en-
\n
cumbrances on all or part of their respective assets, with
\n
the exception of expressly permitted encumbrances;
\n
\u2022 disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their as-
\n
sets or operations, with the exception of expressly per-
\n
mitted disposals;
\n
\u2022 pari passu clauses, under which the payment undertak-
\n
ings of the borrower have the same seniority as its other
\n
unsecured and unsubordinated payment obligations;
\n
\u2022 change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required to
\n
renegotiate the terms and conditions of the financing or
\n
make compulsory early repayment of the loans granted;
\n
\u2022 rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022 cross-default clauses, under which the occurrence of a
\n
default event in respect of a specified financial liability
\n
(above a threshold level) of the issuer or, in some cas-
\n
es, the guarantor constitutes a default in respect of the
\n
liabilities in question, which become immediately repay-
\n
able.
\n
Some loan contracts entered into by Enel SpA, including as
\n
guarantor, provide for some additional covenants, such as:
\n
\u2022 the commitment to use the loan exclusively to hedge
\n
collateral for trading activities on the energy markets;
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending
\n
bank can request the cancellation of its financial com-
\n
mitment undertaken by it and the early payment of the
\n
sums disbursed if it has suffered ascertained harm to its
\n
own reputation or that of other persons as a result of
\n
substantial breach of certain regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure com-
\n
pliance with certain environmental and social regulations
\n
and standards.
\n

\n\n

\n\n

\n\n
In some cases, the covenants are also binding for the sig-
\n
nificant companies or subsidiaries of the obligated parties.
\n
All the borrowings considered specify \u201cevents of default\u201d
\n
typical of international business practice, such as, for ex-
\n
ample, insolvency, bankruptcy proceedings or the entity
\n
ceases trading.
\n
In addition, the guarantees issued by Enel in the interest
\n
of e-distribuzione SpA for certain loans to e-distribuzi-
\n
one SpA from Cassa Depositi e Prestiti SpA require that
\n
at the end of each six-month measurement period Enel\u2019s
\n
net consolidated financial debt shall not exceed 4.5 times
\n
annual consolidated EBITDA.
\n
Finally, the debt of Endesa SA, Enel Am\u00e9ricas SA, Enel Chile
\n
SA and the other Spanish and Latin American subsidiaries
\n
(notably Enel Generaci\u00f3n Chile SA) contains covenants and
\n
events of default typical of international business practice.
\n
48.3.2 Short-term borrowings \u2013 \u20ac18,392 million
\n
At December 31, 2022 short-term borrowings totaled
\n
\u20ac18,392 million, an increase of \u20ac5,086 million compared
\n
with December 31, 2021, and break down as follows:
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Short-term bank borrowings 1,320 1,329 (9)
\n
Commercial paper 13,838 10,708 3,130
\n
Cash collateral and other financing on derivatives 1,513 918 595
\n
Other short-term borrowings
\n
(1)
\n
1,721 351 1,370
\n
Short-term borrowings 18,392 13,306 5,086
\n
(1) Does not include other current borrowings included in \u201cOther current financial liabilities\u201d.
\n
Commercial paper liabilities totaling \u20ac13,838 million con-
\n
cerned issues by Enel Finance International, Endesa and
\n
Enel Finance America.
\n
The main commercial paper programs include:
\n
\u2022 \u20ac8,000 million of Enel Finance International, an increase
\n
from \u20ac6,000 million in 2021;
\n
\u2022 \u20ac5,000 million of Endesa, an increase from \u20ac4,000 mil-
\n
lion in 2021;
\n
\u2022 $5,000 million (equivalent to \u20ac4,414 million at December
\n
31, 2022), of Enel Finance America.
\n
At December 31, 2022, the whole amount of commercial
\n
paper issues, equal to \u20ac13,838 million, was linked to sus-
\n
tainability objectives.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1023": { "value": "\n
39. Employee benefits \u2013 \u20ac2,202 million
\n
The Group provides its employees with a variety of bene-
\n
fits, including deferred compensation benefits, additional
\n
months\u2019 pay for having reached age limits or eligibility for
\n
old-age pension, loyalty bonuses for achievement of se-
\n
niority milestones, supplemental retirement and health-
\n
care plans, residential electricity discounts and similar
\n
benefits. More specifically:
\n
\u2022 for Italy, the item \u201cPension benefits\u201d regards estimated
\n
accruals made to cover benefits due under the supple-
\n
mental retirement schemes of retired executives and the
\n
benefits due to personnel under law or contract at the
\n
time the employment relationship is terminated. For the
\n
foreign companies, the item refers to post-employment
\n
benefits, of which the most material regard the pension
\n
benefit schemes of Endesa in Spain, which break down
\n
into three types that differ on the basis of employee se-
\n
niority and company. In general, under the framework
\n
agreement of October 25, 2000, employees participate
\n
in a specific defined contribution pension plan and, in
\n
cases of disability or death of employees in service, a de-
\n
fined benefit plan which is covered by appropriate insur-
\n
ance policies. In addition, the group has two other lim-
\n
ited-enrollment plans (i) for current and retired Endesa
\n
employees covered by the electricity industry collective
\n
bargaining agreement prior to the changes introduced
\n
with the framework agreement noted earlier and (ii) for
\n
employees of the Catalan companies merged in the past
\n
(Fecsa/Enher/HidroEmpord\u00e0). Both are defined benefit
\n
plans and benefits are fully ensured, with the exception
\n
of the former plan for benefits in the event of the death
\n
of a retired employee. Finally, the Brazilian companies
\n
have also established defined benefit plans;
\n
\u2022 the item \u201cElectricity discount\u201d comprises benefits re-
\n
garding electricity supply associated in particular with
\n
foreign companies;
\n
\u2022 the item \u201cHealth insurance\u201d refers to benefits for current
\n
or retired employees covering medical expenses;
\n
\u2022 the item \u201cOther benefits\u201d mainly regards the loyalty bo-
\n
nus, which is adopted in various countries and for Italy
\n
is represented by the estimated liability for the benefit
\n
entitling employees covered by the electricity workers
\n
national collective bargaining agreement to a bonus for
\n
achievement of seniority milestones (25th and 35th year
\n
of service). It also includes other incentive plans, which
\n
provide for the award to certain Company managers of a
\n
monetary bonus subject to specified conditions.
\n
The following table reports changes in the defined benefit
\n
obligation for post-employment and other long-term em-
\n
ployee benefits at December 31, 2022, and December 31,
\n
2021, respectively, as well as a reconciliation of that obliga-
\n
tion with the actuarial liability.
\n

\n\n
Millions of euro 2022 2021
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Total
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Total
\n
CHANGES IN ACTUARIAL
\n
OBLIGATION
\n
Change in actuarial obligation
\n
previous year
\n
Actuarial obligation at the
\n
start of the year
\n
4,240 410 206 190 5,046 4,408 403 217 222 5,250
\n
Current service cost 13 1 5 13 32 17 2 4 28 51
\n
Interest expense 320 7 8 5 340 214 3 7 3 227
\n
Actuarial (gains)/losses arising
\n
from changes in demographic
\n
assumptions
\n
- - - - - 192 - (6) - 186
\n
Actuarial (gains)/losses arising
\n
from changes in financial
\n
assumptions
\n
(533) (93) (38) (18) (682) (664) (14) 6 (1) (673)
\n
Experience adjustments 119 (80) 8 1 48 452 31 (9) - 474
\n
Past service cost (3) - - - (3) (17) - - (3) (20)
\n
(Gains)/Losses arising from
\n
settlements
\n
(163) - - - (163) (4) - - - (4)
\n
Exchange differences 335 - 6 (1) 340 14 (1) (1) - 12
\n
Employer contributions - - - - - - - - - -
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (470) (15) (13) (44) (542) (379) (15) (12) (58) (464)
\n
Other changes - - - (6) (6) 7 1 - (1) 7
\n
Reclassification to assets 8 - - - 8 - - - - -
\n
Liabilities included in disposal
\n
groups classified as held for
\n
sale
\n
(101) (6) (20) (22) (149) - - - - -
\n
Actuarial obligation at year-
\n
end (A)
\n
3,765 224 162 118 4,269 4,240 410 206 190 5,046
\n
CHANGES IN PLAN ASSETS
\n
Fair value of plan assets at the
\n
start of the year
\n
2,348 - - - 2,348 2,299 - - - 2,299
\n
Interest income 193 - - - 193 121 - - - 121
\n
Expected return on plan assets
\n
excluding amounts included in
\n
interest income
\n
(184) - - - (184) 38 - - - 38
\n
Exchange differences 213 - - - 213 17 - - - 17
\n
Employer contributions 286 15 13 22 336 252 15 12 28 307
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (470) (15) (13) (22) (520) (379) (15) (12) (28) (434)
\n
Other payments (163) - - - (163) - - - - -
\n
Changes in the consolidation
\n
scope
\n
(99) - - - (99) - - - - -
\n
Fair value of plan assets at
\n
year-end (B)
\n
2,124 - - - 2,124 2,348 - - - 2,348
\n
EFFECT OF ASSET CEILING
\n
Asset ceiling at the start of
\n
the year
\n
26 - - - 26 13 - - - 13
\n
Interest income 2 - - - 2 1 - - - 1
\n
Changes in asset ceiling 27 - - - 27 12 - - - 12
\n
Exchange differences 2 - - - 2 - - - - -
\n
Changes in the consolidation
\n
scope
\n
----- -----
\n
Asset ceiling at year-end (C) 57 - - - 57 26 - - - 26
\n
Net liability in statement of
\n
financial position (A-B+C)
\n
1,698 224 162
\n
118 2,202 1,918 410 206 190 2,724
\n

\n\n
The liability recognized came to \u20ac2,202 million, a decrease
\n
of \u20ac522 million on 2021. Change in 2022 reflects the re-
\n
classification as held for sale of the actuarial liabilities of
\n
Enel Generaci\u00f3n Costanera SA and Central Dock Sud SA
\n
in Argentina, 3SUN Srl in Italy, all the companies in Roma-
\n
nia and Greece and PJSC Enel Russia and its subsidiaries,
\n
the latter sold in the last quarter of 2022. Furthermore, the
\n
actuarial measurement of a plan of Asociaci\u00f3n Nuclear As-
\n
c\u00f3-Vandell\u00f3s II AIE in Spain showed a surplus with respect
\n
to the obligation assumed by the company, and was thus
\n
reclassified in a specific asset item of the balance sheet.
\n
Millions of euro
\n
2022 2021
\n
(Gains)/Losses taken to profit or loss
\n
Service cost and past service cost 22 9
\n
Net interest expense 149 107
\n
(Gains)/Losses arising from settlements - (4)
\n
Actuarial (gains)/losses on other long-term benefits 722
\n
Other changes (20) 1
\n
Tot al 158 135
\n
Millions of euro
\n
2022 2021
\n
Change in (gains)/losses in OCI
\n
Expected return on plan assets excluding amounts included in interest income 184 (38)
\n
Actuarial (gains)/losses on defined benefit plans (614) (13)
\n
Changes in asset ceiling excluding amounts included in interest income 27 12
\n
Other changes - (1)
\n
Tot al (403) (40)
\n
The change in the cost recognized in profit or loss was
\n
equal to \u20ac23 million. The impact on the income statement
\n
is, therefore, greater but essentially in line with 2021.
\n
The liability recognized in the statement of financial posi-
\n
tion at the end of the year is reported net of the fair value
\n
of plan assets, amounting to \u20ac2,124 million at December
\n
31, 2022. Those assets, which are entirely in Spain and Bra-
\n
zil, break down as follows:
\n
2022 2021
\n
Investments quoted in active markets
\n
Equity instruments 10% 8%
\n
Fixed-income securities 66% 54%
\n
Investment property 3% 3%
\n
Other 21% -
\n
Unquoted investments
\n
Assets held by insurance undertakings --
\n
Other - 35%
\n
Tot al 100% 100%
\n
The main actuarial assumptions used to calculate the lia-
\n
bilities in respect of employee benefits and the plan assets,
\n
which are consistent with those used the previous year, are
\n
set out in the following table.
\n

\n\n
Italy Iberia Latin America
\n
Other
\n
countries Italy Iberia Latin America
\n
Other
\n
countries
\n
2022 2021
\n
Discount rate
\n
3.60%-
\n
3.70%
\n
3.57%-3.77% 5.40%-10.40% 3.75%-7.65%
\n
0.00%-
\n
0.80%
\n
0.00%-1.16% 5.60%-9.67%
\n
0.80%-
\n
8.40%
\n
Inflation rate 2.30% 2.78% 3.00%-8.00%
\n
2.40%-
\n
3.50%
\n
1.50% 2.20% 3.00% -8.00%
\n
1.50%-
\n
4.01%
\n
Rate of wage
\n
increases
\n
2.30%-
\n
4.30%
\n
2.78% 3.80%-8.49%
\n
3.00%
\n
-10.00%
\n
0.80%-
\n
1.80%
\n
2.20% 3.80%-8.00%
\n
2.50%-
\n
10.00%
\n
Rate of increase in
\n
healthcare costs
\n
3.30% 4.98% 7.12%-10.00% - 2.50% 4.40% 7.12%-8.00% -
\n
Expected rate of
\n
return on plan assets
\n
- 3.76%-3.77% 10.40% 7.40% - 0.57% 9.30% -9.46% -
\n
The following table reports the outcome of a sensitivity
\n
analysis that demonstrates the effects on the defined ben-
\n
efit obligation of changes reasonably possible at the end
\n
of the year in the actuarial assumptions used in estimating
\n
the obligation.
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits Pension benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance Other benefits
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Decrease of 0.5%
\n
in discount rate
\n
185 2 6 (17) 225 27 11 -
\n
Increase of 0.5% in
\n
discount rate
\n
(118) (22) (9) (23) (184) (30) (14) (10)
\n
Increase of 0.5% in
\n
inflation rate
\n
16 (11) (8) (21) 2 (4) (2) (6)
\n
Decrease of 0.5%
\n
in inflation rate
\n
37 (10) 6 (16) 28 (2) 9 (2)
\n
Increase of 0.5% in
\n
remuneration
\n
29 (10) (2) (17) 14 (3) (2) -
\n
Increase of 0.5% in
\n
pensions currently
\n
being paid
\n
28 (10) (2) (20) 14 (3) (2) (5)
\n
Increase of 1% in
\n
healthcare costs
\n
- - (147) - - - 20 1
\n
Increase of 1 year
\n
in life expectancy
\n
of active and
\n
retired employees
\n
55 (9) 5 (17) 98 (3) 14 (5)
\n
The sensitivity analysis used an approach that extrapolates
\n
the effect on the defined benefit obligation of reasonable
\n
changes in an individual actuarial assumption, leaving the
\n
other assumptions unchanged.
\n
The contributions expected to be paid into defined benefit
\n
plans in the subsequent year amount to \u20ac221 million.
\n
The following table reports expected benefit payments in
\n
the coming years for defined benefit plans.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Within 1 year 427 392
\n
In 1-2 years 397 364
\n
In 2-5 years 1,124 1,077
\n
More than 5 years 1,826 1,714
\n
Expected payments are increasing in general. This is main-
\n
ly due to Brazil and Argentina.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1043": { "value": "\n
40. Provisions for risks and charges \u2013 \u20ac7,380 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Non-current Current Total Non-current Current Total
\n
Provision for litigation, risks and other charges:
\n
- nuclear decommissioning 581 - 581 666 - 666
\n
- site retirement, removal and restoration 2,686 247 2,933 3,066 203 3,269
\n
- litigation 652 51 703 790 44 834
\n
- environmental certificates - 292 292 - 32 32
\n
- taxes and duties 313 26 339 267 28 295
\n
- other 803 316 1,119 821 347 1,168
\n
Total 5,035 932 5,967 5,610 654 6,264
\n
Provision for early retirement incentives and other
\n
restructuring plans
\n
231 192 423 435 293 728
\n
Provision for restructuring programs connected with
\n
the energy transition
\n
789 201 990 1,152 179 1,331
\n
TOTAL 6,055 1,325 7,380 7,197 1,126 8,323
\n
Millions of euro Accrual Reversal Utilization
\n
Discoun-
\n
ting
\n
Provisions
\n
for site reti-
\n
rement and
\n
restoration
\n
Change in
\n
consolida-
\n
tion scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
Reclassifications
\n
of liabilities
\n
included in
\n
disposal groups
\n
held for sale
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Provision for litigation,
\n
risks and other charges:
\n
- nuclear
\n
decommissioning
\n
666 - - - 8 (93) - - - - 581
\n
- site retirement, removal
\n
and restoration
\n
3,269 201 (135) (167) (12) (207) (2) 16 (1) (29) 2,933
\n
- litigation 834 239 (123) (162) 59 - - 42 35 (221) 703
\n
- environmental
\n
certificates
\n
32 345 (24) (8) - - - - (35) (18) 292
\n
- taxes and duties 295 45 (30) (10) 8 - 8 10 13 - 339
\n
- other 1,168 375 (79) (309) 11 (2) 39 (3) (38) (43) 1,119
\n
Total 6,264 1,205 (391) (656) 74 (302) 45 65 (26) (311) 5,967
\n
Provision for early
\n
retirement incentives
\n
and other restructuring
\n
plans
\n
728 4 (32) (244) (26) - - - (4) (3) 423
\n
Provision for
\n
restructuring programs
\n
connected with the
\n
energy transition
\n
1,331 51 (177) (157) (51) - - 2 (4) (5) 990
\n
TOTAL 8,323 1,260 (600) (1,057) (3) (302) 45 67 (34) (319) 7,380
\n
Nuclear decommissioning provision
\n
At December 31, 2022 the provision reflected solely the
\n
costs that would be incurred at the time of decommis-
\n
sioning of nuclear plants by Enresa, a Spanish public entity
\n
responsible for such activities in accordance with Royal
\n
Decree 1349/2003 and Law 24/2005. In general, the costs
\n
are quantified on the basis of a standard contract between
\n
Enresa and the electricity companies approved by the
\n
Ministry for the Economy in September 2001, which reg-
\n
ulates the retirement and closing of nuclear power plants.
\n
The time horizon envisaged, three years, corresponds to
\n
the period from the termination of power generation to
\n
the transfer of plant management to Enresa (so-called
\n
post-operational costs) and takes account, among the
\n
various assumptions used to estimate the amount, of the
\n
quantity of unused nuclear fuel expected at the date of
\n
closure of each of the Spanish nuclear plants on the basis
\n
of the provisions of the concession agreement.
\n
Site retirement, removal and restoration
\n
provision
\n
This provision represents the present value of the esti-
\n
mated cost for the retirement and removal of non-nuclear
\n
plants where there is a legal or constructive obligation to
\n
do so. The provision mainly regarded the Endesa Group
\n
and Enel Produzione. The change in the provision in 2022
\n

\n\n

\n
was mainly linked to the redetermination of the future re-
\n
tirement costs of certain plants in Iberia and North America
\n
as well as the uses and releases of provisions set aside in
\n
previous years to deal with the decarbonization process.
\n
The following table summarizes the temporal breakdown
\n
of payments connected with the site retirement, removal
\n
and restoration provision.
\n
Millions of euro
\n
Payments by time bracket
\n
(nominal value) Discounted amount
\n
Within 1 year 248 247
\n
In 1-5 years 1,221 1,134
\n
More than 5 years 2,275 1,552
\n
Tot al 3,744 2,933
\n
Litigation provision
\n
The litigation provision covers contingent liabilities in re-
\n
spect of pending litigation and other disputes. It includes
\n
an estimate of the potential liability relating to disputes
\n
that arose during the year, as well as revised estimates of
\n
the potential costs associated with disputes initiated in
\n
prior years, based on the indications of internal and exter-
\n
nal consultants. The balance for litigation mainly regards
\n
the companies in Latin America (\u20ac395 million), Spain (\u20ac169
\n
million) and Italy (\u20ac127 million).
\n
The decrease compared with the previous year, equal to
\n
\u20ac131 million, mainly reflects the decrease in the provision
\n
in Brazil following the deconsolidation of Celg-D.
\n
Provision for environmental certificates
\n
The provision for environmental certificates covers costs in
\n
respect of shortfalls in the environmental certificates need
\n
for compliance with national or supranational environ-
\n
mental protection requirements and mainly regards Iberia
\n
(Endesa Energ\u00eda and Endesa Generaci\u00f3n SA).
\n
Provision for taxes and duties
\n
The provision for taxes and duties covers the estimated
\n
liability deriving from tax disputes concerning direct and
\n
indirect taxes.
\n
The balance of the provision also includes the provision for
\n
current and potential disputes concerning local proper-
\n
ty tax (whether the Imposta Comunale sugli Immobili (ICI)
\n
or the Imposta Municipale Unica (IMU)) in Italy. In Italy, the
\n
Group has taken due account of developments in land
\n
registry regulations (which with effect from January 1, 2016
\n
excluded machinery, devices, equipment and other plant
\n
specific to a production process from the calculation of
\n
the imputed rent for buildings classified in land registry
\n
group D, which includes generation plants) in estimating
\n
the liability for such taxes, both for the purposes of quan-
\n
tifying the probable risk associated with pending litigation
\n
and generating a reasonable valuation of probable future
\n
charges on positions that have not yet been assessed by
\n
the Revenue Agency and municipalities.
\n\n
Other provisions
\n
Other provisions cover various risks and charges, mainly
\n
in connection with regulatory disputes and disputes with
\n
local authorities regarding various duties and fees or other
\n
charges.
\n
The decrease of \u20ac49 million in other provisions is mainly
\n
attributable to Enel Global Trading for uses of provisions
\n
for insurance compensation.
\n

\n\n
Provision for early retirement incentives and
\n
other restructuring plans
\n
The provision for early retirement incentives and other
\n
restructuring plans includes the estimated charges relat-
\n
ed to binding agreements for the voluntary termination
\n
of employment contracts in response to organizational
\n
needs. The reduction of \u20ac305 million for the year main-
\n
ly reflects uses of provisions for incentives established in
\n
previous period in Spain (Acuerdo de Salida Voluntaria) and
\n
Italy to cover the early termination of employment for cer-
\n
tain employees.
\n
Provision for restructuring programs
\n
connected with the energy transition
\n
Enel, in its role as a leader of the energy transition, has
\n
placed decarbonization and growth of renewables around
\n
the world at the center of its strategy.
\n
In this context, Enel has begun restructuring the activities
\n
associated with the energy transition process, which in-
\n
volves thermal generation plants in all the geographical ar-
\n
eas in which the Group operates. The consequent revision
\n
of processes and operating models will require changes in
\n
the roles and skills of employees, which the Group intends
\n
to implement with highly sustainable plans based on re-
\n
deployment programs, with major upskilling and reskilling
\n
plans and voluntary individual early retirement agreements.
\n
The energy transition is also based on the progressive and
\n
expansive development of digital tools, as digitization is
\n
essential to responding to multiple external forces and
\n
making informed and well-considered decisions at every
\n
level within the Group.
\n

\n\n
A provision was therefore established in 2020 for restruc-
\n
turing programs, which at December 31, 2022 amounted
\n
to \u20ac990 million, which is mainly attributable to Spain and
\n
Italy, and represents the estimated costs that the Group
\n
will incur following the acceleration of the energy transi-
\n
tion, for all direct and indirect activities related to the re-
\n
view of processes and operating models and the roles and
\n
skills of employees.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1047": { "value": "\n
Other provisions
\n
Other provisions cover various risks and charges, mainly
\n
in connection with regulatory disputes and disputes with
\n
local authorities regarding various duties and fees or other
\n
charges.
\n
The decrease of \u20ac49 million in other provisions is mainly
\n
attributable to Enel Global Trading for uses of provisions
\n
for insurance compensation.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1045": { "value": "\n
41. Other non-current financial liabilities \u2013 \u20ac - million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Other non-current financial liabilities - 120 (120) -
\n
Tot al - 120 (120) -
\n
The change in \u201cOther non-current financial liabilities\u201d came
\n
to \u20ac120 million and regards the decrease in the non-cur-
\n
rent portion of liabilities in respect of the Spanish electrical
\n
system deficit, which were included in net financial debt.
\n

\n\n
45. Other current financial liabilities \u2013 \u20ac853 million
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued financial expense and deferred financial income 710 539 171 31.7%
\n
Other items 143 86 57 66.3%
\n
Tot al 853 625 228 36.5%
\n
The increase in other current financial liabilities is mainly
\n
attributable to the increase of \u20ac171 million in accrued fi-
\n
nancial expense and deferred financial income, as a result
\n
of higher accrued expenses on bond issues.
\n
Other items mainly regard liabilities for accrued interest.
\n

\n\n
48.2 Financial liabilities by category
\n
The following table shows the carrying amount for each
\n
category of financial liability provided for under IFRS 9,
\n
broken down into current and non-current financial lia-
\n
bilities, showing hedging derivatives and derivatives mea-
\n
sured at fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Financial liabilities measured at amortized cost 48.2.1 68,432 54,914 45,697
\n
42,330
\n
Financial liabilities at fair value through profit or loss
\n
Derivative financial liabilities at FVTPL 48.4 588 169 11,642
\n
19,696
\n
Total financial liabilities at fair value through profit or loss 588 169 11,642 19,696
\n
Derivative financial liabilities designated as hedging instruments
\n
Fair value hedge derivatives 48.4 191 5 - -
\n
Cash flow hedge derivatives 48.4 5,116 3,165 4,499
\n
4,911
\n
Total derivative financial liabilities designated as hedging
\n
instruments
\n
5,307 3,170 4,499 4,911
\n
TOTAL 73,158 58,253 63,007
\n
66,937
\n
For more information on fair value measurement, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\n
48.2.1 Financial liabilities measured at amortized cost
\n
The following table shows financial liabilities at amortized
\n
cost by nature, broken down into current and non-current
\n
financial liabilities.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Long-term borrowings 48.3 68,191 54,500 48.3 2,835 4,031
\n
Short-term borrowings - - 48.3 18,392 13,306
\n
Trade payables 44 36 94 44 17,605 16,865
\n
Other financial liabilities 205
\n
320 6,865 8,128
\n
Tot al 68,432
\n
54,914 45,697 42,330
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1042": { "value": "\n

\n\n

\n\n

\n
42. Other non-current liabilities \u2013 \u20ac4,246 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued operating expenses and deferred income 347 498 (151) -30.3%
\n
Other items 3,899 4,027 (128) -3.2%
\n
Tot al 4,246 4,525 (279) -6.2%
\n

\n\n
The change in \u201cOther items\u201d reflected the decrease of \u20ac45
\n
million in \u201cOther tax liabilities beyond 12 months\u201d, as well as
\n
the decrease of \u20ac351 million in \u201cOther liabilities\u201d relating to
\n
the outcome of the PIS/COFINS dispute in Brazil (already
\n
discussed under \u201cOther non-current assets\u201d), only partially
\n
offset by the increase of \u20ac323 million in \u201cLiabilities for tax
\n
partnerships\u201d in North America.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1046": { "value": "\n

\n\n

\n
42. Other non-current liabilities \u2013 \u20ac4,246 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued operating expenses and deferred income 347 498 (151) -30.3%
\n
Other items 3,899 4,027 (128) -3.2%
\n
Tot al 4,246 4,525 (279) -6.2%
\n

\n\n
The change in \u201cOther items\u201d reflected the decrease of \u20ac45
\n
million in \u201cOther tax liabilities beyond 12 months\u201d, as well as
\n
the decrease of \u20ac351 million in \u201cOther liabilities\u201d relating to
\n
the outcome of the PIS/COFINS dispute in Brazil (already
\n
discussed under \u201cOther non-current assets\u201d), only partially
\n
offset by the increase of \u20ac323 million in \u201cLiabilities for tax
\n
partnerships\u201d in North America.
\n

\n\n

\n\n

\n\n

\n
43. Other current liabilities \u2013 \u20ac11,713 million
\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n\n

\n\n
The change in \u201cOther current liabilities\u201d mainly reflects:
\n
\u2022 the decrease in \u201cAmounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, with the decrease
\n
in amounts due to the Energy and Environmental Ser-
\n
vices Fund, determined by the update of rate in force for
\n
2022 with the Regulatory Authority for Energy, Networks
\n
and Environment (ARERA) Resolutions no. 35/2022,
\n
141/2022, 295/2022 and 462/2022, which complete-
\n
ly zeroed system charges rates for all types of users as
\n
from January 1, 2022;
\n

\n\n

\n\n

\n\n

\n\n
\u2022 the decrease in \u201cOther tax liabilities\u201d, mainly attributable
\n
to Italy following the start in 2021 of the Group settlement
\n
mechanism for VAT obligations by the Parent, Enel SpA;
\n

\n\n
\u2022 the decrease in \u201cOther liabilities\u201d, mainly attributable to
\n
Italy in respect of expired derivatives on energy com-
\n
modities.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1040": { "value": "\n

\n
42. Other non-current liabilities \u2013 \u20ac4,246 million
\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued operating expenses and deferred income 347 498 (151) -30.3%
\n
Other items 3,899 4,027 (128) -3.2%
\n
Tot al 4,246 4,525 (279) -6.2%
\n

\n\n
The change in \u201cOther items\u201d reflected the decrease of \u20ac45
\n
million in \u201cOther tax liabilities beyond 12 months\u201d, as well as
\n
the decrease of \u20ac351 million in \u201cOther liabilities\u201d relating to
\n
the outcome of the PIS/COFINS dispute in Brazil (already
\n
discussed under \u201cOther non-current assets\u201d), only partially
\n
offset by the increase of \u20ac323 million in \u201cLiabilities for tax
\n
partnerships\u201d in North America.
\n

\n\n

\n
43. Other current liabilities \u2013 \u20ac11,713 million
\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n\n

\n\n
The change in \u201cOther current liabilities\u201d mainly reflects:
\n
\u2022 the decrease in \u201cAmounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, with the decrease
\n
in amounts due to the Energy and Environmental Ser-
\n
vices Fund, determined by the update of rate in force for
\n
2022 with the Regulatory Authority for Energy, Networks
\n
and Environment (ARERA) Resolutions no. 35/2022,
\n
141/2022, 295/2022 and 462/2022, which complete-
\n
ly zeroed system charges rates for all types of users as
\n
from January 1, 2022;
\n

\n\n

\n\n
\u2022 the decrease in \u201cOther tax liabilities\u201d, mainly attributable
\n
to Italy following the start in 2021 of the Group settlement
\n
mechanism for VAT obligations by the Parent, Enel SpA;
\n

\n\n
\u2022 the decrease in \u201cOther liabilities\u201d, mainly attributable to
\n
Italy in respect of expired derivatives on energy com-
\n
modities.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1049": { "value": "\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Accrued operating expenses and deferred income 347 498 (151) -30.3%
\n
Other items 3,899 4,027 (128) -3.2%
\n
Tot al 4,246 4,525 (279) -6.2%
\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1044": { "value": "\n

\n\n

\n\n

\n
43. Other current liabilities \u2013 \u20ac11,713 million
\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n\n

\n\n
The change in \u201cOther current liabilities\u201d mainly reflects:
\n
\u2022 the decrease in \u201cAmounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, with the decrease
\n
in amounts due to the Energy and Environmental Ser-
\n
vices Fund, determined by the update of rate in force for
\n
2022 with the Regulatory Authority for Energy, Networks
\n
and Environment (ARERA) Resolutions no. 35/2022,
\n
141/2022, 295/2022 and 462/2022, which complete-
\n
ly zeroed system charges rates for all types of users as
\n
from January 1, 2022;
\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
\u2022 the decrease in \u201cOther tax liabilities\u201d, mainly attributable
\n
to Italy following the start in 2021 of the Group settlement
\n
mechanism for VAT obligations by the Parent, Enel SpA;
\n

\n\n
\u2022 the decrease in \u201cOther liabilities\u201d, mainly attributable to
\n
Italy in respect of expired derivatives on energy com-
\n
modities.
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1048": { "value": "\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Amounts due to customers 2,094 1,950 144 7.4%
\n
Amounts due to institutional market operators 2,115 2,961 (846) -28.6%
\n
Amounts due to employees 519 471 48 10.2%
\n
Other tax liabilities 1,046 1,274 (228) -17.9%
\n
Amounts due to social security institutions 215 205 10 4.9%
\n
Contingent consideration 46 45 1 2.2%
\n
Put options granted to non-controlling shareholders - 4 (4) -
\n
Current accrued expenses and deferred income 441 395 46 11.6%
\n
Dividends 2,228 2,191 37 1.7%
\n
Other liabilities 3,009 3,463 (454) -13.1%
\n
Tot al 11,713 12,959 (1,246) -9.6%
\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDepositsFromCustomersExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1041": { "value": "\n
44. Trade payables \u2013 \u20ac17,641 million
\n
The item amounted to \u20ac17,641 million (\u20ac16,959 million at
\n
December 31, 2021) and includes payables in respect of
\n
electricity supplies, fuel, materials, equipment associated
\n
with tenders, and other services.
\n
More specifically, trade payables falling due in less than 12
\n
months amounted to \u20ac17,605 million (\u20ac16,865 million at
\n
December 31, 2021), while those falling due in more than
\n
12 months amounted to \u20ac36 million (\u20ac94 million at De-
\n
cember 31, 2021).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1050": { "value": "\n
46. Cash flows
\n
Millions of euro
\n
2022 2021 Change
\n
Cash and cash equivalents at the beginning of the year
\n
(1)
\n
8,990 6,002 2,988
\n
Cash flows from operating activities
\n
(2)
\n
8,674 9,915 (1,241)
\n
of which discontinued operations (391) 280
\n
Cash flows from/(used in) investing activities (13,626) (10,875) (2,751)
\n
of which discontinued operations (351) (453)
\n
Cash flows from financing activities
\n
(2)
\n
7,369 3,931 3,438
\n
of which discontinued operations 656 118
\n
Impact of exchange rate fluctuations on cash and cash equivalents 136 17 119
\n
Cash and cash equivalents at the end of the year
\n
(3)
\n
11,543 8,990 2,553
\n
(1) Of which cash and cash equivalents equal to \u20ac8,315 million at January 1, 2022 (\u20ac5,266 million at January 1, 2021), short-term securities equal to \u20ac88 million
\n
at January 1, 2022 (\u20ac67 million at January 1, 2021) and cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of \u20ac44 million at January
\n
1, 2022 (\u20ac29 million at January 1, 2021) and cash and cash equivalents pertaining to \u201cdiscontinued operations\u201d equal to \u20ac543 million at January 1, 2022 (\u20ac640
\n
million at January 1, 2021).
\n
(2) In order to improve presentation, for comparative purposes only, realized financial income and expense connected solely with loans in currencies have been reclas-
\n
sified under a new item \u201cCollections/(Payments) associated with derivatives connected with borrowings\u201d in the section on cash flows from financing activities.
\n
(3) Of which cash and cash equivalents equal to \u20ac11,041 million at December 31, 2022 (\u20ac8,315 million at December 31, 2021), short-term securities equal to
\n
\u20ac78 million at December 31, 2022 (\u20ac88 million at December 31, 2021) and cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of
\n
\u20ac98 million at December 31, 2022 (\u20ac44 million at December 31, 2021) and to \u201cdiscontinued operations\u201d equal to \u20ac326 million at December 31, 2022 (\u20ac543
\n
million at December 31, 2021).
\n
Cash flows from operating activities in 2022 was a posi-
\n
tive \u20ac8,674 million, a decrease of \u20ac1,241 million on 2021,
\n
mainly attributable to increased cash requirements con-
\n
nected with changes in net working capital.
\n
Cash flows used in investing activities in 2022 came to
\n
\u20ac13,626 million, from \u20ac10,875 million in 2021.
\n
More specifically, investments in property, plant and equip-
\n
ment, intangibles, property investment and contract assets
\n
came to \u20ac14,503 million (including \u20ac156 million classified
\n
as available for sale), an increase on 2021.
\n
Investments in companies or business units, net of cash
\n
and cash equivalents acquired, amount to \u20ac1,275 million
\n
and mainly refer to the acquisition by Enel Produzione SpA
\n
of 100% of ERG Hydro Srl (now Enel Hydro Appennino Cen-
\n
trale Srl), for \u20ac1,196 million net of cash and cash equiva-
\n
lents acquired of \u20ac69 million.
\n
Disposals of businesses or business units, net of cash and
\n
cash equivalents sold, amount to \u20ac2,032 million and mainly
\n
refer to:
\n
\u2022 the sale by EGP SpA to Al Rayyan Holding LLC (controlled
\n
by the Qatar Investment Authority) of a 50% interest in
\n
EGP Matimba NewCo 1 Srl, indirect owner of six projects
\n
in South Africa (for \u20ac102 million net of cash and cash
\n
equivalents sold of \u20ac6 million);
\n
\u2022 the sale by Enel X Germany of the entire interest held in
\n
Cremzow KG and Cremzow Verwaltungs (for \u20ac8 million
\n
net of cash and cash equivalents sold of \u20ac4 million);
\n
\u2022 the sale by Enel Brasil SA of the entire interest held in
\n
CGTF - Central Geradora Termel\u00e9trica Fortaleza SA (for
\n
\u20ac29 million net of cash and cash equivalents sold of \u20ac60
\n
million);
\n
\u2022 the sale of the entire interest held in Enel SpA in PJSC
\n
Enel Russia, equal to 56.43% of the share capital of the
\n
latter, to PJSC Lukoil and Closed Combined Mutual In-
\n
vestment Fund \u201cGazprombank-Frezia\u201d (for \u20ac20 million
\n
net of cash and cash equivalents sold of \u20ac117 million);
\n
\u2022 the sale of the entire interest held by Enel Chile SA in
\n
Chilean power transmission company Enel Transmisi\u00f3n
\n
Chile SA, to Sociedad Transmisora Metropolitana SpA,
\n
controlled by Inversiones Grupo Saesa Ltda, for a total
\n
consideration of \u20ac1,342 million;
\n
\u2022 the sale of a 50% quota in its wholly-owned subsidiary
\n
Gridspertise Srl, to the international private equity fund
\n
CVC Capital Partners Fund VIII, for \u20ac272 million net of
\n
cash and cash equivalents sold of \u20ac27 million;
\n
\u2022 the sale of the entire interest held by Enel Am\u00e9ricas in
\n
the Brazilian electricity distribution company Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), equal to 99.9% of the
\n
share capital of the latter, to Equatorial Participa\u00e7\u00f5es e
\n
Investimentos SA, controlled by Equatorial Energia SA,
\n
for a total consideration of \u20ac259 million net of cash and
\n
cash equivalents sold of \u20ac10 million.
\n
Cash flows from/(used in) other investing activities in 2022
\n
came to 120 million and mainly reflects:
\n
\n\n
\u2022 the sale of a 1.1% interest held by Enel X International in
\n
Ufinet, for \u20ac73 million;
\n
\u2022 the sale by Enel Kansas LLC of a 50% interest held in
\n
Rocky Caney Holdings LLC and EGPNA Renewable Ener-
\n
gy Partners for \u20ac94 million;
\n
\u2022 the acquisition of 50% of the share capital of Mooney for
\n
\u20ac225 million;
\n
\u2022 the sale by Enel Green Power Canada Inc. of a 49% in-
\n
terest held in Pincher Creek LP and Riverview LP for \u20ac56
\n
million;
\n
\u2022 minor disposals mainly in Italy, Iberia, North America and
\n
Latin America.
\n
Cash flows from financing activities came to a total \u20ac7,369
\n
million, from \u20ac3,931 million used in 2021, mainly reflecting:
\n
\u2022 the net increase as the balance between repayments,
\n
new borrowings and other changes in financial payables
\n
for \u20ac12,420 million;
\n
\u2022 distribution of dividends in the amount of \u20ac4,901 mil-
\n
lion, plus \u20ac123 million paid to holders of perpetual hybrid
\n
bonds;
\n
\u2022 capital increases in subsidiaries with non-controlling in-
\n
terests for \u20ac12 million, particularly in Australia.
\n
In 2022, cash flows used in investing activities in the
\n
amount of \u20ac13,626 million fully absorbed the cash flows
\n
from operating activities for \u20ac8,674 million, with the dif-
\n
ference coming from financing activities in the amount of
\n
\u20ac7,369 million. The difference is reflected in an increase
\n
in cash and cash equivalents at December 31, 2022 to
\n
\u20ac11,543 million, from \u20ac8,990 million at the end of 2021.
\n
The change was also affected by effects associated with
\n
the positive developments in the exchange rates of local
\n
currencies against the euro, in the amount of \u20ac136 million.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1053": { "value": "\n
47. Net financial position and long-term financial assets and securities
\n
\u2013 \u20ac60,068 million
\n
The following table shows the net financial position and
\n
long-term financial assets and securities on the basis of
\n
the items on the statement of consolidated financial po-
\n
sition.
\n
Millions of euro
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Change
\n
Long-term borrowings 38 68,191 54,500 13,691 25.1%
\n
Other non-current financial borrowings
\n
(1)
\n
41 - 120 (120) -
\n
Short-term borrowings 38 18,392 13,306 5,086 38.2%
\n
Other current financial borrowings
\n
(2)
\n
-12(12) -
\n
Current portion of long-term borrowings 38 2,835 4,031 (1,196) -29.7%
\n
Other non-current financial assets included in net financial debt 29.1 (4,213) (2,692) (1,521) -56.5%
\n
Other current financial assets included in net financial debt 30.1 (13,501) (8,467) (5,034) -59.5%
\n
Cash and cash equivalents 35 (11,041) (8,858) (2,183) -24.6%
\n
Net exchange rate derivatives associated with borrowings
\n
(3)
\n
(595) (259) (336) -
\n
Tot al
\n
(3)
\n
60,068 51,693 8,375 16.2%
\n
(1) The item \u201cOther non-current financial borrowings\u201d is represented by \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(2) The item \u201cOther current financial borrowings\u201d is included under \u201cOther current financial liabilities\u201d in the statement of financial position.
\n
(3) In order to improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\n
The financial position is reported in compliance with Guide-
\n
line 39, issued on March 4, 2021 by ESMA and applicable
\n
as from May 5, 2021, and with warning notice no. 5/2021
\n
issued by CONSOB on April 29, 2021, which replaced the
\n
references to the CESR Recommendations and the ref-
\n
erences in Communication no. DEM/6064293 of July 28,
\n
2006 regarding the net financial position.
\n
The net financial debt of the Enel Group at December 31,
\n
2022 and December 31, 2021 is reconciled with net finan-
\n
cial debt as provided for in the presentation methods of
\n
the Enel Group.
\n

\n\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Liquidity
\n
Cash and cash equivalents on hand 35 8 27 -
\n
Bank and post office deposits 8,968 8,118 850 10.5%
\n
Liquid assets 9,003 8,126 877 10.8%
\n
Cash equivalents 2,038 732 1,306 -
\n
Securities 78 88 (10) -11.4%
\n
Short-term loan assets 10,585 6,841 3,744 54.7%
\n
Current portion of long-term loan assets 2,838 1,538 1,300 84.5%
\n
Other current financial assets 13,501 8,467 5,034 59.5%
\n
Liquidity 24,542 17,325 7,217 41.7%
\n
Current financial debt
\n
Bank debt (1,320) (1,329) 9 0.7%
\n
Commercial paper (13,838) (10,708) (3,130) -29.2%
\n
Other short-term borrowings
\n
(1)
\n
(3,234) (1,281) (1,953) -
\n
Current financial debt (including debt instruments) (18,392) (13,318) (5,074) -38.1%
\n
Current portion of long-term bank borrowings (890) (989) 99 10.0%
\n
Bonds issued (current portion) (1,612) (2,700) 1,088 40.3%
\n
Other borrowings (current portion) (333) (342) 9 2.6%
\n
Non-current financial debt (current portion) (2,835) (4,031) 1,196 29.7%
\n
Current financial debt (21,227) (17,349) (3,878) -22.4%
\n
Net current financial debt 3,315 (24) 3,339 -
\n
Non-current financial debt
\n
Bank borrowings (15,261) (12,579) (2,682) -21.3%
\n
Other borrowings
\n
(2)
\n
(2,851) (2,942) 91 3.1%
\n
Non-current financial debt (excluding current portion and debt
\n
instruments)
\n
(18,112) (15,521) (2,591) -16.7%
\n
Bonds (50,079) (39,099) (10,980) -28.1%
\n
Trade payables and other non-interest-bearing non-current liabilities with
\n
a significant financing component
\n
----
\n
Non-current financial position (68,191) (54,620) (13,571) -24.8%
\n
Financial assets in respect of \u201cAssets classified as held for sale\u201d 543 85 458 -
\n
Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
(1,435) (784) (651) -83.0%
\n
Net financial position as per CONSOB instructions (65,768) (55,343) (10,425) -18.8%
\n
Long-term financial receivables and securities 4,213 2,692 1,521 56.5%
\n
Net exchange rate derivatives associated with borrowings
\n
(3)
\n
595 259 336 -
\n
( - ) Financial assets in respect of \u201cAssets classified as held for sale\u201c (543) (85) (458) -
\n
( - ) Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
1,435 784 651 83.0%
\n
NET FINANCIAL DEBT
\n
(3)
\n
(60,068) (51,693) (8,375) -16.2%
\n
(1) Includes current financial borrowings included in \u201cOther current financial liabilities\u201d in the statement of financial position.
\n
(2) Includes other non-current financial borrowings presented under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(3) In order to improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2021 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\n

\n\n
The net position as per CONSOB instructions does not
\n
include derivatives designated as hedges for hedge ac-
\n
counting purposes or entered into for trading purposes as
\n
they are used for hedging.
\n
At December 31, 2022, those financial assets and liabili-
\n
ties are reported separately in the statement of financial
\n
position under the following items: \u201cNon-current financial
\n
derivative assets\u201d in the amount of \u20ac3,970 million (\u20ac2,772
\n
million at December 31, 2021), \u201cCurrent financial derivative
\n
assets\u201d in the amount of \u20ac14,830 million (\u20ac22,791 million
\n
at December 31, 2021), \u201cNon-current financial derivative
\n
liabilities\u201d in the amount of \u20ac5,895 million (\u20ac3,339 million
\n
at December 31, 2021), and \u201cCurrent financial derivative li-
\n
abilities\u201d in the amount of \u20ac16,141 million (\u20ac24,607 million
\n
at December 31, 2021).
\n
Furthermore, for the purpose of better representing the
\n
Enel Group\u2019s net financial debt, it includes the fair value of
\n
the cross currency swaps entered into to hedge foreign
\n
currency loans to external counterparties. For more infor-
\n
mation on the classification of such derivatives, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n
48.1.2 Financial assets at fair value through other
\n
comprehensive income
\n
The following table shows financial assets at fair value
\n
through other comprehensive income by nature, broken
\n
down into current and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Investments in other companies at FVOCI 29 360
\n
40 --
\n
Securities 29.1 447 403 30.1 78 87
\n
Receivables and other financial assets at FVOCI 94
\n
263 201 57
\n
Tot al 901 706 279 144
\n

\n\n
Changes in financial assets at FVOCI
\n
Investments in other companies
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 40 -
\n
Purchases 2-
\n
Sales -
\n
-
\n
Changes in fair value through OCI --
\n
Other changes (2)
\n
-
\n
Closing balance at Dec. 31, 2021 40 -
\n
Opening balance at Jan. 1, 2022 40
\n
-
\n
Purchases 149 -
\n
Sales -
\n
-
\n
Changes in fair value through OCI 11 -
\n
Other changes 160
\n
-
\n
Closing balance at Dec. 31, 2022 360 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 551 102
\n
Purchases 165 -
\n
Sales (87)
\n
-
\n
Changes in fair value through OCI 2-
\n
Reclassifications (85) 85
\n
Other changes 120
\n
(43)
\n
Closing balance at Dec. 31, 2021 666 144
\n
Opening balance at Jan. 1, 2022 666
\n
144
\n
Purchases 225 -
\n
Sales (41)
\n
(14)
\n
Changes in fair value through OCI (38) -
\n
Reclassifications (102) 102
\n
Other changes (168)
\n
47
\n
Closing balance at Dec. 31, 2022 541 279
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDebtSecuritiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1063": { "value": "\n

\n
48. Financial instruments by category
\n
This note provides disclosures necessary for users to
\n
assess the significance of financial instruments for the
\n
Group\u2019s financial position and performance.
\n\n
48.1 Financial assets by category
\n
The following table reports the carrying amount for each
\n
category of financial asset provided for under IFRS 9, bro-
\n
ken down into current and non-current financial assets,
\n
showing hedging derivatives and derivatives measured at
\n
fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Financial assets at amortized cost 48.1.1 5,731 4,092 40,057 34,671
\n
Financial assets at FVOCI 48.1.2 901 706 279 144
\n
Financial assets at fair value through profit or loss
\n
Derivative financial assets at FVTPL 48.1.3 473 277 12,075 19,664
\n
Other financial assets at FVTPL 48.1.3 3,442 2,662 1,049 141
\n
Total financial assets at fair value through profit or loss 3,915 2,939 13,124 19,805
\n
Derivative financial assets designated as hedging instruments
\n
Fair value hedge derivatives 48.1.4 37 61 - -
\n
Cash flow hedge derivatives 48.1.4 3,460 2,434 2,755 3,127
\n
Total derivative financial assets designated as hedging instruments 3,497 2,495 2,755 3,127
\n
TOTAL 14,044 10,232 56,215 57,747
\n
For more information on the recognition and classification
\n
of current and non-current derivative assets, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n
For more information on fair value measurement, see note
\n
52 \u201cAssets and liabilities measured at fair value\u201d.
\n

\n\n

\n\n

\n\n

\n\n

\n

\n
48.1.1 Financial assets measured at amortized cost
\n
The following table reports financial assets measured at
\n
amortized cost by nature, broken down into current and
\n
non-current financial assets.
\n\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Cash and cash equivalents - - 35 10,169 8,759
\n
Trade receivables 34 1,388 1,301 34 15,217 14,775
\n
Current portion of long-term loan assets - - 30.1 2,838 1,538
\n
Cash collateral - - 30.1 8,319 6,485
\n
Other financial assets 29.1 3,766 2,289 30.1 2,090 315
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 295 260 29 12 64
\n
Other financial assets at amortized cost 282 242 1,412 2,735
\n
Tot al 5,731 4,092 40,057 34,671
\n

\n\n
Impairment of financial assets at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac45,788 million at December 31, 2022 (\u20ac38,763 million at
\n
December 31, 2021) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,087 million at De-
\n
cember 31, 2022 (\u20ac4,051 million at the end of the previous
\n
year).
\n
The Group mainly has the following types of financial as-
\n
sets measured at amortized cost subject to impairment
\n
testing:
\n
\u2022 cash and cash equivalents;
\n
\u2022 trade receivables and contract assets;
\n
\u2022 loan assets;
\n
\u2022 other financial assets.
\n
While cash and cash equivalents are also subject to the
\n
impairment requirements of IFRS 9, the identified impair-
\n
ment loss was immaterial.
\n\n
The expected credit loss (ECL) \u2013 determined using proba-
\n
bility of default (PD), loss given default (LGD) and exposure
\n
at default (EAD) \u2013 is the difference between all contractual
\n
cash flows that are due in accordance with the contract
\n
and all cash flows that are expected to be received (i.e., all
\n
shortfalls) discounted at the original effective interest rate
\n
(EIR).
\n
For calculating ECL, the Group applies two different ap-
\n
proaches:
\n
\u2022 the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receivables.
\n
This approach, based on an assessment of any signif-
\n
icant increase in credit risk since initial recognition, is
\n
performed comparing the PD at origination with PD at
\n
the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss al-
\n
lowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e., staging):
\n
\u2013 12-month ECL, for financial assets for which there has
\n
not been a significant increase in credit risk since ini-
\n
tial recognition;
\n
\u2013 lifetime ECL, for financial assets for which there has
\n
been a significant increase in credit risk or which are
\n
credit impaired (i.e., defaulted based on past due in-
\n
formation);
\n
\u2022 the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a significant
\n
financing component, based on lifetime ECL without
\n
tracking changes in credit risk.
\n
A forward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
future events and macroeconomic developments that
\n
could impact the risk associated with the portfolio or fi-
\n
nancial instrument.
\n
Depending on the nature of the financial assets and the
\n
credit risk information available, the assessment of the in-
\n
crease in credit risk can be performed on:
\n
\u2022 an individual basis, if the receivables are individually sig-
\n
nificant and for all receivables which have been individ-
\n
ually identified for impairment based on reasonable and
\n
supportable information;
\n
\u2022 a collective basis, if no reasonable and supportable in-
\n
formation is available without undue cost or effort to
\n
measure expected credit losses on an individual instru-
\n
ment basis.
\n
When there is no reasonable expectation of recovering a
\n
financial asset in its entirety or a portion thereof, the gross
\n
carrying amount of the financial asset shall be reduced.
\n
A write-off represents a derecognition event (e.g., the right
\n
to cash flows is legally or contractually extinguished, trans-
\n
ferred or expired).
\n

\n

\n\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports expected credit losses on fi-
\n
nancial assets measured at amortized cost on the basis of
\n
the general simplified approach.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Gross amount
\n
Expected
\n
credit loss
\n
allowance Total Gross amount
\n
Expected
\n
credit loss
\n
allowance Total
\n
Cash and cash equivalents 10,169 - 10,169 8,759 - 8,759
\n
Trade receivables 20,388 3,783 16,605 19,739 3,663 16,076
\n
Loan assets 17,261 248 17,013 10,861 234 10,627
\n
Other financial assets at amortized cost 2,057 56 2,001 3,455 154 3,301
\n
Total 49,875 4,087 45,788 42,814 4,051 38,763
\n
To measure expected losses, the Group assesses trade re-
\n
ceivables and contract assets with the simplified approach,
\n
both on an individual basis (e.g., government entities, au-
\n
thorities, financial counterparties, wholesale sellers, traders
\n
and large companies, etc.) and a collective basis (e.g., retail
\n
customers).
\n
In the case of individual assessments, PD is generally ob-
\n
tained from external providers.
\n
Otherwise, in the case of collective assessments, trade re-
\n
ceivables are grouped on the basis of their shared credit risk
\n
characteristics and information on past due positions, con-
\n
sidering a specific definition of default.
\n
Based on each business and local regulatory framework, as
\n
well as differences between customer portfolios, including
\n
their default and recovery rates (comprising expectations
\n
for recovery beyond 90 days):
\n
\u2022 the Group mainly defines a defaulted position as one that
\n
is 180 days past due. Accordingly, beyond this time lim-
\n
it, trade receivables are presumed to be credit impaired);
\n
and
\n
\u2022 specific clusters are defined on the basis of specific mar-
\n
kets, business and risk characteristics.
\n
Contract assets substantially have the same risk character-
\n
istics as trade receivables for the same types of contracts.
\n
In order to measure the ECL for trade receivables on a col-
\n
lective basis, as well as for contract assets, the Group uses
\n
the following assumptions regarding the ECL parameters:
\n
\u2022 PD, assumed equal to the average default rate, is calculat-
\n
ed by cluster and considering historical data from at least
\n
24 months;
\n
\u2022 LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022 EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices is-
\n
sued but not past due and invoices to be issued.
\n
Despite the deterioration in the collection status of certain
\n
customer segments, which was taken into consideration in
\n
determining impairment of trade receivables, the Group\u2019s
\n
portfolio has so far demonstrated resilience to the mac-
\n
roeconomic context and the current price scenario. This
\n
reflects the expansion of digital collection channels and a
\n
solid diversification of commercial customers.
\n
The following table reports changes in the allowance for ex-
\n
pected credit losses on loan assets in accordance with the
\n
general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 65 143
\n
Accruals -9
\n
Uses --
\n
Reversals to profit or loss (25) (9)
\n
Other changes 25 26
\n
Closing balance at Dec. 31, 2021 65 169
\n
Opening balance at Jan. 1, 2022 65 169
\n
Accruals 22 5
\n
Uses --
\n
Reversals to profit or loss - (11)
\n
Other changes (58) 56
\n
Closing balance at Dec. 31, 2022 29 219
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
The following table reports changes in the allowance for
\n
expected credit losses on trade receivables in accordance
\n
with the simplified approach.
\n
Millions of euro
\n
Opening balance at Jan. 1, 2021 3,287
\n
Accruals 1,285
\n
Uses 709
\n
Reversals to profit or loss (202)
\n
Other changes (1,416)
\n
Closing balance at Dec. 31, 2021 3,663
\n
Opening balance at Jan. 1, 2022 3,663
\n
Accruals 1,375
\n
Uses (766)
\n
Reversals to profit or loss (265)
\n
Other changes (224)
\n
Closing balance at Dec. 31, 2022 3,783
\n
The following table reports changes in the allowance for
\n
expected credit losses on other financial assets at amor-
\n
tized cost in accordance with the simplified approach.
\n
Millions of euro ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 129
\n
Accruals 94
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (68)
\n
Closing balance at Dec. 31, 2021 154
\n
Opening balance at Jan. 1, 2022 154
\n
Accruals 180
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (277)
\n
Closing balance at Dec. 31, 2022 56
\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\n\n\n
48.1.2 Financial assets at fair value through other
\n
comprehensive income
\n
The following table shows financial assets at fair value
\n
through other comprehensive income by nature, broken
\n
down into current and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Investments in other companies at FVOCI 29 360
\n
40 --
\n
Securities 29.1 447 403 30.1 78 87
\n
Receivables and other financial assets at FVOCI 94
\n
263 201 57
\n
Tot al 901 706 279 144
\n

\n\n

\n\n

\n\n

\n\n

\n

\n\n
Changes in financial assets at FVOCI
\n
Investments in other companies
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 40 -
\n
Purchases 2-
\n
Sales -
\n
-
\n
Changes in fair value through OCI --
\n
Other changes (2)
\n
-
\n
Closing balance at Dec. 31, 2021 40 -
\n
Opening balance at Jan. 1, 2022 40
\n
-
\n
Purchases 149 -
\n
Sales -
\n
-
\n
Changes in fair value through OCI 11 -
\n
Other changes 160
\n
-
\n
Closing balance at Dec. 31, 2022 360 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2021 551 102
\n
Purchases 165 -
\n
Sales (87)
\n
-
\n
Changes in fair value through OCI 2-
\n
Reclassifications (85) 85
\n
Other changes 120
\n
(43)
\n
Closing balance at Dec. 31, 2021 666 144
\n
Opening balance at Jan. 1, 2022 666
\n
144
\n
Purchases 225 -
\n
Sales (41)
\n
(14)
\n
Changes in fair value through OCI (38) -
\n
Reclassifications (102) 102
\n
Other changes (168)
\n
47
\n
Closing balance at Dec. 31, 2022 541 279
\n

\n\n\n

\n\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n

\n\n

\n\n
48.1.4 Derivative financial assets designated as hedging
\n
instruments
\n
For more information on derivative financial assets, please
\n
see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n

\n\n

\n\n
48.2 Financial liabilities by category
\n
The following table shows the carrying amount for each
\n
category of financial liability provided for under IFRS 9,
\n
broken down into current and non-current financial lia-
\n
bilities, showing hedging derivatives and derivatives mea-
\n
sured at fair value through profit or loss separately.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Financial liabilities measured at amortized cost 48.2.1 68,432 54,914 45,697
\n
42,330
\n
Financial liabilities at fair value through profit or loss
\n
Derivative financial liabilities at FVTPL 48.4 588 169 11,642
\n
19,696
\n
Total financial liabilities at fair value through profit or loss 588 169 11,642 19,696
\n
Derivative financial liabilities designated as hedging instruments
\n
Fair value hedge derivatives 48.4 191 5 - -
\n
Cash flow hedge derivatives 48.4 5,116 3,165 4,499
\n
4,911
\n
Total derivative financial liabilities designated as hedging
\n
instruments
\n
5,307 3,170 4,499 4,911
\n
TOTAL 73,158 58,253 63,007
\n
66,937
\n
For more information on fair value measurement, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\n
48.2.1 Financial liabilities measured at amortized cost
\n
The following table shows financial liabilities at amortized
\n
cost by nature, broken down into current and non-current
\n
financial liabilities.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Long-term borrowings 48.3 68,191 54,500 48.3 2,835 4,031
\n
Short-term borrowings - - 48.3 18,392 13,306
\n
Trade payables 44 36 94 44 17,605 16,865
\n
Other financial liabilities 205
\n
320 6,865 8,128
\n
Tot al 68,432
\n
54,914 45,697 42,330
\n

\n\n

\n\n

\n\n

\n\n
48.3 Borrowings
\n
48.3.1 Long-term borrowings (including the portion
\n
falling due within 12 months) \u2013 \u20ac71,026 million
\n
The following table reports the nominal value, carrying
\n
amount, and fair value of long-term borrowings including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
(1)
\n
Millions of euro
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Changes
\n
in carrying
\n
amount
\n
2022-
\n
2021
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Bonds:
\n
- listed, fixed rate 30,355 29,892 978 28,914 27,468 27,857 27,413 2,119 25,294 30,279 2,479
\n
- listed, floating rate 2,569 2,547 537 2,010 2,473 2,574 2,557 434 2,123 2,545 (10)
\n
- unlisted, fixed rate 18,959 18,727 - 18,727 17,249 11,293 11,207 50 11,157 12,670 7,520
\n
- unlisted, floating rate 525 525 97 428 600 622 622 97 525 728
\n
(97)
\n
Total bonds 52,408 51,691 1,612 50,079 47,790 42,346 41,799 2,700 39,099 46,222 9,892
\n
Bank borrowings:
\n
- fixed rate 3,367 3,273 211 3,062 3,021 2,414 2,405 238 2,167 2,298 868
\n
- floating rate 12,884 12,848 677 12,171 12,570 10,139 10,109 751 9,358 10,037
\n
2,739
\n
- use of revolving credit
\n
lines
\n
30 30 2 28 26 1,054 1,054 - 1,054 1,054
\n
(1,024)
\n
Total bank borrowings 16,281 16,151 890 15,261 15,617 13,607 13,568 989 12,579 13,389 2,583
\n
Leases:
\n
- fixed rate 2,630 2,630 251 2,379 2,630 2,477 2,477 242 2,235 2,477 153
\n
- floating rate 42 42 10 32 42 70 70 17 53 70
\n
(28)
\n
Total leases 2,672 2,672 261 2,411 2,672 2,547 2,547 259 2,288 2,547 125
\n
Other non-bank
\n
borrowings:
\n
- fixed rate 504 504 70 434 504 571 595 69 526 569 (91)
\n
- floating rate 8 8 2 6 12 34 22 14 8 25
\n
(14)
\n
Total other non-bank
\n
borrowings
\n
512 512 72 440 516 605 617 83 534 594
\n
(105)
\n
Total fixed-rate
\n
borrowings
\n
55,815 55,026 1,510 53,516 50,872 44,612 44,097 2,718 41,379 48,293
\n
10,929
\n
Total floating-rate
\n
borrowings
\n
16,058 16,000 1,325 14,675 15,723 14,493 14,434 1,313 13,121 14,459 1,566
\n
TOTAL 71,873 71,026 2,835 68,191 66,595 59,105 58,531 4,031 54,500 62,752
\n
12,495
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position that
\n
are included in long-term financial debt.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports long-term financial debt by
\n
currency and interest rate.
\n
Long-term financial debt by currency and interest rate
\n
(1)
\n
Millions of euro
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Euro 34,993 35,383 32,041 32,387 1.9% 2.1% 1.6% 1.9%
\n
US dollar 26,930 27,209 17,518 17,629 4.8% 5.1% 4.2% 4.3%
\n
Pound sterling 4,470 4,610 3,901 3,976 4.6% 4.8% 5.0% 5.2%
\n
Colombian peso 1,310 1,310 1,341 1,341 10.3% 10.3% 6.5% 6.5%
\n
Brazilian real 1,899 1,926 1,720 1,753 10.0% 10.2% 8.8% 8.9%
\n
Swiss franc 359 360 343 344 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 526 531 423 428 5.1% 5.2% 5.2% 5.2%
\n
Peruvian sol 429 429 415 415 5.3% 5.3% 5.2% 5.2%
\n
Russian ruble - - 427 427 6.8% 7.3%
\n
Other currencies 110 115 402 405
\n
Total non-euro currencies 36,033 36,490 26,490 26,718
\n
TOTAL 71,026 71,873 58,531 59,105
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
Long-term financial debt denominated in currencies other
\n
than the euro increased by \u20ac9,543 million, largely attrib-
\n
utable to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term debt
\n
(1)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope
\n
New
\n
borrowings Other changes
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Bonds 42,346 (2,788) (37) 12,390 - 497 52,408
\n
Borrowings 16,759 (6,571) (1,016)
\n
10,009 -28419,465
\n
- of which leases 2,547 (310) (88) 445 -782,672
\n
Total financial debt 59,105 (9,359) (1,053) 22,399 - 781 71,873
\n
(1) Does not include changes in the nominal value of other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the
\n
statement of financial position.
\n
The nominal value of long-term debt amounted to \u20ac71,873
\n
million at December 31, 2022, an increase of \u20ac12,768 mil-
\n
lion compared with December 31, 2021. The increase in
\n
debt reflected new borrowing of \u20ac22,399 million and ex-
\n
change losses of \u20ac781 million, only partially offset by re-
\n
payments of \u20ac9,359 million and the deconsolidation of
\n
debt of various companies, in particular that resulting from
\n
the sale of the equity investment in Enel Russia, equal to
\n
\u20ac1,053 million.
\n
Repayments in 2022 involved bonds in the amount of
\n
\u20ac2,788 million and loans in the amount of \u20ac6,571 million.
\n
Specifically, repayments of bonds in 2022 included:
\n
\u2022 \u20ac50 million in respect of a fixed-rate bond issued by Enel
\n
Finance International, maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n

\n\n

\n\n

\n\n

\n\n

\n\n
\u2022 270,000 million Colombian pesos (equivalent to \u20ac52
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2022;
\n
\u2022 \u20ac1,949 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in September 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in September
\n
2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in November 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in December
\n
2022.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022 \u20ac5,250 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022 \u20ac264 million in respect of Endesa loans, of which \u20ac132
\n
million in sustainable loans;
\n
\u2022 \u20ac504 million in respect of sustainable loans of Group\u2019s
\n
Italian companies;
\n
\u2022 the equivalent of \u20ac354 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2022 involved \u20ac12,390 million in bonds
\n
and \u20ac10,009 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2022 and translated into euros
\n
at the exchange rate prevailing at December 31, 2022.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of
\n
euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance International 17.01.2022 1,250 EUR 0.25% Fixed rate 17.11.2025
\n
Enel Finance International 17.01.2022 750 EUR 0.88% Fixed rate 17.01.2031
\n
Enel Finance International 17.01.2022 750 EUR 1.25% Fixed rate 17.01.2035
\n
Enel Finance International 11.04.2022 845 GBP 2.88% Fixed rate 11.04.2029
\n
Enel Finance International 15.06.2022 703 USD 4.25% Fixed rate 15.06.2025
\n
Enel Finance International 15.06.2022 703 USD 4.63% Fixed rate 15.06.2027
\n
Enel Finance International 15.06.2022 937 USD 5.00% Fixed rate 15.06.2032
\n
Enel Finance International 15.06.2022 937 USD 5.50% Fixed rate 15.06.2052
\n
Enel Finance International 09.09.2022 1,000 EUR 3.88% Fixed rate 09.03.2029
\n
Enel Finance International 14.10.2022 703 USD 6.80% Fixed rate 14.10.2025
\n
Enel Finance International 14.10.2022 1,171 USD 7.50% Fixed rate 14.10.2032
\n
Enel Finance International 14.10.2022 937 USD 7.75% Fixed rate 14.10.2052
\n
Enel Finance America 14.10.2022 937 USD 7.10% Fixed rate 14.10.2027
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 12.05.2022 142 BRL IPCA + 6.14% Floating rate 15.04.2032
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 30.05.2022 106 BRL IPCA + 6.21% Floating rate 17.05.2032
\n
Total bonds 11,871
\n
Bank borrowings
\n
Enel SpA 07.03.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 14.09.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 30.09.2022 350 EUR Euribor + 0.45% Floating rate 26.07.2025
\n
Enel SpA 30.09.2022 648 EUR Euribor + 0.40% Floating rate 12.05.2025
\n
Enel SpA 30.09.2022 1,852 EUR Euribor + 0.40% Floating rate 05.03.2026
\n
Enel SpA 30.09.2022 1,000 EUR Euribor + 0.52% Floating rate 02.10.2024
\n
e-distibuzione 05.08.2022 300 EUR Euribor + 0.473% Floating rate 05.08.2037
\n
Enel Italia 29.07.2022 60 EUR Euribor 6M + 0.462% Floating rate 29.07.2037
\n
Enel Finance America 06.10.2022 403 USD USD SOFR 6M CMP + 1.22% Floating rate 15.05.2034
\n
Enel Finance America 03.11.2022 187 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 13.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 21.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Endesa 17.01.2022 300 EUR Euribor 6M + 0.53% Floating rate 20.12.2033
\n
Endesa 25.03.2022 400 EUR Euribor 3M + 0.72% Floating rate 31.07.2024
\n
Endesa 28.03.2022 250 EUR Euribor 6M + 0.368% Floating rate 30.03.2037
\n
Endesa 30.03.2022 50 EUR Euribor 6M + 0.45% Floating rate 31.07.2024
\n
Endesa 31.03.2022 250 EUR Euribor 3M + 0.85% Floating rate 31.07.2024
\n
Endesa 31.03.2022 275 EUR Euribor 3M + 1.20% Floating rate 31.07.2024
\n
Endesa 31.03.2022 75 EUR 1.405% Fixed rate 01.04.2027
\n
Endesa 08.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 29.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 10.05.2022 100 EUR Euribor 3M + 0.65% Floating rate 31.07.2024
\n
Endesa 25.05.2022 500 EUR 1.895% Fixed rate 13.05.2027
\n
Endesa 19.10.2022 200 EUR Euribor 3M + 1.30% Floating rate 31.07.2024
\n
Endesa 18.11.2022 250 EUR Euribor 6M + 0.582% Floating rate 18.11.2037
\n
Enel Colombia 05.04.2022 93 COP COP IBR 3M + 2.05% Floating rate 05.04.2028
\n
Enel Colombia 28.07.2022 79 COP COP IBR 3M + 1.6% Floating rate 28.07.2028
\n
Enel Colombia 30.11.2022 70 COP COP IBR 3M + 2.98% Floating rate 30.11.2029
\n
Enel Distribuci\u00f3n Per\u00fa 04.04.2022 52 PEN 6.96% Fixed rate 19.03.2025
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 24.03.2022 51 USD USD SOFR CMP + 0.91% Floating rate 21.03.2025
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 01.09.2022 88 USD 3.61% Fixed rate 01.09.2037
\n
Total bank borrowings 8,665
\n

\n\n

\n\n

\n\n

\n\n

\n\n
The following table reports the impact on gross long-term
\n
debt of hedges to mitigate currency risk.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
(1)
\n
Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Euro 34,993 35,383 49.2% 23,473 58,856 81.9% 32,041 32,387 54.8% 16,657 49,044 83.0%
\n
US dollar 26,930 27,209 37.9% (19,741) 7,468 10.4% 17,518 17,629 29.8% (13,423) 4,206 7.1%
\n
Pound sterling 4,470 4,610 6.4% (4,610) - - 3,901 3,976 6.7% (3,976) - -
\n
Colombian peso 1,310 1,310 1.8% - 1,310 1.8% 1,341 1,341 2.3% - 1,341 2.3%
\n
Brazilian real 1,899 1,926 2.7% 1,187 3,113 4.4% 1,720 1,753 3.0% 1,028 2,781 4.7%
\n
Swiss franc 359 360 0.5% (360) - - 343 344 0.6% (344) - -
\n
Chilean peso/UF 526 531 0.7% - 531 0.7% 423 428 0.7% - 428 0.7%
\n
Peruvian sol 429 429 0.6% - 429 0.6% 415 415 0.7% - 415 0.7%
\n
Russian ruble - - - - - - 427 427 0.7% - 427 0.7%
\n
Other currencies 110 115 0.2% 51 166 0.2% 402 405 0.7% 58 463
\n
0.8%
\n
Total non-euro
\n
currencies 36,033 36,490 50.8% (23,473) 13,017 18.1% 26,490 26,718 45.2% (16,657) 10,061 17.0%
\n
TOTAL 71,026 71,873 100.0% - 71,873 100.0% 58,531 59,105 100.0% - 59,105
\n
100.0%
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
The amount of floating-rate debt that is not hedged
\n
against interest rate risk is the main risk factor that could
\n
adversely impact profit or loss (raising borrowing costs) in
\n
the event of an increase in market interest rates.
\n
Millions of euro 2022 2021
\n
Pre-hedge % Post-hedge
\n
% Pre-hedge % Post-hedge %
\n
Floating rate 34,450 38.2% 31,353 34.7% 27,811 38.4% 22,478 31.0%
\n
Fixed rate 55,815 61.8% 58,912 65.3% 44,612 61.6% 49,945 69.0%
\n
Total 90,265 90,265 72,423 72,423
\n
At December 31, 2022, 38.2% of long and medium-term
\n
financial debt was floating rate (38.4% at December 31,
\n
2021). Taking account of hedges of interest rates consid-
\n
ered effective pursuant to the IFRS-EU, 34.7% of long and
\n
medium-term net financial debt at December 31, 2022
\n
was exposed to interest rate risk (31% at December 31,
\n
2021). These figures are in line with the limits established in
\n
the risk management policy.
\n
The following table shows the impact of the IBOR reform
\n
on long-term financial debt for the main indices (for more
\n
details, please see the section \u201cReform of benchmarks for
\n
the determination of interest rates - IBOR reform\u201d in note
\n
51.1).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional amount Phase 1 Phase 2 Phase 1 Phase 2
\n
USD LIBOR/SOFR 1,310 - 888 -
\n
GBP LIBOR/SONIA ---
\n
-
\n
Tot al 1,310 - 888 -
\n

\n\n

\n\n

\n\n

\n\n

\n\n
Long-term debt \u2013 Main covenants
\n
The Group\u2019s main long-term financial liabilities are gov-
\n
erned by covenants that are commonly adopted in inter-
\n
national business practice. They include in particular bond
\n
issues carried out within the framework of the Global/Euro
\n
Medium Term Notes program, issues of subordinated un-
\n
convertible hybrid bonds (so-called \u201chybrid bonds\u201d) and
\n
loans granted by banks and other financial institutions (in-
\n
cluding the European Investment Bank and Cassa Depositi
\n
e Prestiti SpA).
\n
The main covenants regarding bond issues carried out
\n
within the framework of the Global/Euro Medium Term
\n
Notes program of Enel and Enel Finance International NV
\n
(including the green bonds of Enel Finance International
\n
NV guaranteed by Enel SpA, which are used to finance the
\n
Group\u2019s so-called eligible green projects) and those re-
\n
garding bonds issued by Enel Finance International NV on
\n
the US market guaranteed by Enel SpA can be summarized
\n
as follows:
\n
\u2022 negative pledge clauses under which the issuer and the
\n
guarantor may not establish or maintain mortgages, liens
\n
or other encumbrances on all or part of their assets or
\n
revenue to secure certain financial liabilities, unless the
\n
same encumbrances are extended equally or pro rata to
\n
the bonds in question;
\n
\u2022 pari passu clauses, under which the bonds and the as-
\n
sociated security constitute a direct, unconditional and
\n
unsecured obligation of the issuer and the guarantor,
\n
are issued without preferential rights among them and
\n
have at least the same seniority as other present and fu-
\n
ture unsubordinated and unsecured bonds of the issuer
\n
and the guarantor;
\n
\u2022 cross-default clauses, under which the occurrence of
\n
a default event in respect of a specified financial liabil-
\n
ity (above a threshold level) of the issuer, the guarantor
\n
or, in some cases, \u201csignificant\u201d subsidiaries constitutes
\n
a default in respect of the liabilities in question, which
\n
become immediately repayable.
\n
Since 2019, Enel Finance International NV has issued a
\n
number of \u201csustainable\u201d bonds on the European market (as
\n
part of the Euro Medium Term Notes - EMTN bond issue
\n
program) and on the American market, both guaranteed
\n
by Enel SpA, linked to the achievement of a number of the
\n
Sustainable Development Goals (SDGs) of the United Na-
\n
tions that contain the same covenants as other bonds of
\n
the same type.
\n
In 2022, Enel Finance America LLC issued a \u201csustainable\u201d
\n
bond of the same type, guaranteed by Enel SpA, on the
\n
US market.
\n
The main covenants covering Enel\u2019s hybrid bonds, includ-
\n
ing the perpetual hybrid bond issues, which will only be
\n
repaid in the event of the dissolution or liquidation of the
\n
Company, can be summarized as follows:
\n
\u2022 subordination clauses, under which each hybrid bond is
\n
subordinate to all other bonds issued by the company
\n
and has the same seniority with all other hybrid financial
\n
instruments issued, being senior only to equity instru-
\n
ments;
\n
\u2022 prohibition on mergers with other companies, the sale
\n
or leasing of all or a substantial part of the company\u2019s
\n
assets to another company, unless the latter succeeds
\n
in all obligations of the issuer.
\n
The main covenants envisaged in the loan contracts
\n
of Enel and Enel Finance International NV and the other
\n
Group companies, including the sustainability-linked loan
\n
facility agreements obtained by Enel SpA, can be summa-
\n
rized as follows:
\n
\u2022 negative pledge clauses, under which the borrower and,
\n
in some cases, the guarantor are subject to limitations
\n
on the establishment of mortgages, liens or other en-
\n
cumbrances on all or part of their respective assets, with
\n
the exception of expressly permitted encumbrances;
\n
\u2022 disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their as-
\n
sets or operations, with the exception of expressly per-
\n
mitted disposals;
\n
\u2022 pari passu clauses, under which the payment undertak-
\n
ings of the borrower have the same seniority as its other
\n
unsecured and unsubordinated payment obligations;
\n
\u2022 change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required to
\n
renegotiate the terms and conditions of the financing or
\n
make compulsory early repayment of the loans granted;
\n
\u2022 rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022 cross-default clauses, under which the occurrence of a
\n
default event in respect of a specified financial liability
\n
(above a threshold level) of the issuer or, in some cas-
\n
es, the guarantor constitutes a default in respect of the
\n
liabilities in question, which become immediately repay-
\n
able.
\n
Some loan contracts entered into by Enel SpA, including as
\n
guarantor, provide for some additional covenants, such as:
\n
\u2022 the commitment to use the loan exclusively to hedge
\n
collateral for trading activities on the energy markets;
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending
\n
bank can request the cancellation of its financial com-
\n
mitment undertaken by it and the early payment of the
\n
sums disbursed if it has suffered ascertained harm to its
\n
own reputation or that of other persons as a result of
\n
substantial breach of certain regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure com-
\n
pliance with certain environmental and social regulations
\n
and standards.
\n

\n\n

\n\n

\n\n

\n\n

\n\n
In some cases, the covenants are also binding for the sig-
\n
nificant companies or subsidiaries of the obligated parties.
\n
All the borrowings considered specify \u201cevents of default\u201d
\n
typical of international business practice, such as, for ex-
\n
ample, insolvency, bankruptcy proceedings or the entity
\n
ceases trading.
\n
In addition, the guarantees issued by Enel in the interest
\n
of e-distribuzione SpA for certain loans to e-distribuzi-
\n
one SpA from Cassa Depositi e Prestiti SpA require that
\n
at the end of each six-month measurement period Enel\u2019s
\n
net consolidated financial debt shall not exceed 4.5 times
\n
annual consolidated EBITDA.
\n
Finally, the debt of Endesa SA, Enel Am\u00e9ricas SA, Enel Chile
\n
SA and the other Spanish and Latin American subsidiaries
\n
(notably Enel Generaci\u00f3n Chile SA) contains covenants and
\n
events of default typical of international business practice.
\n
48.3.2 Short-term borrowings \u2013 \u20ac18,392 million
\n
At December 31, 2022 short-term borrowings totaled
\n
\u20ac18,392 million, an increase of \u20ac5,086 million compared
\n
with December 31, 2021, and break down as follows:
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Short-term bank borrowings 1,320 1,329 (9)
\n
Commercial paper 13,838 10,708 3,130
\n
Cash collateral and other financing on derivatives 1,513 918 595
\n
Other short-term borrowings
\n
(1)
\n
1,721 351 1,370
\n
Short-term borrowings 18,392 13,306 5,086
\n
(1) Does not include other current borrowings included in \u201cOther current financial liabilities\u201d.
\n
Commercial paper liabilities totaling \u20ac13,838 million con-
\n
cerned issues by Enel Finance International, Endesa and
\n
Enel Finance America.
\n
The main commercial paper programs include:
\n
\u2022 \u20ac8,000 million of Enel Finance International, an increase
\n
from \u20ac6,000 million in 2021;
\n
\u2022 \u20ac5,000 million of Endesa, an increase from \u20ac4,000 mil-
\n
lion in 2021;
\n
\u2022 $5,000 million (equivalent to \u20ac4,414 million at December
\n
31, 2022), of Enel Finance America.
\n
At December 31, 2022, the whole amount of commercial
\n
paper issues, equal to \u20ac13,838 million, was linked to sus-
\n
tainability objectives.
\n

\n\n

\n\n
48.4 Derivative financial liabilities
\n
For more information on derivative financial liabilities,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n
48.5 Net gain/(loss)
\n
The following table shows net gains and losses by category
\n
of financial instruments, excluding derivatives.
\n
Millions of euro 2022 2021
\n
(1)
\n
Net gain/(loss)
\n
Of which
\n
impairment
\n
(loss)/gain Net gain/(loss)
\n
Of which
\n
impairment
\n
(loss)/gain
\n
Financial assets at amortized cost (1,242) (1,305) (883) (1,151)
\n
Financial assets at FVOCI
\n
Equity investments at FVOCI - - - -
\n
Other financial assets at FVOCI (4) - 15 -
\n
Total financial assets at FVOCI (4) - 15 -
\n
Financial assets at FVTPL
\n
Financial assets at FVTPL 9 - 3 -
\n
Financial assets designated upon initial recognition (fair value option) - - - -
\n
Total financial assets at FVTPL 9 - 3 -
\n
Financial liabilities measured at amortized cost (2,357) - (4,310) -
\n
Financial liabilities at FVTPL
\n
Financial liabilities held for trading - - - -
\n
Financial liabilities designated upon initial recognition (fair value option) - - - -
\n
Total financial liabilities at FVTPL - - - -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of revenue connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements of
\n
IFRS 5 for their classification as discontinued operations have been met.
\n
For more details on net gains and losses on derivatives,
\n
please see note 14 \u201cNet financial income/(expense) from
\n
derivatives\u201d.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1065": { "value": "\n

\n

\n
48.1.1 Financial assets measured at amortized cost
\n
The following table reports financial assets measured at
\n
amortized cost by nature, broken down into current and
\n
non-current financial assets.
\n\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Cash and cash equivalents - - 35 10,169 8,759
\n
Trade receivables 34 1,388 1,301 34 15,217 14,775
\n
Current portion of long-term loan assets - - 30.1 2,838 1,538
\n
Cash collateral - - 30.1 8,319 6,485
\n
Other financial assets 29.1 3,766 2,289 30.1 2,090 315
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 295 260 29 12 64
\n
Other financial assets at amortized cost 282 242 1,412 2,735
\n
Tot al 5,731 4,092 40,057 34,671
\n

\n\n
Impairment of financial assets at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac45,788 million at December 31, 2022 (\u20ac38,763 million at
\n
December 31, 2021) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,087 million at De-
\n
cember 31, 2022 (\u20ac4,051 million at the end of the previous
\n
year).
\n
The Group mainly has the following types of financial as-
\n
sets measured at amortized cost subject to impairment
\n
testing:
\n
\u2022 cash and cash equivalents;
\n
\u2022 trade receivables and contract assets;
\n
\u2022 loan assets;
\n
\u2022 other financial assets.
\n
While cash and cash equivalents are also subject to the
\n
impairment requirements of IFRS 9, the identified impair-
\n
ment loss was immaterial.
\n\n
The expected credit loss (ECL) \u2013 determined using proba-
\n
bility of default (PD), loss given default (LGD) and exposure
\n
at default (EAD) \u2013 is the difference between all contractual
\n
cash flows that are due in accordance with the contract
\n
and all cash flows that are expected to be received (i.e., all
\n
shortfalls) discounted at the original effective interest rate
\n
(EIR).
\n
For calculating ECL, the Group applies two different ap-
\n
proaches:
\n
\u2022 the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receivables.
\n
This approach, based on an assessment of any signif-
\n
icant increase in credit risk since initial recognition, is
\n
performed comparing the PD at origination with PD at
\n
the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss al-
\n
lowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e., staging):
\n
\u2013 12-month ECL, for financial assets for which there has
\n
not been a significant increase in credit risk since ini-
\n
tial recognition;
\n
\u2013 lifetime ECL, for financial assets for which there has
\n
been a significant increase in credit risk or which are
\n
credit impaired (i.e., defaulted based on past due in-
\n
formation);
\n
\u2022 the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a significant
\n
financing component, based on lifetime ECL without
\n
tracking changes in credit risk.
\n
A forward-looking adjustment can be applied considering
\n
qualitative and quantitative information in order to reflect
\n
future events and macroeconomic developments that
\n
could impact the risk associated with the portfolio or fi-
\n
nancial instrument.
\n
Depending on the nature of the financial assets and the
\n
credit risk information available, the assessment of the in-
\n
crease in credit risk can be performed on:
\n
\u2022 an individual basis, if the receivables are individually sig-
\n
nificant and for all receivables which have been individ-
\n
ually identified for impairment based on reasonable and
\n
supportable information;
\n
\u2022 a collective basis, if no reasonable and supportable in-
\n
formation is available without undue cost or effort to
\n
measure expected credit losses on an individual instru-
\n
ment basis.
\n
When there is no reasonable expectation of recovering a
\n
financial asset in its entirety or a portion thereof, the gross
\n
carrying amount of the financial asset shall be reduced.
\n
A write-off represents a derecognition event (e.g., the right
\n
to cash flows is legally or contractually extinguished, trans-
\n
ferred or expired).
\n

\n

\n\n

\n\n
The following table reports expected credit losses on fi-
\n
nancial assets measured at amortized cost on the basis of
\n
the general simplified approach.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Gross amount
\n
Expected
\n
credit loss
\n
allowance Total Gross amount
\n
Expected
\n
credit loss
\n
allowance Total
\n
Cash and cash equivalents 10,169 - 10,169 8,759 - 8,759
\n
Trade receivables 20,388 3,783 16,605 19,739 3,663 16,076
\n
Loan assets 17,261 248 17,013 10,861 234 10,627
\n
Other financial assets at amortized cost 2,057 56 2,001 3,455 154 3,301
\n
Total 49,875 4,087 45,788 42,814 4,051 38,763
\n
To measure expected losses, the Group assesses trade re-
\n
ceivables and contract assets with the simplified approach,
\n
both on an individual basis (e.g., government entities, au-
\n
thorities, financial counterparties, wholesale sellers, traders
\n
and large companies, etc.) and a collective basis (e.g., retail
\n
customers).
\n
In the case of individual assessments, PD is generally ob-
\n
tained from external providers.
\n
Otherwise, in the case of collective assessments, trade re-
\n
ceivables are grouped on the basis of their shared credit risk
\n
characteristics and information on past due positions, con-
\n
sidering a specific definition of default.
\n
Based on each business and local regulatory framework, as
\n
well as differences between customer portfolios, including
\n
their default and recovery rates (comprising expectations
\n
for recovery beyond 90 days):
\n
\u2022 the Group mainly defines a defaulted position as one that
\n
is 180 days past due. Accordingly, beyond this time lim-
\n
it, trade receivables are presumed to be credit impaired);
\n
and
\n
\u2022 specific clusters are defined on the basis of specific mar-
\n
kets, business and risk characteristics.
\n
Contract assets substantially have the same risk character-
\n
istics as trade receivables for the same types of contracts.
\n
In order to measure the ECL for trade receivables on a col-
\n
lective basis, as well as for contract assets, the Group uses
\n
the following assumptions regarding the ECL parameters:
\n
\u2022 PD, assumed equal to the average default rate, is calculat-
\n
ed by cluster and considering historical data from at least
\n
24 months;
\n
\u2022 LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022 EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices is-
\n
sued but not past due and invoices to be issued.
\n
Despite the deterioration in the collection status of certain
\n
customer segments, which was taken into consideration in
\n
determining impairment of trade receivables, the Group\u2019s
\n
portfolio has so far demonstrated resilience to the mac-
\n
roeconomic context and the current price scenario. This
\n
reflects the expansion of digital collection channels and a
\n
solid diversification of commercial customers.
\n
The following table reports changes in the allowance for ex-
\n
pected credit losses on loan assets in accordance with the
\n
general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 65 143
\n
Accruals -9
\n
Uses --
\n
Reversals to profit or loss (25) (9)
\n
Other changes 25 26
\n
Closing balance at Dec. 31, 2021 65 169
\n
Opening balance at Jan. 1, 2022 65 169
\n
Accruals 22 5
\n
Uses --
\n
Reversals to profit or loss - (11)
\n
Other changes (58) 56
\n
Closing balance at Dec. 31, 2022 29 219
\n

\n\n
The following table reports changes in the allowance for
\n
expected credit losses on trade receivables in accordance
\n
with the simplified approach.
\n
Millions of euro
\n
Opening balance at Jan. 1, 2021 3,287
\n
Accruals 1,285
\n
Uses 709
\n
Reversals to profit or loss (202)
\n
Other changes (1,416)
\n
Closing balance at Dec. 31, 2021 3,663
\n
Opening balance at Jan. 1, 2022 3,663
\n
Accruals 1,375
\n
Uses (766)
\n
Reversals to profit or loss (265)
\n
Other changes (224)
\n
Closing balance at Dec. 31, 2022 3,783
\n
The following table reports changes in the allowance for
\n
expected credit losses on other financial assets at amor-
\n
tized cost in accordance with the simplified approach.
\n
Millions of euro ECL lifetime allowance
\n
Opening balance at Jan. 1, 2021 129
\n
Accruals 94
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (68)
\n
Closing balance at Dec. 31, 2021 154
\n
Opening balance at Jan. 1, 2022 154
\n
Accruals 180
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (277)
\n
Closing balance at Dec. 31, 2022 56
\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAllowanceForCreditLossesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1061": { "value": "\n

\n\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1064": { "value": "\n

\n\n

\n\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsDesignatedAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1059": { "value": "\n

\n\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1060": { "value": "\n
48.1.3 Financial assets at fair value through profit or loss
\n
The following table shows financial assets at fair value
\n
through profit or loss by nature, broken down into current
\n
and non-current financial assets.
\n
Millions of euro Non-current Current
\n
Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021 Notes
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Derivatives at FVTPL 51 473 277 51 12,075 19,664
\n
Investments in liquid assets - - 35 872 99
\n
Financial assets at FVTPL - - 30, 30.1 176 41
\n
Securities --30.1-
\n
1
\n
Equity investments in other companies at FVTPL 29 6 32 - -
\n
Financial assets from service concession arrangements at FVTPL 29 3,436 2,630 - -
\n
Tot al 3,915 2,939 13,123 19,805
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1062": { "value": "\n
48.3 Borrowings
\n
48.3.1 Long-term borrowings (including the portion
\n
falling due within 12 months) \u2013 \u20ac71,026 million
\n
The following table reports the nominal value, carrying
\n
amount, and fair value of long-term borrowings including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
(1)
\n
Millions of euro
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more than
\n
12 months Fair value
\n
Changes
\n
in carrying
\n
amount
\n
2022-
\n
2021
\n
at Dec. 31, 2022
\n
at Dec. 31, 2021
\n
Bonds:
\n
- listed, fixed rate 30,355 29,892 978 28,914 27,468 27,857 27,413 2,119 25,294 30,279 2,479
\n
- listed, floating rate 2,569 2,547 537 2,010 2,473 2,574 2,557 434 2,123 2,545 (10)
\n
- unlisted, fixed rate 18,959 18,727 - 18,727 17,249 11,293 11,207 50 11,157 12,670 7,520
\n
- unlisted, floating rate 525 525 97 428 600 622 622 97 525 728
\n
(97)
\n
Total bonds 52,408 51,691 1,612 50,079 47,790 42,346 41,799 2,700 39,099 46,222 9,892
\n
Bank borrowings:
\n
- fixed rate 3,367 3,273 211 3,062 3,021 2,414 2,405 238 2,167 2,298 868
\n
- floating rate 12,884 12,848 677 12,171 12,570 10,139 10,109 751 9,358 10,037
\n
2,739
\n
- use of revolving credit
\n
lines
\n
30 30 2 28 26 1,054 1,054 - 1,054 1,054
\n
(1,024)
\n
Total bank borrowings 16,281 16,151 890 15,261 15,617 13,607 13,568 989 12,579 13,389 2,583
\n
Leases:
\n
- fixed rate 2,630 2,630 251 2,379 2,630 2,477 2,477 242 2,235 2,477 153
\n
- floating rate 42 42 10 32 42 70 70 17 53 70
\n
(28)
\n
Total leases 2,672 2,672 261 2,411 2,672 2,547 2,547 259 2,288 2,547 125
\n
Other non-bank
\n
borrowings:
\n
- fixed rate 504 504 70 434 504 571 595 69 526 569 (91)
\n
- floating rate 8 8 2 6 12 34 22 14 8 25
\n
(14)
\n
Total other non-bank
\n
borrowings
\n
512 512 72 440 516 605 617 83 534 594
\n
(105)
\n
Total fixed-rate
\n
borrowings
\n
55,815 55,026 1,510 53,516 50,872 44,612 44,097 2,718 41,379 48,293
\n
10,929
\n
Total floating-rate
\n
borrowings
\n
16,058 16,000 1,325 14,675 15,723 14,493 14,434 1,313 13,121 14,459 1,566
\n
TOTAL 71,873 71,026 2,835 68,191 66,595 59,105 58,531 4,031 54,500 62,752
\n
12,495
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position that
\n
are included in long-term financial debt.
\n

\n\n
The following table reports long-term financial debt by
\n
currency and interest rate.
\n
Long-term financial debt by currency and interest rate
\n
(1)
\n
Millions of euro
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest
\n
rate
\n
at Dec. 31, 2022 at Dec. 31, 2021 at Dec. 31, 2022 at Dec. 31, 2021
\n
Euro 34,993 35,383 32,041 32,387 1.9% 2.1% 1.6% 1.9%
\n
US dollar 26,930 27,209 17,518 17,629 4.8% 5.1% 4.2% 4.3%
\n
Pound sterling 4,470 4,610 3,901 3,976 4.6% 4.8% 5.0% 5.2%
\n
Colombian peso 1,310 1,310 1,341 1,341 10.3% 10.3% 6.5% 6.5%
\n
Brazilian real 1,899 1,926 1,720 1,753 10.0% 10.2% 8.8% 8.9%
\n
Swiss franc 359 360 343 344 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 526 531 423 428 5.1% 5.2% 5.2% 5.2%
\n
Peruvian sol 429 429 415 415 5.3% 5.3% 5.2% 5.2%
\n
Russian ruble - - 427 427 6.8% 7.3%
\n
Other currencies 110 115 402 405
\n
Total non-euro currencies 36,033 36,490 26,490 26,718
\n
TOTAL 71,026 71,873 58,531 59,105
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
Long-term financial debt denominated in currencies other
\n
than the euro increased by \u20ac9,543 million, largely attrib-
\n
utable to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term debt
\n
(1)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope
\n
New
\n
borrowings Other changes
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
Bonds 42,346 (2,788) (37) 12,390 - 497 52,408
\n
Borrowings 16,759 (6,571) (1,016)
\n
10,009 -28419,465
\n
- of which leases 2,547 (310) (88) 445 -782,672
\n
Total financial debt 59,105 (9,359) (1,053) 22,399 - 781 71,873
\n
(1) Does not include changes in the nominal value of other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the
\n
statement of financial position.
\n
The nominal value of long-term debt amounted to \u20ac71,873
\n
million at December 31, 2022, an increase of \u20ac12,768 mil-
\n
lion compared with December 31, 2021. The increase in
\n
debt reflected new borrowing of \u20ac22,399 million and ex-
\n
change losses of \u20ac781 million, only partially offset by re-
\n
payments of \u20ac9,359 million and the deconsolidation of
\n
debt of various companies, in particular that resulting from
\n
the sale of the equity investment in Enel Russia, equal to
\n
\u20ac1,053 million.
\n
Repayments in 2022 involved bonds in the amount of
\n
\u20ac2,788 million and loans in the amount of \u20ac6,571 million.
\n
Specifically, repayments of bonds in 2022 included:
\n
\u2022 \u20ac50 million in respect of a fixed-rate bond issued by Enel
\n
Finance International, maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in February 2022;
\n

\n\n
\u2022 270,000 million Colombian pesos (equivalent to \u20ac52
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2022;
\n
\u2022 \u20ac1,949 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in September 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in September
\n
2022;
\n
\u2022 \u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International maturing in November 2022;
\n
\u2022 300,000 million Colombian pesos (equivalent to \u20ac58
\n
million at December 31, 2022) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in December
\n
2022.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022 \u20ac5,250 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022 \u20ac264 million in respect of Endesa loans, of which \u20ac132
\n
million in sustainable loans;
\n
\u2022 \u20ac504 million in respect of sustainable loans of Group\u2019s
\n
Italian companies;
\n
\u2022 the equivalent of \u20ac354 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2022 involved \u20ac12,390 million in bonds
\n
and \u20ac10,009 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2022 and translated into euros
\n
at the exchange rate prevailing at December 31, 2022.
\n

\n\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of
\n
euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance International 17.01.2022 1,250 EUR 0.25% Fixed rate 17.11.2025
\n
Enel Finance International 17.01.2022 750 EUR 0.88% Fixed rate 17.01.2031
\n
Enel Finance International 17.01.2022 750 EUR 1.25% Fixed rate 17.01.2035
\n
Enel Finance International 11.04.2022 845 GBP 2.88% Fixed rate 11.04.2029
\n
Enel Finance International 15.06.2022 703 USD 4.25% Fixed rate 15.06.2025
\n
Enel Finance International 15.06.2022 703 USD 4.63% Fixed rate 15.06.2027
\n
Enel Finance International 15.06.2022 937 USD 5.00% Fixed rate 15.06.2032
\n
Enel Finance International 15.06.2022 937 USD 5.50% Fixed rate 15.06.2052
\n
Enel Finance International 09.09.2022 1,000 EUR 3.88% Fixed rate 09.03.2029
\n
Enel Finance International 14.10.2022 703 USD 6.80% Fixed rate 14.10.2025
\n
Enel Finance International 14.10.2022 1,171 USD 7.50% Fixed rate 14.10.2032
\n
Enel Finance International 14.10.2022 937 USD 7.75% Fixed rate 14.10.2052
\n
Enel Finance America 14.10.2022 937 USD 7.10% Fixed rate 14.10.2027
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 12.05.2022 142 BRL IPCA + 6.14% Floating rate 15.04.2032
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 30.05.2022 106 BRL IPCA + 6.21% Floating rate 17.05.2032
\n
Total bonds 11,871
\n
Bank borrowings
\n
Enel SpA 07.03.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 14.09.2022 200 EUR Euribor + 0.38% Floating rate 03.05.2024
\n
Enel SpA 30.09.2022 350 EUR Euribor + 0.45% Floating rate 26.07.2025
\n
Enel SpA 30.09.2022 648 EUR Euribor + 0.40% Floating rate 12.05.2025
\n
Enel SpA 30.09.2022 1,852 EUR Euribor + 0.40% Floating rate 05.03.2026
\n
Enel SpA 30.09.2022 1,000 EUR Euribor + 0.52% Floating rate 02.10.2024
\n
e-distibuzione 05.08.2022 300 EUR Euribor + 0.473% Floating rate 05.08.2037
\n
Enel Italia 29.07.2022 60 EUR Euribor 6M + 0.462% Floating rate 29.07.2037
\n
Enel Finance America 06.10.2022 403 USD USD SOFR 6M CMP + 1.22% Floating rate 15.05.2034
\n
Enel Finance America 03.11.2022 187 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 13.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Enel Finance America 21.12.2022 141 USD USD TERM SOFR 3M + 1.25% Floating rate 05.08.2024
\n
Endesa 17.01.2022 300 EUR Euribor 6M + 0.53% Floating rate 20.12.2033
\n
Endesa 25.03.2022 400 EUR Euribor 3M + 0.72% Floating rate 31.07.2024
\n
Endesa 28.03.2022 250 EUR Euribor 6M + 0.368% Floating rate 30.03.2037
\n
Endesa 30.03.2022 50 EUR Euribor 6M + 0.45% Floating rate 31.07.2024
\n
Endesa 31.03.2022 250 EUR Euribor 3M + 0.85% Floating rate 31.07.2024
\n
Endesa 31.03.2022 275 EUR Euribor 3M + 1.20% Floating rate 31.07.2024
\n
Endesa 31.03.2022 75 EUR 1.405% Fixed rate 01.04.2027
\n
Endesa 08.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 29.04.2022 50 EUR 1.967% Fixed rate 13.05.2027
\n
Endesa 10.05.2022 100 EUR Euribor 3M + 0.65% Floating rate 31.07.2024
\n
Endesa 25.05.2022 500 EUR 1.895% Fixed rate 13.05.2027
\n
Endesa 19.10.2022 200 EUR Euribor 3M + 1.30% Floating rate 31.07.2024
\n
Endesa 18.11.2022 250 EUR Euribor 6M + 0.582% Floating rate 18.11.2037
\n
Enel Colombia 05.04.2022 93 COP COP IBR 3M + 2.05% Floating rate 05.04.2028
\n
Enel Colombia 28.07.2022 79 COP COP IBR 3M + 1.6% Floating rate 28.07.2028
\n
Enel Colombia 30.11.2022 70 COP COP IBR 3M + 2.98% Floating rate 30.11.2029
\n
Enel Distribuci\u00f3n Per\u00fa 04.04.2022 52 PEN 6.96% Fixed rate 19.03.2025
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 24.03.2022 51 USD USD SOFR CMP + 0.91% Floating rate 21.03.2025
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo 01.09.2022 88 USD 3.61% Fixed rate 01.09.2037
\n
Total bank borrowings 8,665
\n

\n\n
The following table reports the impact on gross long-term
\n
debt of hedges to mitigate currency risk.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
(1)
\n
Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging Initial debt structure
\n
Impact of
\n
hedge
\n
Debt structure
\n
after hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Carrying
\n
amount
\n
Nominal
\n
value
\n
%
\n
Euro 34,993 35,383 49.2% 23,473 58,856 81.9% 32,041 32,387 54.8% 16,657 49,044 83.0%
\n
US dollar 26,930 27,209 37.9% (19,741) 7,468 10.4% 17,518 17,629 29.8% (13,423) 4,206 7.1%
\n
Pound sterling 4,470 4,610 6.4% (4,610) - - 3,901 3,976 6.7% (3,976) - -
\n
Colombian peso 1,310 1,310 1.8% - 1,310 1.8% 1,341 1,341 2.3% - 1,341 2.3%
\n
Brazilian real 1,899 1,926 2.7% 1,187 3,113 4.4% 1,720 1,753 3.0% 1,028 2,781 4.7%
\n
Swiss franc 359 360 0.5% (360) - - 343 344 0.6% (344) - -
\n
Chilean peso/UF 526 531 0.7% - 531 0.7% 423 428 0.7% - 428 0.7%
\n
Peruvian sol 429 429 0.6% - 429 0.6% 415 415 0.7% - 415 0.7%
\n
Russian ruble - - - - - - 427 427 0.7% - 427 0.7%
\n
Other currencies 110 115 0.2% 51 166 0.2% 402 405 0.7% 58 463
\n
0.8%
\n
Total non-euro
\n
currencies 36,033 36,490 50.8% (23,473) 13,017 18.1% 26,490 26,718 45.2% (16,657) 10,061 17.0%
\n
TOTAL 71,026 71,873 100.0% - 71,873 100.0% 58,531 59,105 100.0% - 59,105
\n
100.0%
\n
(1) Does not include other non-current financial borrowings reported under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
The amount of floating-rate debt that is not hedged
\n
against interest rate risk is the main risk factor that could
\n
adversely impact profit or loss (raising borrowing costs) in
\n
the event of an increase in market interest rates.
\n
Millions of euro 2022 2021
\n
Pre-hedge % Post-hedge
\n
% Pre-hedge % Post-hedge %
\n
Floating rate 34,450 38.2% 31,353 34.7% 27,811 38.4% 22,478 31.0%
\n
Fixed rate 55,815 61.8% 58,912 65.3% 44,612 61.6% 49,945 69.0%
\n
Total 90,265 90,265 72,423 72,423
\n
At December 31, 2022, 38.2% of long and medium-term
\n
financial debt was floating rate (38.4% at December 31,
\n
2021). Taking account of hedges of interest rates consid-
\n
ered effective pursuant to the IFRS-EU, 34.7% of long and
\n
medium-term net financial debt at December 31, 2022
\n
was exposed to interest rate risk (31% at December 31,
\n
2021). These figures are in line with the limits established in
\n
the risk management policy.
\n
The following table shows the impact of the IBOR reform
\n
on long-term financial debt for the main indices (for more
\n
details, please see the section \u201cReform of benchmarks for
\n
the determination of interest rates - IBOR reform\u201d in note
\n
51.1).
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Notional amount Phase 1 Phase 2 Phase 1 Phase 2
\n
USD LIBOR/SOFR 1,310 - 888 -
\n
GBP LIBOR/SONIA ---
\n
-
\n
Tot al 1,310 - 888 -
\n

\n\n
Long-term debt \u2013 Main covenants
\n
The Group\u2019s main long-term financial liabilities are gov-
\n
erned by covenants that are commonly adopted in inter-
\n
national business practice. They include in particular bond
\n
issues carried out within the framework of the Global/Euro
\n
Medium Term Notes program, issues of subordinated un-
\n
convertible hybrid bonds (so-called \u201chybrid bonds\u201d) and
\n
loans granted by banks and other financial institutions (in-
\n
cluding the European Investment Bank and Cassa Depositi
\n
e Prestiti SpA).
\n
The main covenants regarding bond issues carried out
\n
within the framework of the Global/Euro Medium Term
\n
Notes program of Enel and Enel Finance International NV
\n
(including the green bonds of Enel Finance International
\n
NV guaranteed by Enel SpA, which are used to finance the
\n
Group\u2019s so-called eligible green projects) and those re-
\n
garding bonds issued by Enel Finance International NV on
\n
the US market guaranteed by Enel SpA can be summarized
\n
as follows:
\n
\u2022 negative pledge clauses under which the issuer and the
\n
guarantor may not establish or maintain mortgages, liens
\n
or other encumbrances on all or part of their assets or
\n
revenue to secure certain financial liabilities, unless the
\n
same encumbrances are extended equally or pro rata to
\n
the bonds in question;
\n
\u2022 pari passu clauses, under which the bonds and the as-
\n
sociated security constitute a direct, unconditional and
\n
unsecured obligation of the issuer and the guarantor,
\n
are issued without preferential rights among them and
\n
have at least the same seniority as other present and fu-
\n
ture unsubordinated and unsecured bonds of the issuer
\n
and the guarantor;
\n
\u2022 cross-default clauses, under which the occurrence of
\n
a default event in respect of a specified financial liabil-
\n
ity (above a threshold level) of the issuer, the guarantor
\n
or, in some cases, \u201csignificant\u201d subsidiaries constitutes
\n
a default in respect of the liabilities in question, which
\n
become immediately repayable.
\n
Since 2019, Enel Finance International NV has issued a
\n
number of \u201csustainable\u201d bonds on the European market (as
\n
part of the Euro Medium Term Notes - EMTN bond issue
\n
program) and on the American market, both guaranteed
\n
by Enel SpA, linked to the achievement of a number of the
\n
Sustainable Development Goals (SDGs) of the United Na-
\n
tions that contain the same covenants as other bonds of
\n
the same type.
\n
In 2022, Enel Finance America LLC issued a \u201csustainable\u201d
\n
bond of the same type, guaranteed by Enel SpA, on the
\n
US market.
\n
The main covenants covering Enel\u2019s hybrid bonds, includ-
\n
ing the perpetual hybrid bond issues, which will only be
\n
repaid in the event of the dissolution or liquidation of the
\n
Company, can be summarized as follows:
\n
\u2022 subordination clauses, under which each hybrid bond is
\n
subordinate to all other bonds issued by the company
\n
and has the same seniority with all other hybrid financial
\n
instruments issued, being senior only to equity instru-
\n
ments;
\n
\u2022 prohibition on mergers with other companies, the sale
\n
or leasing of all or a substantial part of the company\u2019s
\n
assets to another company, unless the latter succeeds
\n
in all obligations of the issuer.
\n
The main covenants envisaged in the loan contracts
\n
of Enel and Enel Finance International NV and the other
\n
Group companies, including the sustainability-linked loan
\n
facility agreements obtained by Enel SpA, can be summa-
\n
rized as follows:
\n
\u2022 negative pledge clauses, under which the borrower and,
\n
in some cases, the guarantor are subject to limitations
\n
on the establishment of mortgages, liens or other en-
\n
cumbrances on all or part of their respective assets, with
\n
the exception of expressly permitted encumbrances;
\n
\u2022 disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their as-
\n
sets or operations, with the exception of expressly per-
\n
mitted disposals;
\n
\u2022 pari passu clauses, under which the payment undertak-
\n
ings of the borrower have the same seniority as its other
\n
unsecured and unsubordinated payment obligations;
\n
\u2022 change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required to
\n
renegotiate the terms and conditions of the financing or
\n
make compulsory early repayment of the loans granted;
\n
\u2022 rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022 cross-default clauses, under which the occurrence of a
\n
default event in respect of a specified financial liability
\n
(above a threshold level) of the issuer or, in some cas-
\n
es, the guarantor constitutes a default in respect of the
\n
liabilities in question, which become immediately repay-
\n
able.
\n
Some loan contracts entered into by Enel SpA, including as
\n
guarantor, provide for some additional covenants, such as:
\n
\u2022 the commitment to use the loan exclusively to hedge
\n
collateral for trading activities on the energy markets;
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending
\n
bank can request the cancellation of its financial com-
\n
mitment undertaken by it and the early payment of the
\n
sums disbursed if it has suffered ascertained harm to its
\n
own reputation or that of other persons as a result of
\n
substantial breach of certain regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure com-
\n
pliance with certain environmental and social regulations
\n
and standards.
\n

\n\n
In some cases, the covenants are also binding for the sig-
\n
nificant companies or subsidiaries of the obligated parties.
\n
All the borrowings considered specify \u201cevents of default\u201d
\n
typical of international business practice, such as, for ex-
\n
ample, insolvency, bankruptcy proceedings or the entity
\n
ceases trading.
\n
In addition, the guarantees issued by Enel in the interest
\n
of e-distribuzione SpA for certain loans to e-distribuzi-
\n
one SpA from Cassa Depositi e Prestiti SpA require that
\n
at the end of each six-month measurement period Enel\u2019s
\n
net consolidated financial debt shall not exceed 4.5 times
\n
annual consolidated EBITDA.
\n
Finally, the debt of Endesa SA, Enel Am\u00e9ricas SA, Enel Chile
\n
SA and the other Spanish and Latin American subsidiaries
\n
(notably Enel Generaci\u00f3n Chile SA) contains covenants and
\n
events of default typical of international business practice.
\n
48.3.2 Short-term borrowings \u2013 \u20ac18,392 million
\n
At December 31, 2022 short-term borrowings totaled
\n
\u20ac18,392 million, an increase of \u20ac5,086 million compared
\n
with December 31, 2021, and break down as follows:
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Short-term bank borrowings 1,320 1,329 (9)
\n
Commercial paper 13,838 10,708 3,130
\n
Cash collateral and other financing on derivatives 1,513 918 595
\n
Other short-term borrowings
\n
(1)
\n
1,721 351 1,370
\n
Short-term borrowings 18,392 13,306 5,086
\n
(1) Does not include other current borrowings included in \u201cOther current financial liabilities\u201d.
\n
Commercial paper liabilities totaling \u20ac13,838 million con-
\n
cerned issues by Enel Finance International, Endesa and
\n
Enel Finance America.
\n
The main commercial paper programs include:
\n
\u2022 \u20ac8,000 million of Enel Finance International, an increase
\n
from \u20ac6,000 million in 2021;
\n
\u2022 \u20ac5,000 million of Endesa, an increase from \u20ac4,000 mil-
\n
lion in 2021;
\n
\u2022 $5,000 million (equivalent to \u20ac4,414 million at December
\n
31, 2022), of Enel Finance America.
\n
At December 31, 2022, the whole amount of commercial
\n
paper issues, equal to \u20ac13,838 million, was linked to sus-
\n
tainability objectives.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSubordinatedLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1056": { "value": "\n
49. Risk management
\n
Financial risk management governance and
\n
objectives
\n
As part of its operations, the Enel Group is exposed to a va-
\n
riety of financial risks, notably interest rate risk, commodity
\n
risk, currency risk, credit and counterparty risk and liquidity
\n
risk.
\n
Enel\u2019s primary objective is to mitigate financial risks appro-
\n
priately so that they do not give rise to unexpected chang-
\n
es in results.
\n
The following sections detail the above financial risks.
\n
There were no changes in the sources of exposure to such
\n
risks compared with the previous year.
\n
Interest rate risk
\n
Interest rate risk derives primarily from the use of financial
\n
instruments and manifests itself as unexpected changes
\n
in charges on financial liabilities, if indexed to floating rates
\n
and/or exposed to the uncertainty of financial terms and
\n
conditions in negotiating new debt instruments, or as an
\n
unexpected change in the value of financial instruments
\n
measured at fair value (such as fixed-rate debt).
\n
The main financial liabilities held by the Group include
\n
bonds, bank borrowings, borrowings from other lenders,
\n
commercial paper, derivatives, cash deposits received to
\n
secure commercial or derivative contracts (guarantees,
\n
cash collateral).
\n
The Enel Group mainly manages interest rate risk through
\n
the definition of an optimal financial structure, with the
\n
dual goal of stabilizing borrowing costs and containing the
\n
cost of funds.
\n
This goal is pursued through the diversification of the port-
\n
folio of financial liabilities by contract type, maturity and
\n
interest rate, and modifying the risk profile of specific ex-
\n
posures using OTC derivatives, mainly interest rate swaps
\n
and interest rate options. The term of such derivatives
\n
does not exceed the maturity of the underlying financial li-
\n
ability, so that any change in the fair value and/or expected
\n
cash flows of such contracts is offset by a corresponding
\n
change in the fair value and/or cash flows of the hedged
\n
position.
\n
Proxy hedging techniques can be used in a number of re-
\n
sidual circumstances, when the hedging instruments for
\n

\n\n

\n
the risk factors are not available on the market or are not
\n
sufficiently liquid.
\n
Using interest rate swaps, the Enel Group agrees with the
\n
counterparty to periodically exchange floating-rate in-
\n
terest flows with fixed-rate flows, both calculated on the
\n
same notional principal amount.
\n
The following table reports the notional amount of interest
\n
rate derivatives at December 31, 2022 and December 31,
\n
2021 broken down by type of contract.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Floating-to-fixed interest rate swaps 5,836
\n
7, 7 00
\n
Fixed-to-floating interest rate swaps 1,401 722
\n
Fixed-to-fixed interest rate swaps --
\n
Floating-to-floating interest rate swaps 618 391
\n
Interest rate options -50
\n
Tot al 7,855
\n
8,863
\n
For more details on interest rate derivatives, please see
\n
note 51 \u201cDerivatives and hedge accounting\u201d.
\n
Interest rate risk sensitivity analysis
\n
Enel analyzes the sensitivity of its exposure by estimating
\n
the effects of a change in interest rates on the portfolio of
\n
financial instruments.
\n
More specifically, sensitivity analysis measures the po-
\n
tential impact on profit or loss and on equity of market
\n
scenarios that would cause a change in the fair value of
\n
derivatives or in the financial expense associated with un-
\n
hedged gross debt.
\n
These market scenarios are obtained by simulating parallel
\n
increases and decreases in the yield curve as at the re-
\n
porting date.
\n
There were no changes introduced in the methods and as-
\n
sumptions used in the sensitivity analysis compared with
\n
the previous year.
\n
With all other variables held constant, the Group\u2019s pre-tax
\n
profit would be affected by a change in the level of interest
\n
rates as follows:
\n
Millions of euro 2022
\n
Pre-tax impact on profit or loss Pre-tax impact on equity
\n
Basis
\n
points Increase Decrease Increase
\n
Decrease
\n
Change in financial expense on gross long-term floating-rate
\n
debt after hedging
\n
25 32
\n
(32) --
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
25 25
\n
(25) --
\n
Change in the fair value of derivatives designated as hedging
\n
instruments
\n
Cash flow hedges 25 - - 29 (29)
\n
Fair value hedges 25 - - (9)
\n
9
\n
At December 31, 2022, 22.3% (24.5% at December 31,
\n
2021) of the nominal value of gross long-term financial
\n
debt was floating rate. Taking account of effective cash
\n
flow hedges of interest rate risk (in accordance with the
\n
provisions of the IFRS-EU), 82.0% of the nominal value of
\n
gross long-term financial debt was hedged at December
\n
31, 2022 (84.5% at December 31, 2021).
\n\n
Currency risk
\n
Currency risk mainly manifests itself as unexpected
\n
changes in the financial statement items associated with
\n
transactions denominated in a currency other than the
\n
presentation currency. The Group\u2019s consolidated financial
\n
statements are also exposed to translation risk as a result
\n
of the conversion of the financial statements of foreign
\n
subsidiaries, which are denominated in local currencies,
\n
into euros as the Group\u2019s presentation currency.
\n
The Group\u2019s exposure to currency risk is connected with
\n
the purchase or sale of fuels and power, investments (cash
\n
flows for capitalized costs), dividends and the purchase or
\n
sale of equity investments, commercial transactions and
\n
financial assets and liabilities.
\n
The Group policies for managing currency risk provide for
\n
the mitigation of the effects on profit or loss of changes
\n
in the level of exchange rates, with the exception of the
\n
translation effects connected with consolidation.
\n

\n

\n\n

\n\n

\n\n
In order to minimize the exposure to currency risk, Enel im-
\n
plements diversified revenue and cost sources geograph-
\n
ically, and uses indexing mechanisms in commercial con-
\n
tracts. Enel also uses various types of derivative, typically
\n
on the OTC market.
\n
The derivatives in the Group\u2019s portfolio of financial instru-
\n
ments include cross currency interest rate swaps, currency
\n
forwards and currency swaps. The term of such contracts
\n
does not exceed the maturity of the underlying instru-
\n
ment, so that any change in the fair value and/or expected
\n
cash flows of such instruments offsets the corresponding
\n
change in the fair value and/or cash flows of the hedged
\n
position.
\n
Cross currency interest rate swaps are used to transform a
\n
long-term financial liability denominated in currency other
\n
than the presentation currency into an equivalent liability in
\n
the presentation currency.
\n
Currency forwards are contracts in which the counter-
\n
parties agree to exchange principal amounts denominat-
\n
ed in different currencies at a specified future date and
\n
exchange rate (the strike). Such contracts may call for the
\n
actual exchange of the two principal amounts (deliverable
\n
forwards) or payment of the difference generated by dif-
\n
ferences between the strike exchange rate and the prevail-
\n
ing exchange rate at maturity (non-deliverable forwards). In
\n
the latter case, the strike rate and/or the spot rate can be
\n
determined as averages of the rates observed in a given
\n
period.
\n
Currency swaps are contracts in which the counterparties
\n
enter into two transactions of the opposite sign at differ-
\n
ent future dates (normally one spot, the other forward) that
\n
provide for the exchange of principal denominated in dif-
\n
ferent currencies.
\n
The following table reports the notional amount of trans-
\n
actions outstanding at December 31, 2022 and December
\n
31, 2021, broken down by type of hedged item.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Cross currency interest rate swaps (CCIRSs) hedging debt denominated in currencies other than the euro 28,444 21,123
\n
Currency forwards hedging currency risk on commodities 8,392 6,183
\n
Currency forwards/CCIRSs hedging future cash flows in currencies other than the euro 5,333 5,034
\n
Other currency forwards 1,497 926
\n
Tot al 43,666 33,266
\n
More specifically, these include:
\n
\u2022 CCIRSs with a notional amount of \u20ac28,444 million to
\n
hedge the currency risk on debt denominated in cur-
\n
rencies other than the euro (\u20ac21,123 million at Decem-
\n
ber 31, 2021);
\n
\u2022 currency forwards and cross currency swaps with a to-
\n
tal notional amount of \u20ac13,725 million used to hedge
\n
the currency risk associated with purchases of natu-
\n
ral gas and fuel and expected cash flows in currencies
\n
other than the euro (\u20ac11,217 million at December 31,
\n
2021); changes in the notional amount during the year
\n
were affected by a greater exposure to exchange rate
\n
risk, in particular towards the US dollar, following the in-
\n
crease in natural gas prices and the increase in the use
\n
of coal for electricity generation;
\n
\u2022 other currency forwards, which include OTC derivatives
\n
transactions carried out to mitigate currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of in-
\n
vestment goods in the renewables and infrastructure
\n
and networks sectors (new generation digital meters),
\n
on operating costs for the supply of cloud services and
\n
on revenue from the sale of renewable energy. During
\n
2022, hedged items included exposures to fluctuations
\n
in the euro/Chinese renminbi exchange rate deriving
\n
from investments in BESS (Battery Energy Storage Sys-
\n
tem) projects.
\n
At December 31, 2022, 51% (45% at December 31, 2021)
\n
of Group long-term debt was denominated in currencies
\n
other than the euro.
\n
Taking account of hedges of currency risk, the percent-
\n
age of debt not hedged against that risk amounted to
\n
18% at December 31, 2022 (17% at December 31, 2021).
\n
Currency risk sensitivity analysis
\n
The Group analyzes the sensitivity of its exposure by es-
\n
timating the effects of a change in exchange rates on the
\n
portfolio of financial instruments.
\n
More specifically, sensitivity analysis measures the po-
\n
tential impact on profit or loss and equity of market
\n
scenarios that would cause a change in the fair value of
\n
derivatives or in the financial expense associated with un-
\n
hedged gross medium/long-term debt.
\n
These scenarios are obtained by simulating the apprecia-
\n
tion/depreciation of the euro against all of the currencies
\n
compared with the value observed as at the reporting
\n
date.
\n

\n\n

\n\n

\n

\n\n
There were no changes in the methods or assumptions
\n
used in the sensitivity analysis compared with the previ-
\n
ous year.
\n
With all other variables held constant, the pre-tax profit
\n
would be affected by changes in exchange rates as fol-
\n
lows.
\n
Millions of euro 2022
\n
Pre-tax impact
\n
on profit or loss Pre-tax impact on equity
\n
Exchange
\n
rate EUR appr. EUR depr. EUR appr.
\n
EUR depr.
\n
Change after hedging in financial expense on gross long-term
\n
debt denominated in currencies other than the euro
\n
10% ----
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
10% 880
\n
(1,073) --
\n
Change in the fair value of derivatives designated as hedging
\n
instruments
\n
Cash flow hedges 10% - - (3,434) 4,193
\n
Fair value hedges 10% (40) 49 - -
\n

\n\n\n
Commodity price risk
\n
The risk of fluctuations in the price of energy commodities
\n
such as electricity, gas, oil, CO
\n
2
\n
, and raw materials such as
\n
minerals and metals is generated by the volatility of pric-
\n
es and structural correlations between them, which cre-
\n
ate uncertainty in the margin on purchases and sales of
\n
electricity and fuels and materials at variable prices (e.g.,
\n
indexed bilateral contracts, transactions on the spot mar-
\n
ket, etc.).
\n
The exposures on indexed contracts are quantified by
\n
breaking down the contracts that generate exposure into
\n
the underlying risk factors.
\n
To contain the effects of fluctuations and stabilize margins,
\n
in accordance with the policies and operating limits deter-
\n
mined by the Group\u2019s governance and leaving an appropri-
\n
ate margin of flexibility to seize any short-term opportuni-
\n
ties that may present themselves, Enel develops and plans
\n
strategies that impact the various phases of the industrial
\n
process linked to the production and sale of electricity and
\n
gas (such as forward procurement and long-term com-
\n
mercial agreements), as well as risk mitigation plans and
\n
techniques using derivative contracts (hedging).
\n
As regards electricity sold by the Group, Enel mainly uses
\n
fixed-price contracts in the form of bilateral physical con-
\n
tracts (PPAs) and financial contracts (e.g., contracts for dif-
\n
ferences, VPP contracts, etc.) in which differences are paid
\n
to the counterparty if the market electricity price exceeds
\n
the strike price and to Enel in the opposite case. The resid-
\n
ual exposure in respect of the sale of energy on the spot
\n
market not hedged with such contracts is aggregated by
\n
uniform risk factors that can be managed with hedging
\n
transactions on the market. Proxy hedging techniques
\n
can be used for the industrial portfolios when the hedg-
\n
ing instruments for the specific risk factors generating
\n
the exposure are not available on the market or are not
\n
sufficiently liquid. In addition, Enel uses portfolio hedging
\n
techniques to assess opportunities for netting intercom-
\n
pany exposures.
\n
The Group mainly uses plain vanilla derivatives for hedging
\n
(more specifically, forwards, swaps, options on commodi-
\n
ties, futures, contracts for differences).
\n
Some of these products can be indexed to a variety of un-
\n
derlyings (coal, gas, oil, CO
\n
2
\n
, different geographical areas,
\n
etc.) and the approaches can be assessed and adapted to
\n
specific needs.
\n
Enel also engages in proprietary trading in order to main-
\n
tain a presence in the Group\u2019s reference energy com-
\n
modity markets. These operations consist in taking on
\n
exposures in energy commodities (oil products, gas, coal,
\n
CO
\n
2
\n
certificates and electricity) using financial derivatives
\n
and physical contracts traded on regulated and over-the-
\n
counter markets, optimizing profits through transactions
\n
carried out on the basis of expected market developments.
\n
The following table reports the notional amount of out-
\n
standing transactions at December 31, 2022 and Decem-
\n
ber 31, 2021, broken down by type of instrument.
\n

\n\n

\n\n

\n

\n\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Forward and futures contracts 114,128 90,273
\n
Swaps 11,271 12,122
\n
Options 504 1,076
\n
Embedded --
\n
Tot al 125,903 103,471
\n
For more details, please see note 51 \u201cDerivatives and hedge
\n
accounting\u201d.
\n
Commodity price risk sensitivity analysis
\n
The following table presents the results of the analysis of
\n
sensitivity to a reasonably possible change in the com-
\n
modity prices underlying the valuation model used in the
\n
scenario at the same date, with all other variables held
\n
constant.
\n
The impact on pre-tax profit of shifts of +15% and -15% in
\n
the price curve for the main commodities that make up
\n
the fuel scenario and the basket of formulas used in the
\n
contracts is mainly attributable to the change in the price
\n
of electricity, gas and petroleum products and, to a lesser
\n
extent, of CO
\n
2
\n
. The impact on equity of the same shifts in
\n
the price curve is primarily due to changes in the price of
\n
electricity, petroleum products and, to a lesser extent, CO
\n
2
\n
.
\n
The Group\u2019s exposure to changes in the prices of other
\n
commodities is not material.
\n
Millions of euro 2022
\n
Pre-tax impact on profit or loss Pre-tax impact on equity
\n
Commodity price Increase Decrease Increase Decrease
\n
Change in the fair value of trading derivatives on
\n
commodities
\n
20% (165) 169 - -
\n
Change in the fair value of derivatives on commodities
\n
designated as hedging instruments
\n
20% (17) 22 (273) 243
\n

\n\n\n
Credit and counterparty risk
\n
The Group\u2019s commercial, commodity and financial trans-
\n
actions expose it to credit risk, i.e., the possibility that a
\n
deterioration in the creditworthiness of a counterparty or
\n
the failure to discharge contractual payment obligations
\n
could lead to the interruption of incoming cash flows and
\n
an increase in collection costs (settlement risk), as well as
\n
lower revenue flows due to the replacement of the original
\n
transactions with similar transactions negotiated on unfa-
\n
vorable market conditions (replacement risk). Other risks
\n
include the reputational and financial risks associated with
\n
significant exposures to a single counterparty or groups of
\n
related customers, or to counterparties operating in the
\n
same sector or in the same geographical area.
\n
Accordingly, the exposure to credit and counterparty risk is
\n
attributable to the following types of transactions:
\n
\u2022 the sale and distribution of electricity and gas in free and
\n
regulated markets and the supply of goods and services
\n
(trade receivables in respect of non-Group debtors);
\n
\u2022 trading activities that involve the physical exchange of
\n
assets or transactions in financial instruments (the com-
\n
modity portfolio);
\n
\u2022 trading in derivatives, bank deposits and, more generally,
\n
financial instruments (the financial portfolio).
\n
In order to minimize credit and counterparty risk, cred-
\n
it exposures are managed at the region/country/global
\n
business line level by different units, thereby ensuring the
\n
necessary segregation of risk management and control
\n
activities. Monitoring the consolidated exposure is carried
\n
out by Enel SpA.
\n
In addition, at the Group level the policy provides for the
\n
use of uniform criteria \u2013 in all the main regions/countries/
\n
global business lines and at the consolidated level \u2013 in mea-
\n
suring commercial credit exposures in order to promptly
\n
identify any deterioration in the quality of outstanding re-
\n
ceivables and any mitigation actions to be taken.
\n
The policy for managing credit and counterparty risk asso-
\n
ciated with commercial activities provides for a preliminary
\n
assessment of the creditworthiness of counterparties and
\n
the adoption of mitigation instruments, such as obtaining
\n
collateral or unsecured guarantees.
\n
In addition, the Group undertakes transactions to factor
\n
receivables without recourse, which results in the com-
\n
plete derecognition of the corresponding assets involved
\n
in the factoring, as the risks and rewards associated with
\n
them have been transferred.
\n
Finally, with regard to financial and commodity transac-
\n
tions, risk mitigation is pursued with a uniform system for
\n
assessing counterparties at the Group level, including im-
\n

\n\n

\n\n

\n\n
plementation at the level of regions/countries/global busi-
\n
ness lines, as well as with the adoption of specific stan-
\n
dardized contractual frameworks that contain risk mitiga-
\n
tion clauses (e.g., netting arrangements) and possibly the
\n
exchange of cash collateral.
\n
Despite the deterioration in the collection status of some
\n
customer segments, which was taken into account in the
\n
assessment of the impairment of trade receivables, to
\n
date the Group portfolio has displayed resilience to the
\n
current macroeconomic context and price scenario. This
\n
reflects the strengthening of digital collection channels
\n
and a sound diversification of the customer base.
\n
Loan assets
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Staging
\n
Basis for
\n
recognition of
\n
expected credit loss
\n
allowance
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance Carrying amount
\n
Performing 12-month ECL 1.2% 16,918 205 16,713
\n
Underperforming Lifetime ECL 4.1% 266 11 255
\n
Non-performing Lifetime ECL 12.6% 254 32
\n
222
\n
Tot al 17,438 248 17,190
\n

\n\n

\n\n

\n\n
Contract assets, trade receivables and other financial assets: individual measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 79 - 79
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,560 41 5,519
\n
Trade receivables past due:
\n
- 1-30 days 1.0% 477 5 472
\n
- 31-60 days 1.3% 75 1 74
\n
- 61-90 days 2.8% 36 1 35
\n
- 91-120 days 7.1% 28 2 26
\n
- 121-150 days 12.5% 24 3 21
\n
- 151-180 days 5.9% 51 3 48
\n
- more than 180 days (credit impaired) 80.8% 1,629 1,317 312
\n
Total trade receivables 7,880 1,373 6,507
\n
Other financial assets
\n
Other financial assets not past due 2.2% 1,401 31 1,370
\n
Other financial assets past due:
\n
- 1-30 days - 35 - 35
\n
- 31-60 days - 219 - 219
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 2 - 2
\n
- more than 180 days (credit impaired) 16.3% 147 24 123
\n
Total other financial assets 1,804 55 1,749
\n
TOTAL 9,763 1,428 8,335
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 110 - 110
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,339 39 5,300
\n
Trade receivables past due:
\n
- 1-30 days 1.2% 489 6 483
\n
- 31-60 days 3.4% 89 3 86
\n
- 61-90 days 10.2% 59 6 53
\n
- 91-120 days 50.0% 34 17 17
\n
- 121-150 days 31.6% 19 6 13
\n
- 151-180 days 26.9% 26 7 19
\n
- more than 180 days (credit impaired) 77.1% 1,813 1,397 416
\n
Total trade receivables 7,868 1,481 6,387
\n
Other financial assets
\n
Other financial assets not past due 1.9% 1,712 32 1,680
\n
Other financial assets past due:
\n
- 1-30 days - 352 - 352
\n
- 31-60 days - 244 - 244
\n
- 61-90 days - - - -
\n
- 91-120 days - 2 - 2
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) 13.9% 332 46 286
\n
Total other financial assets 2,642 78 2,564
\n
TOTAL 10,620 1,559 9,061
\n

\n\n

\n\n

\n\n
Contract assets, trade receivables and other financial assets: collective measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 4.3% 46 2 44
\n
Trade receivables
\n
Trade receivables not past due 2.4% 7,698 187 7,511
\n
Trade receivables past due:
\n
- 1-30 days 2.6% 535 14 521
\n
- 31-60 days 42.3% 123 52 71
\n
- 61-90 days 24.0% 275 66 209
\n
- 91-120 days 29.0% 186 54 132
\n
- 121-150 days 35.6% 146 52 94
\n
- 151-180 days 45.0% 129 58 71
\n
- more than 180 days (credit impaired) 56.4% 3,416 1,927 1,489
\n
Total trade receivables 12,508 2,410 10,098
\n
Other financial assets
\n
Other financial assets not past due - 251 - 251
\n
Other financial assets past due:
\n
- 1-30 days 50.0% 2 1 1
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) - - - -
\n
Total other financial assets 253 1 252
\n
TOTAL 12,807 2,413 10,394
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 11.5% 26 2 24
\n
Trade receivables
\n
Trade receivables not past due 1.7% 4,603 77 4,526
\n
Trade receivables past due:
\n
- 1-30 days 2.8% 3,321 94 3,227
\n
- 31-60 days 9.9% 272 27 245
\n
- 61-90 days 15.3% 183 28 155
\n
- 91-120 days 26.1% 111 29 82
\n
- 121-150 days 32.4% 111 36 75
\n
- 151-180 days 33.3% 90 30 60
\n
- more than 180 days (credit impaired) 58.5% 3,180 1,861 1,319
\n
Total trade receivables 11,871 2,182 9,689
\n
Other financial assets
\n
Other financial assets not past due - 804 76 728
\n
Other financial assets past due:
\n
- 1-30 days - 7 - 7
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 1 - 1
\n
- more than 180 days (credit impaired) - 1 - 1
\n
Total other financial assets 813 76 737
\n
TOTAL 12,710 2,260 10,450
\n

\n\n

\n\n

\n\n
Liquidity risk
\n
Liquidity risk manifests itself as uncertainty about the
\n
Group\u2019s ability to discharge its obligations associated with
\n
financial liabilities that are settled by delivering cash or an-
\n
other financial asset.
\n
Enel manages liquidity risk by implementing measures to
\n
ensure an appropriate level of liquid financial resources,
\n
minimizing the associated opportunity cost and maintain-
\n
ing a balanced debt structure in terms of its maturity pro-
\n
file and funding sources.
\n
In the short term, liquidity risk is mitigated by maintaining
\n
an appropriate level of unconditionally available resources,
\n
including liquidity on hand and short-term deposits, avail-
\n
able committed credit lines and a portfolio of highly liquid
\n
assets.
\n
In the long term, liquidity risk is mitigated by maintaining a
\n
balanced maturity profile for our debt, access to a range of
\n
sources of funding on different markets, in different cur-
\n
rencies and with diverse counterparties.
\n
The mitigation of liquidity risk enables the Group to main-
\n
tain a credit rating that ensures access to the capital mar-
\n
ket and limits the cost of funds, with a positive impact on
\n
its financial position and performance.
\n
The Group holds the following undrawn lines of credit and
\n
commercial paper programs.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Committed credit lines 355 19,122 438 14,822
\n
Uncommitted credit lines 980 - 888 -
\n
Commercial paper 3,847 - 3,709 -
\n
Tot al 5,182 19,122 5,035 14,822
\n
Maturity analysis
\n
The table below summarizes the maturity profile of the
\n
Group\u2019s long-term debt.
\n
Millions of euro
\n
At Dec. 31, 2022 Maturing in
\n
Less than 3
\n
months
\n
From 3
\n
months to 1
\n
year 2024 2025 2026 2027 Beyond
\n
Bonds:
\n
- listed, fixed rate 54 924 4,674 3,421 3,848 3,738 13,233
\n
- listed, floating rate 237 300 391 304 225 199 891
\n
- unlisted, fixed rate - - 1,403 1,395 1,163 2,529 12,237
\n
- unlisted, floating rate - 97 97 97 97 97 40
\n
Total bonds 291 1,321 6,565 5,217 5,333 6,563 26,401
\n
Bank borrowings:
\n
- fixed rate 73 138 928 288 406 692 748
\n
- floating rate 120 557 3,144 1,196 2,399 944 4,488
\n
- use of revolving credit lines - 2 - 26 2 - -
\n
Total bank borrowings 193 697 4,072 1,510 2,807 1,636 5,236
\n
Leases:
\n
- fixed rate 67 184 219 200 172 144 1,644
\n
- floating rate 1 9 10 11 6 1 4
\n
Total leases 68 193 229 211 178 145 1,648
\n
Other non-bank borrowings:
\n
- fixed rate 18 52 61 56 60 56 201
\n
- floating rate - 2 - 6---
\n
Total other non-bank borrowings 18 54 61 62 60 56 201
\n
TOTAL 570 2,265 10,927 7,000 8,378 8,400 33,486
\n

\n\n

\n\n
Commitments to purchase commodities
\n
In conducting its business, the Enel Group has entered into
\n
contracts to purchase specified quantities of commodities
\n
at a certain future date for its own use, which qualify for
\n
the own use exemption provided for under IFRS 9.
\n
The following table reports the undiscounted cash flows
\n
associated with outstanding commitments at December
\n
31, 2022.
\n
Millions of euro
\n
at Dec. 31, 2022 2022-2025 2026-2030 2031-2035 Beyond
\n
Commitments to purchase commodities:
\n
- electricity 64,878 18,777 17,752 10,913 17,436
\n
- fuels 96,996 11,842 59,697 13,466 11,991
\n
Total 161,874 30,619 77,449 24,379
\n
29,427
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1054": { "value": "\n
Currency risk
\n
Currency risk mainly manifests itself as unexpected
\n
changes in the financial statement items associated with
\n
transactions denominated in a currency other than the
\n
presentation currency. The Group\u2019s consolidated financial
\n
statements are also exposed to translation risk as a result
\n
of the conversion of the financial statements of foreign
\n
subsidiaries, which are denominated in local currencies,
\n
into euros as the Group\u2019s presentation currency.
\n
The Group\u2019s exposure to currency risk is connected with
\n
the purchase or sale of fuels and power, investments (cash
\n
flows for capitalized costs), dividends and the purchase or
\n
sale of equity investments, commercial transactions and
\n
financial assets and liabilities.
\n
The Group policies for managing currency risk provide for
\n
the mitigation of the effects on profit or loss of changes
\n
in the level of exchange rates, with the exception of the
\n
translation effects connected with consolidation.
\n

\n

\n\n
In order to minimize the exposure to currency risk, Enel im-
\n
plements diversified revenue and cost sources geograph-
\n
ically, and uses indexing mechanisms in commercial con-
\n
tracts. Enel also uses various types of derivative, typically
\n
on the OTC market.
\n
The derivatives in the Group\u2019s portfolio of financial instru-
\n
ments include cross currency interest rate swaps, currency
\n
forwards and currency swaps. The term of such contracts
\n
does not exceed the maturity of the underlying instru-
\n
ment, so that any change in the fair value and/or expected
\n
cash flows of such instruments offsets the corresponding
\n
change in the fair value and/or cash flows of the hedged
\n
position.
\n
Cross currency interest rate swaps are used to transform a
\n
long-term financial liability denominated in currency other
\n
than the presentation currency into an equivalent liability in
\n
the presentation currency.
\n
Currency forwards are contracts in which the counter-
\n
parties agree to exchange principal amounts denominat-
\n
ed in different currencies at a specified future date and
\n
exchange rate (the strike). Such contracts may call for the
\n
actual exchange of the two principal amounts (deliverable
\n
forwards) or payment of the difference generated by dif-
\n
ferences between the strike exchange rate and the prevail-
\n
ing exchange rate at maturity (non-deliverable forwards). In
\n
the latter case, the strike rate and/or the spot rate can be
\n
determined as averages of the rates observed in a given
\n
period.
\n
Currency swaps are contracts in which the counterparties
\n
enter into two transactions of the opposite sign at differ-
\n
ent future dates (normally one spot, the other forward) that
\n
provide for the exchange of principal denominated in dif-
\n
ferent currencies.
\n
The following table reports the notional amount of trans-
\n
actions outstanding at December 31, 2022 and December
\n
31, 2021, broken down by type of hedged item.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Cross currency interest rate swaps (CCIRSs) hedging debt denominated in currencies other than the euro 28,444 21,123
\n
Currency forwards hedging currency risk on commodities 8,392 6,183
\n
Currency forwards/CCIRSs hedging future cash flows in currencies other than the euro 5,333 5,034
\n
Other currency forwards 1,497 926
\n
Tot al 43,666 33,266
\n
More specifically, these include:
\n
\u2022 CCIRSs with a notional amount of \u20ac28,444 million to
\n
hedge the currency risk on debt denominated in cur-
\n
rencies other than the euro (\u20ac21,123 million at Decem-
\n
ber 31, 2021);
\n
\u2022 currency forwards and cross currency swaps with a to-
\n
tal notional amount of \u20ac13,725 million used to hedge
\n
the currency risk associated with purchases of natu-
\n
ral gas and fuel and expected cash flows in currencies
\n
other than the euro (\u20ac11,217 million at December 31,
\n
2021); changes in the notional amount during the year
\n
were affected by a greater exposure to exchange rate
\n
risk, in particular towards the US dollar, following the in-
\n
crease in natural gas prices and the increase in the use
\n
of coal for electricity generation;
\n
\u2022 other currency forwards, which include OTC derivatives
\n
transactions carried out to mitigate currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of in-
\n
vestment goods in the renewables and infrastructure
\n
and networks sectors (new generation digital meters),
\n
on operating costs for the supply of cloud services and
\n
on revenue from the sale of renewable energy. During
\n
2022, hedged items included exposures to fluctuations
\n
in the euro/Chinese renminbi exchange rate deriving
\n
from investments in BESS (Battery Energy Storage Sys-
\n
tem) projects.
\n
At December 31, 2022, 51% (45% at December 31, 2021)
\n
of Group long-term debt was denominated in currencies
\n
other than the euro.
\n
Taking account of hedges of currency risk, the percent-
\n
age of debt not hedged against that risk amounted to
\n
18% at December 31, 2022 (17% at December 31, 2021).
\n
Currency risk sensitivity analysis
\n
The Group analyzes the sensitivity of its exposure by es-
\n
timating the effects of a change in exchange rates on the
\n
portfolio of financial instruments.
\n
More specifically, sensitivity analysis measures the po-
\n
tential impact on profit or loss and equity of market
\n
scenarios that would cause a change in the fair value of
\n
derivatives or in the financial expense associated with un-
\n
hedged gross medium/long-term debt.
\n
These scenarios are obtained by simulating the apprecia-
\n
tion/depreciation of the euro against all of the currencies
\n
compared with the value observed as at the reporting
\n
date.
\n

\n\n
There were no changes in the methods or assumptions
\n
used in the sensitivity analysis compared with the previ-
\n
ous year.
\n
With all other variables held constant, the pre-tax profit
\n
would be affected by changes in exchange rates as fol-
\n
lows.
\n
Millions of euro 2022
\n
Pre-tax impact
\n
on profit or loss Pre-tax impact on equity
\n
Exchange
\n
rate EUR appr. EUR depr. EUR appr.
\n
EUR depr.
\n
Change after hedging in financial expense on gross long-term
\n
debt denominated in currencies other than the euro
\n
10% ----
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
10% 880
\n
(1,073) --
\n
Change in the fair value of derivatives designated as hedging
\n
instruments
\n
Cash flow hedges 10% - - (3,434) 4,193
\n
Fair value hedges 10% (40) 49 - -
\n

\n\n
Currency risk
\n
The following table reports the maturity profile of the no-
\n
tional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2022 and De-
\n
cember 31, 2021.
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRS)
\n
Total notional amount of CCIRS 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRS EUR/USD 1,171 2,290 2,107 1,171 1,615 11,529 19,883
\n
Average exchange rate EUR/USD 1.33 1.13 1.07 1.18 1.10 1.15
\n
Notional amount for CCIRS EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount for CCIRS EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 140 288 239 94 - - 761
\n
Average exchange rate USD/BRL 5.22 5.50 5.22 5.29
\n
Notional amount for CCIRS EUR/BRL 597 438 181 - 70 - 1,286
\n
Average exchange rate EUR/BRL 6.09 6.25 6.16 3.92
\n
Currency forwards
\n
Total notional amount of forwards 6,127 2,374 625 - - - 9,126
\n
Notional amount - currency forwards EUR/USD 4,713 2,345 625 - - - 7,683
\n
Average currency forward rate - EUR/USD 1.09 1.10 1.11
\n
Notional amount - currency forwards USD/BRL 333 -----333
\n
Average currency forward rate - USD/BRL 5.61
\n
Notional amount - currency forwards EUR/CNH 311 -----311
\n
Average currency forward rate - EUR/CNH 7.41
\n
Notional amount - currency forwards USD/CLP 199 20----219
\n
Average currency forward rate - USD/CLP 906.90 921.05
\n
Notional amount - currency forwards USD/COP 156 2----158
\n
Average currency forward rate - USD/COP 4,720.74 4,444.96
\n

\n\n
Millions of euro Maturity
\n
2022 2023 2024 2025 2026 Beyond Total
\n
At Dec. 31, 2021
\n
Cross currency interest rate swap (CCIRS)
\n
Total notional amount of CCIRS 258 1,574 4,638 1,002 1,153 12,814 21,439
\n
Notional amount for CCIRS EUR/USD - 1,104 2,158 661 1,104 8,632 13,659
\n
Average exchange rate EUR/USD 1.33 1.13 1.17 1.18 1.21
\n
Notional amount for CCIRS EUR/GBP - - 1,012 - - 3,678 4,690
\n
Average exchange rate EUR/GBP 0.88 0.82
\n
Notional amount for CCIRS EUR/CHF - - 218 - - 126 344
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRS USD/BRL 98 132 295 155 49 244 973
\n
Average exchange rate USD/BRL 4.81 5.22 5.55 5.29 5.39 3.57
\n
Notional amount for CCIRS EUR/BRL 160 339 402 79 - 77 1,057
\n
Average exchange rate EUR/BRL 6.41 6.44 6.25 6.71 3.92
\n
Currency forward
\n
Total notional amount of forwards 4,324 1,320 371 4 - - 6,019
\n
Notional amount - currency forwards EUR/USD 3,064 1,268 371 4 - - 4,707
\n
Average currency forward rate - EUR/USD 1.16 1.19 1.18 1.18
\n
Notional amount - currency forwards USD/BRL 311 -----311
\n
Average currency forward rate - USD/BRL 5.65
\n
Notional amount - currency forwards USD/COP 284-----284
\n
Average currency forward rate - USD/COP 3,963.3
\n
Notional amount - currency forwards USD/CLP 145-----145
\n
Average currency forward rate - USD/CLP 818.94
\n
Notional amount - currency forwards USD/CAD 107-----107
\n
Average currency forward rate - USD/CAD 1.24
\n

\n\n
The following table shows the notional amount and the fair
\n
value of the hedging instruments on the currency risk of
\n
transactions outstanding as at December 31, 2022 and
\n
December 31, 2021, broken down by type of hedged item.
\n
Millions of euro Fair value
\n
Notional
\n
amount Fair value
\n
Notional
\n
amount
\n
Hedging instrument Hedged item Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
15 (99) 1,097 12 - 595
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings in foreign
\n
currencies
\n
-- -30-77
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate borrowings/financial
\n
assets in foreign currencies
\n
95 (76) 1,061 88 (19) 953
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
4 (233) 2,445 43 (58) 2,553
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Floating-rate bonds in foreign
\n
currencies
\n
60 - 414 37 - 344
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
1,864 (1,293) 23,381 1,159 (1,095) 16,601
\n
Cross currency interest rate swaps
\n
(CCIRS)
\n
Future cash flows denominated in
\n
foreign currencies
\n
- (50) 335 - (75) 316
\n
Currency forwards
\n
Future cash flows denominated in
\n
foreign currencies
\n
9 (6) 326 7 (3) 378
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign currencies
\n
192 (135) 7,508 106 (36) 4,802
\n
Currency forwards
\n
Purchases of investment goods and
\n
other in foreign currencies
\n
19 (23) 1,292 20 (7) 839
\n
Tot al 2,258 (1,915) 37,859 1,502 (1,293) 27,458
\n
Cash flow hedges and fair value hedges include:
\n
\u2022 CCIRSs with a notional amount of \u20ac26,923 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac258 million;
\n
\u2022 CCIRSs with a notional amount of \u20ac1,810 million used to
\n
hedge the currency risk on floating-rate debt denomi-
\n
nated in currencies other than the euro, with a positive
\n
fair value of \u20ac29 million;
\n
\u2022 currency forwards with a notional amount of \u20ac7,834
\n
million used to hedge the currency risk associated with
\n
purchases of natural gas, purchases of fuel and expect-
\n
ed cash flows in currencies other than the euro, with a
\n
total positive fair value of \u20ac60 million;
\n
\u2022 currency forwards with a notional amount of \u20ac1,292
\n
million and a negative fair value of \u20ac4 million, in respect
\n
of OTC transactions to mitigate the currency risk on ex-
\n
pected cash flows in currencies other than the presen-
\n
tation currency connected with the purchase of invest-
\n
ment goods in the renewables and infrastructure and
\n
networks sectors (new generation digital meters), on
\n
operating costs for the supply of cloud services and on
\n
revenue from the sale of renewable energy.
\n
The following table reports the notional amount and fair
\n
value of foreign exchange derivatives at December 31,
\n
2022 and December 31, 2021, broken down by type of
\n
hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2021
\n
Fair value hedges
\n
CCIRS 99 672 15 42 998 - (99) -
\n
Total 99 672 15 42 998 - (99) -
\n
Cash flow hedges
\n
Currency forwards 4,313 4,117 220 133 4,813 1,902 (164) (46)
\n
CCIRS 16,695 13,553 2,023 1,327 10,941 7,214 (1,652) (1,247)
\n
Total 21,008 17,670 2,243 1,460 15,754 9,116 (1,816) (1,293)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
21,107 18,342 2,258 1,502 16,752 9,116 (1,915) (1,293)
\n

\n\n
The notional amount of CCIRS at December 31, 2022
\n
amounted to \u20ac28,733 million (\u20ac21,439 million at Decem-
\n
ber 31, 2021), an increase of \u20ac7,294 million. Cross curren-
\n
cy interest rate swaps with a total amount of \u20ac258 million
\n
expired, while new derivatives amounted to \u20ac7,500 million,
\n
of which \u20ac6,936 million in respect of bond issues denomi-
\n
nated in British pounds and US dollars in 2022. In addition,
\n
following the novation of a bond in US dollars from Enel
\n
Finance International to Enel Finance America, cross cur-
\n
rency interest rate swaps of \u20ac662 million were terminated
\n
early. The amount also reflects developments in the ex-
\n
change rate of the euro against the main other currencies
\n
and the effect of amortization, which caused their notional
\n
amount to increase by \u20ac714 million.
\n
The notional amount of currency forwards at December
\n
31, 2022 amounted to \u20ac9,126 million (\u20ac6,019 million at De-
\n
cember 31, 2021), an increase of \u20ac3,107 million. The expo-
\n
sure to currency risk, especially that associated with the US
\n
dollar, is mainly due to purchases of natural gas, purchases
\n
of fuel and cash flows in respect of investments. Changes
\n
in the notional amount are connected with a greater ex-
\n
posure to exchange rate risk, in particular towards the US
\n
dollar, resulting from the increase in natural gas prices and
\n
the recovery in the generation of electricity from coal.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1058": { "value": "\n
Commodity price risk
\n
The risk of fluctuations in the price of energy commodities
\n
such as electricity, gas, oil, CO
\n
2
\n
, and raw materials such as
\n
minerals and metals is generated by the volatility of pric-
\n
es and structural correlations between them, which cre-
\n
ate uncertainty in the margin on purchases and sales of
\n
electricity and fuels and materials at variable prices (e.g.,
\n
indexed bilateral contracts, transactions on the spot mar-
\n
ket, etc.).
\n
The exposures on indexed contracts are quantified by
\n
breaking down the contracts that generate exposure into
\n
the underlying risk factors.
\n
To contain the effects of fluctuations and stabilize margins,
\n
in accordance with the policies and operating limits deter-
\n
mined by the Group\u2019s governance and leaving an appropri-
\n
ate margin of flexibility to seize any short-term opportuni-
\n
ties that may present themselves, Enel develops and plans
\n
strategies that impact the various phases of the industrial
\n
process linked to the production and sale of electricity and
\n
gas (such as forward procurement and long-term com-
\n
mercial agreements), as well as risk mitigation plans and
\n
techniques using derivative contracts (hedging).
\n
As regards electricity sold by the Group, Enel mainly uses
\n
fixed-price contracts in the form of bilateral physical con-
\n
tracts (PPAs) and financial contracts (e.g., contracts for dif-
\n
ferences, VPP contracts, etc.) in which differences are paid
\n
to the counterparty if the market electricity price exceeds
\n
the strike price and to Enel in the opposite case. The resid-
\n
ual exposure in respect of the sale of energy on the spot
\n
market not hedged with such contracts is aggregated by
\n
uniform risk factors that can be managed with hedging
\n
transactions on the market. Proxy hedging techniques
\n
can be used for the industrial portfolios when the hedg-
\n
ing instruments for the specific risk factors generating
\n
the exposure are not available on the market or are not
\n
sufficiently liquid. In addition, Enel uses portfolio hedging
\n
techniques to assess opportunities for netting intercom-
\n
pany exposures.
\n
The Group mainly uses plain vanilla derivatives for hedging
\n
(more specifically, forwards, swaps, options on commodi-
\n
ties, futures, contracts for differences).
\n
Some of these products can be indexed to a variety of un-
\n
derlyings (coal, gas, oil, CO
\n
2
\n
, different geographical areas,
\n
etc.) and the approaches can be assessed and adapted to
\n
specific needs.
\n
Enel also engages in proprietary trading in order to main-
\n
tain a presence in the Group\u2019s reference energy com-
\n
modity markets. These operations consist in taking on
\n
exposures in energy commodities (oil products, gas, coal,
\n
CO
\n
2
\n
certificates and electricity) using financial derivatives
\n
and physical contracts traded on regulated and over-the-
\n
counter markets, optimizing profits through transactions
\n
carried out on the basis of expected market developments.
\n
The following table reports the notional amount of out-
\n
standing transactions at December 31, 2022 and Decem-
\n
ber 31, 2021, broken down by type of instrument.
\n

\n\n
Millions of euro Notional amount
\n
at Dec. 31, 2022 at Dec. 31, 2021
\n
Forward and futures contracts 114,128 90,273
\n
Swaps 11,271 12,122
\n
Options 504 1,076
\n
Embedded --
\n
Tot al 125,903 103,471
\n
For more details, please see note 51 \u201cDerivatives and hedge
\n
accounting\u201d.
\n
Commodity price risk sensitivity analysis
\n
The following table presents the results of the analysis of
\n
sensitivity to a reasonably possible change in the com-
\n
modity prices underlying the valuation model used in the
\n
scenario at the same date, with all other variables held
\n
constant.
\n
The impact on pre-tax profit of shifts of +15% and -15% in
\n
the price curve for the main commodities that make up
\n
the fuel scenario and the basket of formulas used in the
\n
contracts is mainly attributable to the change in the price
\n
of electricity, gas and petroleum products and, to a lesser
\n
extent, of CO
\n
2
\n
. The impact on equity of the same shifts in
\n
the price curve is primarily due to changes in the price of
\n
electricity, petroleum products and, to a lesser extent, CO
\n
2
\n
.
\n
The Group\u2019s exposure to changes in the prices of other
\n
commodities is not material.
\n
Millions of euro 2022
\n
Pre-tax impact on profit or loss Pre-tax impact on equity
\n
Commodity price Increase Decrease Increase Decrease
\n
Change in the fair value of trading derivatives on
\n
commodities
\n
20% (165) 169 - -
\n
Change in the fair value of derivatives on commodities
\n
designated as hedging instruments
\n
20% (17) 22 (273) 243
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1057": { "value": "\n
Credit and counterparty risk
\n
The Group\u2019s commercial, commodity and financial trans-
\n
actions expose it to credit risk, i.e., the possibility that a
\n
deterioration in the creditworthiness of a counterparty or
\n
the failure to discharge contractual payment obligations
\n
could lead to the interruption of incoming cash flows and
\n
an increase in collection costs (settlement risk), as well as
\n
lower revenue flows due to the replacement of the original
\n
transactions with similar transactions negotiated on unfa-
\n
vorable market conditions (replacement risk). Other risks
\n
include the reputational and financial risks associated with
\n
significant exposures to a single counterparty or groups of
\n
related customers, or to counterparties operating in the
\n
same sector or in the same geographical area.
\n
Accordingly, the exposure to credit and counterparty risk is
\n
attributable to the following types of transactions:
\n
\u2022 the sale and distribution of electricity and gas in free and
\n
regulated markets and the supply of goods and services
\n
(trade receivables in respect of non-Group debtors);
\n
\u2022 trading activities that involve the physical exchange of
\n
assets or transactions in financial instruments (the com-
\n
modity portfolio);
\n
\u2022 trading in derivatives, bank deposits and, more generally,
\n
financial instruments (the financial portfolio).
\n
In order to minimize credit and counterparty risk, cred-
\n
it exposures are managed at the region/country/global
\n
business line level by different units, thereby ensuring the
\n
necessary segregation of risk management and control
\n
activities. Monitoring the consolidated exposure is carried
\n
out by Enel SpA.
\n
In addition, at the Group level the policy provides for the
\n
use of uniform criteria \u2013 in all the main regions/countries/
\n
global business lines and at the consolidated level \u2013 in mea-
\n
suring commercial credit exposures in order to promptly
\n
identify any deterioration in the quality of outstanding re-
\n
ceivables and any mitigation actions to be taken.
\n
The policy for managing credit and counterparty risk asso-
\n
ciated with commercial activities provides for a preliminary
\n
assessment of the creditworthiness of counterparties and
\n
the adoption of mitigation instruments, such as obtaining
\n
collateral or unsecured guarantees.
\n
In addition, the Group undertakes transactions to factor
\n
receivables without recourse, which results in the com-
\n
plete derecognition of the corresponding assets involved
\n
in the factoring, as the risks and rewards associated with
\n
them have been transferred.
\n
Finally, with regard to financial and commodity transac-
\n
tions, risk mitigation is pursued with a uniform system for
\n
assessing counterparties at the Group level, including im-
\n

\n\n
plementation at the level of regions/countries/global busi-
\n
ness lines, as well as with the adoption of specific stan-
\n
dardized contractual frameworks that contain risk mitiga-
\n
tion clauses (e.g., netting arrangements) and possibly the
\n
exchange of cash collateral.
\n
Despite the deterioration in the collection status of some
\n
customer segments, which was taken into account in the
\n
assessment of the impairment of trade receivables, to
\n
date the Group portfolio has displayed resilience to the
\n
current macroeconomic context and price scenario. This
\n
reflects the strengthening of digital collection channels
\n
and a sound diversification of the customer base.
\n
Loan assets
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Staging
\n
Basis for
\n
recognition of
\n
expected credit loss
\n
allowance
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance Carrying amount
\n
Performing 12-month ECL 1.2% 16,918 205 16,713
\n
Underperforming Lifetime ECL 4.1% 266 11 255
\n
Non-performing Lifetime ECL 12.6% 254 32
\n
222
\n
Tot al 17,438 248 17,190
\n

\n\n
Contract assets, trade receivables and other financial assets: individual measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 79 - 79
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,560 41 5,519
\n
Trade receivables past due:
\n
- 1-30 days 1.0% 477 5 472
\n
- 31-60 days 1.3% 75 1 74
\n
- 61-90 days 2.8% 36 1 35
\n
- 91-120 days 7.1% 28 2 26
\n
- 121-150 days 12.5% 24 3 21
\n
- 151-180 days 5.9% 51 3 48
\n
- more than 180 days (credit impaired) 80.8% 1,629 1,317 312
\n
Total trade receivables 7,880 1,373 6,507
\n
Other financial assets
\n
Other financial assets not past due 2.2% 1,401 31 1,370
\n
Other financial assets past due:
\n
- 1-30 days - 35 - 35
\n
- 31-60 days - 219 - 219
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 2 - 2
\n
- more than 180 days (credit impaired) 16.3% 147 24 123
\n
Total other financial assets 1,804 55 1,749
\n
TOTAL 9,763 1,428 8,335
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets - 110 - 110
\n
Trade receivables
\n
Trade receivables not past due 0.7% 5,339 39 5,300
\n
Trade receivables past due:
\n
- 1-30 days 1.2% 489 6 483
\n
- 31-60 days 3.4% 89 3 86
\n
- 61-90 days 10.2% 59 6 53
\n
- 91-120 days 50.0% 34 17 17
\n
- 121-150 days 31.6% 19 6 13
\n
- 151-180 days 26.9% 26 7 19
\n
- more than 180 days (credit impaired) 77.1% 1,813 1,397 416
\n
Total trade receivables 7,868 1,481 6,387
\n
Other financial assets
\n
Other financial assets not past due 1.9% 1,712 32 1,680
\n
Other financial assets past due:
\n
- 1-30 days - 352 - 352
\n
- 31-60 days - 244 - 244
\n
- 61-90 days - - - -
\n
- 91-120 days - 2 - 2
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) 13.9% 332 46 286
\n
Total other financial assets 2,642 78 2,564
\n
TOTAL 10,620 1,559 9,061
\n

\n\n
Contract assets, trade receivables and other financial assets: collective measurement
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 4.3% 46 2 44
\n
Trade receivables
\n
Trade receivables not past due 2.4% 7,698 187 7,511
\n
Trade receivables past due:
\n
- 1-30 days 2.6% 535 14 521
\n
- 31-60 days 42.3% 123 52 71
\n
- 61-90 days 24.0% 275 66 209
\n
- 91-120 days 29.0% 186 54 132
\n
- 121-150 days 35.6% 146 52 94
\n
- 151-180 days 45.0% 129 58 71
\n
- more than 180 days (credit impaired) 56.4% 3,416 1,927 1,489
\n
Total trade receivables 12,508 2,410 10,098
\n
Other financial assets
\n
Other financial assets not past due - 251 - 251
\n
Other financial assets past due:
\n
- 1-30 days 50.0% 2 1 1
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) - - - -
\n
Total other financial assets 253 1 252
\n
TOTAL 12,807 2,413 10,394
\n
Millions of euro
\n
at Dec. 31, 2021
\n
Average loss
\n
rate (PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Contract assets 11.5% 26 2 24
\n
Trade receivables
\n
Trade receivables not past due 1.7% 4,603 77 4,526
\n
Trade receivables past due:
\n
- 1-30 days 2.8% 3,321 94 3,227
\n
- 31-60 days 9.9% 272 27 245
\n
- 61-90 days 15.3% 183 28 155
\n
- 91-120 days 26.1% 111 29 82
\n
- 121-150 days 32.4% 111 36 75
\n
- 151-180 days 33.3% 90 30 60
\n
- more than 180 days (credit impaired) 58.5% 3,180 1,861 1,319
\n
Total trade receivables 11,871 2,182 9,689
\n
Other financial assets
\n
Other financial assets not past due - 804 76 728
\n
Other financial assets past due:
\n
- 1-30 days - 7 - 7
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - - - -
\n
- 151-180 days - 1 - 1
\n
- more than 180 days (credit impaired) - 1 - 1
\n
Total other financial assets 813 76 737
\n
TOTAL 12,710 2,260 10,450
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1055": { "value": "\n
Liquidity risk
\n
Liquidity risk manifests itself as uncertainty about the
\n
Group\u2019s ability to discharge its obligations associated with
\n
financial liabilities that are settled by delivering cash or an-
\n
other financial asset.
\n
Enel manages liquidity risk by implementing measures to
\n
ensure an appropriate level of liquid financial resources,
\n
minimizing the associated opportunity cost and maintain-
\n
ing a balanced debt structure in terms of its maturity pro-
\n
file and funding sources.
\n
In the short term, liquidity risk is mitigated by maintaining
\n
an appropriate level of unconditionally available resources,
\n
including liquidity on hand and short-term deposits, avail-
\n
able committed credit lines and a portfolio of highly liquid
\n
assets.
\n
In the long term, liquidity risk is mitigated by maintaining a
\n
balanced maturity profile for our debt, access to a range of
\n
sources of funding on different markets, in different cur-
\n
rencies and with diverse counterparties.
\n
The mitigation of liquidity risk enables the Group to main-
\n
tain a credit rating that ensures access to the capital mar-
\n
ket and limits the cost of funds, with a positive impact on
\n
its financial position and performance.
\n
The Group holds the following undrawn lines of credit and
\n
commercial paper programs.
\n
Millions of euro at Dec. 31, 2022 at Dec. 31, 2021
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Expiring within
\n
one year
\n
Expiring
\n
beyond one
\n
year
\n
Committed credit lines 355 19,122 438 14,822
\n
Uncommitted credit lines 980 - 888 -
\n
Commercial paper 3,847 - 3,709 -
\n
Tot al 5,182 19,122 5,035 14,822
\n
Maturity analysis
\n
The table below summarizes the maturity profile of the
\n
Group\u2019s long-term debt.
\n
Millions of euro
\n
At Dec. 31, 2022 Maturing in
\n
Less than 3
\n
months
\n
From 3
\n
months to 1
\n
year 2024 2025 2026 2027 Beyond
\n
Bonds:
\n
- listed, fixed rate 54 924 4,674 3,421 3,848 3,738 13,233
\n
- listed, floating rate 237 300 391 304 225 199 891
\n
- unlisted, fixed rate - - 1,403 1,395 1,163 2,529 12,237
\n
- unlisted, floating rate - 97 97 97 97 97 40
\n
Total bonds 291 1,321 6,565 5,217 5,333 6,563 26,401
\n
Bank borrowings:
\n
- fixed rate 73 138 928 288 406 692 748
\n
- floating rate 120 557 3,144 1,196 2,399 944 4,488
\n
- use of revolving credit lines - 2 - 26 2 - -
\n
Total bank borrowings 193 697 4,072 1,510 2,807 1,636 5,236
\n
Leases:
\n
- fixed rate 67 184 219 200 172 144 1,644
\n
- floating rate 1 9 10 11 6 1 4
\n
Total leases 68 193 229 211 178 145 1,648
\n
Other non-bank borrowings:
\n
- fixed rate 18 52 61 56 60 56 201
\n
- floating rate - 2 - 6---
\n
Total other non-bank borrowings 18 54 61 62 60 56 201
\n
TOTAL 570 2,265 10,927 7,000 8,378 8,400 33,486
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1052": { "value": "\n
50. Offsetting financial assets and financial liabilities
\n
At December 31, 2022, the Group did not hold offset po-
\n
sitions in assets and liabilities, as it is not the Enel Group\u2019s
\n
policy to settle financial assets and liabilities on a net basis.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialAssetsAndFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1051": { "value": "\n
Reform of benchmarks for the determination of interest
\n
rates \u2013 IBOR reform
\n
Overview
\n
Interbank Offered Rates (\u201cIBORs\u201d) are benchmark rates at
\n
which banks can borrow funds on the interbank market on
\n
an unsecured basis for a given period ranging from over-
\n
night to 12 months, in a specific currency.
\n
In recent years there have been a number of cases of ma-
\n
nipulation of these rates by the banks contributing to their
\n
calculation. For this reason, regulators around the world
\n
have begun a sweeping reform of interest rate bench-
\n
marks that includes the replacement of some benchmarks
\n
with alternative risk-free rates (the IBOR reform).
\n
The Group\u2019s main exposure is based on Euribor and USD
\n
LIBOR.
\n
Euribor is still considered compliant with the European
\n
Benchmarks Regulation (BMR) and this permits market
\n
participants to continue to use it for both existing and new
\n
contracts.
\n
In line with the most recent guidance issued by the major
\n
regulatory bodies:
\n
\u2022 the 1-month, 3-month and 6-month USD LIBOR bench-
\n
marks will become unrepresentative after June 30, 2023
\n
and the alternative reference rate will be the Secured
\n
Overnight Financing Rate (SOFR);
\n
\u2022 the 1-month, 3-month and 6-month GBP LIBOR bench-
\n
marks will become unrepresentative after December 31,
\n
2021 and the alternative reference rate will be the Ster-
\n
ling Overnight Index Average (SONIA).
\n
As a result of the IBOR reform, a number of temporary ex-
\n
ceptions to the rules on hedge relationships have been al-
\n
lowed in implementation of the amendments to IFRS 9 is-
\n
sued in September 2019 (Phase 1) and August 2020 (Phase
\n
2) to address, respectively:
\n

\n\n
\u2022 pre-replacement issues that impact financial reporting
\n
in the period preceding the replacement of an existing
\n
interest rate benchmark with an alternative risk-free rate
\n
(Phase 1); and
\n
\u2022 post-replacement issues that could impact financial
\n
reporting when an existing interest rate benchmark is
\n
reformed or replaced and there is no longer any initial
\n
uncertainty, but hedge contracts and relationships still
\n
need to be updated to reflect the new benchmark rates
\n
(Phase 2).
\n
Impact of the IBOR reform on the Group
\n
In a context of uncertainty regarding the IBOR transition in
\n
the various countries, the Group has determined the over-
\n
all number and nominal value of the contracts impacted by
\n
the reform. In addition, a number of contractual amend-
\n
ments have already been implemented in contracts pre-
\n
viously indexed to GBP LIBOR in 2021 and others will be
\n
amended in 2023 on the basis of the evolution of the IBOR
\n
reform and market practice.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and USD LIBOR and is almost entirely
\n
hedged using financial derivatives.
\n
At the reporting date, the Group is planning to take no
\n
action with regard to Euribor since, as stated above, this
\n
benchmark has been comprehensively reformed to com-
\n
ply with the European Benchmarks Regulation. Despite the
\n
continuity with Euribor, replacement clauses may be re-
\n
quired and could therefore be implemented by the Group
\n
in the new contracts in accordance with the evolution of
\n
accepted market practice.
\n
During 2022, the Group obtained new US dollar loans in-
\n
dexed to SOFR. The main focus over the coming months
\n
will be how to change existing USD LIBOR to USD SOFR ex-
\n
posures and how to use the new, alternative risk-free rates
\n
for new financial transactions.
\n
The Group\u2019s derivative instruments are managed through
\n
contracts that are mainly based on framework agreements
\n
defined by the International Swaps and Derivatives Associ-
\n
ation (ISDA).
\n
The ISDA has revised its standardized contracts in light of
\n
the IBOR reform and amended the choices for floating rates
\n
within the 2006 ISDA definitions to include replacement
\n
clauses that would apply upon the permanent discontinu-
\n
ation of specific key benchmarks. These changes took ef-
\n
fect on January 25, 2021. Transactions represented in the
\n
2006 ISDA definitions carried out on January 25, 2021 or
\n
later include adjusted floating-rate options (e.g., the choice
\n
of floating rate with replacement clause), while transactions
\n
completed before that date (previous derivative contracts)
\n
continue to be based on the 2006 ISDA definitions.
\n
For this reason, the ISDA published an IBOR Fallback Pro-
\n
tocol to facilitate multilateral amendments to include the
\n
amended definitions.
\n
The Group is assessing whether to: (i) adopt that protocol
\n
in the light of its exposure and developments in the IBOR
\n
reform or (ii) adjust in advance any contracts impacted bi-
\n
laterally by the reform.
\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, USD LIBOR and
\n
SONIA.
\n
The Group has assessed the impact of uncertainty engen-
\n
dered by the IBOR reform on hedge relationships at De-
\n
cember 31, 2022 with reference to both hedging instru-
\n
ments and hedged items. Both the hedged items and the
\n
hedging instruments will change their parameterization
\n
from interbank market-based benchmarks (IBORs) to al-
\n
ternative risk-free rates (RFRs) as a result of the contrac-
\n
tual amendments that will take effect in the coming years.
\n
In particular, uncertainty remains as to how the replacement
\n
will take place with regard to both hedging instruments and
\n
hedged items indexed to USD LIBOR. The Group manages
\n
the uncertainty associated with these hedge relationships
\n
by continuing to apply the temporary exceptions provided
\n
for in the amendments to IFRS 9 issued in September 2019
\n
(Phase 1). It was therefore felt that the benchmark indices
\n
for determining the interest rates on which the cash flows
\n
of the hedged items or the hedging instruments are based
\n
would not change as a consequence of the IBOR reform.
\n
The exception was applied for the following hedge rela-
\n
tionship requirements:
\n
\u2022 determine if a forecast transaction is highly probable;
\n
\u2022 establish whether the future hedged cash flows will arise
\n
in a discontinued cash flow hedge relationship;
\n
\u2022 assess the economic relationship between the hedged
\n
item and the hedging instrument.
\n
The hedge relationships impacted may become ineffective
\n
attributable to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In any case,
\n
the Group will seek to implement the replacements at the
\n
same time.
\n
In addition, the Group changed the reference to GBP LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically equiv-
\n
alent, SONIA benchmark at the end of 2021. Consequently,
\n
the Group no longer applies the amendments to IFRS 9
\n
issued in September 2019 (Phase 1) to these hedge rela-
\n
tionships and, consequently, is applying the amendments
\n
to IFRS 9 issued in August 2020 (Phase 2), modifying the
\n
formal designation of the hedge relationship as required
\n
by the IBOR reform and without considering this event as a
\n
termination of the hedge relationship.
\n

\n\n
Furthermore, for cash flow hedge relationships, in modify-
\n
ing the description of the hedged item in the hedge rela-
\n
tionship, the amounts accumulated in the cash flow hedge
\n
reserve were considered on the basis of the alternative
\n
benchmark index in relation to which the future hedged
\n
cash flows are determined.
\n
The following table provides details of the notional amounts
\n
of the hedging instruments for which the amendments to
\n
IFRS 9 (both Phase 1 and Phase 2) were applied as at De-
\n
cember 31, 2022, broken down by the alternative bench-
\n
mark index used for determining the interest rate.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2022
\n
Hedging instruments Phase 1 Phase 2
\n
USD LIBOR/SOFR 977 -
\n
GBP LIBOR/SONIA - 1,240
\n
Tot al 977
\n
1,240
\n

\n\n
Unamended contracts including those with specific
\n
replacement clauses
\n
The Group is monitoring the evolution of the transition
\n
from the old interest rate benchmarks to the new rates,
\n
reviewing the overall value of contracts that have not yet
\n
been indexed to the new benchmark rates and, among
\n
these, the value of contracts which already include specific
\n
replacement clauses. The Group considers a contract to
\n
have not yet incorporated an alternative benchmark rate
\n
when the interest rate of the contract is indexed to an in-
\n
terest rate benchmark still involved in the IBOR reform and,
\n
therefore, when uncertainties still exist as to how and when
\n
replacement with the new benchmark will take place.
\n

\n

\n", "dimensions": { "concept": "ifrs-full:DescriptionOfChangesToEntitysRiskManagementStrategyArisingFromEntitysExposureToFinancialInstrumentsSubjectToInterestRateBenchmarkReformExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag974": { "value": "\n

\n
Fair value measurement
\n\n
52. Assets and liabilities measured at
\n
fair value
\n
The Group determines fair value in accordance with IFRS
\n
13 whenever such measurement is required by the IFRS as
\n
a recognition or measurement criterion.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The best proxy of fair value is market price, i.e., the current
\n
publicly available price actually used on a liquid and active
\n
market.
\n
The fair value of assets and liabilities is classified in accor-
\n
dance with the three-level hierarchy described below, de-
\n
pending on the inputs and valuation techniques used in
\n
determining their fair value:
\n
\u2022 Level 1, where the fair value is determined on the basis
\n
of quoted prices (unadjusted) in active markets for iden-
\n
tical assets or liabilities that the entity can access at the
\n
measurement date;
\n
\u2022 Level 2, where the fair value is determined on the basis
\n
of inputs other than quoted prices included within Level
\n
1 that are observable for the asset or liability, either di-
\n
rectly (such as prices) or indirectly (derived from prices);
\n
\u2022 Level 3, where the fair value is determined on the basis
\n
of unobservable inputs.
\n
This note also provides detailed disclosures concerning
\n
the valuation techniques and inputs used to perform these
\n
measurements.
\n
To that end:
\n
\u2022 recurring fair value measurements of assets or liabilities
\n
are those required or permitted by the IFRS in the state-
\n
ment of financial position at the close of each period;
\n
\u2022 non-recurring fair value measurements are those re-
\n
quired or permitted by the IFRS in the statement of fi-
\n
nancial position in particular circumstances.
\n
For general information or specific disclosures on the ac-
\n
counting treatment of these circumstances, please see
\n
note 2 \u201cAccounting policies\u201d.
\n
52.1 Assets measured at fair value in the
\n
statement of financial position
\n
The following table shows, for each class of assets mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position, the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
of those assets are classified.
\n

\n\n

\n\n

\n\n

\n

\n

\n\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2022
\n
Equity investments in other
\n
companies at FVOCI
\n
29 360 14 43 303 - - - -
\n
Securities at FVOCI 29.1, 30.1 447 447 - - 78 78 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
94 - 94 - 201 - 201 -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 7--7 ----
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 3,436 - 3,436 - - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
8--8 176176--
\n
Other cash investments at
\n
FVTPL
\n
---- 87242-830
\n
Non-monetary grants in
\n
respect of environmental
\n
certificates
\n
16--16 ----
\n
Fair value hedge derivatives:
\n
- on interest rates 51 22 - 22 - - - - -
\n
- on exchange rates 51 15 - 15 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 336 - 336 - - - - -
\n
- on exchange rates 51 1,854 - 1,854 - 389 - 389 -
\n
- on commodities 51 1,270 314 300 656 2,366 496 1,597 273
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 74 - 74 -
\n
- on commodities 51 472 109 362 1 12,001 10,640 1,360 1
\n
Inventories measured at fair
\n
value
\n
51 15 15 - - 18 - 18 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n
The fair value of \u201cEquity investments in other companies
\n
at FVOCI\u201d is determined for listed companies on the basis
\n
of the quoted price at the close of the year, while that for
\n
unlisted companies is based on a reliable valuation of the
\n
relevant assets and liabilities.
\n\n
\u201cFinancial assets from service concession arrangements
\n
at FVTPL\u201d concern electricity distribution operations in
\n
Brazil, mainly by Enel Distribui\u00e7\u00e3o Rio de Janeiro, Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1, and Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, as well as
\n
the generation plant of PH Chucas in Costa Rica, and are
\n
accounted for in accordance with IFRIC 12.
\n

\n\n
Fair value was estimated as the net replacement cost
\n
based on the most recent rate information available and
\n
on the general price index for the Brazilian market.
\n
The current portion of \u201cLoan assets and other financial as-
\n
sets at FVTPL\u201d essentially regard investments of liquidity.
\n
Their fair value is determined using Level 1 as based on
\n
market inputs.
\n
Level 3 of the non-current portion of \u201cLoan assets and
\n
other financial assets at FVTPL\u201d reports the receivable
\n
in respect of the sale of Slovak Power Holding, which
\n
amounted to \u20ac8 million at December 31, 2022. Its fair value
\n
was determined using the contractual price formula. The
\n
current portion of \u201cLoan assets and other financial assets
\n
at FVTPL\u201d includes under Level 1 investments in securities
\n
and funds held mainly by Latin American companies.
\n
The current portion of \u201cOther cash investments at FVTPL\u201d
\n
at Level 3 mainly refers to the optimization of Enel SpA\u2019s
\n
excess cash holdings.
\n
The fair value of derivative contracts is determined us-
\n
ing the official prices for instruments traded on regulated
\n
markets. The fair value of instruments not listed on a reg-
\n
ulated market is determined using valuation methods ap-
\n
propriate for each type of financial instrument and market
\n
data as of the end of the reporting period (such as interest
\n
rates, exchange rates, volatility), discounting expected fu-
\n
ture cash flows on the basis of the market yield curve and
\n

\n\n

\n\n

\n\n
translating amounts in currencies other than the euro us-
\n
ing exchange rates provided by the World Markets Refinitiv
\n
(WMR) Company.
\n
Derivatives on interest rates and exchange rates are all
\n
measured using Level 2 inputs.
\n
The fair value of derivatives on commodities is almost al-
\n
ways measured using Level 1 or Level 2 inputs, as the de-
\n
termination is based on market inputs as these contracts
\n
are entered into with exchange counterparties, leading
\n
sector operators or financial institutions.
\n
Marginal exceptions include certain derivatives relating to
\n
certain long-term financial contracts (virtual power pur-
\n
chase agreements, or VPPAs), for which internal measure-
\n
ment models were also used in part in order to measure
\n
these instruments over longer time horizons, given the illi-
\n
quidity of the underlying variables.
\n
In accordance with the IFRS, the Group assess credit risk,
\n
both of the counterparty (Credit Valuation Adjustment or
\n
CVA) and its own (Debit Valuation Adjustment or DVA), in
\n
order to adjust the fair value of financial instruments for
\n
the corresponding amount of counterparty risk where
\n
necessary. More specifically, the Group measures CVA/DVA
\n
using a Potential Future Exposure valuation technique for
\n
the net exposure of the position and subsequently allocat-
\n
ing the adjustment to the individual financial instruments
\n
that make up the overall portfolio. All of the inputs used in
\n
this technique are observable on the market.
\n
52.2 Assets not measured at fair value in the
\n
statement of financial position
\n
For each class of assets not measured at fair value on a
\n
recurring basis but whose fair value must be reported, the
\n
following table reports the fair value at the end of the year
\n
and the level in the fair value hierarchy into which the fair
\n
value measurements of those assets are classified.
\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Investment property 22 154 16 - 138 - - - -
\n
Inventories 33 - - - - 47 - - 47
\n
The table reports the fair value of investment property and
\n
inventories of real estate not used in the business in the
\n
amount of \u20ac154 million and \u20ac47 million respectively. The
\n
amounts were calculated with the assistance of apprais-
\n
als conducted by independent experts, who used different
\n
methods depending on the specific assets involved.
\n
52.3 Liabilities measured at fair value in the
\n
statement of financial position
\n
The following table reports for each class of liabilities mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
are classified.
\n
Millions of euro Non-current liabilities Current liabilities
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Fair value hedge derivatives:
\n
- on interest rates 51 92-92- ----
\n
- on exchange rates 51 99 - 99 - - - - -
\n
- on commodities 51 - - - - ----
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 59 - 59 - 1 - 1 -
\n
- on exchange rates 51 1,640 - 1,640 - 176 - 176 -
\n
- on commodities 51 3,417 1,722 1,551 144 4,322 3,049 1,250 23
\n
Trading derivatives:
\n
- on interest rates 51 ---- 23-23-
\n
- on exchange rates 51 1 - 1 - 34 - 34 -
\n
- on commodities 51 587 192 395 - 11,585 10,595 990 -
\n
Contingent consideration 46 - - 46 46 - 44 2
\n

\n\n

\n\n

\n\n
Contingent consideration mainly regards a number of
\n
equity investments held by the Group in North America,
\n
whose fair value was determined on the basis of the con-
\n
tractual terms and conditions.
\n
52.4 Liabilities not measured at fair value in the
\n
statement of financial position
\n
For each class of liabilities not measured at fair value in the
\n
statement of financial position but whose fair value must
\n
be reported, the following table reports the fair value at the
\n
end of the period and the level in the fair value hierarchy
\n
into which the fair value measurements of those liabilities
\n
are classified.
\n
Millions of euro
\n
Notes Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022
\n
Bonds:
\n
- fixed rate 48.3.1 44,717 41,964 2,753 -
\n
- floating rate 48.3.1 3,073 62 3,011 -
\n
Bank borrowings:
\n
- fixed rate 48.3.1 3,021 - 3,021 -
\n
- floating rate 48.3.1 12,596 - 12,596 -
\n
Non-bank borrowings:
\n
- fixed rate 48.3.1 3,134 - 3,134 -
\n
- floating rate 48.3.1 54 - 54 -
\n
Tot al 66,595 42,026 24,569 -
\n
For listed debt instruments, the fair value is given by official
\n
prices. For unlisted instruments the fair value is determined
\n
using appropriate valuation techniques for each category
\n
of financial instrument and market data at the close of the
\n
year, including the credit spreads of Enel.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag973": { "value": "\n
52. Assets and liabilities measured at
\n
fair value
\n
The Group determines fair value in accordance with IFRS
\n
13 whenever such measurement is required by the IFRS as
\n
a recognition or measurement criterion.
\n
Fair value is defined as the price that would be received
\n
to sell an asset or paid to transfer a liability, in an orderly
\n
transaction, between market participants, at the measure-
\n
ment date (i.e., an exit price).
\n
The best proxy of fair value is market price, i.e., the current
\n
publicly available price actually used on a liquid and active
\n
market.
\n
The fair value of assets and liabilities is classified in accor-
\n
dance with the three-level hierarchy described below, de-
\n
pending on the inputs and valuation techniques used in
\n
determining their fair value:
\n
\u2022 Level 1, where the fair value is determined on the basis
\n
of quoted prices (unadjusted) in active markets for iden-
\n
tical assets or liabilities that the entity can access at the
\n
measurement date;
\n
\u2022 Level 2, where the fair value is determined on the basis
\n
of inputs other than quoted prices included within Level
\n
1 that are observable for the asset or liability, either di-
\n
rectly (such as prices) or indirectly (derived from prices);
\n
\u2022 Level 3, where the fair value is determined on the basis
\n
of unobservable inputs.
\n
This note also provides detailed disclosures concerning
\n
the valuation techniques and inputs used to perform these
\n
measurements.
\n
To that end:
\n
\u2022 recurring fair value measurements of assets or liabilities
\n
are those required or permitted by the IFRS in the state-
\n
ment of financial position at the close of each period;
\n
\u2022 non-recurring fair value measurements are those re-
\n
quired or permitted by the IFRS in the statement of fi-
\n
nancial position in particular circumstances.
\n
For general information or specific disclosures on the ac-
\n
counting treatment of these circumstances, please see
\n
note 2 \u201cAccounting policies\u201d.
\n
52.1 Assets measured at fair value in the
\n
statement of financial position
\n
The following table shows, for each class of assets mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position, the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
of those assets are classified.
\n

\n\n

\n

\n

\n\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2022
\n
Equity investments in other
\n
companies at FVOCI
\n
29 360 14 43 303 - - - -
\n
Securities at FVOCI 29.1, 30.1 447 447 - - 78 78 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
94 - 94 - 201 - 201 -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 7--7 ----
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 3,436 - 3,436 - - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
8--8 176176--
\n
Other cash investments at
\n
FVTPL
\n
---- 87242-830
\n
Non-monetary grants in
\n
respect of environmental
\n
certificates
\n
16--16 ----
\n
Fair value hedge derivatives:
\n
- on interest rates 51 22 - 22 - - - - -
\n
- on exchange rates 51 15 - 15 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 336 - 336 - - - - -
\n
- on exchange rates 51 1,854 - 1,854 - 389 - 389 -
\n
- on commodities 51 1,270 314 300 656 2,366 496 1,597 273
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 74 - 74 -
\n
- on commodities 51 472 109 362 1 12,001 10,640 1,360 1
\n
Inventories measured at fair
\n
value
\n
51 15 15 - - 18 - 18 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n
The fair value of \u201cEquity investments in other companies
\n
at FVOCI\u201d is determined for listed companies on the basis
\n
of the quoted price at the close of the year, while that for
\n
unlisted companies is based on a reliable valuation of the
\n
relevant assets and liabilities.
\n\n
\u201cFinancial assets from service concession arrangements
\n
at FVTPL\u201d concern electricity distribution operations in
\n
Brazil, mainly by Enel Distribui\u00e7\u00e3o Rio de Janeiro, Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1, and Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, as well as
\n
the generation plant of PH Chucas in Costa Rica, and are
\n
accounted for in accordance with IFRIC 12.
\n

\n\n
Fair value was estimated as the net replacement cost
\n
based on the most recent rate information available and
\n
on the general price index for the Brazilian market.
\n
The current portion of \u201cLoan assets and other financial as-
\n
sets at FVTPL\u201d essentially regard investments of liquidity.
\n
Their fair value is determined using Level 1 as based on
\n
market inputs.
\n
Level 3 of the non-current portion of \u201cLoan assets and
\n
other financial assets at FVTPL\u201d reports the receivable
\n
in respect of the sale of Slovak Power Holding, which
\n
amounted to \u20ac8 million at December 31, 2022. Its fair value
\n
was determined using the contractual price formula. The
\n
current portion of \u201cLoan assets and other financial assets
\n
at FVTPL\u201d includes under Level 1 investments in securities
\n
and funds held mainly by Latin American companies.
\n
The current portion of \u201cOther cash investments at FVTPL\u201d
\n
at Level 3 mainly refers to the optimization of Enel SpA\u2019s
\n
excess cash holdings.
\n
The fair value of derivative contracts is determined us-
\n
ing the official prices for instruments traded on regulated
\n
markets. The fair value of instruments not listed on a reg-
\n
ulated market is determined using valuation methods ap-
\n
propriate for each type of financial instrument and market
\n
data as of the end of the reporting period (such as interest
\n
rates, exchange rates, volatility), discounting expected fu-
\n
ture cash flows on the basis of the market yield curve and
\n

\n\n
translating amounts in currencies other than the euro us-
\n
ing exchange rates provided by the World Markets Refinitiv
\n
(WMR) Company.
\n
Derivatives on interest rates and exchange rates are all
\n
measured using Level 2 inputs.
\n
The fair value of derivatives on commodities is almost al-
\n
ways measured using Level 1 or Level 2 inputs, as the de-
\n
termination is based on market inputs as these contracts
\n
are entered into with exchange counterparties, leading
\n
sector operators or financial institutions.
\n
Marginal exceptions include certain derivatives relating to
\n
certain long-term financial contracts (virtual power pur-
\n
chase agreements, or VPPAs), for which internal measure-
\n
ment models were also used in part in order to measure
\n
these instruments over longer time horizons, given the illi-
\n
quidity of the underlying variables.
\n
In accordance with the IFRS, the Group assess credit risk,
\n
both of the counterparty (Credit Valuation Adjustment or
\n
CVA) and its own (Debit Valuation Adjustment or DVA), in
\n
order to adjust the fair value of financial instruments for
\n
the corresponding amount of counterparty risk where
\n
necessary. More specifically, the Group measures CVA/DVA
\n
using a Potential Future Exposure valuation technique for
\n
the net exposure of the position and subsequently allocat-
\n
ing the adjustment to the individual financial instruments
\n
that make up the overall portfolio. All of the inputs used in
\n
this technique are observable on the market.
\n
52.2 Assets not measured at fair value in the
\n
statement of financial position
\n
For each class of assets not measured at fair value on a
\n
recurring basis but whose fair value must be reported, the
\n
following table reports the fair value at the end of the year
\n
and the level in the fair value hierarchy into which the fair
\n
value measurements of those assets are classified.
\n
Millions of euro Non-current assets Current assets
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Investment property 22 154 16 - 138 - - - -
\n
Inventories 33 - - - - 47 - - 47
\n
The table reports the fair value of investment property and
\n
inventories of real estate not used in the business in the
\n
amount of \u20ac154 million and \u20ac47 million respectively. The
\n
amounts were calculated with the assistance of apprais-
\n
als conducted by independent experts, who used different
\n
methods depending on the specific assets involved.
\n
52.3 Liabilities measured at fair value in the
\n
statement of financial position
\n
The following table reports for each class of liabilities mea-
\n
sured at fair value on a recurring or non-recurring basis in
\n
the statement of financial position the fair value measure-
\n
ment at the end of the reporting period and the level in the
\n
fair value hierarchy into which the fair value measurements
\n
are classified.
\n
Millions of euro Non-current liabilities Current liabilities
\n
Notes Fair value Level 1 Level 2 Level 3 Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022 at Dec. 31, 2022
\n
Fair value hedge derivatives:
\n
- on interest rates 51 92-92- ----
\n
- on exchange rates 51 99 - 99 - - - - -
\n
- on commodities 51 - - - - ----
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 59 - 59 - 1 - 1 -
\n
- on exchange rates 51 1,640 - 1,640 - 176 - 176 -
\n
- on commodities 51 3,417 1,722 1,551 144 4,322 3,049 1,250 23
\n
Trading derivatives:
\n
- on interest rates 51 ---- 23-23-
\n
- on exchange rates 51 1 - 1 - 34 - 34 -
\n
- on commodities 51 587 192 395 - 11,585 10,595 990 -
\n
Contingent consideration 46 - - 46 46 - 44 2
\n

\n\n
Contingent consideration mainly regards a number of
\n
equity investments held by the Group in North America,
\n
whose fair value was determined on the basis of the con-
\n
tractual terms and conditions.
\n
52.4 Liabilities not measured at fair value in the
\n
statement of financial position
\n
For each class of liabilities not measured at fair value in the
\n
statement of financial position but whose fair value must
\n
be reported, the following table reports the fair value at the
\n
end of the period and the level in the fair value hierarchy
\n
into which the fair value measurements of those liabilities
\n
are classified.
\n
Millions of euro
\n
Notes Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2022
\n
Bonds:
\n
- fixed rate 48.3.1 44,717 41,964 2,753 -
\n
- floating rate 48.3.1 3,073 62 3,011 -
\n
Bank borrowings:
\n
- fixed rate 48.3.1 3,021 - 3,021 -
\n
- floating rate 48.3.1 12,596 - 12,596 -
\n
Non-bank borrowings:
\n
- fixed rate 48.3.1 3,134 - 3,134 -
\n
- floating rate 48.3.1 54 - 54 -
\n
Tot al 66,595 42,026 24,569 -
\n
For listed debt instruments, the fair value is given by official
\n
prices. For unlisted instruments the fair value is determined
\n
using appropriate valuation techniques for each category
\n
of financial instrument and market data at the close of the
\n
year, including the credit spreads of Enel.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag850": { "value": "\n
53. Share-based payments
\n
Starting in 2019, the Shareholders\u2019 Meeting of Enel SpA
\n
(\u201cEnel\u201d or the \u201cCompany\u201d) has each year approved the
\n
adoption of long-term share-based incentive plans for the
\n
management of Enel and/or its subsidiaries pursuant to
\n
Article 2359 of the Italian Civil Code. Each of the incen-
\n
tive plans approved (the 2019 Long-Term Incentive Plan,
\n
the 2020 Long-Term Incentive Plan, the 2021 Long-Term
\n
Incentive Plan, the 2022 Long-Term Incentive Plan; referred
\n
to hereinafter, respectively, the \u201c2019 LTI Plan\u201d, \u201c2020 LTI
\n
Plan\u201d, the 2021 LTI Plan\u201d, the \u201c2022 LTI Plan\u201d and, jointly, the
\n
\u201cPlans\u201d) provides for the grant of ordinary Company shares
\n
(\u201cShares\u201d) to the respective beneficiaries subject to the
\n
achievement of specific performance targets.
\n
Plan beneficiaries are the Chief Executive Officer/General
\n
Manager of Enel and Enel Group managers in the positions
\n
most directly responsible for company performance or
\n
considered to be of strategic interest. The Plans provide
\n
for the award to the beneficiaries of an incentive consist-
\n
ing of a monetary component and an equity component.
\n
This incentive \u2013 determined, at the time of the award, as
\n
a base value calculated in relation to the fixed remuner-
\n
ation of the individual beneficiary \u2013 may vary depending
\n
on the degree of achievement of each of the three-year
\n
performance targets by the Plans, ranging from zero up to
\n
a maximum of 280% or 180% of the base value in the case,
\n
respectively, of the Chief Executive Officer/General Man-
\n
ager or the other beneficiaries.
\n
The Plans establish that, of the total incentive effectively
\n
vested, the bonus will be fully paid in Shares in the amount
\n
of (i) up to 100% of the base value for the Chief Executive
\n
Officer/General Manager (up to 130% for the 2022 LTI Plan),
\n
and (ii) up to 50% of the base value for the other beneficia-
\n
ries (up to 65% for the 2022 LTI Plan).
\n
The actual award of the bonus under the Plans is subject
\n
to the achievement of specific performance targets during
\n
the three year performance period. If these targets are
\n
achieved, 30% of both the stock and cash components
\n
of the incentive will be paid in the first year following the
\n
end of the performance period and the remaining 70% will
\n
be paid in the second year following the end of the per-
\n

\n\n
\n
\n
\n

\n
formance period. The payment of a substantial portion
\n
of long-term variable remuneration (70% of the total) is
\n
therefore deferred to the second year following the end of
\n
the performance period of the individual Plans.
\n
The following table provides information on the 2019 LTI
\n
Plan, the 2020 LTI Plan, the 2021 LTI Plan, and the 2022 LTI
\n
Plan.
\n
For more information on the characteristics of the Plans,
\n
please see the information documents prepared pursuant
\n
to Article 84-bis of the CONSOB Regulation issued with
\n
Resolution no. 11971 of May 14, 1999 (the Issuers Regu-
\n
lation), which are available to the public in the section of
\n
Enel\u2019s website (www.enel.com) dedicated to the Sharehold-
\n
ers\u2019 Meetings held respectively on May 16, 2019, May 14,
\n
2020, May 20, 2021 and May 19, 2022.
\n
Grant date Performance period
\n
Verification of
\n
achievement of
\n
targets Payout
\n
2019 LTI Plan 12.11.2019
\n
(47)
\n
2019-2021 2022
\n
(48)
\n
2022-2023
\n
(49)
\n
2020 LTI Plan 17.09.2020
\n
(50)
\n
2020-2022 2023
\n
(51)
\n
2023-2024
\n
2021 LTI Plan 16.09.2021
\n
(52)
\n
2021-2023 2024
\n
(53)
\n
2024-2025
\n
2022 LTI Plan 21.09.2022
\n
(54)
\n
2022-2024 2025
\n
(55)
\n
2025-2026
\n
In implementation of the authorizations granted by the
\n
Shareholders\u2019 Meetings held on May 16, 2019, May 14, 2020,
\n
May 20, 2021 and May 19, 2022, in compliance with the
\n
associated terms and conditions, the Board of Directors
\n
approved \u2013 at is meetings of September 19, 2019, July 29,
\n
2020, June 17, 2021 and June 16, 2022 \u2013 the launch of share
\n
buyback programs to serve the 2019 LTI Plan, the 2020 LTI
\n
Plan, the 2021 LTI Plan and the 2022 LTI Plan, respectively.
\n
The number of Shares whose purchase was authorized by
\n
the Board of Directors for each Plan, the actual number of
\n
Shares purchased, the associated weighted average price
\n
and total value are shown below.
\n
(47) The date on which the Board of Directors approved the procedures and timing for granting the 2019 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of November 11, 2019).
\n
(48) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2021, the Board of Directors verified the level
\n
of achievement of the performance targets of the 2019 LTI Plan.
\n
(49) On September 5, 2022 the Company awarded part of the equity component of the bonus vested by the beneficiaries of the 2019 LTI Plan, in accordance
\n
with the Plan rules.
\n
(50) The date on which the Board of Directors approved the procedures and timing for granting the 2020 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of September 16, 2020).
\n
(51) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2022, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2020 LTI Plan.
\n
(52) The date on which the Board of Directors approved the procedures and timing for granting the 2021 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of June 9, 2021).
\n
(53) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2023, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2021 LTI Plan.
\n
(54) The date on which the Board of Directors approved the procedures and timing for granting the 2022 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of June 8, 2022).
\n
(55) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2024, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2022 LTI Plan.
\n

\n\n
Purchases authorized by the
\n
Board of Directors Actual purchases
\n
Number of shares Number of shares
\n
Weighted average price
\n
(euros per share) Total value (euros)
\n
2019 LTI Plan
\n
No more than 2,500,000
\n
for a maximum amount of
\n
\u20ac10,500,000 million
\n
1,549,152
\n
(56)
\n
6.7779 10,499,999
\n
2020 LTI Plan 1,720,000 1,720,000
\n
(57)
\n
7.4366 12,790,870
\n
2021 LTI Plan 1,620,000 1,620,000
\n
(58)
\n
7.8737 12,755,459
\n
2022 LTI Plan 2,700,000 2,700,000
\n
(59)
\n
5.1951 14,026,715
\n
As a result of the purchases made to support the 2019 LTI
\n
Plan, the 2020 LTI Plan, the 2021 LTI Plan and the 2022 LTI
\n
Plan, and taking into account the award on September 5,
\n
2022 of 435,357 shares to the beneficiaries of the 2019 LTI
\n
Plan, at December 31, 2022 Enel holds a total of 7,153,795
\n
treasury shares, equal to 0.07% of share capital.
\n
The following information concerns the equity instruments
\n
granted in 2019, 2020, 2021 and 2022.
\n
2022 2021
\n
Number of shares
\n
granted at the grant
\n
date
\n
Fair value per
\n
share at the
\n
grant date
\n
Number of
\n
shares potentially
\n
available for
\n
award
\n
Number of shares
\n
awarded
\n
Number of
\n
shares potentially
\n
available for
\n
award
\n
Number of shares
\n
awarded
\n
2019 LTI Plan 1,538,547 6.983 1,021,328 435,357
\n
(60)
\n
1,529,182 -
\n
2020 LTI Plan 1,638,775 7.380 1,631,951 - 1,638,775 -
\n
2021 LTI Plan 1,577,773 7.0010 1,577,773 - 1,577,773 -
\n
2022 LTI Plan 2,398,143 4.8495 2,395,323 - - -
\n
The fair value of those equity instruments is measured on
\n
the basis of the market price of Enel Shares at the grant
\n
date.
\n
(61)
\n
The cost of the equity component is determined on the
\n
basis of the fair value of the equity instruments granted
\n
and is recognized over the duration of the vesting period
\n
through an equity reserve.
\n
The total costs recognized by the Group through profit or
\n
loss amounted to \u20ac11 million in 2022 (\u20ac9 million in 2021).
\n
There have been no terminations or amendments involving
\n
the 2019 LTI Plan, the 2020 LTI Plan, the 2021 LTI Plan, or the
\n
2022 LTI Plan.
\n
(56) Shares purchased in the period between September 23 and December 2, 2019, equal to about 0.015% of share capital.
\n
(57) Shares purchased in the period between September 3 and October 28, 2020, equal to about 0.017% of share capital.
\n
(58) Shares purchased in the period between June 18 and July 21, 2021, equal to about 0.016% of share capital.
\n
(59) Shares purchased in the period between June 17 and July 20, 2022, equal to about 0.026% of share capital.
\n
(60) The table shows the number of shares awarded on September 5, 2022, to the beneficiaries of the 2019 LTI Plan, which make up the equity component of the
\n
bonus vested by the beneficiaries following the achievement of the performance objectives of the Plan. The disbursement of the remaining portion of the equity
\n
component of the bonus is deferred to 2023, in accordance with the terms and procedures of the rules of the 2019 LTI Plan.
\n
(61) For the 2019 LTI Plan, the grant date is November 12, 2019, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2019 LTI Plan to the beneficiaries.
\n
For the 2020 LTI Plan, the grant date is September 17, 2020, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2020 LTI Plan to the beneficiaries.
\n
For the 2021 LTI Plan, the grant date is September 16, 2021, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2021 LTI Plan to the beneficiaries.
\n
For the 2022 LTI Plan, the grant date is September 21, 2022, i.e., the date of the meeting of the Board of Directors that approved the procedures and timing
\n
of the grant under the 2022 LTI Plan to the beneficiaries.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag343": { "value": "\n
54. Related parties
\n
As an operator in the field of generation, distribution,
\n
transport and sale of electricity and the sale of natural gas,
\n
Enel carries out transactions with a number of companies
\n
directly or indirectly controlled by the Italian State, the
\n
Group\u2019s controlling shareholder.
\n
The table below summarizes the main types of transac-
\n
tions carried out with such counterparties.
\n
Related party Relationship Nature of main transactions
\n
Single Buyer
\n
Fully controlled (indirectly) by the Ministry for the
\n
Economy and Finance
\n
Purchase of electricity for the enhanced protection market
\n
Cassa Depositi e
\n
Prestiti Group
\n
Directly controlled by the Ministry for the Economy and
\n
Finance
\n
Sale of electricity on the Ancillary Services Market (Terna)
\n
Sale of electricity transport services (Eni Group)
\n
Purchase of transport, dispatching and metering services (Terna)
\n
Purchase of postal services (Poste Italiane)
\n
Purchase of fuels for generation plants and natural gas storage and
\n
distribution services (Eni Group)
\n
ESO - Energy
\n
Services Operator
\n
Fully controlled (directly) by the Ministry for the
\n
Economy and Finance
\n
Sale of subsidized electricity
\n
Payment of A3 component for renewable resource incentives
\n
EMO - Energy
\n
Markets Operator
\n
Fully controlled (indirectly) by the
\n
Ministry for the Economy and Finance
\n
Sale of electricity on the Power Exchange (EMO)
\n
Purchase of electricity on the Power Exchange for pumping and
\n
plant planning (EMO)
\n
Leonardo Group
\n
Directly controlled by the Ministry for the Economy and
\n
Finance
\n
Purchase of IT services and supply of goods
\n
In addition, the Group conducts essentially commercial
\n
transactions with associated companies or companies in
\n
which it holds non-controlling interests.
\n
Finally, Enel also maintains relationships with the pension
\n
funds FOPEN and FONDENEL, as well as Fondazione Enel
\n
and Enel Cuore, an Enel non-profit company devoted to
\n
providing social and healthcare assistance.
\n
All transactions with related parties were carried out on
\n
normal market terms and conditions, which in some cas-
\n
es are determined by the Regulatory Authority for Energy,
\n
Networks and the Environment.
\n

\n\n
Credit facility guaranteed by SACE - Disclosure
\n
obligations established by Article 13, paragraph
\n
3, letter c) (ii), of CONSOB Regulation on
\n
transactions with related parties
\n
In compliance with the disclosure obligations established
\n
under Article 13, paragraph 3, letter c) (ii), of CONSOB
\n
Regulation no. 17221 of March 12, 2010, as amended (the
\n
\u201cCONSOB Regulation\u201d), and Article 13.4, letter c) (ii), of the
\n
Enel Procedure for Transactions with Related Parties (the
\n
\u201cEnel Procedure\u201d), we hereby disclose that a transaction
\n
with related parties was carried out in 2022 which qualifies
\n
as a transaction of \u201cgreater importance\u201d having an ordinary
\n
nature and completed at market-equivalent or standard
\n
terms. More specifically, on December 23, 2022, Enel SpA
\n
signed with a pool of financial institutions \u2013 composed of
\n
Banco BPM SpA, BPER Banca SpA, Cassa Depositi e Pres-
\n
titi SpA, Intesa Sanpaolo SpA and UniCredit SpA \u2013 a loan
\n
agreement in the form of a revolving credit facility in the
\n
amount of \u20ac12 billion, of which up to 70% of the nominal
\n
amount is guaranteed by SACE SpA.
\n
This credit facility, and the related guarantee, is aimed
\n
at funding the collateral requirements of the Enel Group
\n
companies operating in Italy (specifically Enel Global Trad-
\n
ing SpA) for trading on energy markets and is part of the
\n
temporary measures to support the liquidity of companies,
\n
provided in the form of a guarantee, envisaged by Article
\n
15 of Decree Law 50 of May 17, 2022, ratified with Law 91 of
\n
July 15, 2022 (the so-called \u201cAid Decree Law\u201d), as amended.
\n
The overall transaction qualifies as a transaction with
\n
related parties due to the fact that Enel SpA, Cassa De-
\n
positi e Prestiti SpA and SACE SpA are companies under
\n
the common control of Italy\u2019s Ministry for the Economy
\n
and Finance. Taking into account the amounts indicated
\n
above (and, in particular, in consideration of the value of
\n
the guarantee), it qualifies as a related-party transaction
\n
of \u201cgreater importance\u201d. The transaction in question was
\n
completed applying the exemption pursuant to Article 13,
\n
paragraph 3, letter c), of the CONSOB Regulation and Ar-
\n
ticle 13.4, letter c), of the Enel Procedure, as an ordinary
\n
transaction completed at market-equivalent or standard
\n
terms.
\n
In particular, the transaction is connected with the ordi-
\n
nary exercise of \u201cfinance activity connected to the op-
\n
erations\u201d of the Group headed by Enel SpA, taking into
\n
account, inter alia, the object, recurrence and size of the
\n
same, as well as the nature of the counterparties. Further-
\n
more, the main terms and conditions applicable to it are
\n
governed by Article 15 of the Aid Decree Law. For the por-
\n
tion of the loan for which it is responsible, Cassa Depositi
\n
e Prestiti SpA applied to Enel SpA the same terms and
\n
conditions that are applied by the other banks.
\n
The following tables summarize transactions with relat-
\n
ed parties, associated companies and joint ventures out-
\n
standing at December 31, 2022 and December 31, 2021
\n
and carried out during the period.
\n

\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Income statement
\n
Revenue from sales and services - 7,949 87 4,497 196
\n
Other income - - - 389 -
\n
Other financial income - - - - -
\n
Electricity, gas and fuel purchases 6,379 16,817 2 4,266 3
\n
Costs for services and other materials - 220 2 3,258 73
\n
Other operating costs 10 147 - 420 3
\n
Net results from commodity contracts - - - 50 -
\n
Other financial expense 1 - 2 10 -
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Statement of financial position
\n
Other non-current financial assets - - - - -
\n
Trade receivables - 220 6 1,040 38
\n
Current financial derivative assets - - - - -
\n
Other current financial assets - - - 5 -
\n
Other current assets - - 30 58 2
\n
Long-term borrowings - - - 447 -
\n
Non-current contract liabilities - - - 9 8
\n
Non-current financial derivative liabilities - - - - -
\n
Short-term borrowings - - - - -
\n
Current portion of long-term borrowings - - - 89 -
\n
Trade payables 1,211 305 6 1,097 (1)
\n
Other current financial liabilities - - - - -
\n
Current contract liabilities - - - 23 20
\n
Other current liabilities - - - 3 23
\n
Other information
\n
Guarantees issued - 20 - 11 58
\n
Guarantees received - - - 134 36
\n
Commitments - - - 149 -
\n

\n\n
Total 2022
\n
Associates and joint
\n
ventures
\n
Overall total 2022
\n
Total in financial
\n
statements % of total
\n
12,729 210 12,939 135,653 9.5%
\n
389 - 389 4,864 8.0%
\n
- 154 154 3,430 4.5%
\n
27,467 413 27,880 96,896 28.8%
\n
3,553 247 3,800 20,228 18.8%
\n
580 1 581 4,685 12.4%
\n
50 - 50 2,365 2.1%
\n
13 21 34 5,880 0.6%
\n
Total at Dec. 31, 2022
\n
Associates and joint
\n
ventures
\n
Overall total
\n
at Dec. 31, 2022
\n
Total in financial
\n
statements % of total
\n
- 1,885 1,885 8,359 22.6%
\n
1,304 259 1,563 16,605 9.4%
\n
- 5 514,830 -
\n
5 99 104 13,753 0.8%
\n
90 63 153 4,314 3.5%
\n
447 327 774 68,191 1.1%
\n
17 - 17 5,747 0.3%
\n
- 9 9 5,895 0.2%
\n
- 14 14 18,392 0.1%
\n
89 21 110 2,835 3.9%
\n
2,618 192 2,810 17,641 15.9%
\n
- 1 18530.1%
\n
43 - 43 1,775 2.4%
\n
26 21 47 11,713 0.4%
\n
89 - 89
\n
170 - 170
\n
149 - 149
\n

\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Income statement
\n
Revenue from sales and services - 3,018 275 3,165 210
\n
Other income - - - 5 -
\n
Financial income - - - 15 -
\n
Electricity, gas and fuel purchases 4,613 6,363 - 2,572 -
\n
Costs for services and other materials - 75 3 2,874 57
\n
Other operating costs 6 198 - 13 1
\n
Results from commodity contracts - - - 13 -
\n
Other financial expense - - - 10 -
\n
(1) The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group Other
\n
Statement of financial position
\n
Other non-current financial assets -----
\n
Non-current financial derivative assets -----
\n
Other non-current assets - - - 119 -
\n
Trade receivables - 469 9 659 36
\n
Current financial derivative assets -----
\n
Other current financial assets ----1
\n
Other current assets - - 76 21 2
\n
Long-term borrowings - - - 536 -
\n
Non-current contract liabilities - - - 187 7
\n
Non-current financial derivative liabilities -----
\n
Short-term borrowings -----
\n
Current portion of long-term
\n
borrowings
\n
---89-
\n
Trade payables 1,903 641 1 1,466 12
\n
Current contract liabilities - - - 12 -
\n
Other current liabilities - - - 38 38
\n
Other information
\n
Guarantees issued - 40 - 11 59
\n
Guarantees received - - - 138 36
\n
Commitments - - - 401 -
\n

\n\n
Total 2021
\n
Associates and joint
\n
ventures Overall total 2021
\n
Total in financial
\n
statements
\n
(1)
\n
% of total
\n
6,668 342 7,010 81,900 8.6%
\n
5 1 6 3,819 0.2%
\n
15 123 138 1,862 7.4%
\n
13,548 278 13,826 47,702 29.0%
\n
3,009 143 3,152 19,240 16.4%
\n
218 - 218 1,968 11.1%
\n
13 11 24 2,523 1.0%
\n
10 22 32 6,087 0.5%
\n
Total
\n
at Dec. 31, 2021
\n
Associates and joint
\n
ventures
\n
Overall total
\n
at Dec. 31, 2021
\n
Total in financial
\n
statements % of total
\n
- 1,120 1,120 5,704 19.6%
\n
- 14 14 2,772 0.5%
\n
119 - 119 3,268 3.6%
\n
1,173 148 1,321 16,076 8.2%
\n
- 32 32 22,791 0.1%
\n
1 156 157 8,645 1.8%
\n
99 24 123 5,002 2.5%
\n
536 344 880 54,500 1.6%
\n
194 - 194 6,214 3.1%
\n
- 1 1 3,339 -
\n
- 6 6 13,306 -
\n
89 20 109 4,031 2.7%
\n
4,023 59 4,082 16,959 24.1%
\n
12 - 12 1,433 0.8%
\n
76 4 80 12,959 0.6%
\n
110 - 110
\n
174 - 174
\n
401 - 401
\n

\n\n
With regard to disclosures on the remuneration of direc-
\n
tors, members of the Board of Statutory Auditors and key
\n
management personnel, provided for under IAS 24, please
\n
see the following tables.
\n
Millions of euro
\n
2022 2021 Change
\n
Remuneration of members of the Board of Directors and Board of
\n
Statutory Auditors and the General Manager
\n
Short-term employee benefits 5 5 - -
\n
Other long-term benefits 1 1 - -
\n
Tot al 66--
\n
Millions of euro
\n
2022 2021 Change
\n
Remuneration of key management personnel
\n
Short-term employee benefits 13 13 - -
\n
Other long-term benefits 2 4 (2) -50%
\n
Tot al 15 17 (2) -11.8%
\n
In November 2010, the Board of Directors of Enel SpA ap-
\n
proved a procedure governing the approval and execution
\n
of transactions with related parties carried out by Enel SpA
\n
directly or through subsidiaries (the \u201cEnel Procedure\u201d). The
\n
procedure (available at https://www.enel.com/investors/
\n
bylaws-rules-and-policies/transactions-with-related-par-
\n
ties/) sets out rules designed to ensure the transparency
\n
and procedural and substantive propriety of transactions
\n
with related parties. It was adopted in implementation of
\n
the provisions of Article 2391-bis of the Italian Civil Code
\n
and the implementing regulations issued by CONSOB with
\n
Resolution no. 17221 of March 12, 2010, as amended (the
\n
\u201cCONSOB Regulation\u201d).
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag207": { "value": "\n
55. Government grants - Disclosure pursuant to Article 1,
\n
paragraphs 125-129, of Law 124/2017
\n
Pursuant to Article 1, paragraphs 125-129, of Law 124/2017
\n
as amended, the following provides information on grants
\n
received from Italian public agencies and bodies, as well
\n
as donations by Enel SpA and the fully consolidated sub-
\n
sidiaries to companies, individuals and public and private
\n
entities. The disclosure comprises: (i) grants received from
\n
Italian public entities/State entities; and (ii) donations
\n
made by Enel SpA and Group subsidiaries to public or pri-
\n
vate parties resident or established in Italy.
\n
The following disclosure includes payments in excess of
\n
\u20ac10,000 made by the same grantor/donor during 2022,
\n
even if made in multiple financial transactions. They are
\n
recognized on a cash basis.
\n
Pursuant to the provisions of Article 3-quater of Decree
\n
Law 135 of December 14, 2018, ratified with Law 12 of Feb-
\n
ruary 11, 2019, for grants received, please refer to the in-
\n
formation contained in the National Register of State Aid
\n
referred to in Article 52 of Law 234 of December 24, 2012.
\n
Grants received in millions of euro
\n
Financial
\n
institution/Grantor Beneficiary Amount Notes
\n
Anpal Enel Green Power
\n
Italia Srl
\n
(0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Green Power
\n
Italia Srl
\n
(0.05) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Invitalia MISE Enel Green Power
\n
Italia Srl
\n
(8.44) Return of instalment of grant under first progress statement of Development
\n
Contract 3SUN HJT, following abandonment of original project to expand the Catania
\n
facility
\n
Anpal Enel Green Power
\n
SpA
\n
(0.07) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Green Power
\n
SpA
\n
(0.05) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Thermal
\n
Generation Srl
\n
(0.06) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Thermal
\n
Generation Srl
\n
(0.02) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Grids (0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Grids (0.04) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global Trading
\n
SpA
\n
(0.005) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global Trading
\n
SpA
\n
(0.006) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Produzione
\n
SpA
\n
(0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Produzione
\n
SpA
\n
(0.03) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal e-distribuzione
\n
SpA
\n
(0.17) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n

\n\n
Grants received in millions of euro
\n
Financial
\n
institution/Grantor Beneficiary Amount Notes
\n
Anpal e-distribuzione
\n
SpA
\n
(0.10) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Regione Lazio Enel X Srl 0.07 Instalment of grant as balance for the Homix-Care project, funded under the ROP
\n
ERDF Lazio 2014-2020
\n
Anpal Enel X Srl (0.02) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel X Srl (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Sole Srl - Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Sole Srl (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Regione Sicilia Enel X Mobility Srl 2.03 Instalment of grant for Sicilia Smart Charging project, financed by the Region of Sicily
\n
through National Plan for Electric Vehicle Charging Infrastructure
\n
Anpal Servizio Elettrico
\n
Nazionale SpA
\n
(0.02) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Servizio Elettrico
\n
Nazionale SpA
\n
(0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Energia SpA (0.14) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Energia SpA (0.02) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Services Srl
\n
(0.06) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Global
\n
Services Srl
\n
(0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Italia SpA (0.04) Instalment of grant returned in second instance FNC-C-06952, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
Anpal Enel Italia SpA (0.01) Instalment of grant returned in third instance FNC-C-10223, financed through
\n
the New Skills Fund referred to in Art. 88 of Decree Law of May 19, 2020 and the
\n
ministerial decree of October 9, 2020
\n
(7.413) Total
\n

\n\n
Grants made in millions of euro
\n
Grantor Beneficiary Amount Notes
\n
Enel SpA FGS Onlus 0.05 Donation to promote equal opportunities
\n
Enel SpA European University Institute 0.10 Donation for scientific research on European energy issues
\n
Enel SpA Fondazione Centro Studi Enel 0.10 Enel Foundation grant
\n
Enel SpA Earthrise Trust 0.01 Donation for rural development projects
\n
Enel SpA International Energy Agency 0.08 Donation for the study of the energy market
\n
Enel SpA Comunit\u00e0 Sant\u2019Egidio 0.04 Gadgets donation
\n
Enel SpA Associazione UISP Unione Italiana
\n
Sport per Tutti
\n
0.03 Gadgets donation
\n
Enel SpA Onlus CESIE 0.06 Gadgets donation
\n
Enel SpA Onlus Sport Senza Frontiere 0.02 Gadgets donation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.06 30% 1st tranche - project presentation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.06 30% 2nd tranche - digital content creation
\n
Enel Produzione SpA Associazione Juppiter APS giovanile 0.08 40% last tranche - conclusion
\n
Enel Produzione SpA Fondazione Centro Studi Enel 0.09 Enel Foundation \u2013 balance of 2021 grant
\n
Enel Produzione SpA Fondazione Centro Studi Enel 0.48 Enel Foundation \u2013 1st instalment of 2022 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.13 2nd instalment of Enel Cuore 2021 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.18 1st instalment of Enel Cuore 2022 grant
\n
Enel Produzione SpA Fondazione WWF Italia 0.01 Agreement Enel Produzione
\n
Enel Produzione SpA Associazione Le Colonne 0.03 Donation \u201cAccogliere ad Arte\u201d
\n
Enel Italia SpA Enel Cuore Onlus 0.15 2021 grant
\n
Enel Italia SpA Societ\u00e0 Coop, Greenwill 0.01 Modal donation \u201cAlleva la speranza Greenwill\u201d
\n
Enel Italia SpA Foglietti Enrico 0.01 Modal donation \u201cAlleva la speranza Foglietti Enrico\u201d
\n
Enel Italia SpA Feat Impresa Locale 0.02 1st instalment 2022 donation WE Feat arl
\n
Enel Italia SpA Help Code Italia 0.04 Enel Helpcode project \u201c\u00c8 viva la scuola labs\u201d
\n
Enel Italia SpA Fondazione Accademia Nazionale
\n
\u201cSanta Cecilia\u201d
\n
0.60 Modal donation 2022
\n
Enel Italia SpA Fondazione Teatro alla Scala 0.60 Donation 2022
\n
Enel Italia SpA Fondazione Teatro Maxxi 0.60 Modal donation 2022
\n
Enel Italia SpA Enel Cuore Onlus 0.02 Extraordinary contribution 2022
\n
Enel Italia SpA Fondazione Centro Studi Enel 0.05 Grants 2022
\n
Enel Italia SpA Help Code Italia 0.02 Payment for the start of energy courses
\n
Enel Italia SpA Moige - Movimento italiano genitori
\n
Onlus
\n
0.05 Donation to support the Young Ambassadors Campaign for digital citizenship
\n
to counter cyber risk, bulling and cyberbullying in all its forms - 2nd instalment
\n
and balance
\n
Enel Italia SpA Fondazione Centro Studi Enel 0.11 Balance of 2021 grant
\n
e-distribuzione SpA Enel Cuore Onlus 2.09 80% balance of 2021 grant
\n
e-distribuzione SpA Enel Cuore Onlus 0.47 20% instalment of 2022 grant
\n
e-distribuzione SpA Fondazione Centro Studi Enel 1.41 50% balance of 2021 grant
\n
e-distribuzione SpA Fondazione Centro Studi 1.28 50% instalment of 2022 grant
\n
Enel X Srl Enel Cuore Onlus 0.04 2022 grant
\n
Enel Green Power Italia Unione dei Comuni Montani Amiata
\n
Grossetana (Sarchioto - Borrello -
\n
Simoni Giorgio)
\n
0.04 Donation to the Union of Amiata Grossetana mountain municipalities as part
\n
of sustainability activities linked to the BG3 power station smart repowering
\n
project, for the \u201cNon Solo Neve\u201d and \u201cFondo per la Montagna\u201d projects
\n
developed by the beneficiary. The projects envisage the construction and
\n
redevelopment of a bike-pedestrian path with urban furniture and signage for
\n
the benefit of the area, also affecting municipalities with a geothermal vocation
\n
in an area where Enel Green Power has been operating for a long time
\n
Enel Energia SpA Confimprese 0.01 Association dues 2022 - 029/22
\n
Enel Energia SpA Anigas 0.10 Association dues 2022
\n
Enel Energia SpA Fondazione Centro Studi Enel 1.01 Balance 2021 grant
\n
Enel Energia SpA Enel Cuore Onlus 1.49 Balance 2021 grant
\n
Enel Energia SpA Enel Cuore Onlus 0.20 \u201cNel Cuore dello Spazio Enel\u201d project
\n
Enel Energia SpA Enel Cuore Onlus 0.33 20% instalment of 2022 grant
\n
Enel Energia SpA Fondazione Centro Studi Enel 0.90 50% instalment of 2022 grant
\n
Enel Energia SpA Associazione Milano & Partners 0.05 Association dues 2022
\n
Enel Energia SpA Assonime 0.02 Association dues 2022
\n
Enel Energia SpA Proxigas 0.10 Balance Proxigas
\n
Enel Energia SpA Enel Cuore Onlus 0.04 Association dues
\n
Enel Global Trading SpA Enel Cuore Onlus 0.14 Contribution aimed at supporting and developing projects of Enel Cuore Onlus
\n
Enel Global Trading SpA Fondazione Centro Studi Enel
\n
0.10 Contribution aimed at supporting and developing Research and Higher
\n
Education projects
\n
13.71 Total
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGovernmentGrantsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag60": { "value": "\n

\n\n
56. Contractual commitments and guarantees
\n
The commitments entered into by the Enel Group and the
\n
guarantees given to third parties are shown below.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Guarantees given:
\n
- sureties and other guarantees granted to third parties 4,296 4,937 (641)
\n
Commitments to suppliers for:
\n
- electricity purchases 64,878 71,244 (6,366)
\n
- fuel purchases 96,996 58,042 38,954
\n
- various supplies 2,449 1,631 818
\n
- tenders 6,165 4,668 1,497
\n
- other 6,889 6,187 702
\n
Tot al 177,377 141,772 35,605
\n
TOTAL 181,673 146,709 34,964
\n
Compared with December 31, 2021, the decrease of
\n
\u20ac6,366 million in commitments for \u201celectricity purchases\u201d
\n
is essentially attributable to companies in Latin America,
\n
in particular in Brazil, and mainly reflects the sale of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), partially offset by the
\n
increase in Chile, mainly attributable to new contracts and
\n
developments in commodity prices.
\n
The increase of \u20ac38,954 million in commitments for \u201cfuel
\n
purchases\u201d mainly regards gas supplies, especially in Italy
\n
and Spain, and reflected the increase in demand for natu-
\n
ral gas and in gas prices.
\n
For more details on the expiry of commitments and guar-
\n
antees, please see the section \u201cCommitments to purchase
\n
commodities\u201d in note 49.
\n

\n\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag59": { "value": "\n
56. Contractual commitments and guarantees
\n
The commitments entered into by the Enel Group and the
\n
guarantees given to third parties are shown below.
\n
Millions of euro
\n
at Dec. 31, 2022 at Dec. 31, 2021 Change
\n
Guarantees given:
\n
- sureties and other guarantees granted to third parties 4,296 4,937 (641)
\n
Commitments to suppliers for:
\n
- electricity purchases 64,878 71,244 (6,366)
\n
- fuel purchases 96,996 58,042 38,954
\n
- various supplies 2,449 1,631 818
\n
- tenders 6,165 4,668 1,497
\n
- other 6,889 6,187 702
\n
Tot al 177,377 141,772 35,605
\n
TOTAL 181,673 146,709 34,964
\n
Compared with December 31, 2021, the decrease of
\n
\u20ac6,366 million in commitments for \u201celectricity purchases\u201d
\n
is essentially attributable to companies in Latin America,
\n
in particular in Brazil, and mainly reflects the sale of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s), partially offset by the
\n
increase in Chile, mainly attributable to new contracts and
\n
developments in commodity prices.
\n
The increase of \u20ac38,954 million in commitments for \u201cfuel
\n
purchases\u201d mainly regards gas supplies, especially in Italy
\n
and Spain, and reflected the increase in demand for natu-
\n
ral gas and in gas prices.
\n
For more details on the expiry of commitments and guar-
\n
antees, please see the section \u201cCommitments to purchase
\n
commodities\u201d in note 49.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag24": { "value": "\n
57. Contingent assets and liabilities
\n
The following reports the main contingent assets and lia-
\n
bilities at December 31, 2022, which are not recognized in
\n
the consolidated financial statements as they do not meet
\n
the requirements provided for in IAS 37.
\n
Brindisi Sud thermal generation plant - Ash
\n
dispute - Italy
\n
With regard to the criminal investigation initiated by the
\n
Public Prosecutor\u2019s Office of the Court of Lecce in 2017
\n
concerning the use of fly ash in the cement industry, the
\n
Brindisi Sud power plant was involved in a criminal inves-
\n
tigation involving accused individuals and Enel Produzione
\n
(EP) pursuant to Legislative Decree 231 of June 8, 2001,
\n
that resulted in the issue of a preventive seizure order that
\n
allowed operation of the plant as well as the seizure of EP
\n
assets and receivables up to an amount of about \u20ac500
\n
million. The seizures were subsequently revoked follow-
\n
ing the positive outcome of testing by the independent
\n
experts appointed by the investigating magistrate, which
\n
confirmed the non-hazardous nature of the ash, finding it
\n
suitable for use in the cement-making process, as well as
\n
the appropriateness of the operation of the plant. Subse-
\n
quently, a pre-trial hearing was conducted in 2021, follow-
\n
ing which the pre-trial hearing judge granted petitions to
\n
participate in the trial as civil plaintiff filed by the City of
\n
Brindisi, which quantified damages at about \u20ac27 million,
\n
requesting a provisional award of \u20ac8 million, and by the Re-
\n
gion of Puglia, which has not yet quantified the damages
\n
requested. The pre-trial hearing judge remanded all of the
\n
defendants before the Court of Brindisi. At the hearing of
\n
May 26, 2022, the court, in upholding the objection raised
\n
by EP that the preliminary hearing of October 22, 2021,
\n
held without the necessary presence of the parties, should
\n
be declared void, declared the hearing and the instrument
\n
ordering committal for trial void and submitted the trial
\n
documentation to the Court of Lecce for a new preliminary
\n
hearing. At the following hearing of October 7, 2022, which
\n
was held as summary judgement at the request of the
\n
defendant, the court issued its ruling acquitting all of the
\n
defendants of the charges because \u201cthe alleged offense
\n
did not occur\u201d. The ruling also acquitted EP as the admin-
\n
istrative offense alleged under the provisions of Legislative
\n
Decree 231/2001 had not occurred as there were no pred-
\n
icate offenses, in conformity with the position of the Public
\n
Prosecutor and the defense.
\n
Enel, Enel Energia and Servizio Elettrico
\n
Nazionale antitrust proceeding - Italy
\n
On May 11, 2017, the Competition Authority announced the
\n
beginning of proceedings for alleged abuse of a dominant
\n
position against Enel SpA (Enel), Enel Energia SpA (EE) and
\n
Servizio Elettrico Nazionale SpA (SEN). The proceeding was
\n
initiated on the basis of complaints filed by the Italian As-
\n
sociation of Energy Wholesalers and Traders (AIGET) and
\n
the company Green Network SpA (GN), as well as a number
\n
of complaints from individual consumers.
\n
On December 20, 2018 the Competition Authority issued
\n
its final ruling, with which it levied a fine of about \u20ac93 mil-
\n
lion on all three Group companies, for violation of Article
\n
102 of the Treaty on the Functioning of the European
\n
Union (TFEU).
\n
The main disputed conduct consisted in abuse of a domi-
\n
nant position by the three companies (to the benefit in par-
\n
ticular of EE) who allegedly used the privacy consent given
\n
by SEN consumers, to the detriment of competing traders.
\n
With regard to other allegations made with the measure to
\n
initiate the proceeding, concerning the organization and
\n
performance of sales activities at physical locations (Enel
\n
Points and Enel Point Partner Shops) and winback policies
\n
reported by GN, the Competition Authority reached the
\n
conclusion that the preliminary findings did not provide
\n
sufficient evidence of any abusive conduct on the part of
\n
Enel Group companies.
\n
The companies involved challenged the measures of the
\n
Competition Authority before the Lazio Regional Admin-
\n
istrative Court, which with a decision filed on October
\n
17, 2019 partially upheld the appeals filed by SEN and EE,
\n
shortening the period of abuse and requiring the Compe-
\n
tition Authority to recalculate the penalty in accordance
\n
with the criteria specified in the ruling. With a measure
\n
dated November 27, 2019, the Competition Authority set
\n
the recalculated penalty at \u20ac27,529,786.46.
\n
The rulings of the Regional Administrative Court were chal-
\n
lenged on appeal before the Council of State. With an or-
\n
der of July 20, 2020, the Council of State suspended the
\n
ruling and ordered that the issue be submitted for a pre-
\n
liminary ruling before the Court of Justice of the European
\n
Union (CJEU) pursuant to Article 267 of the TFEU, formulat-
\n
ing a number of questions aimed at clarifying the interpre-
\n
tation of the concept of \u201cabuse of a dominant position\u201d to
\n
be applied to the present case.
\n
With a ruling of May 12, 2022, the CJEU provided the re-
\n
quested interpretation and, subsequently, on December 1,
\n
2022, the Council of State, in application of the guidelines
\n
set out by the CJEU, fully voided the fine levied by the Com-
\n
petition Authority and, upholding the arguments present-
\n
ed by the companies, denied that any abuse of position
\n
had occurred.
\n
Hydroelectric concessions - Italy
\n
Italian regulations governing large-scale hydroelectric
\n
concessions were most recently modified by the \u201cSimplifi-
\n
cations Decree\u201d (Decree Law 135 of 2018 ratified with Law
\n
12 of February 11, 2019), which introduced a series of inno-
\n
vations regarding the granting of such concessions upon
\n
their expiry and the valorization of the assets and works
\n

\n\n
connected to them to be transferred to the new conces-
\n
sion holder. This legislation also introduced a number of
\n
changes in the matter of concession fees, establishing a
\n
fixed and variable component of fees, as well as an obli-
\n
gation to provide free power to public bodies (220 kWh
\n
of power for each kW of average nominal capacity of the
\n
facilities covered by the concession). In implementation
\n
of this national law and under specific enabling authori-
\n
ty, various regions (Lombardy, Piedmont, Emilia-Romagna,
\n
Friuli-Venezia Giulia, the Province of Trento, Calabria and
\n
Basilicata) enacted regional laws.
\n
In particular, the regions of Lombardy, Piedmont and Emil-
\n
ia-Romagna, in application of these new regulations, re-
\n
quested payment from Enel Green Power Italia and Enel
\n
Produzione of the dual-component fee and the monetiza-
\n
tion of the free power.
\n
Enel Green Power Italia and Enel Produzione challenged
\n
the first implementing acts issued under the individual re-
\n
gional laws and the subsequent payment notices of fees
\n
and the monetization of free electricity supplies before
\n
the Regional Administrative Court and Regional Water
\n
Resources Court (of Lombardy, Piedmont and Emilia-Ro-
\n
magna), asking that they be declared void and raising the
\n
question of constitutional illegitimacy of both the nation-
\n
al law and the regional laws. The Regional Administrative
\n
Court and then the Council of State, at the appeal stage,
\n
deferred their jurisdiction in favor of the Superior Public
\n
Water Resources Court, before which Enel Green Power
\n
Italia and Enel Produzione resumed the disputes, which are
\n
now at the preliminary stage.
\n
The companies initiated the proceedings by complaining
\n
that the regional implementing acts \u2013 as well as the re-
\n
gional legislation which they implement \u2013 were constitu-
\n
tionally illegitimate, first for violation of national legislation
\n
and various primary principles protected both by the Ital-
\n
ian Constitution and European law concerning legitimate
\n
expectations, property rights, reasonableness, private ini-
\n
tiative, and concessions, where:
\n
\u2022 they provide for retroactive application to valid large di-
\n
version concessions of the dual-component fee and the
\n
obligation to supply free power or its financial equiva-
\n
lent;
\n
\u2022 they order the monetization of the obligation to supply
\n
free energy, which is not envisaged in the national law.
\n
Furthermore, the introduction by the regions of these new
\n
obligations to pay the new dual-component fee (divided
\n
into a fixed component and a variable component) and
\n
to supply a certain annual quantity of electricity free of
\n
charge in the form of payment of the associated monetary
\n
value, which is also to be paid by the holders of valid con-
\n
cessions that have not yet expired, creates an unexpected
\n
and unreasonable financial imbalance in the concession
\n
relationships. This circumstance is in evident contrast with
\n
the principles of reasonableness, proportionality and le-
\n
gitimate expectation of concession fees, compliance with
\n
which is required by constitutional case law if, in the con-
\n
text of long-term relationships, pejorative modifications
\n
are introduced.
\n
Both the national law and the regional implementing leg-
\n
islation violate Community principles and constitutional
\n
principles such as property rights, the principle of legal
\n
certainty, and the freedom of enterprise. In particular, the
\n
rules do not expressly provide for the transfer of the busi-
\n
ness unit from the outgoing to the successor concession
\n
holder, and also establish inadequate criteria for the valo-
\n
rization of the works to be transferred, which threatens to
\n
create what is essentially a mechanism for expropriation, in
\n
violation of constitutional principles.
\n
Finally, the Council of Ministers had challenged a number
\n
of the regional implementing laws before the Constitu-
\n
tional Court, claiming the violation of various constitution-
\n
al principles. Enel Green Power Italia participated in the
\n
aforementioned proceedings (together with a number of
\n
trade associations and other sector operators) concerning
\n
constitutional legitimacy undertaken by the government
\n
against the Province of Trento and the Regions of Lom-
\n
bardy, Piedmont and Basilicata. The Council of Ministers
\n
subsequently withdrew the appeals as the complaints of
\n
illegitimacy they brought were resolved by subsequent
\n
regional laws. The Constitutional Court therefore extin-
\n
guished the proceedings, with the consequent cancel-
\n
lation of the related interventions by Enel Green Power
\n
Italia, despite the fact that the latter concerned different
\n
constitutionality issues than those raised by the Council of
\n
Ministers.
\n
Antitrust proceeding 12461 EE \u2013 Contract
\n
renewals
\n
On December 13, 2022, the Competition Authority notified
\n
Enel Energia SpA (\u201cCompany\u201d or \u201cEE\u201d) and six other com-
\n
panies (Hera, A2A, Acea, Eni Plenitude, Engie, Edison) that
\n
it had initiated a proceeding for unfair commercial prac-
\n
tices, contesting the violation of certain provisions of the
\n
Consumer Code and Article 3 of Decree Law 115 of August
\n
9, 2022 (the so-called \u201csecond Aid Decree\u201d) of August 10,
\n
2022, ratified with Law 142 of September 21, 2022. Simi-
\n
lar proceedings had previously been initiated against four
\n
other operators (Iren, Iberdrola, E.ON and Dolomiti).
\n
In particular, the Competition Authority, acting on the basis
\n
of reports received and without any preliminary investiga-
\n
tion, argued that EE had sent its customers, in the period
\n
from May to October 2022, notices of price changes that
\n
were allegedly generic and omissive to the extent that they
\n
did not specify the expiry date of the financial conditions
\n
subject to renewal and represented a unwarranted exer-
\n
cise of ius variandi in modification of the financial condi-
\n
tions of the supply relationship, in violation of the afore-
\n
mentioned Article 3 of the second Aid Decree.
\n
With the measure initiating the procedure, the Competi-
\n
tion Authority simultaneously prohibited on a precaution-
\n

\n\n
ary basis the sending of new price change notices and or-
\n
dered the correction of those already sent.
\n
All the operators subject to the order, including EE, chal-
\n
lenged the provision, which was based on the assumption
\n
that any price change had been prohibited to suppliers in
\n
the period indicated by the second Aid Decree (August 10
\n
- April 30).
\n
With an order of December 22, 2022, issued as part of
\n
the appeal filed by Iren, the Council of State distinguished
\n
contractual renewals (of expiring offers) from those cov-
\n
ered by ius variandi and excluded the applicability of Article
\n
3 of the decree law. This principle was also recognized by
\n
the Government, which, with the Milleproroghe Decree of
\n
December 29, 2022, established that Article 3 of the sec-
\n
ond Aid Decree shall not apply to the contractual clauses
\n
that allow an electricity and natural gas supply company
\n
to update the contractual financial conditions upon expiry
\n
of the same, in compliance with the contractual terms of
\n
notice and without prejudice to the right of withdrawal of
\n
the counterparty. The Milleproroghe Decree also extended
\n
the duration of the prohibition to June 30, 2023.
\n
Following the pronouncement of the Council of State and
\n
the aforementioned clarifying legislative intervention, the
\n
Competition Authority, with a new precautionary mea-
\n
sure of December 30, 2022, ordered the partial upholding
\n
of the original precautionary measure and confirmed the
\n
prohibition on changes or renewals of the financial con-
\n
ditions of expiring contracts for which the expiry date was
\n
not specifically identified or in any case predeterminable in
\n
the associated notice sent to the customer.
\n
EE filed an appeal for additional reasons, whose hearing,
\n
together with all the various appeals lodged by other oper-
\n
ators, took place on February 22, 2023 and the publication
\n
of the ruling is pending.
\n
BEG litigation - Italy, France, Luxembourg
\n
Following an arbitration proceeding initiated by BEG SpA
\n
(BEG) in Italy, Enelpower SpA (Enelpower) obtained a rul-
\n
ing in its favor in 2002, which was upheld by the Court of
\n
Cassation in 2010, which entirely rejected the petition for
\n
damages with regard to alleged breach by Enelpower of
\n
an agreement concerning the assessment of the possible
\n
construction of a hydroelectric power station in Albania.
\n
Subsequently, BEG, acting through its subsidiary Albania
\n
BEG Ambient Shpk (ABA), filed suit against Enelpower and
\n
Enel SpA (Enel) in Albania concerning the matter, obtain-
\n
ing a ruling from the District Court of Tirana on March 24,
\n
2009, upheld by the Albanian Court of Cassation, ordering
\n
Enelpower and Enel to pay tortious damages of about \u20ac25
\n
million for 2004 as well as an unspecified amount of tor-
\n
tious damages for subsequent years. Following the ruling,
\n
Albania BEG Ambient demanded payment of more than
\n
\u20ac430 million.
\n
On November 5, 2016, Enel and Enelpower filed a petition
\n
with the Albanian Court of Cassation, asking for the ruling
\n
issued by the District Court of Tirana on March 24, 2009 to
\n
be voided. The proceeding is still pending.
\n
With a ruling of the Court of Appeal of Rome of March
\n
7, 2022, the further proceedings undertaken by Enel and
\n
Enelpower before the Court of Rome were concluded,
\n
having sought recognition of BEG\u2019s liability for having cir-
\n
cumvented the arbitration award rendered in Italy in favor
\n
of Enelpower through the aforementioned initiatives un-
\n
dertaken by the subsidiary ABA. With the ruling, the Court
\n
of Appeal of Rome upheld the ruling of first instance ren-
\n
dered by the Court of Rome on June 16, 2015, which had
\n
denied the petition in the proceeding.
\n
On May 20, 2021, the European Court of Human Rights
\n
(ECHR) issued a ruling with which it decided the appeal
\n
brought by BEG against the Italian State for violation of
\n
Article 6.1 of the European Convention on Human Rights.
\n
With this decision, the Court denied BEG\u2019s request to re-
\n
open the above arbitration proceedings, and also rejected
\n
BEG\u2019s claim for pecuniary damages amounting to about
\n
\u20ac1.2 billion due to the absence of a causal link with the
\n
disputed conduct, granting it only \u20ac15,000.00 in non-pe-
\n
cuniary damages.
\n
Nonetheless, on December 29, 2021, BEG, with an action
\n
that the company and its legal counsel deemed unfound-
\n
ed and specious, also decided to sue the Italian State be-
\n
fore the Court of Milan, to demand, as a consequence of
\n
the ECHR ruling, damages for tortious liability in an amount
\n
of about \u20ac1.8 billion. In this case, BEG also involved Enel
\n
and Enelpower by way of a claim of joint and several liabili-
\n
ty. With an order of June 14, 2022, the Court of Milan, in ac-
\n
cepting the objection of territorial incompetence raised by
\n
the State Attorney, declared its incompetence to hear the
\n
dispute in favor of the Court of Rome, the court exclusively
\n
competent to hear the causes in which the Italian State is
\n
involved, ordering BEG to pay the costs of the proceed-
\n
ings in favor of the defendants. BEG did not resume the
\n
judgment before the Court of Rome within the legal term
\n
of 14 October 2022 and therefore the proceeding was ex-
\n
tinguished.
\n
A short time later, on November 3, 2022, BEG resubmitted
\n
the same claims for damages of the terminated proceed-
\n
ing, serving a new writ of summons before the Court of Mi-
\n
lan against the same defendants, with the exception of the
\n
Italian State, which BEG declared not to wishing to agree to
\n
this judgement. The first appearance hearing is set for May
\n
9, 2023. The company is preparing its defenses to proceed
\n
with the appearance in court in order to contest the claim,
\n
which is considered entirely specious and unfounded, like
\n
the previous similar initiative.
\n

\n\n
Proceedings undertaken by Albania BEG
\n
Ambient Shpk (ABA) to obtain enforcement
\n
of the ruling of the District Court of Tirana of
\n
March 24, 2009
\n
France
\n
In February 2012, ABA filed suit against Enel and Enelpow-
\n
er with the Tribunal de Grande Instance in Paris in order
\n
to render the ruling of the Albanian court enforceable in
\n
France. Enel SpA and Enelpower SpA challenged the suit.
\n
Following the beginning of the case before the Tribunal de
\n
Grande Instance, between 2012 and 2013 Enel France was
\n
served with a number of \u201cSaisie Conservatoire de Cr\u00e9anc-
\n
es\u201d (orders for the precautionary attachment of receiv-
\n
ables) in favor of ABA to conserve any receivables of Enel
\n
in respect of Enel France.
\n
On January 29, 2018, the Tribunal de Grande Instance is-
\n
sued a ruling in favor of Enel and Enelpower, denying ABA
\n
the recognition and enforcement of the Tirana court\u2019s rul-
\n
ing in France for lack of the requirements under French
\n
law for the purposes of granting exequatur. Among other
\n
issues, the Tribunal de Grande Instance ruled that: (i) the
\n
Albanian ruling conflicted with an existing decision (the
\n
arbitration ruling of 2002) and that (ii) the fact that BEG
\n
sought to obtain in Albania what it was not able to obtain in
\n
the Italian arbitration proceeding, resubmitting the same
\n
claim through ABA, represented fraud.
\n
Subsequently, with a ruling of May 4, 2021, the Paris Court
\n
of Appeal denied the appeal by ABA in full, fully upholding
\n
the non-compatibility of the Albanian ruling with the ar-
\n
bitration award of 2002 determined by the TGI, ordering
\n
it to reimburse Enel and Enelpower \u20ac200,000.00 each for
\n
legal costs.
\n
On June 21, 2021, ABA filed an appeal with the Cour de
\n
Cassation against the ruling of the Paris Court of Appeal.
\n
Enel and Enelpower have appeared in court and the hear-
\n
ing for the final discussion of the case is set for March 28,
\n
2023.
\n
Enel initiated a separate proceeding to obtain release of
\n
the precautionary attachments granted to ABA and which
\n
are no longer valid as a result of the appeal ruling. With
\n
an order of June 16, 2022, the Court of Paris ordered the
\n
release of the precautionary attachments while also order-
\n
ing ABA to pay Enel a total of about \u20ac146,000 in damages
\n
and legal costs. ABA challenged the aforementioned re-
\n
lease order, requesting its suspension as a precautionary
\n
measure. The request for precautionary suspension was
\n
rejected on November 23, 2022 and the appeal continues
\n
in the trial court. At the same time, Enel is taking the nec-
\n
essary actions for credit recovery.
\n
The Netherlands
\n
At the end of July 2014, ABA filed suit with the Court of Am-
\n
sterdam to render the ruling of the Albanian court enforce-
\n
able in the Netherlands.
\n
Following an initial ruling of June 29, 2016, in favor of ABA,
\n
in a ruling of July 17, 2018, the Amsterdam Court of Appeal
\n
upheld the appeal advanced by Enel and Enelpower, rul-
\n
ing that the Albanian judgment cannot be recognized and
\n
enforced in the Netherlands, as it was arbitrary and mani-
\n
festly unreasonable and therefore contrary to Dutch public
\n
order. Subsequently, the proceeding before the Court of
\n
Appeal continued with regard to the subordinate question
\n
raised by ABA with which it asked the Dutch court to rule
\n
on the merits of the dispute in Albania and in particular
\n
the alleged tortious liability of Enel and Enelpower in the
\n
failure to build the power plant in Albania. On December 3,
\n
2019, the Amsterdam Court of Appeal issued a definitive
\n
ruling in which it fully quashed the trial court judgment of
\n
June 29, 2016, rejecting any claim made by ABA, thereby
\n
confirming the denial of recognition and enforcement of
\n
the Albanian ruling in the Netherlands. The Court came to
\n
this conclusion after affirming its jurisdiction over ABA\u2019s
\n
subordinate claim and re-analyzing the merits of the case
\n
under Albanian law, finding no tortious liability on the part
\n
of Enel and Enelpower. As a result of the decision of the
\n
Court of Appeal, Enel and Enelpower are therefore not li-
\n
able to pay any amount to ABA, which was in fact ordered
\n
by the Court of Appeal to reimburse the companies for the
\n
losses incurred in illegitimate conservative seizures, to be
\n
quantified as part of a specific procedure, and the costs of
\n
the trial and appeal proceedings.
\n
On July 16, 2021 the Supreme Court completely rejected
\n
ABA\u2019s appeal of the rulings of the Court of Appeal, ordering
\n
it to reimburse court costs. The decision of the Court of
\n
Appeal has thus become final.
\n
Luxembourg
\n
In Luxembourg, again at the initiative of ABA, J.P. Morgan
\n
Bank Luxembourg SA was also served with an order for
\n
a number of precautionary seizures of any receivables of
\n
both Enel Group companies in respect of the bank.
\n
In parallel ABA filed a claim to obtain enforcement of the
\n
ruling of the Court of Tirana in Luxembourg. Owing to a
\n
number of procedural delays, the proceeding is still in the
\n
initial stages and no ruling has been issued.
\n
United States and Ireland
\n
In 2014, ABA had initiated two proceedings requesting ex-
\n
ecution of the Albanian sentence before the courts of the
\n
State of New York and Ireland, which both ruled in favor of
\n
Enel and Enelpower, respectively, on February 23 and Feb-
\n
ruary 26, 2018. Accordingly, there are no lawsuits pending
\n
in Ireland or New York State.
\n
Environmental incentives - Spain
\n
With the Decision of November 27, 2017 on the issue of
\n
environmental incentives for thermal power plants (the
\n
\u201cDecision\u201d), the European Commission reached the prelim-
\n
inary conclusion that the environmental incentive for coal
\n

\n\n
power plants provided for in Spain\u2019s Order ITC/3860/2007
\n
represents State aid pursuant to Article 107, paragraph 1,
\n
of the Treaty on the Functioning of the European Union
\n
(TFEU), expressing doubts about the compatibility of the
\n
incentive with the internal market while recognizing that
\n
the incentives are in line with the European Union\u2019s envi-
\n
ronmental policy. On March 2, 2018, the Commission\u2019s Di-
\n
rectorate-General for Competition has initiated a formal
\n
enquiry pursuant to Article 108, paragraph 2, of the TFEU,
\n
in order to establish whether the incentive in question con-
\n
stituted state aid compatible with the internal market. The
\n
formal enquiry pursuant to Article 108 of the TFUE is still
\n
open. On April 13, 2018, Endesa Generaci\u00f3n SA, acting as
\n
an interested third party, submitted comments contesting
\n
this interpretation. Subsequently, on September 8, 2021,
\n
the appeal of the decision lodged by Gas Natural (now
\n
Naturgy) with the General Court of the European Union
\n
was denied. The ruling was appealed by Naturgy and EDP
\n
Espa\u00f1a before the Court of Justice of the European Union
\n
(CJEU). Endesa Generaci\u00f3n has filed a request to partici-
\n
pate in the proceeding and, with an order of June 1, 2022,
\n
the CJUE allowed that participation. Endesa Generaci\u00f3n
\n
then filed its briefs in the proceedings initiated by Naturgy
\n
and EDP Espa\u00f1a on July 8 and 13, 2022, respectively.
\n
Social Bonus - Spain
\n
In relation to the various financing schemes for the Social
\n
Bonus adopted by the Spanish Government \u2013 in relation to
\n
which on December 21, 2021, the Tribunal Supremo had
\n
declared inapplicable the scheme envisaged in Article 45,
\n
paragraph 4 of Spain\u2019s Electricity Industry Law no. 24 of De-
\n
cember 26, 2013 (LSE) for incompatibility with Article 3.2 of
\n
Directive 2009/72/EC of the European Parliament, in line
\n
with the decision issued in this regard by the Court of Justice
\n
of the European Union (CJEU) on October 14, 2021 \u2013 with
\n
ruling no. 212/2022 of February 21, 2022 the Tribunal Su-
\n
premo also ruled on the appeals filed by Endesa SA, Endesa
\n
Energ\u00eda SAU and Energ\u00eda XXI Comercializadora de Referen-
\n
cia SLU (Endesa) and other companies in the energy sector
\n
against the third scheme for financing the Social Bonus, and
\n
for co-financing with government authorities of the supply
\n
to vulnerable consumers, envisaged under Article 45, para-
\n
graph 4 of LSE, Royal Decree Law 7/2016 of December 23
\n
and Royal Decree 897/2017 of October 6.
\n
With the ruling, the Tribunal Supremo, partially allowing the
\n
appeals, found that (i) the aforesaid regime was inapplicable;
\n
(ii) Articles 12 to 17 of Royal Decree 897/2017 of 6 October
\n
are inapplicable and void, and (iii) the appellants were en-
\n
titled to be compensated for the amounts paid to finance
\n
the Social Bonus and provide co-financing with government
\n
authorities, and to reimbursement of all costs incurred to
\n
fulfill the obligations set out in this mechanism, deducting
\n
any amounts transferred to customers, where applicable.
\n
In the absence of voluntary compliance by the authorities,
\n
on November 10, 2022 the companies filed a petition for
\n
enforcement of the ruling, requesting payment of the re-
\n
lated amounts; the proceeding is currently pending.
\n
\u201cEndesa I and II\u201d industrial relations
\n
dispute - Spain
\n
With effect from January 1, 2019, Endesa notified the work-
\n
ers and their union representatives that the 4th Collective
\n
Bargaining Agreement must be considered terminated
\n
under the terms of the \u201cframework guarantee contract\u201d
\n
and the \u201cagreement on the voluntary suspension or reso-
\n
lution of employment contracts in the period 2013-2018\u201d,
\n
applying from that date the provisions of general labor law,
\n
as well as the applicable legal criteria established in the
\n
matter. Yet, the interpretative differences between Endesa
\n
and the trade union representatives regarding the effects
\n
of the resolution of the 4th Collective Bargaining Agree-
\n
ment with regard, in particular, to the social benefits grant-
\n
ed to retired personnel, led to the initiation of a suit by the
\n
unions represented in the company. On March 26, 2019,
\n
the court of first instance issued a ruling in favor of Endesa,
\n
but the unions appealed against this decision before the
\n
Tribunal Supremo.
\n
On July 7, 2021, the Tribunal Supremo issued a definitive
\n
ruling denying the appeals lodged by the aforementioned
\n
unions against the ruling of the court of first instance, af-
\n
firming that social benefits (including those relating to
\n
electricity prices) originate exclusively in the collective bar-
\n
gaining agreements, both for employees currently in ser-
\n
vice and those who have retired, as well as for their family
\n
members, with the consequence that the termination of
\n
such agreements (as happened in the case of the 4th Col-
\n
lective Bargaining Agreement) produces the general con-
\n
tractual regulation of the conditions established therein
\n
for employees currently in service and. for those who have
\n
retired and their family members, the definitive extinction
\n
of all their rights, until new regulations (which came with
\n
the 5th Endesa Collective Bargaining Agreement).
\n
In parallel, numerous individual suits have been filed by staff
\n
and former employees who had agreed to participate in
\n
termination incentive agreements in order to obtain judi-
\n
cial confirmation that the termination of the 4th Endesa
\n
Collective Bargaining Agreement did not affect them. The
\n
majority of these proceedings, initially suspended pending
\n
the definition of the collective action pending before the
\n
Tribunal Supremo, were rolled together to incorporate the
\n
outcome of the ruling of the latter, that, regarding a \u201ccollec-
\n
tive dispute\u201d, would have the value of res judicata in respect
\n
of individual proceedings concerning the same issue.
\n
Meanwhile, on January 21, 2020, the arbitration award was
\n
issued on the arbitration submitted before the Servicio In-
\n
terconfederal de Mediaci\u00f3n y Arbitraje (SIMA) with a view
\n
to resolving the main issues concerning the 5th Endesa
\n
Collective Bargaining Agreement with the company. The
\n
award amended certain parts of the 5th Endesa Collective
\n
Bargaining Agreement, which was subsequently signed
\n

\n\n
by the social partners and entered force on January 23,
\n
2020. On the same date, Endesa also signed two further
\n
collective bargaining agreements (a \u201cframework guaran-
\n
tee contract\u201d and an \u201cagreement on voluntary measures to
\n
suspend or terminate employment contracts\u201d) with all the
\n
unions present in the company. On June 17, 2020, the 5th
\n
Endesa Collective Bargaining Agreement was published in
\n
the Spanish Official Journal (Bolet\u00edn Oficial del Estado), tak-
\n
ing full effect.
\n
On December 30, 2020, the Audiencia Nacional notified
\n
Endesa a new petition for a \u201ccollective dispute\u201d initiated by
\n
three trade unions with minority representation filed on De-
\n
cember 1, 2020, concerning the cancellation of some \u201cde-
\n
rogatory provisions\u201d of the 5th Endesa Collective Bargain-
\n
ing Agreement. The plaintiffs claim that the contested \u201cde-
\n
rogatory provisions\u201d would imply the illegitimate abolition
\n
of social benefits and economic rights of workers. Endesa
\n
considers these provisions to be fully legitimate, in line with
\n
the arguments made during proceeding concerning the re-
\n
duction of social benefits for retired personnel. With a ruling
\n
of November 15, 2021, the petitions of the plaintiff unions
\n
were rejected, with verification of the legitimacy of the 5th
\n
Endesa Collective Bargaining Agreement. The ruling was
\n
appealed by the trade unions before the Tribunal Supremo
\n
and the proceeding is currently under way.
\n
GNL Endesa Generaci\u00f3n SA arbitration
\n
proceeding - Spain
\n
In the course of an arbitration proceeding to review the
\n
price of a long-term supply contract for liquefied natural
\n
gas (LNG) initiated by Endesa Generaci\u00f3n SA, the defen-
\n
dant, an LNG production company, filed a counterclaim
\n
demanding payment of some $1 billion. The amount of the
\n
claim could be revised by the plaintiff depending on mar-
\n
ket developments in months up to the completion of arbi-
\n
tration proceeding, which is scheduled for the 2nd Quarter
\n
of 2023. The company believes that this counterclaim is
\n
unfounded and late and external legal counsel believes it is
\n
highly unlikely to be upheld.
\n
Furnas-Tractebel litigation - Brazil
\n
In 1998 the Brazilian company CIEN (now Enel CIEN) signed
\n
an agreement with Tractebel for the delivery of electricity
\n
from Argentina through its Argentina-Brazil interconnec-
\n
tion line. As a result of Argentine regulatory changes intro-
\n
duced as a consequence of the economic crisis in 2002,
\n
Enel CIEN was unable to make the electricity available to
\n
Tractebel.
\n
In October 2009, Tractebel sued Enel CIEN, which submit-
\n
ted its defense. Enel CIEN cited force majeure as a result
\n
of the Argentine crisis as the main argument in its de-
\n
fense. Out of court, Tractebel has indicated that it plans
\n
to acquire 30% of the interconnection line involved in the
\n
dispute. With a ruling of February 16, 2023, the court of
\n
first instance denied the grounds of the claim submitted
\n
by Tractebel against Enel CIEN. The time limit for appealing
\n
that ruling is currently pending. The amount involved in the
\n
dispute is estimated at about R$658 million (about \u20ac117
\n
million), plus damages to be quantified.
\n
For analogous reasons, in May 2010 Furnas had also filed
\n
suit against Enel CIEN for failure to deliver electricity, re-
\n
questing payment of about R$571.6 million (about \u20ac91
\n
million), in addition to unspecified damages, seeking to
\n
acquire ownership (in this case 70%) of the interconnec-
\n
tion line. The proceeding was decided in Enel CIEN\u2019s favor
\n
with a ruling of the Tribunal de Justi\u00e7a with a definitive
\n
ruling of October 18, 2019, which denied all of the claims
\n
of Furnas.
\n
Cibran litigation - Brazil
\n
Companhia Brasileira de Antibi\u00f3ticos (Cibran) has filed
\n
six suits against the Enel Group company Ampla Energia
\n
e Servi\u00e7os SA (today Enel Distribui\u00e7\u00e3o Rio de Janeiro) to
\n
obtain damages for alleged losses incurred as a result of
\n
the interruption of electricity service by the Brazilian dis-
\n
tribution company between 1987 and 2002, in addition
\n
to non-pecuniary damages. The Court ordered a unified
\n
technical appraisal for those cases, the findings of which
\n
were partly unfavorable to Enel Distribui\u00e7\u00e3o Rio de Janeiro.
\n
The latter challenged the findings, asking for a new study,
\n
which led to the denial of part of Cibran\u2019s petitions. Cibran
\n
subsequently challenged the findings of the new study, but
\n
without success.
\n
The first suit, filed in 1999 and regarding the years from
\n
1995 to 1999, was adjudicated with a ruling of the court of
\n
first instance against Enel Distribui\u00e7\u00e3o Rio de Janeiro. Enel
\n
Distribui\u00e7\u00e3o Rio de Janeiro appealed the ruling and the ap-
\n
peal was upheld by the Tribunal de Justi\u00e7a, which denied all
\n
of Cibran\u2019s claims. The ruling became definitive on August
\n
24, 2020.
\n
With regard to the second case, filed in 2006 and regarding
\n
the years from 1987 to 1994, on June 1, 2015, the courts is-
\n
sued a ruling ordering Enel Distribui\u00e7\u00e3o Rio de Janeiro to pay
\n
R$96,465,103 (about \u20ac23 million) plus interest in pecuniary
\n
damages and R$80,000 (about \u20ac19,000) in non-pecuniary
\n
damages. On July 8, 2015, Enel Distribui\u00e7\u00e3o Rio de Janeiro
\n
appealed the decision with the Tribunal de Justi\u00e7a of Rio de
\n
Janeiro, which on November 6, 2019 issued a ruling on merits
\n
granting Ampla\u2019s petition and denying all of Cibran\u2019s claims.
\n
On November 25, 2019, Cibran filed an appeal against the
\n
ruling of the Tribunal de Justi\u00e7a of Rio de Janeiro, which
\n
was preliminarily denied for formal reasons on September
\n
10, 2020. On January 29, 2021, Cibran appealed (agravo de
\n
instrumento) the decisions before the Superior Tribunal de
\n
Justi\u00e7a (STJ), which was denied on June 8, 2021. On June 22,
\n
2021, Cibran filed an appeal (agravo interno) with the STJ,
\n
which was denied on March 24, 2022. On April 19, 2022, Ci-
\n
bran filed another appeal (recurso extraordinario), which was
\n
denied with ruling of May 13, 2022, against which Cibran has
\n
appealed and the proceeding is pending.
\n

\n\n
A ruling from the court of first instance is still pending for
\n
the remaining four suits for the years 2001 and 2002. The
\n
value of all the disputes is estimated at about R$681 mil-
\n
lion (about \u20ac121 million).
\n
Coperva litigation - Brazil
\n
As part of the project to expand the grid in rural areas of
\n
Brazil, in 1982 Companhia Energ\u00e9tica do Cear\u00e1 SA (Coelce,
\n
today Enel Distribui\u00e7\u00e3o Cear\u00e1), then owned by the Brazil-
\n
ian government and now an Enel Group company, had en-
\n
tered into contracts for the use of the grids of a number
\n
of cooperatives established specifically to pursue the ex-
\n
pansion project. The contracts provided for the payment
\n
of a monthly fee by Enel Distribui\u00e7\u00e3o Cear\u00e1, which was also
\n
required to maintain the networks.
\n
Those contracts, between cooperatives established in
\n
special circumstances and the then public-sector compa-
\n
ny, do not specifically identify the grids governed by the
\n
agreements, which prompted a number of the coopera-
\n
tives to sue Enel Distribui\u00e7\u00e3o Cear\u00e1 asking for, among oth-
\n
er things, a revision of the fees agreed in the contracts.
\n
These proceedings include the suit filed by Cooperativa de
\n
Eletrifica\u00e7\u00e3o Rural do Vale do Acarau Ltda (Coperva) with a
\n
value of about R$427 million (about \u20ac75 million). Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1 was granted rulings in its favor from the
\n
trial court and the court of appeal, but Coperva filed a fur-
\n
ther appeal (embargo de declara\u00e7\u00e3o) based on procedural
\n
issues, which was also denied by the appeal court in a ruling
\n
of January 11, 2016. On February 3, 2016, Coperva lodged
\n
an extraordinary appeal before the Tribunal Superior de
\n
Justi\u00e7a (TSJ) against the appeal court ruling on the merits,
\n
which was granted on November 5, 2018 for the ruling is-
\n
sued in the previous appeal (embargo de declara\u00e7\u00e3o). On
\n
December 3, 2018, Enel Distribui\u00e7\u00e3o Cear\u00e1 filed an appeal
\n
(agravo interno) against this ruling of the TSJ. The proceed-
\n
ings are currently pending.
\n
ANEEL litigation - Brazil
\n
In 2014, Eletropaulo (today Enel Distribui\u00e7\u00e3o S\u00e3o Paulo) ini-
\n
tiated an action before the Brazilian federal courts seeking
\n
to void the administrative measure of the Ag\u00eancia Nacion-
\n
al de Energia El\u00e9trica (ANEEL, the national electricity agen-
\n
cy), which in 2012 retroactively introduced a negative coef-
\n
ficient to be applied in determining rates for the following
\n
regulatory period (2011-2015). With this provision, ANEEL
\n
ordered the restitution of the value of some compo-
\n
nents of the network previously included in rates because
\n
they were considered non-existent and denied Enel Dis-
\n
tribui\u00e7\u00e3o S\u00e3o Paulo\u2019s request to include additional compo-
\n
nents in rates. The administrative measure of ANEEL was
\n
challenged and on September 9, 2014 it was suspended
\n
on a precautionary basis. The first-instance proceeding
\n
is still in its preliminary stages and the value of the suit is
\n
about R$1.3 billion (about \u20ac241 million).
\n
Endicon \u2013 Brazil
\n
On October 17, 2021 Endicon (former Enel service provid-
\n
er in Brazil) filed a lawsuit against Enel Distribui\u00e7\u00e3o Rio de
\n
Janeiro and Enel Distribui\u00e7\u00e3o Cear\u00e1 in which it seeks total
\n
damages of approximately R$435 million (about \u20ac77 mil-
\n
lion) for pecuniary and non-pecuniary damages incurred
\n
in connection with certain events allegedly attributable to
\n
Group companies, which occurred during the execution
\n
of the contracts between the parties, and from the abu-
\n
sive exercise of contractual rights by the latter, which is al-
\n
leged to have produced a loss on the management of the
\n
contracts. On May 10, 2022, in upholding the appeals filed
\n
by the two Group companies, the precautionary measure
\n
that had been previously notified to the companies and
\n
immediately suspended was definitively revoked. It had re-
\n
quired them to (i) publicly announce the material facts of
\n
the dispute and (ii) record a contingency in the financial
\n
statements of the companies in relation to the dispute. In
\n
the meantime, on December 2, 2021, Enel Distribui\u00e7\u00e3o Rio
\n
de Janeiro and Enel Distribui\u00e7\u00e3o Cear\u00e1 presented their de-
\n
fenses in the proceedings on the merits, which continue in
\n
the first instance.
\n
Socrel \u2013 Brazil
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo has been sued by Servi\u00e7os de
\n
Eletricidade and Telecomunica\u00e7\u00f5es Ltda (Socrel) for dam-
\n
ages for losses caused by an alleged unlawful termination
\n
of contract by the Group company that involved a series of
\n
contracts between the parties, which would have caused
\n
Socrel\u2019s liquidity crisis. Following an expert report issued
\n
during the proceedings, Socrel\u2019s request was quantified at
\n
R$295 million (about \u20ac52 million). The proceeding is cur-
\n
rently pending before the court of first instance.
\n
Extraordinary 2022 rate revision (Cear\u00e1) \u2013
\n
Brazil
\n
On April 19, 2022, the Ag\u00eancia Nacional de Energia El\u00e9tri-
\n
ca (ANEEL) issued resolution no. 3.026/2022 with which
\n
it authorized an average 24.85% rate increase for 2022
\n
for the electricity distribution services performed by Enel
\n
Distribui\u00e7\u00e3o Cear\u00e1. Both private individuals and public
\n
institutions have challenged this resolution before the
\n
Federal Regional Court of the district of Cear\u00e1, for a to-
\n
tal of six proceedings requesting, on precautionary basis,
\n
the cancellation of the effects of the resolution and, on a
\n
permanent basis, the voidance of the resolution itself, ar-
\n
guing that the rate increase is illegitimate. In all proceed-
\n
ings, Enel Distribui\u00e7\u00e3o Cear\u00e1 has contested the petition-
\n
ers\u2019 claims, arguing the legitimacy of the rate adjustment.
\n
On June 21, 2022, the Federal Regional Court rejected the
\n
precautionary request and joindered the six proceedings
\n
in a single proceeding in consideration of fact that the
\n
relief sought and the cause of action are the same. On
\n
September 23, 2022, Enel Distribui\u00e7\u00e3o Cear\u00e1 also sub-
\n
mitted that, as a result of certain legislative measures,
\n

\n\n
the rate had been reduced following an extraordinary
\n
rate review and a reduction in taxes. The trial proceeding
\n
continues. The estimated value of the proceeding has not
\n
been determined.
\n
GasAtacama Chile \u2013 Chile
\n
In January 2020, the appeal proceeding was completed
\n
for the administrative fine levied in August 2016 by the
\n
Superintendencia de Electricidad y Combustibles (SEC)
\n
against GasAtacama Chile (now Enel Generaci\u00f3n Chile)
\n
concerning the information provided to the CDEC- SING
\n
(Centro de Despacho Econ\u00f3mico de Carga) in relation
\n
to the variables of the Technical Minimum and the Min-
\n
imum Operation Time at the Atacama power station.
\n
Upon completion of the proceeding, the amount of the
\n
fine was reduced from approximately $6 million to about
\n
$432,000 and the amount was paid by the company.
\n
In relation to the issue mentioned above, a number of op-
\n
erators of the Sistema Interconectado del Norte Grande
\n
(SING), including Aes Gener SA, El\u00e9ctrica Angamos SA and
\n
Engie Energ\u00eda Chile SA, sued GasAtacama Chile seeking
\n
damages of about \u20ac58 million (the former two) and about
\n
\u20ac150 million (the other operators). The aforementioned
\n
disputes have been partially combined into a single pro-
\n
ceeding and are currently pending (after the resumption of
\n
the proceeding following the lifting of the national emer-
\n
gency in response to the COVID-19 pandemic, the court
\n
served the provision that determines the substantial facts
\n
and issues of the trial, the preliminary investigation phase
\n
is completed and the proceeding continues its course).
\n
El Quimbo \u2013 Colombia
\n
A number of legal actions (\u201cacciones de grupo\u201d and \u201cac-
\n
ciones populares\u201d) brought by residents and fishermen in
\n
the affected area are pending with regard to the El Qui-
\n
mbo project for the construction by Emgesa (now Enel
\n
Colombia) of a 400 MW hydroelectric plant in the region
\n
of Huila (Colombia). More specifically, the first collective
\n
action, currently in the preliminary stage, was brought
\n
by around 1,140 residents of the municipality of Garz\u00f3n,
\n
who claim that the construction of the plant would re-
\n
duce their business revenue by 30%. A second action was
\n
brought, between August 2011 and December 2012, by
\n
residents and businesses/associations of five municipali-
\n
ties of Huila claiming damages related to the closing of a
\n
bridge (Paso El Colegio). With regard to acciones popu-
\n
lares, or class action lawsuits, in 2008 a suit was filed by a
\n
number of residents of the area demanding, among oth-
\n
er things, that the environmental permit be suspended.
\n
As part of this action, on September 11, 2020, the Huila
\n
Court issued a partially unfavorable ruling against Emge-
\n
sa, sentencing it to fulfill the obligations already provid-
\n
ed for in the environmental license. Both the Autoridad
\n
Nacional de Licencias Ambientales (ANLA) and Emgesa
\n
challenged this decision before the Council of State. On
\n
September 20, 2022, ANLA\u2019s appeal was denied because
\n
it had been filed late. The proceeding continues in rela-
\n
tion to Emgesa\u2019s appeal.
\n
Another acci\u00f3n popular was brought by a number of fish
\n
farming companies over the alleged impact that filling the
\n
Quimbo basin would have on fishing in the Betania basin
\n
downstream from Quimbo. After a number of precaution-
\n
ary rulings, on February 22, 2016, the Huila Court issued
\n
a ruling allowing generation to continue for six months.
\n
The court ordered Emgesa to prepare a technical design
\n
that would ensure compliance with oxygen level require-
\n
ments and to provide collateral of about 20,000,000,000
\n
Colombian pesos (about \u20ac5.5 million).
\n
The Huila Court subsequently extended the six-month
\n
time limit, and therefore, in the absence of contrary court
\n
rulings the Quimbo plant is continuing to generate elec-
\n
tricity as the oxygenation system installed by Emgesa has
\n
so far demonstrated that it can maintain the oxygen lev-
\n
els required by the court. On March 22, 2018, ANLA and
\n
CAM jointly presented the final report on the monitoring
\n
of water quality downstream of the dam of the El Quimbo
\n
hydroelectric plant. Both authorities confirmed the com-
\n
pliance of Emgesa with the oxygen level requirements.
\n
After the parties had filed briefs, on January 12, 2021, it
\n
was learned that the ruling of first instance of the Court
\n
of Huila had been issued (it was subsequently notified to
\n
the company on February 1, 2021). The ruling, while ac-
\n
knowledging that the oxygenation system implemented
\n
by Emgesa had mitigated the risks associated with the
\n
protection of fauna in the Bethany basin, imposed a se-
\n
ries of obligations on the environmental authorities in-
\n
volved, as well as on Emgesa itself. In particular, the lat-
\n
ter is required to implement a decontamination project
\n
to ensure that the water in the basin does not generate
\n
risks for the flora and fauna of the river, which will be sub-
\n
ject to verification by ANLA, and to make permanent the
\n
operation of the oxygenation system, adapting it to com-
\n
ply with the parameters established by ANLA. On March
\n
4, 2021, Emgesa challenged the appeal ruling before the
\n
Council of State.
\n
On December 31, 2021, the Council of State ruled that
\n
Emgesa\u2019s appeal was admissible. The proceeding is con-
\n
tinuing at the appeal level.
\n
Nivel de Tensi\u00f3n Uno proceedings - Colombia
\n
This dispute involves an \u201cacci\u00f3n de grupo\u201d brought by
\n
Centro M\u00e9dico de la Sabana hospital and other parties
\n
against Codensa (now Enel Colombia) seeking restitu-
\n
tion of allegedly excess rates. The action is based upon
\n
the alleged failure of Codensa to apply a subsidized rate
\n
that they claim the users should have paid as Tensi\u00f3n Uno
\n
category users (voltage of less than 1 kV) and owners of
\n
infrastructure, as established in Resolution no. 82/2002,
\n
as amended by Resolution no. 97/2008. The preliminary
\n
stage has been completed and a ruling is pending. The
\n

\n\n
estimated value of the proceeding is about 337 billion
\n
Colombian pesos (about \u20ac96 million).
\n
Chucas arbitration - Costa Rica
\n
PH Chucas SA (Chucas) is a special purpose entity estab-
\n
lished by Enel Green Power Costa Rica SA after it won a
\n
tender organized in 2007 by the Instituto Costarricense
\n
de Electricidad (ICE) for the construction of a 50 MW hy-
\n
droelectric plant and the sale of the power generated by
\n
the plant to ICE under a build, operate and transfer con-
\n
tract (BOT).
\n
On May 27, 2015, Chucas initiated an arbitration proceed-
\n
ing before the C\u00e1mara Costarricense-Norteamericana
\n
de Comercio (AMCHAM CICA) seeking reimbursement of
\n
the additional costs incurred to build the plant and as a
\n
result of the delays in completing the project as well as
\n
voidance of the fine levied by ICE for alleged delays in fi-
\n
nalizing the works. In a decision issued in November 2017,
\n
the arbitration board ruled in Chucas\u2019 favor, granting rec-
\n
ognition of the additional costs incurred in the amount
\n
of about $113 million (about \u20ac91 million) and legal costs
\n
and found that Chucas was not liable to pay the finds to
\n
ICE. ICE appealed the arbitration ruling before the Su-
\n
preme Court and on September 5, 2019 Chucas was no-
\n
tified of the ruling partially upholding ICE\u2019s appeal to void
\n
the arbitration ruling for a number of formal procedural
\n
reasons. On September 11, 2019, Chucas filed a \u201crecurso
\n
de aclaraci\u00f3n y adici\u00f3n\u201d with the same court and it was
\n
partially upheld on June 8, 2020. The Court\u2019s decision ex-
\n
panded on the ruling of September 5, 2019 with infor-
\n
mation concerning the admission of evidence deposited
\n
by Chucas without, however, modifying the decision con-
\n
cerning the voidance of the arbitration award.
\n
On July 14, 2020, Chucas filed a new request for arbitra-
\n
tion with the AMCHAM CICA for a preliminary estimated
\n
amount of about $240 million. On August 14, 2020, ICE
\n
filed its response, requesting the dismissal of the pro-
\n
ceeding for lack of jurisdiction on the part of the arbi-
\n
tration tribunal. The request for dismissal was denied by
\n
AMCHAM CICA. In parallel, ICE filed precautionary ap-
\n
peals to the Tribunal Contencioso Administrativo against
\n
Chucas and the AMCHAM CICA seeking to suspend the
\n
arbitration proceedings. While these appeals were pre-
\n
liminarily upheld, they were subsequently denied. In May
\n
2021, Chucas filed its arbitration request complete with
\n
preliminary demands, quantifying the value of its claim at
\n
about $362 million (about \u20ac305 million). In June 2021, ICE
\n
filed its defense, continuing to assert a lack of jurisdiction.
\n
ICE has not made a counterclaim. On August 4, 2021, the
\n
arbitration tribunal rejected ICE\u2019s claim of lack of juris-
\n
diction. The matter has subsequently been submitted for
\n
consideration to the first section of the Supreme Court
\n
and the arbitration proceedings was suspended.
\n
On May 12, 2022, with a measure that was notified to the
\n
company on July 28, 2022, the first section of the Supreme
\n
Court ruled that the arbitration tribunal was incompetent
\n
to hear the dispute. On August 8, 2022, Chucas filed an
\n
extraordinary appeal against this ruling, the overall reso-
\n
lution of which is expected for mid-2023. The arbitration
\n
proceeding is suspended.
\n
Kino arbitration - Mexico
\n
On September 16, 2020, Kino Contractor SA de Cv (Kino
\n
Contractor), Kino Facilities Manager SA de Cv (Kino Fa-
\n
cilities) and Enel SpA (Enel) were notified of a request for
\n
arbitration filed by Parque Solar Don Jos\u00e9 SA de Cv, Villan-
\n
ueva Solar SA de Cv and Parque Solar Villanueva Tres SA
\n
de Cv (together, \u201cProject Companies\u201d) in which the Proj-
\n
ect Companies alleged the violation (i) by Kino Contractor
\n
of certain provisions of the EPC Contract and (ii) by Kino
\n
Facilities of certain provisions of the Asset Management
\n
Agreement, both contracts concerning solar projects
\n
owned by the three companies filing for arbitration.
\n
Enel, which is the guarantor of the obligations assumed
\n
by Kino Contractor and Kino Facilities under the above
\n
contracts, has also been called into the arbitration pro-
\n
ceeding, but no specific claims have been filed against it.
\n
The Project Companies, in which Enel Green Power SpA is
\n
a non-controlling shareholder, are controlled by CDPQ In-
\n
fraestructura Participaci\u00f3n SA de Cv (which is controlled
\n
by Caisse de D\u00e9p\u00f4t et Placement du Qu\u00e9bec) and CKD
\n
Infraestructura M\u00e9xico SA de Cv. After the request for ar-
\n
bitration and the related response from the defendants,
\n
the parties exchanged further introductory briefs, in which
\n
the financial claim of the counterparties was updated to
\n
about $135 million, while Kino Facilities has not continued
\n
its counter-claim. The hearing was held in October 2022
\n
and the final phase is currently pending. The issuance of
\n
the arbitration award is expected by mid-2023.
\n
Allianz \u2013 North America
\n
On May 18, 2022, High Lonesome Wind Project LLC was
\n
sued in New York Superior Court by Allianz Risk Transfer
\n
Ltd for about $203 million concerning an alleged liability
\n
accrued by the company, as of February 2020, in con-
\n
nection with a Proxy Revenue Swap. The claim is being
\n
contested in its entirety. The proceedings are currently
\n
pending before the Southern District Court in New York.
\n
Gastalsa \u2013 Peru
\n
In 2011, Empresa de Gas de Talara SA (Gastalsa) filed a
\n
claim before the Civil Court of Talara requesting to revoke
\n
the measure that canceled the concession of natural gas
\n
granted to it in the Parinas district, the Province of Talara
\n
and the Department of Piura, and the consequent trans-
\n
fer of the gas pipeline owned by Enel Generaci\u00f3n Piura SA
\n
(EGPIURA) to Gastalsa itself.
\n
On January 6, 2022, the court partially upheld the Gastal-
\n
sa claim. In February 2022, EGPIURA learned of a precau-
\n
tionary measure issued by the Civil Court of Talara of the
\n

\n\n
Superior Court of Justice of Sullana (Juzgado Civil de Ta-
\n
lara de la Corte Superior de Justicia de Sullana) in favor of
\n
Gastalsa which orders the Direcci\u00f3n General de Hidrocar-
\n
buros del Ministerio de Energ\u00eda y Minas, the Organismo
\n
Superior de la Inversi\u00f3n en Energ\u00eda y Miner\u00eda (Osinergmin)
\n
and the Ministry of Energy to (i) restore the natural gas
\n
concession of the Parinas district, the Province of Talara
\n
and the Department of Piura in favor of Gastalsa; and (ii)
\n
proceed with the upgrade and transfer of the pipeline to
\n
Gastalsa. The above means that the economic value of
\n
the gas pipeline, currently owned by EGPIURA (which sup-
\n
plies natural gas to the Malacas thermal power station) is
\n
to be estimated for transfer to Gastalsa.
\n
On August 2, 2022, the Sala Civil de la Corte Superior
\n
de Justicia de Sullana ruled against Gastalsa in the sec-
\n
ond-level appeal, referring the case to the court of first
\n
instance for a new decision. As a result of that decision,
\n
on September 9, 2022, the precautionary measure issued
\n
earlier was revoked.
\n
In the meantime, in July 2022, the Constitutional Court
\n
had granted the petition of the system operator, an inter-
\n
ested third party, acknowledging that the original petition
\n
of Gastalsa had been filed after the time limit. On January
\n
24, 2023 the Constitutional Court also denied the appeal
\n
of that measure.
\n
Gab\u010d\u00edkovo litigation - Slovakia
\n
Slovensk\u00e9 elektr\u00e1rne (SE) is involved in a number of cas-
\n
es before the national courts concerning the 720 MW
\n
Gab\u010d\u00edkovo hydroelectric plant, which is administered by
\n
Vodohospod\u00e1rska V\u00fdsatavba \u0160t\u00e1tny Podnik (VV) and whose
\n
operation and maintenance, as part of the privatization of
\n
SE in 2006, had been entrusted to SE for a period of 30
\n
years under an operating agreement (the VEG Operating
\n
Agreement).
\n
Immediately after the closing of the privatization, the Pub-
\n
lic Procurement Office (PPO) filed suit with the Court of
\n
Bratislava seeking to void the VEG Operating Agreement
\n
on the basis of alleged violations of the regulations gov-
\n
erning public tenders, qualifying the contract as a service
\n
contract and as such governed by those regulations. In No-
\n
vember 2011 the trial court ruled in favor of SE, whereupon
\n
the PPO appealed the decision.
\n
In parallel with the PPO action, VV also filed a number of
\n
suits, asking in particular for the voidance of the VEG Op-
\n
erating Agreement. On December 12, 2014, VV withdrew
\n
unilaterally from the VEG Operating Agreement, notifying
\n
its termination on March 9, 2015, for breach of contract.
\n
On March 9, 2015, the decision of the appeals court over-
\n
turned the ruling of the trial court and voided the contract
\n
as part of the action pursued by the PPO. SE lodged an
\n
extraordinary appeal against that decision before the Su-
\n
preme Court. At a hearing of June 29, 2016, the Supreme
\n
Court denied the appeal and SE then appealed the ruling
\n
to the Constitutional Court, which denied the appeal on
\n
January 18, 2017.
\n
In addition, SE lodged a request for arbitration with the
\n
Vienna International Arbitral Centre (VIAC) under the VEG
\n
Indemnity Agreement. Under that accord, which had been
\n
signed as part of the privatization between the National
\n
Property Fund (now MH Manazment - MHM) of the Slovak
\n
Republic and SE, the latter was entitled to an indemnity in
\n
the event of the early termination of the VEG Operating
\n
Agreement for reasons not attributable to SE. On June 30,
\n
2017, the arbitration court issued its ruling denying the re-
\n
quest of SE.
\n
In parallel with this arbitration proceeding launched by SE,
\n
both VV and MHM filed two suits in the Slovakian courts to
\n
void the VEG Indemnity Agreement owing to the alleged
\n
connection of the latter with the VEG Operating Agree-
\n
ment. These proceedings were joindered and, on Septem-
\n
ber 27, 2017, the Court of Bratislava denied the request of
\n
the plaintiffs for procedural reasons. Both VV and MHM
\n
appealed that decision, and both the appeals were denied
\n
upholding the trial court decision in favor of SE. VV filed an
\n
extraordinary appeal (dovolanie) against that decision on
\n
March 9, 2020, with the Supreme Court, to which SE re-
\n
plied with a brief submitted on June 8, 2020. SE also filed an
\n
appeal before the Slovak Constitutional Court, which was
\n
denied on July 29, 2021. On March 24, 2021, the Supreme
\n
Court overturned the decision of the Bratislava Court of
\n
Appeal, referring the judgment to the latter court, and the
\n
proceeding is currently pending.
\n
At the local level, VV has also filed other suits against SE for
\n
alleged unjustified enrichment (estimated at about \u20ac360
\n
million plus interest) for the period from 2006 to 2015. SE
\n
filed counter-claims for all of the proceedings under way.
\n
Developments in those proceedings can be summarized
\n
as follows:
\n
\u2022 for 2006-2008, at the hearing of June 26, 2019, the
\n
Court of Bratislava rejected VV\u2019s main claim and, con-
\n
sequently, SE\u2019s counterclaim. The ruling in first instance
\n
was appealed by both parties before the Court of Ap-
\n
peal of Bratislava. As for the appeal proceedings (a) the
\n
proceedings relating to 2006 were completed with the
\n
decision of December 6, 2022, notified to SE on Feb-
\n
ruary 18, 2023, which upheld the ruling in first instance.
\n
SE is assessing which course of action to pursue; (b) the
\n
proceedings relating to the years 2007 and 2008 are still
\n
pending;
\n
\u2022 the proceedings relating to the years 2011, 2014 and
\n
2015 are all pending before the court of first instance
\n
and briefs have been exchanged between the parties. For
\n
proceedings relating to the years 2011 and 2014 hear-
\n
ings before the court of first instance were postponed
\n
to specified dates before being postponed to dates to
\n
be determined owing the pandemic. For the proceeding
\n
relating to 2015 the hearing before the court of first in-
\n
stance is scheduled for March 7, 2023;
\n
\u2022 the proceedings relating to the years 2009, 2010 and
\n

\n\n
2013 were completed in the court of first instance with
\n
ruling issued by the Court of Bratislava on, respectively,
\n
November 24, 15 and 22, 2022, rejecting both VV\u2019s claim
\n
and SE\u2019s counterclaim. Between December 2022 and
\n
January 2023 both SE and VV filed appeals against the
\n
rulings relating to the years 2010 and 2013, and on Jan-
\n
uary 19, 2023 SE also filed an appeal against the ruling
\n
relating to the year 2009;
\n
\u2022 as regards the proceeding relating to the year 2012, on
\n
February 2, 2023 SE was notified of the appeal ruling up-
\n
holding the ruling of first instance denying of both VV\u2019s
\n
claim and SE\u2019s counterclaim. SE is considering which
\n
course of action to pursue.
\n
Finally, in another proceeding VV asked for SE to return
\n
the fee for the transfer from SE to VV of the technology
\n
assets of the Gab\u010d\u00edkovo plant as part of the privatization,
\n
with a value of about \u20ac43 million plus interest. After issuing
\n
a preliminary decision on the case in which it noted the
\n
lack of standing of VV, on December 18, 2020, the Court
\n
of Bratislava issued a decision in favor of SE, rejecting VV\u2019s
\n
claims. On January 4, 2021, VV filed an appeal against that
\n
decision, and the proceeding is pending.
\n
Tax litigation in Brazil
\n
Withholding Tax \u2013 Ampla
\n
In 1998, Ampla Energia e Servi\u00e7os SA (Ampla) financed
\n
the acquisition of Coelce with the issue of bonds in the
\n
amount of $350 million (\u201cFixed Rate Notes\u201d - FRN) sub-
\n
scribed by its Panamanian subsidiary, which had been es-
\n
tablished to raise funds abroad. Under the special rules
\n
then in force, subject to maintaining the bond until 2008,
\n
the interest paid by Ampla to its subsidiary was not subject
\n
to withholding tax in Brazil.
\n
However, the financial crisis of 1998 forced the Panama-
\n
nian company to refinance itself with its Brazilian parent,
\n
which for that purpose obtained loans from local banks.
\n
The tax authorities considered this financing to be the
\n
equivalent of the early extinguishment of the bond, with
\n
the consequent loss of entitlement to the exemption from
\n
withholding tax.
\n
In December 2005, Ampla Energia e Servi\u00e7os carried out a
\n
spin-off that involved the transfer of the residual FRN debt
\n
and the associated rights and obligations to Ampla Inves-
\n
timentos e Servi\u00e7os SA.
\n
On November 6, 2012, the C\u00e2mara Superior de Recursos
\n
Fiscais (the highest level of administrative courts) issued
\n
a ruling against Ampla, for which the company promptly
\n
asked that body for clarifications. On October 15, 2013,
\n
Ampla was notified of the denial of the request for clari-
\n
fication (embargo de declara\u00e7\u00e3o), thereby upholding the
\n
previous adverse decision. The company provided security
\n
for the debt and on June 27, 2014 continued litigation be-
\n
fore the ordinary courts (Tribunal de Justi\u00e7a).
\n
In December 2017, the court appointed an expert to ex-
\n
amine the issue in greater detail in support of the future
\n
ruling. In September 2018, the expert submitted a report,
\n
requesting additional documentation.
\n
In December 2018, the company provided the additional
\n
documentation and is awaiting the court\u2019s assessment of
\n
the arguments and documents presented.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac246 million.
\n
PIS/COFINS/ICMS - Enel Distribui\u00e7\u00e3o S\u00e3o Paulo
\n
In March 2017, the Supremo Tribunal Federal of Brazil (STF)
\n
ruled on the calculation of the PIS and COFINS taxes, con-
\n
firming the argument that the ICMS - Imposto sobre Cir-
\n
cula\u00e7\u00e3o de Mercadorias e Servi\u00e7os (tax on the circular of
\n
goods and services) was not included in the calculation
\n
basis of the PIS and COFINS.
\n
In May 2021, the STF established that the ruling would have
\n
effect from the judgment of March 2017, except for taxpay-
\n
ers who had filed an appeal before that date.
\n
The Group\u2019s Brazilian companies affected by the STF ruling
\n
had already initiated legal action in their respective federal
\n
regional courts. Subsequently, the latter notified them of
\n
the final decision, recognizing the right to deduct the ICMS
\n
applied to their operations from the calculation basis of
\n
the PIS and COFINS. Since the excess payment of the PIS
\n
and COFINS taxes had been transferred to final customers,
\n
at the same time as the recognition of these recoverable
\n
taxes, a liability in respect of those customers was recog-
\n
nized in the same amount, net of any costs incurred or to
\n
be incurred in the legal proceedings. These liabilities rep-
\n
resent an obligation to reimburse the recovered taxes to
\n
final customers.
\n
In this regard, Enel Distribui\u00e7\u00e3o S\u00e3o Paulo initiated two
\n
proceedings that led to rulings in its favor. These regard-
\n
ed the periods from December 2003 to December 2014
\n
and from January 2015 onwards. With regard to the second
\n
proceeding, the Federal Union filed an action of rescission
\n
against the company, disputing the fact that part of the
\n
period in question (prior to March 2017) would be adversely
\n
impacted by the STF ruling of May 2021.
\n
In May 2022, the company challenged this action and will
\n
defend its actions through the various levels of the court
\n
system.
\n
The estimated amount involved in the proceeding at De-
\n
cember 31, 2022 was about \u20ac206 million.
\n
IRPJ/CSLL \u2013 Eletropaulo
\n
On October 5, 2021, Eletropaulo received an assessment
\n
notice from the Brazilian tax authorities contesting the de-
\n
ductibility for income tax purposes (Imposto sobre a Renda
\n
das Pessoas Jur\u00eddicas - IRPJ and Contribui\u00e7ao Social sobre o
\n
Lucro L\u00edquido - CSLL) of the amortization of the increased
\n
values generated by extraordinary corporate transactions
\n
carried out before the acquisition of the company by the
\n
Enel Group. The contested period runs from 2017 to 2019.
\n

\n\n
Considering its position sound, the company presented its
\n
defense at the first level of administrative adjudication.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac137 million.
\n
PIS \u2013 Eletropaulo
\n
In July 2000, Eletropaulo filed suit seeking a tax credit for
\n
PIS (Programa Integra\u00e7\u00e3o Social) paid in application of
\n
regulations (Decree Laws 2.445/1988 and 2.449/1988)
\n
that were subsequently declared unconstitutional by the
\n
Supremo Tribunal Federal (STF). In May 2012, the Superior
\n
Tribunal de Justi\u00e7a (STJ) issued a final ruling in favor of the
\n
company that recognized the right to the credit.
\n
In 2002, before the issue of that favorable final ruling, the
\n
company had offset its credit against other federal taxes.
\n
This behavior was contested by the federal tax authorities
\n
but the company, claiming it had acted correctly, chal-
\n
lenged in court the assessments issued by the federal tax
\n
authorities. Following defeat at the initial level of adjudica-
\n
tion, the company appealed.
\n
The amount involved in the dispute at December 31, 2022
\n
was about \u20ac123 million.
\n
ICMS - Ampla, Coelce and Eletropaulo
\n
The States of Rio de Janeiro, Cear\u00e1 and S\u00e3o Paulo issued
\n
a number of tax assessments against Ampla Energia e
\n
Servi\u00e7os SA (for the years 1996-1999 and 2007-2017),
\n
Companhia Energ\u00e9tica do Cear\u00e1 (2003, 2004, 2006-2012,
\n
2015 and 2016) and Eletropaulo (2008-2021), challeng-
\n
ing the deduction of ICMS - Imposto sobre Circula\u00e7\u00e3o de
\n
Mercadorias e Servi\u00e7os (tax on the circular of goods and
\n
services) in relation to the purchase of certain non-current
\n
assets. The companies challenged the assessments, argu-
\n
ing that they correctly deducted the tax and asserting that
\n
the assets, the purchase of which generated the ICMS, are
\n
intended for use in their electricity distribution activities.
\n
The companies are continuing to defend their actions at
\n
the various levels of adjudication.
\n
The amount involved in the disputes totaled approximately
\n
\u20ac95 million at December 31, 2022.
\n
Withholding Tax - Endesa Brasil
\n
On November 4, 2014, the Brazilian tax authorities issued
\n
an assessment against Endesa Brasil SA (now Enel Brasil SA)
\n
alleging the failure to apply withholding tax to payments of
\n
allegedly higher dividends to non-resident recipients.
\n
More specifically, in 2009, Endesa Brasil, as a result of the
\n
first-time application of the IFRS, had derecognized good-
\n
will, recognizing the effects in equity, on the basis of the
\n
correct application of the accounting standards it had
\n
adopted. The Brazilian tax authorities, however, asserted
\n
\u2013 during an audit \u2013 that the accounting treatment was in-
\n
correct and that the effects of the derecognition should
\n
have been recognized through profit or loss. As a result,
\n
the corresponding amount (about \u20ac202 million) was re-
\n
classified as a payment of income to non-residents and,
\n
therefore, subject to withholding tax of 15%.
\n
It should be noted that the accounting treatment adopted by
\n
the company was agreed with the external auditor and also
\n
confirmed by a specific legal opinion issued by a local firm.
\n
Following unfavorable rulings from the administrative courts,
\n
the company is continuing to defend its actions in court and
\n
the appropriateness of the accounting treatment.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac69 million.
\n
ICMS \u2013 Coelce
\n
The State of Cear\u00e1 has filed various tax assessments
\n
against Companhia Energ\u00e9tica do Cear\u00e1 SA (Coelce) over
\n
the years (for tax periods from 2005 to 2014), contesting
\n
the determination of the deductible portion of the ICMS -
\n
Imposto sobre Circula\u00e7\u00e3o de Mercadorias e Servi\u00e7os (tax
\n
on the circular of goods and services) and in particular the
\n
method of calculation of the pro-rata deduction with ref-
\n
erence to the revenue deriving from the application of a
\n
special rate envisaged by the Brazilian government for the
\n
sale of electricity to low-income households (Baixa Renda).
\n
The company has appealed the individual assessments, ar-
\n
guing that the tax deduction was calculated correctly. The
\n
company is defending its actions in the various levels of
\n
jurisdiction.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac55 million.
\n
PIS \u2013 Eletropaulo
\n
In December 1995, the Brazilian government increased
\n
the rate of the federal PIS (Programa Integra\u00e7\u00e3o Social) tax
\n
from 0.50% to 0.65% with the issue of a provisional mea-
\n
sure (Executive Provisional Order).
\n
Subsequently, the provisional measure was re-issued five
\n
times before its definitive ratification into law in 1998. Un-
\n
der Brazilian legislation, an increase in the tax rate (or the
\n
establishment of a new tax) can only be ordered by law and
\n
take effect 90 days after its publication.
\n
Eletropaulo therefore filed suit arguing that an increase in
\n
the tax rate would only have been effective 90 days after
\n
the last Provisional Order, claiming that the effects of the
\n
first four provisional measures should be considered void
\n
(since they were never ratified into law). This dispute ended
\n
in April 2008 with recognition of the validity of the increase
\n
in the PIS rate starting from the first provisional measure.
\n
In May 2008, the Brazilian tax authorities filed a suit against
\n
Eletropaulo to request payment of taxes corresponding
\n
to the rate increase from March 1996 to December 1998.
\n
Eletropaulo has fought the request at the various levels of
\n
adjudication, arguing that the time limit for the issue of
\n
the notice of assessment had lapsed. In particular, since
\n
more than five years have passed since the taxable event
\n
(December 1995, the date of the first provisional measure)
\n
without issuing any formal instrument, the right of the tax
\n

\n\n
authorities to request the payment of additional taxes and
\n
the authority to undertake legal action to obtain payment
\n
have been challenged.
\n
In 2017, following the unfavorable decisions issued in pre-
\n
vious rulings, Eletropaulo filed an appeal in defense of its
\n
rights and its actions with the Superior Tribunal de Justi\u00e7a
\n
(STJ) and the Supremo Tribunal Federal (STF). The proceed-
\n
ings are still pending while the amounts subject to dispute
\n
have been covered by a bank guarantee.
\n
With regard to the request of the Office of the Attorney
\n
General of the Brazilian National Treasury Department to
\n
replace the bank guarantee with a deposit in court, the
\n
court of second instance granted the petition. The com-
\n
pany therefore replaced the bank guarantee with a cash
\n
deposit and filed a clarification motion against the related
\n
decision, which is currently awaiting a decision.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac45 million.
\n
FINSOCIAL \u2013 Eletropaulo
\n
Following a final ruling issued by the Federal Regional Court
\n
on September 11, 2011, Eletropaulo was recognized the
\n
right to compensation for certain FINSOCIAL credits (so-
\n
cial contributions) relating to sums paid from September
\n
1989 to March 1992.
\n
Despite the expiration of the relative statute of limitations,
\n
the Federal Tax Authority contested the determination of
\n
some credits and rejected the corresponding offsetting,
\n
issuing tax assessments that the company promptly chal-
\n
lenged in the administrative courts, defending the legiti-
\n
macy of its calculations and actions.
\n
After an unfavorable ruling at first instance, the company
\n
filed an appeal before the administrative court of second
\n
instance.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac43 million.
\n
Tax litigation in Spain
\n
Income tax - Enel Iberia, Endesa and subsidiaries
\n
In 2018, the Spanish tax authorities completed a general
\n
audit involving the companies of the Group participating
\n
in the Spanish tax consolidation mechanism. This audit,
\n
which began in 2016, involved corporate income tax, value
\n
added tax and withholding taxes (mainly for the years 2011
\n
to 2014).
\n
With reference to the main claims, the companies involved
\n
have challenged the related assessments at the first ad-
\n
ministrative level (Tribunal Econ\u00f3mico-Administrativo Cen-
\n
tral - TEAC), defending the correctness of their actions.
\n
On April 4, 2022, the TEAC rejected the appeal and the
\n
companies are continuing to defend their actions in court
\n
(Audiencia Nacional).
\n
With regard to the disputes concerning corporate income
\n
tax, the issues for which an unfavorable outcome is con-
\n
sidered possible amounted to about \u20ac133 million at De-
\n
cember 31, 2022:
\n
\u2022 Enel Iberia is defending the appropriateness of the crite-
\n
rion adopted for determining the deductibility of capital
\n
losses deriving from stock sales (around \u20ac88 million) and
\n
certain financial expense (around \u20ac15 million);
\n
\u2022 Endesa and its subsidiaries are mainly defending the ap-
\n
propriateness of the criteria adopted for the deductibil-
\n
ity of certain financial expense (about \u20ac24 million) and
\n
costs for decommissioning nuclear power plants (about
\n
\u20ac6 million).
\n
In 2021, the Spanish tax authorities concluded a new gen-
\n
eral audit for the years from 2015 to 2018. The companies
\n
involved challenged the related assessments at the first
\n
level of administrative adjudication (TEAC), arguing that
\n
they had acted correctly.
\n
In relation to the main dispute regarding corporate income
\n
tax, which concerned the deductibility of certain financial
\n
charges, the dispute for which an adverse outcome is consid-
\n
ered possible has a value of about \u20ac222 million at December
\n
31, 2022 (Enel Iberia \u20ac210 million and Endesa SA \u20ac12 million).
\n
Income tax - Enel Green Power Espa\u00f1a SL
\n
On June 7, 2017, the Spanish tax authorities issued a notice
\n
of assessment to Enel Green Power Espa\u00f1a SL, contesting
\n
the treatment of the merger of Enel Uni\u00f3n Fenosa Ren-
\n
ovables SA (\u201cEUFER\u201d) into Enel Green Power Espa\u00f1a SL in
\n
2011 as a tax neutral transaction, asserting that the trans-
\n
action had no valid economic reason.
\n
On July 6, 2017, the company appealed the assessment at
\n
the first administrative level (Tribunal Econ\u00f3mico-Adminis-
\n
trativo Central - TEAC), defending the appropriateness of
\n
the tax treatment applied to the merger. The company has
\n
provided the supporting documentation demonstrating
\n
the synergies achieved as a result of the merger in order
\n
to prove the existence of a valid economic reason for the
\n
transaction. On December 10, 2019, the TEAC denied the
\n
appeal and the company is continuing to defend its ac-
\n
tions in court (Audiencia Nacional).
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac100 million.
\n
Tax litigation in Italy
\n
Withholding Tax \u2013 Enel Servizio Elettrico Nazionale
\n
As a result of a tax audit initiated in March 2018 and fol-
\n
lowing a subsequent investigation conducted with ques-
\n
tionnaires submitted to the banks involved as assignees
\n
in certain transfers of receivables from Servizio Elettrico
\n
Nazionale SpA (SEN) in respect of mass market custom-
\n
ers under a framework agreement, on December 19, 2018,
\n
the Revenue Agency Regional Directorate of Lazio Large
\n
Taxpayers Office, notified the company of an assessment
\n
in respect of the alleged violation of withholding tax obli-
\n

\n\n
gations relating to the amounts paid to the banks as part
\n
of the aforementioned transfers in 2013.
\n
In particular, the dispute arises from an assessment by the
\n
Office that: (i) reclassified, for tax purposes only, the assign-
\n
ment of receivables as a financing transaction; (ii) asserted
\n
an alleged withholding obligation for the company com-
\n
mensurate with the cost of the transaction (as the difference
\n
between the nominal value of the assigned receivables and
\n
the transfer price), reconstructing the subsequent transac-
\n
tions involving the assigned receivables (further sales and/or
\n
securitizations with non-residents carried out by the banks),
\n
in which the company had no role.
\n
In the first stages of the proceeding, which arose following
\n
SEN\u2019s appeal of the assessment, the company\u2019s objections
\n
concerning the illegitimacy of the Office\u2019s reclassification
\n
of the transaction for tax purposes and, consequently, of
\n
the payment flows were not upheld, despite significant
\n
procedural violations in the assessment activity.
\n
In 2022, the conditions for a settlement arose, which the
\n
company decided to accept for the sole purpose of avoid-
\n
ing the continuation of the pending dispute concerning
\n
a matter characterized by interpretative uncertainty. This
\n
solution provides for an overall revision of the tax claim and
\n
the withdrawal of claims for subsequent years.
\n
The settlement involved the payment during the year by
\n
the company of about \u20ac45 million and the action was de-
\n
prived of purpose.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag2": { "value": "\n
58. Future accounting standards
\n
The following provides a list of accounting standards,
\n
amendments and interpretations that will take effect for
\n
the Group after December 31, 2022.
\n
\u2022 \u201cAmendments to IAS 1 - Classification of Liabilities as
\n
Current or Non-current\u201d, issued in January 2020. The
\n
amendments regard the provisions of IAS 1 concern-
\n
ing the presentation of liabilities. More specifically, the
\n
changes clarify:
\n
\u2013 the criteria to adopt in classifying a liability as current
\n
or non-current, specifying the meaning of right of an
\n
entity to defer settlement and that that right must ex-
\n
ist at the end of the reporting period;
\n
\u2013 that the classification is unaffected by the intentions
\n
or expectations of management about when the en-
\n
tity will exercise its right to defer settlement of a lia-
\n
bility;
\n
\u2013 that the right to defer exists if and only if the entity
\n
satisfies the terms of the loan at the end of the re-
\n
porting period, even if the creditor does not verify
\n
compliance until later; and
\n
\u2013 that settlement regards the transfer to the counterpar-
\n
ty of cash, equity instruments, other assets or services.
\n
The amendments will take effect, subject to endorse-
\n
ment, for annual periods beginning on or after January
\n
1, 2024.
\n
(62)
\n
\u2022 \u201cAmendments to IAS 1 - Non-current Liabilities with Cov-
\n
enants\u201d, issued in October 2022. IAS 1 requires classifi-
\n
cation of liabilities as non-current only where an entity
\n
has a right to defer settlement in the 12 months following
\n
the reporting date. The amendments of the standard im-
\n
prove disclosure when the right to defer settlement of a
\n
liability for at least 12 months is subject to compliance
\n
with covenants and specify that the classification of the
\n
liability as current or non-current at the reporting date
\n
is not affected by covenants that must be complied with
\n
subsequent to the reporting date.
\n
The amendments will take effect, subject to endorsement,
\n
for annual periods beginning on or after January 1, 2024.
\n
\u2022 \u201cAmendments to IAS 1 and IFRS Practice Statement 2
\n
- Disclosure of Accounting Policies\u201d, issued in February
\n
2021. The amendments are intended to support entities
\n
in deciding which accounting policies to disclose in the
\n
financial statements. The amendments to IAS 1 require
\n
companies to disclose their material accounting policy
\n
information rather than their significant accounting pol-
\n
icies. A guide on how to apply the concept of materiality
\n
to disclosures on accounting policies is provided in the
\n
amendments to IFRS Practice Statement 2. The amend-
\n
ments will take effect for annual periods beginning on or
\n
after January 1, 2023.
\n
\u2022 \u201cAmendments to IAS 8 - Definition of Accounting Esti-
\n
mates\u201d, issued in February 2021. The amendments clar-
\n
ify how companies should distinguish changes in ac-
\n
counting policies from changes in accounting estimates.
\n
The definition of changes in accounting estimates has
\n
been replaced with a definition of accounting estimates
\n
as \u201cmonetary amounts in financial statements that are
\n
subject to measurement uncertainty\u201d. The amendments
\n
will take effect for annual periods beginning on or after
\n
January 1, 2023.
\n
\u2022 \u201cAmendments to IAS 12 - Income Taxes: Deferred Tax re-
\n
lated to Assets and Liabilities arising from a Single Trans-
\n
action\u201d, issued in May 2021. The amendments require
\n
entities to recognize deferred tax on transactions that at
\n
initial recognition give rise to equal taxable and deductible
\n
temporary differences. The amendments will take effect
\n
for annual periods beginning on or after January 1, 2023.
\n
\u2022 \u201cAmendments to IFRS 10 and IAS 28 \u2013 Sale or Contribu-
\n
tion of Assets between an Investor and its Associate or
\n
Joint Venture\u201d, issued in September 2014. The amend-
\n
ments clarify the accounting treatment for sales or con-
\n
tribution of assets between an investor and its associates
\n
or joint ventures. They confirm that the accounting treat-
\n

\n

\n\n
(62) In July 2020, an amendment was issued to postpone the date of entry into force from January 1, 2023 to January 1, 2024.
\n

\n\n
ment depends on whether the assets sold or contributed
\n
to an associate or joint venture constitute a \u201cbusiness\u201d
\n
(as defined in IFRS 3). The IASB has deferred the effective
\n
date of these amendments indefinitely.
\n
\u2022 \u201cIFRS 17 \u2013 Insurance Contracts\u201d, issued in May 2017. The
\n
standard introduces different models for calculating the
\n
costs of insurance and reinsurance. The standard will take
\n
effect for annual periods beginning on or after January 1,
\n
2023. The Group has recalculated the impact of the first-
\n
time application of IFRS 17 at January 1, 2022 and the total
\n
impact at December 31, 2022 is estimated as a positive
\n
change of up to \u20ac30 million, mainly due to the discount-
\n
ing of reserves.
\n
\u2022 \u201cAmendments to IFRS 16 - Lease Liability in a Sale and
\n
Leaseback\u201d, issued in September 2022. The amendments
\n
require the seller-lessee to measure the right-of-use as-
\n
set arising from a sale and leaseback transaction in pro-
\n
portion to the previous carrying amount of the asset in-
\n
volved in the arrangement and in line with the retained
\n
right-of-use. Consequently, the seller-lessee will be al-
\n
lowed to recognize only the amount of any capital gain or
\n
loss relating to the rights transferred to the buyer-lessor.
\n
The amendments do not prescribe specific measurement
\n
requirements for liabilities deriving from a leaseback.
\n
However, they include examples that illustrate the initial
\n
and subsequent measurement of the liability by including
\n
variable payments that do not depend on an index or a
\n
rate. This representation is a departure from the general
\n
accounting model required by IFRS 16, in which variable
\n
payments that do not depend on an index or a rate are
\n
recognized through profit or loss in the period in which
\n
the event or condition that determines these payments
\n
occurs. In this regard, the seller-lessee will have to devel-
\n
op and apply an accounting policy to determine the lease
\n
payments such that any amount of retained right-of-use
\n
gain or loss is not recognized.
\n
The amendments will take effect, subject to endorse-
\n
ment, for annual periods beginning January 1, 2024. In
\n
conformity with \u201cIAS 8 - Accounting Policies, Changes in
\n
Accounting Estimates and Errors\u201d, retrospective applica-
\n
tion is permitted for sale and leaseback transactions en-
\n
tered into after the date of initial application of IFRS 16.
\n
The Group is assessing the potential impact of the future
\n
application of the new provisions.
\n

\n", "dimensions": { "concept": "ifrs-full:ExplanationOfNotAppliedNewStandardsOrInterpretations", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag1": { "value": "\n
59. Events after the reporting period
\n
Enel places new perpetual hybrid bonds for \u20ac1.75 billion
\n
to refinance some of its outstanding hybrid bonds
\n
On January 9, 2023, Enel SpA launched the issuance of
\n
non-convertible, subordinated, perpetual, hybrid bonds
\n
for institutional investors on the European market, de-
\n
nominated in euros for an aggregate principal amount of
\n
\u20ac1.75 billion (the \u201cNew Securities\u201d). At the same time, Enel
\n
also announced, through a separate notice, the launch of
\n
voluntary tender offers to repurchase for cash and sub-
\n
sequently cancel, for a total aggregate principal amount
\n
equal to the principal amount raised from the New Secu-
\n
rities, any-and-all of the \u20ac750 million equity-accounted
\n
perpetual hybrid bond with first call date in August 2023,
\n
as well as part of the outstanding $1,250 million hybrid
\n
bond due September 2073 with call date in September
\n
2023, subject to satisfaction of a number of conditions.
\n
Enel announces the results of the tender offer on the
\n
perpetual hybrid bond denominated in euros
\n
With the conclusion of the voluntary tender offer launched
\n
on January 9, 2023 and expired on January 16, 2023,
\n
on January 18, 2023 Enel announced that it will repur-
\n
chase for cash its outstanding perpetual hybrid bond
\n
denominated in euros for an aggregate nominal amount
\n
of \u20ac699,970,000.00. Taking into account the principal
\n
amount raised through the issue of new securities and
\n
the principal amount of securities purchased in connec-
\n
tion with the tender offer for the euro-denominated bond,
\n
the capped maximum acceptance amount (\u201cCapped Max-
\n
imum Amount\u201d) for the concurrent tender offer for its
\n
$1,250 million hybrid bond due September 2073 with call
\n
date in September 2023 has been removed.
\n
Enel announces the results of the tender offer on the
\n
perpetual hybrid bond denominated in euros
\n
As a consequence of the removal of the capped maximum
\n
acceptance amount (\u201cCapped Maximum Amount\u201d) on the
\n
dollar-denominated bond \u2013 as announced on January
\n
18, 2023 \u2013 Enel has accepted for purchase all of the of-
\n
fers validly tendered on the dollar-denominated bond by
\n
the Early Tender Deadline for a total nominal amount of
\n
$411,060,000.
\n
Enel launches a \u20ac1.5 billion sustainability-linked bond
\n
On February 14, 2023, Enel Finance International NV
\n
launched a dual-tranche sustainability-linked bond for in-
\n
stitutional investors for a total of \u20ac1.5 billion. The new issue
\n
envisages for the first time the use by Enel of multiple Key
\n
Performance Indicators (KPIs) per tranche. One tranche of
\n

\n\n
the bond combines a KPI linked to the EU taxonomy with a
\n
KPI linked to the United Nations Sustainable Development
\n
Goals (SDGs). The other tranche of the bond is linked to
\n
two KPIs related to the Group\u2019s full decarbonization path,
\n
across direct and indirect greenhouse gas emission re-
\n
duction.
\n
Enel starts disposal process for assets in Argentina by
\n
selling thermal generation activities
\n
On February 17, 2023, the Enel Group, through its subsidi-
\n
ary Enel Argentina, signed and closed the deal for the sale
\n
to energy company Central Puerto SA of the Group\u2019s 75.7%
\n
stake in the thermal generation company Enel Generaci\u00f3n
\n
Costanera.
\n
At the same time, Enel has signed the agreement on the
\n
sale to Central Puerto of the Group\u2019s 41.2% stake in the
\n
thermal generation company Central Dock Sud. The total
\n
consideration for the sale of Enel\u2019s equity in the two com-
\n
panies amounts to $102 million.
\n
Enel signs agreement to sell its Romanian operations to
\n
PPC
\n
On March 9, 2023, Enel SpA signed an agreement with
\n
Greek company Public Power Corporation SA (PPC) for the
\n
sale of all the equity stakes held by the Enel Group in Ro-
\n
mania. The agreement provides that PPC will pay a total of
\n
approximately \u20ac1,260 million, equivalent to an enterprise
\n
value of about \u20ac1,900 million (on a 100% basis). The overall
\n
transaction is expected to generate a total positive effect
\n
on the Group\u2019s consolidated net debt of approximately
\n
\u20ac1.7 billion, of which about \u20ac0.1 billion in 2022 and the re-
\n
maining amount in 2023, alongside a cumulative negative
\n
impact for 2022-2023 on reported Group profit amounting
\n
to approximately \u20ac1.4 billion, of which around \u20ac0.6 billion
\n
related to the release of the foreign exchange reserve to
\n
be booked in 2023.
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag3": { "value": "\n
60. Fees of the Audit Firm pursuant to Article 149-duodecies
\n
of the CONSOB Issuers Regulation
\n
Fees pertaining to 2022 paid by Enel SpA and its subsid-
\n
iaries at December 31, 2022 to the Audit Firm and entities
\n
belonging to its network for services are summarized in
\n
the following table, pursuant to the provisions of Article
\n
149-duodecies of the CONSOB Issuers Regulation.
\n
Millions of euro
\n
Type of service Entity providing the service Fees
\n
Enel SpA
\n
Auditing
\n
of which:
\n
- KPMG SpA 0.5
\n
- entities of the KPMG network -
\n
Certification services
\n
of which:
\n
- KPMG SpA 2.1
\n
- entities of the KPMG network -
\n
Other services
\n
of which:
\n
- KPMG SpA -
\n
- entities of the KPMG network -
\n
Total 2.6
\n
Enel SpA subsidiaries
\n
Auditing
\n
of which:
\n
- KPMG SpA 4.3
\n
- entities of the KPMG network 7.9
\n
Certification services
\n
of which:
\n
- KPMG SpA 1.3
\n
- entities of the KPMG network 1.1
\n
Other services
\n
of which:
\n
- KPMG SpA 0.1
\n
- entities of the KPMG network -
\n
Total 14.7
\n
TOTAL 17.3
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "Tag978": { "value": "\n
Subsidiaries, associates and other significant equity
\n
investments of the Enel Group at December 31, 2022
\n
In compliance with Articles 38 and 39 of Legislative Decree
\n
127/1991 and CONSOB Notice no. DEM/6064293 of July
\n
28, 2006, a list of subsidiaries and associates of Enel SpA
\n
at December 31, 2022, pursuant to Article 2359 of the Ita-
\n
lian Civil Code, and of other significant equity investments
\n
is provided below. Enel has full title to all investments.
\n
The following information is included for each company:
\n
name, registered office, share capital, currency in which
\n
share capital is denominated, business segment, method
\n
of consolidation, Group companies that have a stake in the
\n
company and their respective ownership share, and the
\n
Group\u2019s ownership share.
\n
The following provides a key to the icons representing the
\n
business segments.
\n
Business segment Description of business segments
\n
Group holding company
\n
Country holding company
\n
Enel Green Power
\n
Thermal Generation
\n
Trading
\n
Enel Grids
\n
Enel X
\n
End-user Markets
\n
Services
\n
Finance
\n
Enel X Way
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parent
\n
Enel SpA Rome IT 10,166,679,946.00 EUR
\n
Holding 100.00%
\n
Subsidiaries
\n
25 Mile Creek
\n
Windfarm LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
25 Mile PPA LLC Andover US 1.00 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
25RoseFarms Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
3SUN Srl Catania IT 1,000,000.00 EUR
\n
AFS
\n
Enel Green Power
\n
Italia Srl
\n
96.74%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
3.26%
\n
3Sun USA LLC Andover US 1.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
400 Manley Solar LLC Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
4814 Investments LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
ABC Solar 11 SpA
\n
Santiago de
\n
Chile
\n
CL 1,000,000.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
100.00% 64.93%
\n
ABC Solar 3 SpA
\n
Santiago de
\n
Chile
\n
CL 1,000,000.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
100.00% 64.93%
\n
Ables Springs Solar
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ables Springs Storage
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Abu Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Ace High Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aced Renewables
\n
Hidden Valley (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Acefat AIE Barcelona ES 793,340.00 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Adams Solar PV Project
\n
Two (RF) (Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Adria Link Srl Gorizia IT 300,297.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Aferkat Wind Farm Benslimane MA 389,600.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
100.00% 100.00%
\n
Agassiz Beach LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Agatos Green Power
\n
Trino Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Solar Energy Srl
\n
100.00% 100.00%
\n
Aguil\u00f3n 20 SA Zaragoza ES 2,682,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Alba Energia Ltda Rio de Janeiro BR 16,045,169.00 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Albany Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Alliance SA Managua NI 6,180,150.00 NIO
\n
- Ufinet Latam SLU 99.90% 19.48%
\n
Alpe Adria Energia Srl Udine IT 900,000.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Alta Farms Azure
\n
Ranchland Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Alta Farms Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
Alvorada Energia SA Niter\u00f3i BR 22,317,415.92 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ampla Energia e
\n
Servi\u00e7os SA
\n
Rio de Janeiro BR 4,138,230,386.65 BRL
\n
Line-by-line Enel Brasil SA 99.82% 82.12%
\n
Annandale Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Apiac\u00e1s Energia SA Rio de Janeiro BR 14,216,846.33 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Aquilla Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Aragonesa de
\n
Actividades
\n
Energ\u00e9ticas SAU
\n
Teruel ES 60,100.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Aranort Desarrollos SLU Madrid ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Aravalli Surya (Project 1)
\n
Private Limited
\n
Gurugram IN 31,630,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Arcadia Power Inc. Washington DC US - USD
\n
-
\n
Enel X North
\n
America Inc.
\n
0.14% 0.14%
\n
Arena Green Power
\n
1 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
2 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
3 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
4 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power
\n
5 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Power Solar
\n
11 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
12 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
13 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
20 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Arena Power Solar
\n
33 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
34 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar
\n
35 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arrow Hills Solar
\n
Project
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Asociaci\u00f3n Nuclear
\n
Asc\u00f3-Vandell\u00f3s II AIE
\n
Tarragona ES 19,232,400.00 EUR
\n
Proportional
\n
Endesa Generaci\u00f3n
\n
SAU
\n
85.41% 59.89%
\n
Ateca Renovables SL Madrid ES 3,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 19.72%
\n
35.06%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
14.93%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
15.35%
\n
Athonet France SASU Paris FR 50,000.00 EUR
\n
- Athonet Srl 100.00% 16.00%
\n
Athonet Srl Trieste IT 68,927.57 EUR
\n
- Enel X Srl 16.00% 16.00%
\n
Athonet UK Ltd
\n
Battle, East
\n
Sussex
\n
GB 250,001.00 GBP
\n
- Athonet Srl 100.00% 16.00%
\n
Athonet USA Inc. Wilmington US 1.00 USD
\n
- Athonet Srl 100.00% 16.00%
\n
Atl\u00e1ntico Photovoltaic
\n
SAS ESP
\n
Barranquilla CO 50,587,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Atwater Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Aurora Distributed
\n
Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Solar
\n
Holdings LLC
\n
74 . 13 % 74 . 13 %
\n
Aurora Land Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Solar Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Aurora Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Autumn Hills LLC Wilmington US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Autumn Waltz Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Avikiran Energy India
\n
Private Limited
\n
Gurugram IN 100,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Avikiran Solar India
\n
Private Limited
\n
New Delhi IN 253,659,580.00 INR
\n
AFS
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Avikiran Surya India
\n
Private Limited
\n
Gurugram IN 200,000.00 INR
\n
Equity
\n
Enel Green Power
\n
India Private
\n
Limited
\n
51.00% 51.00%
\n
Avikiran Vayu India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Azure Blue Jay Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Azure Sky Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
AzureRanchII Wind
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Baikal Enterprise SLU
\n
Palma de
\n
Mallorca
\n
ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Baleares Energy SLU
\n
Palma de
\n
Mallorca
\n
ES 4,509.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Barnwell County Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Baylio Solar SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Beaver Falls Water
\n
Power Company
\n
Wilmington US - USD
\n
Line-by-line
\n
Beaver Valley
\n
Holdings LLC
\n
67.50% 67.50%
\n
Beaver Valley Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Beijing Tecnatom
\n
Nuclear Power Safety
\n
Technology Services
\n
Company Limited
\n
Beijing CN 280,000.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Bejaad Solar Plant Casablanca MA 10,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
99.00%
\n
99.00%
\n
Mrs Riveros Perez
\n
Paula Cristina
\n
1.00%
\n
Belltail Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Belomechetskaya WPS Moscow RU 3,010,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Bijou Hills Wind LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bioenergy Casei Gerola
\n
Srl
\n
Rome IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Bison Meadows
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Bison Meadows Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Blair Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Blue Jay Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Blue Jay Solar II LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Blue Star Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
BluRe MA San Jos\u00e9 LU 7,092,970.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
5.00% 1.65%
\n
Bogot\u00e1 ZE SAS Bogot\u00e1 CO 186,361,690.00 COP
\n
AFS Colombia ZE SAS 100.00% 47.18%
\n
Bold Elk Wind Limited
\n
Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Bondia Energia Ltda Niter\u00f3i BR 2,950,888.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Boone Stephens Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Bosa del Ebro SL Zaragoza ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Bottom Grass Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Boujdour Wind Farm Casablanca MA 300,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
90.00% 45.00%
\n
Bouldercombe Solar
\n
Farm Trust
\n
Sydney AU 10.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Bouldercombe
\n
Trust
\n
100.00% 100.00%
\n
Bouldercombe Solar
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Bouldercombe
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
Box Canyon Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
BP Hydro Finance
\n
Partnership
\n
Salt Lake City US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
24.08%
\n
100.00%
\n
Enel Kansas LLC 75.92%
\n
Brandonville Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Bravo Dome Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Brazatortas 220
\n
Renovables SL
\n
Madrid ES 3,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 16.98%
\n
23.81%
\n
Furatena Solar 1
\n
SLU
\n
16.98%
\n
Brazoria West Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Brazos Flat Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brick Road Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bronco Hills Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brush County Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Buck Canyon Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buckshutem Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Buckshutem Solar
\n
II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Buffalo Dunes Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buffalo Dunes Wind
\n
Project LLC
\n
Topeka US - USD
\n
Line-by-line
\n
EGPNA
\n
Development
\n
Holdings LLC
\n
75.00% 75.00%
\n
Buffalo Jump LP Alberta CA 10.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Buffalo Spirit Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Bungala One Finco
\n
(Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Property Trust
\n
100.00% 51.00%
\n
Bungala One Operation
\n
Holding Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala One
\n
Operations (Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One
\n
Operations Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One Property
\n
Holding (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala One Property
\n
Holding Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala One Property
\n
(Pty) Ltd
\n
Sydney AU 1,000.00 AUD
\n
AFS
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala One Property
\n
Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Finco
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Property Trust
\n
100.00% 51.00%
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala Two
\n
Operations Holding
\n
Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala Two
\n
Operations (Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two
\n
Operations Trust
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Property
\n
Holding (Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 51.00%
\n
Bungala Two Property
\n
Holding Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 50.00%
\n
Bungala Two Property
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Bungala Two
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n
Bungala Two Property
\n
Trust
\n
Sydney AU 1.00 AUD
\n
AFS
\n
Bungala Two
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 51.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Burgundy Spruce
\n
Solar LP
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Business Venture
\n
Investments 1468
\n
(Pty) Ltd
\n
Johannesburg ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Butterfly Meadows
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
C&C Castelvetere Srl Rome IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
C&C Uno Energy Srl Rome IT 118,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cactus Mesa Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Campos Promotores
\n
Renovables SL
\n
Elche ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.30% 17.74%
\n
Canastota Wind Power
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Fenner Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Caney River Wind
\n
Project LLC
\n
Overland Park US - USD
\n
Equity
\n
Rocky Caney Wind
\n
LLC
\n
100.00% 10.00%
\n
Canyon Top Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Castle Rock Ridge
\n
Limited Partnership
\n
Alberta CA - CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Catalana d\u2019Iniciatives
\n
SCR SA
\n
Barcelona ES 30,862,800.00 EUR
\n
- Endesa Red SAU 0.94% 0.66%
\n
Cattle Drive Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
CCP.RO Bucharest SA Bucharest RO 79,800,000.00 RON
\n
- Enel Romania SA 9.52% 9.52%
\n
Cdec - Sic Ltda
\n
Santiago de
\n
Chile
\n
CL 709,783,206.00 CLP
\n
-
\n
Enel Green Power
\n
Chile SA
\n
6.00% 3.90%
\n
Cedar Run Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Central Dock Sud SA Buenos Aires AR 1,231,270,567.54 ARS
\n
AFS
\n
Enel Argentina SA 0.24%
\n
33.94%
\n
Inversora Dock
\n
Sud SA
\n
71.78%
\n
Central Geradora
\n
Fotovoltaica Bom
\n
Nome Ltda
\n
Salvador BR 4,979,739.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Central Geradora
\n
Fotovoltaica S\u00e3o
\n
Francisco Ltda
\n
Niter\u00f3i BR 268,128,917.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 0.00%
\n
82.27%
\n
Enel X Brasil SA 100.00%
\n
Central Hidr\u00e1ulica
\n
G\u00fcejar-Sierra SL
\n
Seville ES 364,213.34 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.30% 23.35%
\n
Central T\u00e9rmica de
\n
Anllares AIE
\n
Madrid ES 595,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
33.33% 23.37%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Central Vuelta de
\n
Obligado SA
\n
Buenos Aires AR 500,000.00 ARS
\n
Equity
\n
Central Dock Sud
\n
SA
\n
6.40%
\n
20.93%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.30%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
33.20%
\n
Centrales Nucleares
\n
Almaraz-Trillo AIE
\n
Madrid ES - EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
24.18% 16.95%
\n
Centrum Pre Vedu A
\n
Vyskum SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 6,639.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
CES 1 Private Company Athens GR 500.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 2 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 3 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 4 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 5 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 6 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 7 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CES 8 Private Company Athens GR 501.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.20% 0.20%
\n
CESI - Centro
\n
Elettrotecnico
\n
Sperimentale Italiano
\n
Giacinto Motta SpA
\n
Milan IT 8,550,000.00 EUR
\n
Equity Enel SpA 42.70% 42.70%
\n
Champagne Storage
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Checkerboard Plains
\n
Solar Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Cheyenne Ridge II
\n
Wind Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cheyenne Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Chi Black River LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Minnesota Wind
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Operations Inc. Andover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Power Inc. Naples US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Power Marketing
\n
Inc.
\n
Wilmington US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi West LLC San Francisco US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Chinango SAC San Miguel PE 295,249,298.00 PEN Line-by-line
\n
Enel Generaci\u00f3n
\n
Per\u00fa SAA
\n
80.00% 55.02%
\n
Chisago Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Chisholm View II
\n
Holding LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Chisholm View Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Chisholm View II
\n
Holding LLC
\n
62.79% 62.79%
\n
Chisholm View Wind
\n
Project LLC
\n
New York US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
Cimarron Bend Assets
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Project I LLC
\n
49.00%
\n
100.00%
\n
Cimarron Bend
\n
Wind Project II LLC
\n
49.00%
\n
Cimarron Bend
\n
Wind Project III LLC
\n
1.00%
\n
Enel Kansas LLC 1.00%
\n
Cimarron Bend III
\n
HoldCo LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Cimarron Bend
\n
Wind Holdings
\n
III LLC
\n
100.00% 100.00%
\n
Cimarron Bend Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Project III LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend
\n
Wind Holdings
\n
III LLC
\n
100.00% 100.00%
\n
Cinch Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cipher Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
CityPoste Payment
\n
Digital Srl
\n
Teramo IT 10,000.00 EUR
\n
Equity
\n
CityPoste Payment
\n
SpA
\n
100.00% 50.00%
\n
CityPoste Payment SpA Teramo IT - EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Clear Sky Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Clinton Farms Battery
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Clinton Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cloudwalker Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Cogein Sannio Srl Rome IT 10,000.00 EUR Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cogeneraci\u00f3n El Salto
\n
SL in liquidation
\n
Zaragoza ES 36,060.73 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
20.00% 14.02%
\n
Cogenio Iberia SL Madrid ES 2,874,621.80 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
20.00% 14.02%
\n
Cogenio Srl Rome IT 2,310,000.00 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Cohuna Solar Farm
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Cohuna Holdings
\n
(Pty) Ltd
\n
100.00% 100.00%
\n
Cohuna Solar Farm
\n
Trust
\n
Sydney AU 1.00 AUD
\n
AFS
\n
Enel Green Power
\n
Cohuna Trust
\n
100.00% 100.00%
\n
Colombia ZE SAS Bogot\u00e1 CO 5,503,986,000.00 COP
\n
AFS
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Comanche Crest
\n
Ranch LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Comercializadora
\n
El\u00e9ctrica de C\u00e1diz SA
\n
Cadiz ES 600,000.00 EUR
\n
Equity Endesa Red SAU 33.50% 23.49%
\n
Compagnia Porto di
\n
Civitavecchia SpA in
\n
liquidation
\n
Rome IT 14,730,800.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
25.00% 25.00%
\n
Companhia Energ\u00e9tica
\n
do Cear\u00e1 - Coelce
\n
Fortaleza BR 1,085,346,885.76 BRL
\n
Line-by-line Enel Brasil SA 74.05% 60.92%
\n
Compa\u00f1\u00eda de
\n
Trasmisi\u00f3n del
\n
Mercosur SA - CTM
\n
Buenos Aires AR 2,025,191,313.00 ARS
\n
Line-by-line
\n
Enel Brasil SA 74.15%
\n
82.27%Enel CIEN SA 25.85%
\n
Enel SpA 0.00%
\n
Compa\u00f1\u00eda Energ\u00e9tica
\n
Veracruz SAC
\n
San Miguel PE 2,886,000.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 100.00% 82.27%
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas SA
\n
Soria ES 13,222,000.00 EUR
\n
Equity
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas SA
\n
5.00%
\n
26.29%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
35.63%
\n
Compass Rose Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Concert Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Concho Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Concord Vine Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Consolidated Hydro
\n
Southeast LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Consolidated Pumped
\n
Storage Inc.
\n
Wilmington US 550,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
81.83% 81.83%
\n
Conza Green Energy
\n
Srl
\n
Rome IT 73,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Copper Landing Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Corporaci\u00f3n
\n
Empresarial de
\n
Extremadura SA
\n
Badajoz ES 44,538,000.00 EUR
\n
- Endesa SA 1.01% 0.71%
\n
Corporaci\u00f3n E\u00f3lica de
\n
Zaragoza SL
\n
La Puebla de
\n
Alfinden
\n
ES 271,652.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.00% 17.53%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Country Roads Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cow Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cr\u00e9dito F\u00e1cil Codensa
\n
SA Compa\u00f1\u00eda de
\n
Financiamiento
\n
Bogot\u00e1 CO 32,000,000,000.00 COP
\n
Equity
\n
Colombia ZE SAS 0.00%
\n
23.12%
\n
Enel Colombia SA
\n
ESP
\n
48.99%
\n
Enel X Colombia
\n
SAS ESP
\n
0.00%
\n
Crockett Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Cross Trails Energy
\n
Storage Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cross Trails GESS LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Dairy Meadows Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Daisy Patch Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Danax Energy (Pty) Ltd Sandton ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Dappled Colt Storage
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Dara Solar Investment
\n
Srl
\n
Bucharest RO 14,392,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Dauphin Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
De Rock Int\u2019l Srl Bucharest RO 5,629,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Decimalfigure -
\n
Unipessoal Ltda
\n
Pego PT 2,000.00 EUR
\n
Equity
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica
\n
SA
\n
100.00% 30.68%
\n
Dehesa de los
\n
Guadalupes Solar SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 03
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 04
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Derivex SA Bogot\u00e1 CO 715,292,000.00 COP
\n
-
\n
Enel Colombia SA
\n
ESP
\n
5.00% 2.36%
\n
Desarrollo de Fuerzas
\n
Renovables S de RL
\n
de Cv
\n
Mexico City MX 33,101,350.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99%
\n
100.00%
\n
Kino Facilities
\n
Manager SA de Cv
\n
0.01%
\n
Desert Willow Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
DI.T.N.E. - Distretto
\n
Tecnologico Nazionale
\n
sull\u2019Energia \u2013
\n
Societ\u00e0 Consortile a
\n
Responsabilit\u00e0 Limitata
\n
Rome IT 444,206.61 EUR
\n
-
\n
Enel Produzione
\n
SpA
\n
1.73% 1.73%
\n
Diamond Vista
\n
Holdings LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Diamond Vista Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Dispatch Renewable
\n
Energy Societe
\n
Anonyme
\n
Heraklion, Crete GR 440,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.00% 0.00%
\n
Distribuidora de
\n
Energ\u00eda El\u00e9ctrica del
\n
Bages SA
\n
Barcelona ES 108,240.00 EUR
\n
Line-by-line
\n
Endesa Red SAU 55.00%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
45.00%
\n
Distribuidora El\u00e9ctrica
\n
del Puerto de la Cruz
\n
SAU
\n
Santa Cruz de
\n
Tenerife
\n
ES 12,621,210.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Distrilec Inversora SA Buenos Aires AR 497,612,021.00 ARS
\n
Line-by-line Enel Am\u00e9ricas SA 51.50% 42.37%
\n
Dodge Center
\n
Distributed Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Dolores Wind SA de Cv Mexico City MX 200.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Dominica Energ\u00eda
\n
Limpia SA de Cv
\n
Mexico City MX 2,070,600,646.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Dorset Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Dover Solar I LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Dragonfly Fields Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Drift Sand Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity Enel Kansas LLC 50.00% 50.00%
\n
Drift Sand Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Drift Sand Wind
\n
Holdings LLC
\n
100.00% 50.00%
\n
Dwarka Vayu 1 Private
\n
Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
E.S.CO. Comuni Srl Bergamo IT 1,000,000.00 EUR
\n
Line-by-line Enel X Italia Srl 60.00% 60.00%
\n
Earthly Reflections
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Eastwood Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Ebenezer Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ecosolar2 Private
\n
Company
\n
Grevena GR 1,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.10%
\n
Edgartown Depot Solar
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
Madrid ES 1,204,540,060.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
E-Distribu\u0163ie Banat SA Timisoara RO 382,158,580.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
E-Distribu\u0163ie Dobrogea
\n
SA
\n
Constan\u0163a RO 280,285,560.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
E-Distribu\u0163ie Muntenia
\n
SA
\n
Bucharest RO 271,635,250.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 78.00% 78.00%
\n
e-distribuzione SpA Rome IT 2,600,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
EF Divesture LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Efficientya Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
EGP Australia (Pty) Ltd Sydney AU 10,000.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
EGP Bioenergy Srl Rome IT 1,000,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Puglia Srl
\n
100.00% 100.00%
\n
EGP fotovoltaica La
\n
Loma SAS in liquidation
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
EGP Geronimo Holding
\n
Company Inc.
\n
Wilmington US 1,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP HoldCo 1 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 10 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 11 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 12 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 13 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 14 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 15 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 16 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 17 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 18 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 2 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 3 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 4 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 5 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 6 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGP HoldCo 7 LLC Andover US - USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 8 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP HoldCo 9 LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGP Magdalena Solar
\n
SA de Cv
\n
Mexico City MX 691,771,740.00 MXN
\n
Line-by-line
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.00%
\n
100.00%
\n
Hidroelectricidad
\n
del Pac\u00edfico S de RL
\n
de Cv
\n
1.00%
\n
EGP Matimba NewCo
\n
1 Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
EGP Matimba NewCo
\n
2 Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
EGP Nevada Power LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP North America
\n
PPA LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP Salt Wells Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP San Leandro
\n
Microgrid I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP Solar Services LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
EGP Stillwater Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Stillwater LLC 100.00% 100.00%
\n
EGP Stillwater Solar PV
\n
II LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Stillwater Woods
\n
Hill Holdings LLC
\n
100.00% 100.00%
\n
EGP Timber Hills
\n
Project LLC
\n
Los Angeles US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
1 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
10 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
11 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
12 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
13 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
14 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
15 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
16 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
17 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
18 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2020 HoldCo
\n
19 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
2 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
20 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
21 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
22 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
23 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
24 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
25 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
26 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
27 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
28 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
29 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
3 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
30 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
4 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
5 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
6 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
7 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
8 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo
\n
9 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
1 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
10 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
11 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
12 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
13 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2023 HoldCo
\n
14 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
15 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
16 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
17 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
18 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
19 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
2 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
20 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
3 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
4 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
5 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
6 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
7 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
8 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo
\n
9 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA Development
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America
\n
Development LLC
\n
100.00% 100.00%
\n
EGPNA Hydro Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Preferred Wind
\n
Holdings II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Preferred Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
1 LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA Project HoldCo
\n
2 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
5 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
6 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo
\n
7 LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Renewable
\n
Energy Partners LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA REP
\n
Holdings LLC
\n
10.00% 10.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA REP Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA REP Solar
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA REP Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Renewable
\n
Energy Partners
\n
LLC
\n
100.00% 10.00%
\n
EGPNA Wind Holdings
\n
1 LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
EGPNA-SP Seven
\n
Cowboy Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Elcogas SA in
\n
liquidation
\n
Puertollano
\n
(Ciudad Real)
\n
ES 809,690.40 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
40.99%
\n
33.06%
\n
Enel SpA 4.32%
\n
Elcomex Solar Energy
\n
Srl
\n
Bucharest RO 4,590,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Elecgas SA Pego PT 50,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
50.00% 35.06%
\n
Electra Capital (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
El\u00e9ctrica de Jafre SA Barcelona ES 165,876.00 EUR
\n
Line-by-line
\n
Endesa Red SAU 52.54%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
47.46%
\n
El\u00e9ctrica de Lijar SL Cadiz ES 1,081,821.79 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
El\u00e9ctrica del Ebro SAU Barcelona ES 500,000.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Electricidad de Puerto
\n
Real SA
\n
Cadiz ES 4,960,246.40 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
Electrometal\u00fargica del
\n
Ebro SL
\n
Barcelona ES 2,906,862.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
0.18% 0.12%
\n
Electrotest
\n
Instalaciones, Montajes
\n
y Mantenimientos SL
\n
Puerto Real ES 10,000.00 EUR
\n
- Epresa Energ\u00eda SA 50.00% 17.53%
\n
Eletropaulo
\n
Metropolitana
\n
Eletricidade de S\u00e3o
\n
Paulo SA
\n
S\u00e3o Paulo BR 3,079,524,934.33 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Elini Antwerp BE 76,273,810.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
4.00% 1.32%
\n
Emerald Crescent Solar
\n
Limited Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Emerging Networks El
\n
Salvador SA de Cv
\n
San Salvador SV 2,000.00 USD
\n
-
\n
Emerging Networks
\n
Guatemala SA
\n
1.00%
\n
19.50%
\n
Livister Latam SLU 99.00%
\n
Emerging Networks
\n
Guatemala SA
\n
Guatemala City GT 742,000.00 GTQ
\n
-
\n
Livister Latam SLU 99.99%
\n
19.50%
\n
Ufinet Guatemala
\n
SA
\n
0.01%
\n
Emerging Networks
\n
Latam Inc.
\n
Wilmington US 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
Emerging Networks
\n
Panama SA
\n
Panama City PA 300.00 USD
\n
-
\n
IFX/Eni - SPC
\n
Panama Inc.
\n
100.00% 19.50%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Emintegral Cycle SLU Madrid ES 3,000.00 EUR Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Empresa Carbon\u00edfera
\n
del Sur - ENCASUR
\n
SAU
\n
Madrid ES 18,030,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
Distribuci\u00f3n SAU
\n
Ceuta ES 9,335,000.00 EUR
\n
Line-by-line
\n
Empresa de
\n
Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
SA
\n
100.00% 67.61%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
Energ\u00eda SLU
\n
Ceuta ES 10,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta SA
\n
Ceuta ES 16,562,250.00 EUR
\n
Line-by-line Endesa Red SAU 96.42% 67.61%
\n
Empresa de
\n
Generaci\u00f3n El\u00e9ctrica
\n
Los Pinos SA
\n
San Miguel PE 7,928,044.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
0.00%
\n
Empresa de
\n
Generaci\u00f3n El\u00e9ctrica
\n
Marcona SAC
\n
San Miguel PE 3,368,424.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
0.00%
\n
Empresa Distribuidora
\n
Sur SA - Edesur
\n
Buenos Aires AR 898,585,028.00 ARS
\n
Line-by-line
\n
Distrilec Inversora
\n
SA
\n
56.36%
\n
59.33%
\n
Enel Argentina SA 43.10%
\n
Empresa El\u00e9ctrica
\n
Pehuenche SA
\n
Santiago de
\n
Chile
\n
CL 175,774,920,733.00 CLP
\n
Line-by-line
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
92.65% 56.27%
\n
Empresa Propietaria de
\n
la Red SA
\n
Panama City PA 58,500,000.00 USD
\n
- Enel SpA 11.11% 11.11%
\n
En. Solar 7 Single
\n
Member Private
\n
Company
\n
Maroussi GR 1,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Endesa Capital SAU Madrid ES 60,200.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa
\n
Comercializa\u00e7\u00e3o de
\n
Energia SA
\n
Porto PT 250,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Energ\u00eda
\n
Renovable SLU
\n
Madrid ES 100,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Energ\u00eda SAU Madrid ES 14,445,575.90 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Financiaci\u00f3n
\n
Filiales SAU
\n
Madrid ES 4,621,003,006.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
II SAU
\n
Seville ES 63,107.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
Nuclear SAU
\n
Seville ES 60,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
Lisbon PT 50,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
0.20%
\n
70.12%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
99.20%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
0.60%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
Seville ES 1,940,379,735.35 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Ingenier\u00eda SLU Seville ES 965,305.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Endesa Medios y
\n
Sistemas SLU
\n
Madrid ES 89,999,790.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Operaciones y
\n
Servicios Comerciales
\n
SLU
\n
Madrid ES 10,138,580.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Endesa Red SAU Madrid ES 719,901,723.26 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa X Servicios SLU Madrid ES 60,000.00 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa X Way SL Madrid ES 600,000.00 EUR
\n
Line-by-line
\n
Endesa X Servicios
\n
SLU
\n
49.00%
\n
85.36%
\n
Enel X Way Srl 51.00%
\n
Endesa SA Madrid ES 1,270,502,540.40 EUR
\n
Line-by-line
\n
Endesa SA 0.02%
\n
70.12%
\n
Enel Iberia SRLU 70.10%
\n
Enel Alberta Solar Inc. Calgary CA 1.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Alberta Storage
\n
Inc.
\n
Calgary CA 1.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Alberta Wind Inc. Alberta CA 16,251,021.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Am\u00e9ricas SA
\n
Santiago de
\n
Chile
\n
CL 15,799,498,544.85 USD
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.00%
\n
82.27%
\n
Enel SpA 82.27%
\n
Enel and Shikun & Binui
\n
Innovation Infralab Ltd
\n
Airport City IL 38,000.00 ILS
\n
Equity Enel Grids Srl 50.00% 50.00%
\n
Enel Argentina SA Buenos Aires AR 2,297,711,908.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.92%
\n
82.25%
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
0.08%
\n
Enel Bella Energy
\n
Storage LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Enel Brasil Central SA Rio de Janeiro BR 49,440.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 20.23%
\n
82.27%
\n
Enel X Brasil SA 79.77%
\n
Enel Brasil SA Niter\u00f3i BR 38,070,269,190.10 BRL
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.56%
\n
82.27%
\n
Enel Brasil SA 0.44%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Chile SA
\n
Santiago de
\n
Chile
\n
CL 3,882,103,470,184.00 CLP
\n
Line-by-line Enel SpA 64.93% 64.93%
\n
Enel CIEN SA Rio de Janeiro BR 285,044,682.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Colina SA
\n
Santiago de
\n
Chile
\n
CL 82,222,000.00 CLP
\n
Line-by-line
\n
Enel Chile SA 0.00%
\n
64.34%
\n
Enel Distribuci\u00f3n
\n
Chile SA
\n
100.00%
\n
Enel Colombia SA ESP Bogot\u00e1 CO 655,222,312,800.00 COP
\n
Line-by-line Enel Am\u00e9ricas SA 57.34% 47.18%
\n
Enel Costa Rica CAM
\n
SA
\n
San Jos\u00e9 CR 27,500,000.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Enel Cove Fort II LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Cove Fort LLC Beaver US - USD
\n
Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Distribuci\u00f3n Chile
\n
SA
\n
Santiago de
\n
Chile
\n
CL 177,568,664,063.00 CLP
\n
Line-by-line Enel Chile SA 99.09% 64.34%
\n
Enel Distribuci\u00f3n Per\u00fa
\n
SAA
\n
San Miguel PE 638,563,900.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 83.15% 68.41%
\n
Enel Energia SpA Rome IT 10,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Energ\u00eda SA de Cv Mexico City MX 25,000,100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00% 100.00%
\n
Enel Energie Muntenia
\n
SA
\n
Bucharest RO 37,004,350.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 78.00% 78.00%
\n
Enel Energie SA Bucharest RO 140,000,000.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 51.00% 51.00%
\n
Enel Energy Australia
\n
(Pty) Ltd
\n
Sydney AU 200,100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Illinois LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Ohio LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Pennsylvania
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America Texas LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North
\n
America LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel Energy South
\n
Africa
\n
Wilmington ZA 100.00 ZAR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel Energy Storage
\n
Holdings LLC (formerly
\n
EGP Energy Storage
\n
Holdings LLC)
\n
Andover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Finance America
\n
LLC
\n
Wilmington US 200,000,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Finance
\n
International NV
\n
Amsterdam NL 1,478,810,371.00 EUR
\n
Line-by-line
\n
Enel Holding
\n
Finance Srl
\n
75.00%
\n
100.00%
\n
Enel SpA 25.00%
\n
Enel Fortuna SA Panama City PA 100,000,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
50.06% 23.62%
\n
Enel Future Project
\n
2020 #1 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #10 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #11 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #12 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #13 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #14 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Future Project
\n
2020 #15 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #16 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #17 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #18 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #19 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #2 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #20 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #3 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #4 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #5 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #6 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #7 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #8 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Future Project
\n
2020 #9 LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Enel Generaci\u00f3n Chile
\n
SA
\n
Santiago de
\n
Chile
\n
CL 552,777,320,871.00 CLP
\n
Line-by-line Enel Chile SA 93.55% 60.74%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
Buenos Aires AR 701,988,378.00 ARS
\n
AFS Enel Argentina SA 75.68% 62.25%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
Buenos Aires AR 18,321,776,559.00 ARS
\n
Line-by-line
\n
Enel Argentina SA 8.67%
\n
54.07%
\n
Hidroinvest SA 59.00%
\n
Enel Generaci\u00f3n Per\u00fa
\n
SAA
\n
San Miguel PE 1,538,101,266.24 PEN
\n
Line-by-line Enel Per\u00fa SAC 83.60% 68.78%
\n
Enel Generaci\u00f3n Piura
\n
SA
\n
San Miguel PE 73,982,594.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 96.50% 79.39%
\n
Enel Generaci\u00f3n SA
\n
de Cv
\n
Mexico City MX 7,100,100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00% 100.00%
\n
Enel Geothermal LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Global Services Srl Rome IT 10,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Global Trading
\n
SpA
\n
Rome IT 90,885,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power
\n
25RoseFarms Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Argentina SA
\n
Buenos Aires AR 463,577,761.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.86%
\n
82.27%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.14%
\n
Enel Green Power
\n
Aroeira 01 SA
\n
Rio de Janeiro BR 134,518,400.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 02 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 03 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 04 SA
\n
Rio de Janeiro BR 134,638,500.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Aroeira 05 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 06 SA
\n
Rio de Janeiro BR 134,511,000.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 07 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 08 SA
\n
Rio de Janeiro BR 134,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Aroeira 09 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo Participa\u00e7\u00f5es
\n
SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Australia Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Azure Ranchland
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
AzureRanchII Wind
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Boa
\n
Vista 01 Ltda
\n
Salvador BR 3,554,607.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Boa
\n
Vista E\u00f3lica SA
\n
Rio de Janeiro BR 42,890,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Bouldercombe Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Bouldercombe Trust
\n
Sydney AU 10.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Brejol\u00e2ndia Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Bungala Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cabe\u00e7a de Boi SA
\n
Niter\u00f3i BR 270,114,539.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Cachoeira Dourada SA
\n
Cachoeira
\n
Dourada
\n
BR 64,339,835.85 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.61%
\n
82.07%
\n
Enel Green Power
\n
Cachoeira Dourada
\n
SA
\n
0.15%
\n
Enel Green Power
\n
Canada Inc.
\n
Montreal CA 85,681,857.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cerrado Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Chile SA
\n
Santiago de
\n
Chile
\n
CL 842,121,530.67 USD
\n
Line-by-line
\n
Enel Chile SA 99.99%
\n
64.93%
\n
Enel SpA 0.01%
\n
Enel Green Power
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Cohuna Holdings (Pty)
\n
Ltd
\n
Sydney AU 3,419,700.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Cohuna Trust
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power Cove
\n
Fort Solar LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Cristal E\u00f3lica SA
\n
Rio de Janeiro BR 87,784,899.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.63%
\n
82.27%
\n
Enel Green Power
\n
Cristal E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.37%
\n
Enel Green Power
\n
Cumaru 01 SA
\n
Niter\u00f3i BR 204,653,590.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 02 SA
\n
Niter\u00f3i BR 237,601,272.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 03 SA
\n
Rio de Janeiro BR 225,021,296.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 04 SA
\n
Rio de Janeiro BR 230,869,708.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Cumaru 05 SA
\n
Rio de Janeiro BR 180,208,000.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.94%
\n
82.22%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Cumaru Participa\u00e7oes
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Cumaru Solar 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Cumaru Solar 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Damascena E\u00f3lica SA
\n
Rio de Janeiro BR 83,709,003.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.16%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.84%
\n
Enel Green Power
\n
Delfina A E\u00f3lica SA
\n
Rio de Janeiro BR 284,062,483.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina B E\u00f3lica SA
\n
Rio de Janeiro BR 93,068,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina C E\u00f3lica SA
\n
Rio de Janeiro BR 31,105,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina D E\u00f3lica SA
\n
Rio de Janeiro BR 105,864,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Delfina E E\u00f3lica SA
\n
Niter\u00f3i BR 105,936,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Desenvolvimento Ltda
\n
Rio de Janeiro BR 61,617,590.35 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Green Power
\n
Development Srl
\n
Rome IT 20,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Diamond Vista Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Diamond Vista
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power Dois
\n
Riachos E\u00f3lica SA
\n
Rio de Janeiro BR 83,347,009.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Egypt SAE
\n
Cairo EG 250,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power El
\n
Salvador SA de Cv
\n
El Salvador SV 22,860.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.96%
\n
99.99%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.04%
\n
Enel Green Power
\n
Elkwater Wind Limited
\n
Partnership
\n
Alberta CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.00%
\n
Enel Green Power
\n
Elmsthorpe Wind LP
\n
Calgary CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power
\n
Emiliana E\u00f3lica SA
\n
Rio de Janeiro BR 97,191,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.35%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.65%
\n
Enel Green Power
\n
Emiliana E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
Madrid ES 11,152.74 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Esperan\u00e7a E\u00f3lica SA
\n
Rio de Janeiro BR 99,418,174.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.89%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.11%
\n
Enel Green Power
\n
Esperan\u00e7a Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Estonian Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Fazenda SA
\n
Niter\u00f3i BR 264,141,174.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Fence Post Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Flat
\n
Rocks One Holding
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
EGP Australia (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Enel Green Power Flat
\n
Rocks One Holding
\n
Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Fontes dos Ventos 2 SA
\n
Rio de Janeiro BR 183,315,219.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Fontes dos Ventos 3 SA
\n
Rio de Janeiro BR 221,001,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Fontes II Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Fontes Solar SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ganado Solar Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Germany GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Girgarre Holdings
\n
(Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Enel Green Power
\n
Girgarre Trust
\n
Sydney AU 10.00 AUD
\n
AFS
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 100.00%
\n
Enel Green Power
\n
Global Investment BV
\n
Amsterdam NL 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hadros Wind Limited
\n
Partnership
\n
- CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.00%
\n
Enel Green Power
\n
Hellas SA
\n
Maroussi GR 40,187,850.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
Maroussi GR 600,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
Maroussi GR 141,569,641.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Hilltopper Wind LLC
\n
(formerly Hilltopper
\n
Wind Power LLC)
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Hilltopper Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Horizonte MP Solar SA
\n
Rio de Janeiro BR 431,566,053.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.01%
\n
82.27%
\n
Enel Brasil SA 99.99%
\n
Enel Green Power India
\n
Private Limited
\n
New Delhi IN 200,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
100.00% 100.00%
\n
Enel Green Power
\n
Italia Srl
\n
Rome IT 272,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Green Power
\n
Ituverava Norte Solar
\n
SA
\n
Rio de Janeiro BR 219,806,645.67 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.08%
\n
82.27%
\n
Enel Brasil SA 99.92%
\n
Enel Green Power
\n
Brasil Participa\u00e7\u00f5es
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ituverava Solar SA
\n
Rio de Janeiro BR 227,810,333.00 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Ituverava Sul Solar SA
\n
Rio de Janeiro BR 408,949,643.00 BRL
\n
Line-by-line
\n
Bondia Energia
\n
Ltda
\n
0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Joana E\u00f3lica SA
\n
Rio de Janeiro BR 90,259,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.33%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.67%
\n
Enel Green Power
\n
Kenya Limited
\n
Nairobi KE 100,000.00 KES
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.00%
\n
100.00%
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
1.00%
\n
Enel Green Power
\n
Korea LLC
\n
Seoul KR 5,665,000,000.00 KRW
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Lagoa do Sol 01 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 02 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 03 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 04 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 06 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 07 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Lagoa do Sol 08 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa do Sol 09 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa II Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa III Participa\u00e7\u00f5es
\n
SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Lagoa Participa\u00e7\u00f5es SA
\n
(formerly Enel Green
\n
Power Projetos 45 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Lily
\n
Solar Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Mani\u00e7oba E\u00f3lica SA
\n
Rio de Janeiro BR 90,722,530.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.20%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.80%
\n
Enel Green Power
\n
Matimba Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Enel Green Power
\n
Metehara Solar Privrate
\n
Limited Company
\n
- ET 5,600,000.00 ETB
\n
Line-by-line
\n
Enel Green Power
\n
Solar Metehara SpA
\n
80.00% 80.00%
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
Mexico City MX 662,949,966.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Enel Green Power
\n
Modelo I E\u00f3lica SA
\n
Rio de Janeiro BR 70,842,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Modelo II E\u00f3lica SA
\n
Rio de Janeiro BR 63,742,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morocco SARLAU
\n
Casablanca MA 639,000,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
0.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
100.00%
\n
Enel Green Power
\n
Morro do Chap\u00e9u I
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 248,138,287.11 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morro do Chap\u00e9u II
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 206,050,114.05 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Morro do Chap\u00e9u
\n
Solar 01 SA (formerly
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo III
\n
Participa\u00e7\u00f5es SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Morro Norte 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Morro Norte 04 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Mour\u00e3o SA
\n
Rio de Janeiro BR 25,600,100.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Namibia (Pty) Ltd
\n
Windhoek NA 10,000.00 NAD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
North America
\n
Development LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Green Power
\n
North America Inc.
\n
Andover US - USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Green Power Nova
\n
Olinda 01 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 02 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 03 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 04 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 06 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 07 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 08 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Nova
\n
Olinda 09 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Novo
\n
Lapa 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 04 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 05 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 06 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 07 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power Novo
\n
Lapa 08 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power O&M
\n
Solar LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Paranapanema SA
\n
Niter\u00f3i BR 162,567,500.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Partecipazioni Speciali
\n
Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Pau
\n
Ferro E\u00f3lica SA
\n
Rio de Janeiro BR 74,124,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 97.92%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
2.08%
\n
Enel Green Power
\n
Pau Ferro E\u00f3lica SA
\n
0.00%
\n
Enel Green Power
\n
Pedra do Ger\u00f4nimo
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 119,319,527.57 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.25%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.75%
\n
Enel Green Power Per\u00fa
\n
SAC
\n
San Miguel PE 1,291,373,507.00 PEN
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Enel Green Power
\n
Primavera E\u00f3lica SA
\n
Rio de Janeiro BR 95,674,900.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.50%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.50%
\n
Enel Green Power
\n
Puglia Srl
\n
Rome IT 1,000,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power RA
\n
SAE in liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Rattlesnake Creek
\n
Wind Project LLC
\n
(formerly Rattlesnake
\n
Creek Wind Project
\n
LLC)
\n
Delaware US 1.00 USD Line-by-line
\n
Rattlesnake Creek
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings II LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings II LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Rockhaven Ranchland
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Romania Srl
\n
Bucharest RO 2,430,631,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Roseland Solar LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power RSA
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
EGP Matimba
\n
NewCo 1 Srl
\n
100.00% 50.00%
\n
Enel Green Power RSA
\n
2 (RF) (Pty) Ltd
\n
Johannesburg ZA 120.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
Moscow RU 60,500,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
99.00%
\n
Enel Green Power SpA Rome IT 272,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power Salto
\n
Apiac\u00e1s SA (formerly
\n
Enel Green Power
\n
Damascena E\u00f3lica SA)
\n
Rio de Janeiro BR 274,420,832.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Sannio Srl
\n
Rome IT 750,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power S\u00e3o
\n
Abra\u00e3o E\u00f3lica SA
\n
Rio de Janeiro BR 91,300,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Cirilo 01 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Cirilo 02 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Cirilo 03 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 01 SA
\n
(formerly Enel Green
\n
Power Projetos 10)
\n
Teresina BR 74,960,396.92 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 02 SA
\n
(formerly Enel Green
\n
Power Projetos 11)
\n
Teresina BR 82,268,018.57 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 07 SA
\n
(formerly Enel Green
\n
Power Projetos 42 SA)
\n
Teresina BR 114,522,004.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 08 SA
\n
(formerly Enel Green
\n
Power Projetos 43 SA)
\n
Teresina BR 109,281,818.16 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 10 SA
\n
(formerly Enel Green
\n
Power Projetos 15)
\n
Teresina BR 82,871,484.32 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 11 SA
\n
(formerly Enel Green
\n
Power Projetos 44 SA)
\n
Teresina BR 114,475,154.82 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 12 SA
\n
(formerly Enel Green
\n
Power Projetos 22 SA)
\n
Teresina BR 108,022,914.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 14
\n
Teresina BR 147,279,287.77 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 15
\n
Teresina BR 120,057,468.67 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 17 SA
\n
Teresina BR 122,007,042.67 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 18 SA
\n
(formerly Enel Green
\n
Power Ventos de Santa
\n
\u00c2ngela 13 SA)
\n
Teresina BR 120,981,744.40 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 19 SA
\n
Teresina BR 122,467,788.77 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 21 SA
\n
(formerly Enel Green
\n
Power Projetos 16)
\n
Teresina BR 89,994,200.26 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
S\u00e3o Gon\u00e7alo 22 SA
\n
(formerly Enel Green
\n
Power Projetos 30)
\n
Teresina BR 89,787,960.25 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 3 SA (formerly
\n
Enel Green Power
\n
Projetos 12)
\n
Teresina BR 75,324,686.12 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 4 SA (formerly
\n
Enel Green Power
\n
Projetos 13)
\n
Teresina BR 82,925,257.61 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 5 SA (formerly
\n
Enel Green Power
\n
Projetos 14)
\n
Teresina BR 82,230,525.15 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 6 SA (formerly
\n
Enel Green Power
\n
Projetos 19 SA)
\n
Teresina BR 183,602,691.38 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power
\n
Brasil Participa\u00e7\u00f5es
\n
Ltda
\n
0.00%
\n
Enel Green Power S\u00e3o
\n
Judas E\u00f3lica SA
\n
Niter\u00f3i BR 82,674,900.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.26%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.74%
\n
Enel Green Power S\u00e3o
\n
Micael 01 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 9 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
Enel Green Power S\u00e3o
\n
Micael 02 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 13)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power S\u00e3o
\n
Micael 03 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 16 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Alba Energia Ltda 0.10%
\n
82.27%
\n
Enel Brasil SA 99.90%
\n
Enel Green Power S\u00e3o
\n
Micael 04 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 20 SA)
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power S\u00e3o
\n
Micael 05 SA
\n
Teresina BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Services LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power SHU
\n
SAE in liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Singapore Pte Ltd
\n
Singapore SG 8,000,000.00 SGD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Energy Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Metehara SpA
\n
Rome IT 50,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Solar
\n
Ngonye SpA (formerly
\n
Enel Green Power
\n
Africa Srl)
\n
Rome IT 50,000.00 EUR
\n
AFS
\n
EGP Matimba
\n
NewCo 2 Srl
\n
100.00% 100.00%
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
South Africa 3 (Pty) Ltd
\n
Gauteng ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Stampede Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Swift
\n
Wind LP
\n
Calgary CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power
\n
Tacaic\u00f3 E\u00f3lica SA
\n
Rio de Janeiro BR 50,034,360.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 97.87%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
2.13%
\n
Enel Green Power
\n
Tefnut SAE in
\n
liquidation
\n
Cairo EG 15,000,000.00 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Turkey Enerj\u00ed Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 37,141,108.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
UB33 GmbH & Co. KG
\n
Berlin DE 75,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 1 SA
\n
Teresina BR 182,273,006.17 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 10 SA (formerly
\n
Enel Green Power
\n
Projetos 21)
\n
Teresina BR 122,100,849.07 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 11 SA (formerly
\n
Enel Green Power
\n
Projetos 23)
\n
Teresina BR 132,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 14 SA (formerly
\n
Enel Green Power
\n
Projetos 24)
\n
Teresina BR 198,554,956.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 15 SA (formerly
\n
Enel Green Power
\n
Projetos 25)
\n
Teresina BR 125,100,849.07 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 17 SA (formerly
\n
Enel Green Power
\n
Projetos 26)
\n
Teresina BR 152,022,288.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 19 SA (formerly
\n
Enel Green Power
\n
Projetos 27)
\n
Teresina BR 95,587,248.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 2 SA
\n
Teresina BR 299,922,006.17 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 20 SA (formerly
\n
Enel Green Power
\n
Projetos 28)
\n
Teresina BR 92,895,408.95 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 21 SA (formerly
\n
Enel Green Power
\n
Projetos 29)
\n
Teresina BR 41,179,409.72 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 3 SA (formerly
\n
Enel Green Power
\n
Projetos 4)
\n
Teresina BR 99,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 4 SA (formerly
\n
Enel Green Power
\n
Projetos 6)
\n
Teresina BR 100,732,205.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 5 SA (formerly
\n
Enel Green Power
\n
Projetos 7)
\n
Teresina BR 84,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 6 SA (formerly
\n
Enel Green Power
\n
Projetos 8)
\n
Teresina BR 83,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 7 SA (formerly
\n
Enel Green Power
\n
Projetos 9)
\n
Teresina BR 81,245,805.55 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
Esperan\u00e7a Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 8 SA (formerly
\n
Enel Green Power
\n
Projetos 18)
\n
Teresina BR 91,786,606.48 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela 9 SA (formerly
\n
Enel Green Power
\n
Projetos 20)
\n
Teresina BR 118,786,606.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 12
\n
(formerly Enel Green
\n
Power Projetos 36)
\n
Teresina BR 94,727,364.09 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 13 SA
\n
(formerly Enel Green
\n
Power Projetos 17 SA)
\n
Teresina BR 77,496,725.02 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 16 SA
\n
(formerly Enel Green
\n
Power Projetos 38 SA)
\n
Teresina BR 89,917,563.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
\u00c2ngela ACL 18 SA
\n
(formerly Enel Green
\n
Power Projetos 47 SA)
\n
Teresina BR 86,496,703.24 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 08 SA
\n
(formerly Enel Green
\n
Power Projetos 34 SA)
\n
Rio de Janeiro BR 173,154,500.67 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 1 SA
\n
(formerly Enel Green
\n
Power Fonte dos
\n
Ventos 1 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 13 (formerly
\n
Enel Green Power
\n
Projetos 33 SA)
\n
Rio de Janeiro BR 221,832,010.12 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 15 SA
\n
Rio de Janeiro BR 292,888,027.82 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 16 SA
\n
(formerly Enel Green
\n
Power Projetos 35 SA)
\n
Rio de Janeiro BR 252,240,012.65 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 17 SA
\n
(formerly Enel Green
\n
Power Projetos 31 SA)
\n
Rio de Janeiro BR 252,240,012.65 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 21 SA
\n
(formerly Enel Green
\n
Power Projetos 37 SA)
\n
Rio de Janeiro BR 276,814,829.93 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 22 SA
\n
(formerly Enel Green
\n
Power Projetos 39 SA)
\n
Rio de Janeiro BR 274,625,153.91 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 25 SA
\n
(formerly Enel Green
\n
Power Projetos 40 SA)
\n
Rio de Janeiro BR 171,324,007.59 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 26 SA
\n
(formerly Enel Green
\n
Power Projetos 41 SA)
\n
Rio de Janeiro BR 344,251,125.91 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 26 SA
\n
(formerly Enel
\n
Green Power
\n
Projetos 41 SA)
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 3 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santa
\n
Esperan\u00e7a 7 SA
\n
(formerly Enel Green
\n
Power Lagedo Alto SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green
\n
Power Ventos de
\n
Santa Esperan\u00e7a
\n
Participa\u00e7\u00f5es SA
\n
(formerly Enel Green
\n
Power Cumaru 06 SA)
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santo
\n
Orestes 1 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de Santo
\n
Orestes 2 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
01 SA
\n
Teresina BR 383,436,550.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
02 SA
\n
Teresina BR 369,758,650.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
03 SA
\n
Teresina BR 112,576,700.90 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
04 SA
\n
Teresina BR 379,980,530.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
05 SA
\n
Teresina BR 212,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
06 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
07 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
08 SA
\n
Teresina BR 337,473,758.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
11 SA
\n
Teresina BR 318,740,450.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
13 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
16 SA
\n
Teresina BR 353,284,550.79 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
17 SA
\n
Teresina BR 298,952,100.79 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
18 SA
\n
Teresina BR 332,473,758.81 BRL Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
19 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
22 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
26 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Ventos de S\u00e3o Roque
\n
29 SA
\n
Teresina BR 112,501,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power
\n
Verwaltungs GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power
\n
Vietnam LLC (C\u00f4ng
\n
ty TNHH Enel Green
\n
Power Vi\u0265t Nam)
\n
Ho Chi Minh
\n
City
\n
VN 2,431,933.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power
\n
Villoresi Srl
\n
Rome IT 1,200,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
51.00% 51.00%
\n
Enel Green Power Volta
\n
Grande SA (formerly
\n
Enel Green Power
\n
Projetos I SA)
\n
Niter\u00f3i BR 565,756,528.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Zambia Limited
\n
Lusaka ZM 15,000.00 ZMW
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
1.00%
\n
100.00%
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
99.00%
\n
Enel Green Power Zeus
\n
II - Delfina 8 SA
\n
Rio de Janeiro BR 77,939,980.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Zeus
\n
Sul 1 Ltda
\n
Rio de Janeiro BR 6,986,993.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Zeus
\n
Sul 2 SA
\n
Rio de Janeiro BR 1,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.90%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.10%
\n
Enel Grids Srl Rome IT 10,100,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Guatemala SA Guatemala City GT 67,208,000.00 GTQ
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.00%
\n
47.18%
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Holding Finance
\n
Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Iberia SRLU Madrid ES 336,142,500.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Innovation Hubs
\n
Srl
\n
Rome IT 1,100,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Insurance NV Amsterdam NL 60,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Investment
\n
Holding BV
\n
Amsterdam NL 1,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Italia SpA Rome IT 100,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Kansas
\n
Development Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Kansas LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Land HoldCo LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Logistics Srl Rome IT 1,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Minnesota
\n
Holdings LLC
\n
Minneapolis US - USD
\n
Line-by-line
\n
EGP Geronimo
\n
Holding Company
\n
Inc.
\n
100.00% 100.00%
\n
Enel Nevkan Inc. Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel North America Inc. Andover US 50.00 USD
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Operations
\n
Canada Ltd
\n
Alberta CA 1,000.00 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Panam\u00e1 CAM Srl Panama City PA 3,001.00 USD
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.03%
\n
47.19%
\n
Enel Colombia SA
\n
ESP
\n
99.97%
\n
Enel Per\u00fa SAC San Miguel PE 5,361,789,105.00 PEN
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Enel Produzione SpA Rome IT 1,800,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Renovable Srl Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
Enel Rinnovabile SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
Global Investment
\n
BV
\n
99.00%
\n
100.00%
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
1.00%
\n
Enel Roadrunner Solar
\n
Project Holdings II LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Enel Roadrunner Solar
\n
Project Holdings LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel Romania SA Buftea RO 200,000.00 RON
\n
Discontinued
\n
operations
\n
Enel SpA 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Salt Wells LLC Fallon US - USD Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
Enel Saudi Arabia
\n
Limited
\n
Al Khobar SA 1,000,000.00 SAR
\n
Line-by-line
\n
e-distribuzione
\n
SpA
\n
60.00% 60.00%
\n
Enel Servicii Comune
\n
SA
\n
Bucharest RO 33,000,000.00 RON
\n
Discontinued
\n
operations
\n
E-Distribu\u0163ie Banat
\n
SA
\n
50.00%
\n
51.00%
\n
E-Distribu\u0163ie
\n
Dobrogea SA
\n
50.00%
\n
Enel Sole Srl Rome IT 4,600,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Solu\u00e7\u00f5es
\n
Energ\u00e9ticas Ltda
\n
Rio de Janeiro BR 42,863,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Solu\u00e7\u00f5es
\n
Energ\u00e9ticas Ltda
\n
0.00%
\n
Enel Stillwater LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Geothermal
\n
LLC
\n
100.00% 100.00%
\n
Enel Surprise Valley LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Texkan Inc. Wilmington US 100.00 USD
\n
Line-by-line Chi Power Inc. 100.00% 100.00%
\n
Enel Trade Energy Srl Bucharest RO 2,437,050.00 RON
\n
Discontinued
\n
operations
\n
Enel Romania SA 100.00% 100.00%
\n
Enel Trade Serbia doo
\n
Beograd in liquidation
\n
Belgrade RS 300,000.00 EUR
\n
Line-by-line
\n
Enel Global Trading
\n
SpA
\n
100.00% 100.00%
\n
Enel Trading Argentina
\n
Srl
\n
Buenos Aires AR 14,011,100.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 55.00%
\n
82.26%
\n
Enel Argentina SA 45.00%
\n
Enel Trading Brasil SA Rio de Janeiro BR 5,280,312.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Trading North
\n
America LLC
\n
Wilmington US 10,000,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Uruguay SA Montevideo UY 20,000.00 UYU
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Vayu (Project 2)
\n
Private Limited
\n
Gurugram IN 45,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Enel Wind Project
\n
(Amberi) Private Limited
\n
New Delhi IN 5,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services North America
\n
Inc.
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services Srl
\n
Rome IT - EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Advisory
\n
Services UK Limited
\n
London GB 502.00 GBP
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory
\n
Services USA LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Arecibo LLC Boston US - USD
\n
Line-by-line
\n
Enel X Pr Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X Argentina SAU Buenos Aires AR 127,800,000.00 ARS
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Asputeck Ave.
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Australia Holding
\n
(Pty) Ltd
\n
Melbourne AU 28,424,578.00 AUD
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Australia (Pty)
\n
Ltd
\n
Melbourne AU 7,209,880.00 AUD
\n
Line-by-line
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
100.00% 100.00%
\n
Enel X Battery Storage
\n
Limited Partnership
\n
Oakville CA 10,000.00 CAD
\n
Line-by-line
\n
Enel X Canada
\n
Holding Inc.
\n
0.01%
\n
100.00%
\n
Enel X Canada Ltd 99.99%
\n
Enel X Brasil
\n
Gerenciamento de
\n
Energia Ltda
\n
Sorocaba BR 5,538,403.00 BRL
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
0.00%
\n
100.00%
\n
EnerNOC UK II
\n
Limited
\n
100.00%
\n
Enel X Brasil SA Niter\u00f3i BR 471,725,892.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel X Canada Holding
\n
Inc.
\n
Oakville CA 1,000.00 CAD
\n
Line-by-line Enel X Canada Ltd 100.00% 100.00%
\n
Enel X Canada Ltd Mississauga CA 1,000.00 CAD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Chile SpA
\n
Santiago de
\n
Chile
\n
CL 3,341,831,929.00 CLP
\n
Line-by-line Enel Chile SA 100.00% 64.93%
\n
Enel X College Ave.
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X Colombia SAS
\n
ESP
\n
Bogot\u00e1 CO 50,368,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Enel X Federal LLC Boston US 5,000.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Finance Partner
\n
LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Financial
\n
Services Srl
\n
Rome IT 1,000,000.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Enel X Germany GmbH Berlin DE 25,000.00 EUR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Hayden Rowe St.
\n
Project LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X International Srl Rome IT 100,000.00 EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Ireland Limited Dublin IE 10,841.00 EUR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Italia Srl Rome IT 200,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel X Japan KK Tokyo JP 1,030,000,000.00 JPY
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X KOMIPO Solar
\n
Limited
\n
Seoul KR 8,472,600,000.00 KRW
\n
Line-by-line
\n
Enel X Korea
\n
Limited
\n
80.00% 80.00%
\n
Enel X Korea Limited Seoul KR 11,800,000,000.00 KRW
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Las Piedras LLC Boston US - USD
\n
Line-by-line
\n
Enel X Pr Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X MA Holdings LLC Boston US 100.00 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X MA PV Portfolio
\n
2 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio
\n
3 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X M\u00e9xico S de RL
\n
de Cv
\n
Mexico City MX 39,921,546.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel X International
\n
Srl
\n
100.00%
\n
Enel X Mobility Srl Rome IT 100,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel X Morrissey Blvd.
\n
Project LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X New Zealand
\n
Limited
\n
Wellington NZ 313,606.00 AUD
\n
Line-by-line
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
100.00% 100.00%
\n
Enel X North America
\n
Inc.
\n
Boston US 1,000.00 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Norway AS Porsgrunn NO 11,000,000.00 NOK
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Per\u00fa SAC San Miguel PE 12,005,000.00 PEN
\n
Line-by-line Enel Per\u00fa SAC 100.00% 82.27%
\n
Enel X Polska Sp. zo.o. Warsaw PL 12,275,150.00 PLN
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
Enel X Pr Holdings LLC Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Project MP
\n
Holdings LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Sponsor LLC
\n
100.00% 100.00%
\n
Enel X Project MP
\n
Sponsor LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Romania Srl Bucharest RO 7,044,450.00 RON
\n
Discontinued
\n
operations
\n
Enel X International
\n
Srl
\n
99.97%
\n
100.00%
\n
Enel X Srl 0.03%
\n
Enel X Rus LLC Moscow RU 8,000,000.00 RUB
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
99.00% 99.00%
\n
Enel X Srl Rome IT 1,050,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Services India
\n
Private Limited
\n
Mumbai City IN 45,000.00 INR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00%
\n
100.00%
\n
Enel X North
\n
America Inc.
\n
0.00%
\n
Enel X Singapore Pte
\n
Ltd
\n
Singapore SG 1,212,000.00 SGD
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Taiwan Co. Ltd Taipei City TW 76,100,000.00 TWD
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
Enel X UK Limited London GB 32,628.00 GBP
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Way (Shanghai)
\n
Co. Ltd
\n
Shanghai CN 3,500,000.00 USD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Brasil SA Rio de Janeiro BR 3,045,337.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 20.00%
\n
96.45%
\n
Enel X Way Srl 80.00%
\n
Enel X Way Canada
\n
Holding Ltd
\n
Vancouver CA - CAD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Way Chile SpA
\n
Santiago de
\n
Chile
\n
CL 11,229,030,071.00 CLP
\n
Line-by-line
\n
Enel Chile SA 49.00%
\n
82.81%
\n
Enel X Way Srl 51.00%
\n
Enel X Way France SAS Paris FR 2,901,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Germany
\n
GmbH
\n
Berlin DE 25,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Italia Srl Rome IT 5,000,000.00 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way North
\n
America Inc.
\n
San Carlos US 0.10 USD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Per\u00fa SAC Lima PE 1,561,900.00 PEN
\n
Line-by-line
\n
Enel Per\u00fa SAC 20.00%
\n
96.45%
\n
Enel X Way Srl 80.00%
\n
Enel X Way Romania Srl Bucharest RO 12,778,740.00 RON
\n
Discontinued
\n
operations
\n
Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Srl Rome IT 6,026,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Way Sweden AB Stockholm SE 50,000.00 SEK
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way UK Limited London GB 1.00 GBP
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way USA LLC San Carlos US - USD
\n
Line-by-line
\n
Enel X Way North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Wood St. Project
\n
LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Woodland Solar
\n
Project LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enelpower Contractor
\n
and Development
\n
Saudi Arabia Ltd
\n
Riyadh SA 5,000,000.00 SAR
\n
Line-by-line EnelPower Srl 51.00% 51.00%
\n
Enelpower do Brasil
\n
Ltda
\n
Rio de Janeiro BR 5,689,000.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
EnelPower Srl Milan IT 2,000,000.00 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Energ\u00e9tica Monz\u00f3n
\n
SAC
\n
San Miguel PE 6,463,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
100.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.00%
\n
Energ\u00eda Base Natural
\n
SLU
\n
Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda Ceuta XXI
\n
Comercializadora de
\n
Referencia SAU
\n
Ceuta ES 65,000.00 EUR
\n
Line-by-line
\n
Empresa de
\n
Alumbrado
\n
El\u00e9ctrico de Ceuta
\n
SA
\n
100.00% 67.61%
\n
Energ\u00eda E\u00f3lica \u00c1brego
\n
SLU
\n
Madrid ES 3,576.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Galerna
\n
SLU
\n
Madrid ES 3,413.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Gregal
\n
SLU
\n
Madrid ES 3,250.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda Global de
\n
M\u00e9xico (Enermex) SA
\n
de Cv
\n
Mexico City MX 50,000.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.00% 99.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Energ\u00eda Global
\n
Operaciones Srl
\n
San Jos\u00e9 CR 10,000.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
100.00% 47.18%
\n
Energ\u00eda Limpia de
\n
Amistad SA de Cv
\n
Mexico City MX 33,452,769.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de Palo
\n
Alto SA de Cv
\n
Mexico City MX 673,583,489.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de
\n
Puerto Libertad S de
\n
RL de Cv
\n
Mexico City MX 2,953,980.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.01%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.99%
\n
Energ\u00eda Marina SpA
\n
Santiago de
\n
Chile
\n
CL 2,404,240,000.00 CLP
\n
Equity
\n
Enel Green Power
\n
Chile SA
\n
25.00% 16.23%
\n
Energ\u00eda Neta Sa Caseta
\n
Llucmajor SLU
\n
Palma de
\n
Mallorca
\n
ES 9,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda XXI
\n
Comercializadora de
\n
Referencia SLU
\n
Madrid ES 2,000,000.00 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda
\n
SAU
\n
100.00% 70.12%
\n
Energ\u00eda y Naturaleza
\n
SLU
\n
Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
Santiago de
\n
Chile
\n
CL 12,120,575.70 USD
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Energ\u00edas Alternativas
\n
del Sur SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 546,919.10 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
54.95% 38.53%
\n
Energ\u00edas de Arag\u00f3n
\n
I SLU
\n
Zaragoza ES 3,200,000.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Energ\u00edas de Graus SL Barcelona ES 1,298,160.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.75%
\n
Energ\u00edas Especiales de
\n
Care\u00f3n SA
\n
Santiago de
\n
Compostela
\n
ES 270,450.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
97.00% 68.01%
\n
Energ\u00edas Especiales de
\n
Pe\u00f1a Armada SAU
\n
Madrid ES 963,300.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00edas Especiales del
\n
Alto Ulla SAU
\n
Madrid ES 9,210,840.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00edas Especiales del
\n
Bierzo SA
\n
Torre del Bierzo ES 1,635,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
Energ\u00edas Limpias de
\n
Carmona SL
\n
Seville ES 7,000.00 EUR
\n
Equity
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
6.25%
\n
13.15%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
6.25%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
6.25%
\n
Energ\u00edas Renovables La
\n
Mata SA de Cv
\n
Mexico City MX 656,615,400.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
1.00%
\n
Energie Electrique de
\n
Tahaddart SA
\n
Tangier MA 306,160,000.00 MAD
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
32.00% 22.44%
\n
Energo Sonne Srl Bucharest RO 31,520.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Energotel AS Bratislava SK 2,191,200.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
20.00% 6.60%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
ENergy Hydro Piave Srl
\n
in liquidation
\n
Belluno IT 800,000.00 EUR
\n
Line-by-line
\n
Enel Produzione
\n
SpA
\n
100.00% 100.00%
\n
Energy Podium Private
\n
Company
\n
Katerini Pieria GR 4,001.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.02% 0.02%
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
Melbourne AU 35,128,517.00 AUD
\n
Line-by-line
\n
Enel X Australia
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
EnerNOC GmbH Munich DE 25,000.00 EUR
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
EnerNOC Ireland
\n
Limited
\n
Dublin IE 10,589.00 EUR
\n
Line-by-line
\n
Enel X Ireland
\n
Limited
\n
100.00% 100.00%
\n
EnerNOC UK II Limited London GB 21,000.00 GBP
\n
Line-by-line Enel X UK Limited 100.00% 100.00%
\n
Enigma Green Power
\n
1 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Entech (China)
\n
Information Technology
\n
Co. Ltd
\n
Shenzhen CN 140,000.00 USD
\n
Equity
\n
EnerNOC UK II
\n
Limited
\n
50.00% 50.00%
\n
Entech Utility Service
\n
Bureau Inc.
\n
Lutherville US 1,500.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Envatios Promoci\u00f3n
\n
XX SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
E\u00f3lica Valle del Ebro SA Zaragoza ES 3,561,342.50 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.50% 35.41%
\n
E\u00f3lica Zopiloapan SA
\n
de Cv
\n
Mexico City MX 1,877,201.54 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
56.98%
\n
96.48%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
39.50%
\n
E\u00f3licas de Agaete SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 240,400.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
E\u00f3licas de Fuencaliente
\n
SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 216,360.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
55.00% 38.56%
\n
E\u00f3licas de
\n
Fuerteventura AIE
\n
Puerto del
\n
Rosario
\n
ES - EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
E\u00f3licas de la Patagonia
\n
SA
\n
Buenos Aires AR 480,930.00 ARS
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
E\u00f3licas de Lanzarote SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 1,758,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
E\u00f3licas de Tenerife AIE
\n
Santa Cruz de
\n
Tenerife
\n
ES 420,708.40 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
E\u00f3licos de Tirajana SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Epresa Energ\u00eda SA Cadiz ES 2,500,000.00 EUR
\n
Equity Endesa Red SAU 50.00% 35.06%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ermis 2 Energeiaki
\n
Private Company
\n
Grevena GR 1,002.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.10%
\n
E-Solar 2 Srl Rome IT 2,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
E-Solar Srl Rome IT 2,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Essaouira Wind Farm Casablanca MA 300,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
European Energy
\n
Exchange AG
\n
Leipzig DE 40,050,000.00 EUR
\n
-
\n
Enel Global Trading
\n
SpA
\n
2.38% 2.38%
\n
Evacuaci\u00f3n Carmona
\n
400-220 kV
\n
Renovables SL
\n
Seville ES 10,003.00 EUR
\n
Equity
\n
Envatios Promoci\u00f3n
\n
I SLU
\n
3.13%
\n
6.58%
\n
Envatios Promoci\u00f3n
\n
II SLU
\n
3.13%
\n
Envatios Promoci\u00f3n
\n
III SLU
\n
3.13%
\n
Evolution Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ewiva Srl Milan IT 1,000,000.00 EUR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Expedition Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explotaciones E\u00f3licas
\n
de Escucha SA
\n
Zaragoza ES 3,505,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
70.00% 49.08%
\n
Explotaciones E\u00f3licas
\n
El Puerto SA
\n
Zaragoza ES 3,230,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
73.60% 51.61%
\n
Explotaciones E\u00f3licas
\n
Santo Domingo de
\n
Luna SA
\n
Zaragoza ES 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Explotaciones E\u00f3licas
\n
Saso Plano SA
\n
Zaragoza ES 5,488,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
65.00% 45.58%
\n
Explotaciones E\u00f3licas
\n
Sierra Costera SA
\n
Zaragoza ES 8,046,800.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Explotaciones E\u00f3licas
\n
Sierra La Virgen SA
\n
Zaragoza ES 4,200,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Farrier Station Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Fayette Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fazenda Aroeira
\n
Empreendimento de
\n
Energia Ltda
\n
Rio de Janeiro BR 2,362,045.90 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fence Post Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Fence Post Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fence Post Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fenner Wind Holdings
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Field Day Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Finocchiara Solar Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Finsec Lab Ltd Tel Aviv IL 100.00 ILS
\n
Equity Enel X Srl 30.00% 30.00%
\n
Flagpay Srl Milan IT 10,000.00 EUR
\n
Equity PayTipper SpA 100.00% 50.00%
\n
Flat Rock Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Flat Rocks Girgarre
\n
Cohuna Finco (Pty) Ltd
\n
Sydney AU 120.00 AUD
\n
AFS
\n
Cohuna Solar Farm
\n
Trust
\n
33.33%
\n
100.00%
\n
Flat Rocks One
\n
Wind Farm Trust
\n
33.33%
\n
Girgarre Solar Farm
\n
Trust
\n
33.33%
\n
Flat Rocks One Wind
\n
Farm (Pty) Ltd
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
Flat Rocks One Wind
\n
Farm Trust
\n
Sydney AU 100.00 AUD
\n
AFS
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding Trust
\n
100.00% 100.00%
\n
Flat Top Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Flint Rock Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Florence Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Flowing Spring Farms
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fontib\u00f3n ZE SAS Bogot\u00e1 CO 392,420,000.00 COP
\n
AFS Bogot\u00e1 ZE SAS 100.00% 47.18%
\n
F\u00f3tons de Santo
\n
Anchieta Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 577,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fotovoltaica Yunclillos
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Fourmile Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Fox Run Energy Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Franklintown Farm LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Freedom Energy
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Front Mar\u00edtim del
\n
Bes\u00f2s SL
\n
Barcelona ES 9,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
61.37% 43.03%
\n
Frontiersman Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
FRV Corchitos I SLU Madrid ES 75,800.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
FRV Corchitos II Solar
\n
SLU
\n
Madrid ES 22,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Gibalb\u00edn - Jerez
\n
SLU
\n
Madrid ES 23,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Tarifa SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Villalobillos SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 1
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 3
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRWF Stage 1 (Pty) Ltd Sydney AU 100.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Fundamental
\n
Recognized Systems
\n
SLU
\n
Andorra ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Furatena Solar 1 SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Ganado Solar Holdings
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Ganado Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ganado Solar LLC Andover US - USD
\n
Line-by-line
\n
Ganado Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ganado Storage LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Garob Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 100.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Gas y Electricidad
\n
Generaci\u00f3n SAU
\n
Palma de
\n
Mallorca
\n
ES 213,775,700.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Gauley Hydro LLC Wilmington US - USD
\n
Equity GRPP Holdings LC 100.00% 50.00%
\n
Gauley River
\n
Management LLC
\n
Willison US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Generadora de
\n
Occidente Ltda
\n
Guatemala City GT 16,262,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
99.00%
\n
47.18%
\n
Enel Guatemala SA 1.00%
\n
Generadora E\u00f3lica Alto
\n
Pacora Srl
\n
Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
Generadora
\n
Montecristo SA
\n
Guatemala City GT 3,820,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%
\n
Enel Guatemala SA 0.00%
\n
Generadora Solar
\n
Austral SA
\n
Chiriqu\u00ed PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar de
\n
Occidente SA
\n
Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar El
\n
Puerto SA
\n
Chiriqu\u00ed PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Generadora Solar
\n
Tol\u00e9 Srl
\n
Panama City PA 10,100.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.99%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.01%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Geot\u00e9rmica del Norte
\n
SA
\n
Santiago de
\n
Chile
\n
CL 326,577,419,702.00 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
84.59% 54.92%
\n
Gibson Bay Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Girgarre Solar Farm
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
AFS
\n
Enel Green Power
\n
Girgarre Holdings
\n
(Pty) Ltd
\n
100.00% 100.00%
\n
Girgarre Solar Farm
\n
Trust
\n
Sydney AU 10.00 AUD
\n
AFS
\n
Enel Green Power
\n
Girgarre Trust
\n
100.00% 100.00%
\n
Glass Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Global Commodities
\n
Holdings Limited
\n
London GB 4,042,375.00 GBP
\n
-
\n
Enel Global Trading
\n
SpA
\n
4.68% 4.68%
\n
Globyte SA San Jos\u00e9 CR 900,000.00 CRC
\n
-
\n
Enel Costa Rica
\n
CAM SA
\n
10.00% 4.72%
\n
Gloucester Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
GNL Chile SA
\n
Santiago de
\n
Chile
\n
CL 3,026,160.00 USD
\n
Equity
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
33.33% 20.25%
\n
Goodwell Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Gooseneck Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gorona del Viento El
\n
Hierro SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 30,936,736.00 EUR
\n
Equity
\n
Uni\u00f3n El\u00e9ctrica
\n
de Canarias
\n
Generaci\u00f3n SAU
\n
23.21% 16.28%
\n
Grand Prairie Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Gridspertise Iberia SL Madrid ES 3,000.00 EUR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise Latam SA S\u00e3o Paulo BR 2,010,000.00 BRL
\n
Equity
\n
Enel Brasil SA 0.00%
\n
50.00%
\n
Gridspertise Srl 100.00%
\n
Gridspertise Srl Rome IT 7,500,000.00 EUR
\n
Equity Enel Grids Srl 50.00% 50.00%
\n
Gridspertise LLC Dover US 160,000.00 USD
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
GRPP Holdings LLC Andover US 2.00 USD
\n
Equity
\n
EGPNA REP
\n
Holdings LLC
\n
50.00% 50.00%
\n
Guadarranque Solar
\n
4 SLU
\n
Seville ES 3,006.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
II SAU
\n
100.00% 70.12%
\n
Guayepo Solar SAS Bogot\u00e1 CO 1,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Guir Wind Farm Casablanca MA 10,000.00 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco SARLAU
\n
99.00%
\n
99.00%
\n
Mrs Riveros Perez
\n
Paula Cristina
\n
1.00%
\n
GulfStar Power LLC Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gusty Hill Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
GV Energie Rigenerabili
\n
ITAL-RO Srl
\n
Bucharest RO 1,145,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
0.00%
\n
Hadley Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Hamilton County Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Hansborough Valley
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Harmony Plains Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Hastings Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Heartland Farms Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
Barcelona ES 126,210.00 EUR
\n
Line-by-line Endesa Red SAU 100.00% 70.12%
\n
Hidroel\u00e9ctrica de
\n
Ourol SL
\n
Lugo ES 1,608,200.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Hidroelectricidad del
\n
Pac\u00edfico S de RL de Cv
\n
Colima MX 30,890,736.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
Hidroflamicell SL Barcelona ES 78,120.00 EUR
\n
Line-by-line
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
75.00% 52.59%
\n
Hidroinvest SA Buenos Aires AR 55,312,093.00 ARS
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 41.94%
\n
79.55%
\n
Enel Argentina SA 54.76%
\n
HIF H2 SpA
\n
Santiago de
\n
Chile
\n
CL 6,303,000.00 USD
\n
Equity
\n
Enel Green Power
\n
Chile SA
\n
50.00% 32.46%
\n
High Chaparral Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome
\n
Storage LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind
\n
Holdings LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind
\n
Power LLC
\n
Boston US 100.00 USD
\n
Line-by-line
\n
High Lonesome
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
High Noon Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Street
\n
Corporation (Pty) Ltd
\n
Melbourne AU 2.00 AUD
\n
Line-by-line
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 100.00%
\n
Hilltopper Wind
\n
Holdings LLC
\n
Wilmington US 1,000.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hispano Generaci\u00f3n de
\n
Energ\u00eda Solar SL
\n
Jerez de los
\n
Caballeros
\n
ES 3,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Honey Stone Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Honeybee Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hope Creek LLC Crestview US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Hope Ridge Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Horse Run Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Horse Wrangler Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hubject eRoaming
\n
Technology (Shanghai)
\n
Co. Ltd
\n
Shangai CN 12,668,015.70 CNY
\n
- Hubject GmbH 100.00% 12.50%
\n
Hubject GmbH Berlin DE 65,943.00 EUR
\n
- Enel X Way Srl 12.50% 12.50%
\n
Hubject Inc. Santa Monica US 100,000.00 USD
\n
- Hubject GmbH 100.00% 12.50%
\n
ICE Tudela SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.12% 3.59%
\n
Idalia Park Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Idrosicilia SpA Milan IT 22,520,000.00 EUR
\n
Equity Enel SpA 1.00% 1.00%
\n
IFX Networks Argentina
\n
Srl
\n
Buenos Aires AR 2,260,551.00 ARS
\n
-
\n
IFX/Eni - SPC V Inc. 99.85%
\n
19.50%
\n
Minority Stock
\n
Holding Corp.
\n
0.15%
\n
IFX Networks Colombia
\n
SAS
\n
Bogot\u00e1 CO 18,951,211,000.00 COP
\n
-
\n
IFX Networks
\n
Panama SA
\n
48.43%
\n
19.50%
\n
IFX/Eni - SPC III Inc. 34.60%
\n
Livister Latam SLU 16.97%
\n
IFX Networks LLC Wilmington US 80,848,653.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
IFX Networks Ltd Tortola VG 50,001.00 USD
\n
- IFX Networks LLC 100.00% 19.50%
\n
IFX Networks Panama
\n
SA
\n
Panama City PA 26,460.00 USD
\n
-
\n
IFX/Eni - SPC
\n
Panama Inc.
\n
79.37%
\n
19.50%
\n
Livister Latam SLU 20.63%
\n
IFX/Eni - SPC III Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC IV Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC Panama
\n
Inc.
\n
Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IFX/Eni - SPC V Inc. Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
IIK Energ\u00eda de Dzemul
\n
SA de Cv
\n
Mexico City MX 6,479,172.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
IIK Energ\u00eda de Telchac
\n
SA de Cv
\n
Mexico City MX - MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
Infraestructura de
\n
Evacuaci\u00f3n Pe\u00f1aflor
\n
220 kV SL
\n
Madrid ES 3,500.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
41.14% 28.85%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Infraestructuras Puerto
\n
Santa Mar\u00eda 220 SL
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda I SLU
\n
50.00%
\n
70.12%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda II SLU
\n
50.00%
\n
Infraestructuras San
\n
Serv\u00e1n 220 SL
\n
Madrid ES 12,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.80% 21.60%
\n
Infraestructuras San
\n
Serv\u00e1n Set 400 SL
\n
Madrid ES 90,000.00 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
6.41%
\n
13.48%Baylio Solar SLU 6.41%
\n
Furatena Solar 1
\n
SLU
\n
6.41%
\n
Inkolan Informaci\u00f3n
\n
y Coordinaci\u00f3n de
\n
Obras AIE
\n
Bilbao ES 84,141.68 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Inspectores y
\n
Consultores Ibercal
\n
SLU
\n
Vizcaya ES 3,100.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Instalaciones San
\n
Serv\u00e1n II 400 SL
\n
Madrid ES 11,026.00 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
7.94%
\n
16.69%Baylio Solar SLU 7.94%
\n
Furatena Solar 1
\n
SLU
\n
7.94%
\n
International
\n
Multimedia University
\n
Srl in bankruptcy
\n
- IT 24,000.00 EUR
\n
- Enel Italia SpA 13.04% 13.04%
\n
Inversora Dock Sud SA Buenos Aires AR 828,941,660.00 ARS
\n
AFS Enel Am\u00e9ricas SA 57.14% 47.01%
\n
Ipsomata DPGU Private
\n
Company
\n
Heraklion, Crete GR 5,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.02% 0.02%
\n
Iris Bloom Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Belt Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Bull Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Isamu Ikeda Energia SA Niter\u00f3i BR 16,474,475.77 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Italgest Energy (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Jack River LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Jade Energia Ltda Rio de Janeiro BR 4,107,097.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Jaguito Solar 10 MW SA Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Jessica Mills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Julia Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Junia Insurance Srl
\n
Mosciano
\n
Sant\u2019Angelo (TE)
\n
IT 100.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Juniper Canyon Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Keeneys Creek Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ken Renewables India
\n
Private Limited
\n
Gurugram IN 12,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Khaba Renewable
\n
Energy Private Limited
\n
Gurugram IN 18,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Khidrat Renewable
\n
Energy Private Limited
\n
Gurugram IN 78,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
King Branch Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Kingston Energy
\n
Storage LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Kino Contractor SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
1.00%
\n
Kino Facilities Manager
\n
SA de Cv
\n
Mexico City MX 2,933,340.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Kokkinari DPGU Private
\n
Company
\n
Heraklion, Crete GR 15,000.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.01% 0.01%
\n
Kongul Enerj\u00ed Sanay\u00ed Ve
\n
T\u00edcaret Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 14,537,500.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari Anon\u00edm
\n
\u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Koporie WPS LLC
\n
Leningrad
\n
Region
\n
RU 21,000,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Korea Line Corporation Seoul KR 122,132,520,000.00 KRW
\n
-
\n
Enel Global Trading
\n
SpA
\n
0.25% 0.25%
\n
Koukos Energy Private
\n
Company
\n
Athens GR 4,002.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
0.05% 0.05%
\n
Kromschroeder SA Barcelona ES 627,126.00 EUR
\n
Equity
\n
Endesa Medios y
\n
Sistemas SLU
\n
29.26% 20.52%
\n
Lake Emily Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Lake Pulaski Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Land Run Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Land Run Wind Project
\n
LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Sundance Wind
\n
Project LLC
\n
100.00% 100.00%
\n
Lantern Trail Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Latamsolar Energ\u00edas
\n
Renovables SAS
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Latamsolar Fotovoltaica
\n
Fundaci\u00f3n SAS
\n
Bogot\u00e1 CO 8,000,000.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47.18%
\n
Lathrop Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Lava Solar Project LLC Andover US 1.00 USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lawrence Creek Solar
\n
LLC
\n
Minneapolis US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Lebanon Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Legacy Blossom
\n
Storage Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Lemonade Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Liberty Energy Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Libyan Italian Joint
\n
Company - Azienda
\n
Libico-Italiana (A.L.I.)
\n
Tripoli LY 1,350,000.00 EUR
\n
- EnelPower Srl 0.33% 0.33%
\n
Light Cirrus Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lily Solar Holdings LLC Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Lily Solar Holdings
\n
LLC
\n
100.00% 100.00%
\n
Lily Solar LLC Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Lindahl Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Lindahl Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Lindahl Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Elk Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Little Elk Wind Project
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Little Elk Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Salt Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Litus Energy Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Livister Chile SpA
\n
Santiago de
\n
Chile
\n
CL 11,843,107,407.00 CLP
\n
- Livister Latam SLU 100.00% 19.50%
\n
Livister Latam SLU Madrid ES 2,442,066.00 EUR
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Llano S\u00e1nchez Solar
\n
Power One Srl
\n
Panama City PA 10,020.00 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.20%
\n
47.19%
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
99.80%
\n
Lone Pine Wind Inc. Alberta CA - CAD
\n
-
\n
Enel Green Power
\n
Canada Inc.
\n
10.00% 10.00%
\n
Lone Pine Wind Project
\n
LP
\n
Alberta CA - CAD
\n
Equity
\n
Enel Green Power
\n
Canada Inc.
\n
10.00% 10.00%
\n
Lucas Sostenible SL Madrid ES 1,099,775.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
35.29% 24.74%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Luminary Highlands
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Luz de Angra Energia
\n
SA
\n
Rio de Janeiro BR 4,062,085.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Caruaru Energia
\n
SA
\n
Rio de Janeiro BR 21,027,600.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Jaboat\u00e3o
\n
Energia SA
\n
Rio de Janeiro BR 21,114,200.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Macap\u00e1 Energia
\n
SA
\n
Rio de Janeiro BR 24,338,000.00 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Maicor Wind Srl Rome IT 20,850,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Malaspina Energy Scarl
\n
in liquidation
\n
Bergamo IT 100,000.00 EUR
\n
Line-by-line Enel X Italia Srl 100.00% 100.00%
\n
Mansar Renewable
\n
Energy Private Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Maple Canada
\n
Solutions Holdings Ltd
\n
- CA - CAD
\n
Equity Enel X Canada Ltd 20.00% 20.00%
\n
Maple Energy Solutions
\n
LP
\n
- CA - CAD
\n
Equity
\n
Enel X Canada
\n
Holding Inc.
\n
20.00% 20.00%
\n
Maple Run Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Marte Srl Rome IT 6,100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Marudhar Wind Energy
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
M\u00e1s Energ\u00eda S de RL
\n
de Cv
\n
Mexico City MX 61,872,926.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99%
\n
100.00%
\n
Hidroelectricidad
\n
del Pac\u00edfico S de RL
\n
de Cv
\n
0.01%
\n
Mason Mountain Wind
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
Matrigenix (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Maty Energia Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
MC Solar I LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
McBride Wind Project
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Medidas Ambientales
\n
SL
\n
Burgos ES 60,100.00 EUR
\n
- Tecnatom SA 50.00% 15.78%
\n
Merit Wind Project LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Metro Wind LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Mexicana de
\n
Hidroelectricidad
\n
Mexhidro S de RL de Cv
\n
Mexico City MX 181,728,901.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mibgas SA Madrid ES 3,000,000.00 EUR - Endesa SA 1.35% 0.95%
\n
Midelt Wind Farm SA Casablanca MA 145,000,000.00 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
Minglanilla Renovables
\n
400 kV AIE
\n
Valencia ES - EUR
\n
Proportional
\n
Energ\u00eda Base
\n
Natural SLU
\n
4.79%
\n
25.36%
\n
Energ\u00eda E\u00f3lica
\n
\u00c1brego SLU
\n
7.98%
\n
Energ\u00eda E\u00f3lica
\n
Galerna SLU
\n
9.31%
\n
Energ\u00eda E\u00f3lica
\n
Gregal SLU
\n
9.31%
\n
Energ\u00eda y
\n
Naturaleza SLU
\n
4.79%
\n
Minicentrales Acequia
\n
Cinco Villas AIE
\n
Ejea de los
\n
Caballeros
\n
ES 3,346,993.04 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.39% 3.78%
\n
Minicentrales del Canal
\n
de las B\u00e1rdenas AIE
\n
Zaragoza ES 1,202,000.00 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
15.00% 10.52%
\n
Minicentrales del Canal
\n
Imperial-Gallur SL
\n
Zaragoza ES 1,820,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.50% 25.59%
\n
Minority Stock Holding
\n
Corp.
\n
Tortola VG 100.00 USD
\n
- IFX Networks Ltd 100.00% 19.50%
\n
Mira Energy (Pty) Ltd Johannesburg ZA 100.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Miranda Plataforma
\n
Log\u00edstica SA
\n
Burgos ES 1,800,000.00 EUR
\n
- Nuclenor SA 0.22% 0.08%
\n
MO Land Holdings
\n
1358 LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Moebius Tecnologia
\n
em Informatica SA
\n
Rio de Janeiro BR 150,000.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
100.00% 19.50%
\n
Monte Reina
\n
Renovables SL
\n
Madrid ES 4,000.00 EUR
\n
Equity
\n
FRV Zamora Solar
\n
1 SLU
\n
20.58% 14.43%
\n
Montrose Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Moonbeam Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Mooney Group SpA Milan IT 10,050,000.00 EUR
\n
Equity Enel X Srl 50.00% 50.00%
\n
Mooney SpA Milan IT 87,833,331.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Mooney Servizi SpA Milan IT 8,549,999.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Morgan Branch Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Mount Pleasant Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Mountrail Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
MPG Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Mucho Viento Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mule Bit Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Muskegon County
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Muskegon Green Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Mustang Run Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Nabb Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Napolean Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Nareva Enel Green
\n
Power Morocco SA
\n
Casablanca MA 98,750,000.00 MAD
\n
Equity
\n
Enel Green Power
\n
Morocco SARLAU
\n
50.00% 50.00%
\n
Negocios y Telefon\u00eda
\n
NEDETEL SA
\n
Guayaquil EC 4,773,525.00 USD
\n
- Ufinet Latam SLU 70.00% 13.65%
\n
Net Botanic Internet
\n
Inteligente SA
\n
Rio de Janeiro BR 450,000.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
100.00% 19.50%
\n
Netra Renewable
\n
Energy Private Limited
\n
Gurgaon IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Nevkan Renewables
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Nevkan Inc. 100.00% 100.00%
\n
New York Distributed
\n
Storage Projects LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ngonye Power
\n
Company Limited
\n
Lusaka ZM 10.00 ZMW
\n
AFS
\n
Enel Green Power
\n
Solar Ngonye SpA
\n
(formerly Enel
\n
Green Power Africa
\n
Srl)
\n
80.00% 80.00%
\n
Nojoli Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
North English Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
North Rock Wind LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northland Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northstar Wind Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Northumberland Solar
\n
Project I LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Northwest Hydro LLC Wilmington US - USD
\n
Line-by-line Chi West LLC 100.00% 100.00%
\n
Novolitio Recuperaci\u00f3n
\n
de Bater\u00edas SL
\n
Ponferrada ES 180,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
45.00% 31.55%
\n
Nuclenor SA Burgos ES 102,000,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
50.00% 35.06%
\n
Nuove Energie Srl
\n
Porto
\n
Empedocle
\n
IT 5,204,028.73 EUR
\n
Line-by-line
\n
Enel Global Trading
\n
SpA
\n
100.00% 100.00%
\n
Nxuba Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
51.00% 25.50%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
NYC Storage (353
\n
Chester) SPE LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ochrana A Bezpecnost
\n
Se SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 33,193.92 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Olathe Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Olivum PV Farm 01 SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
OMIP - Operador
\n
do Mercado Ib\u00e9rico
\n
(Portugal) SGPS SA
\n
Lisbon PT 2,610,000.00 EUR
\n
-
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
5.00% 3.51%
\n
Open Range Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Operador del Mercado
\n
Ib\u00e9rico de Energ\u00eda -
\n
Polo Espa\u00f1ol SA
\n
Madrid ES 1,999,998.00 EUR
\n
- Endesa SA 5.00% 3.51%
\n
Oravita Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Orchid Acres Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Origin Goodwell
\n
Holdings LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Wind
\n
Holdings 1 LLC
\n
100.00% 10.00%
\n
Origin Wind Energy
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Osage Wind Holdings
\n
LLC
\n
Wilmington US 100.00 USD
\n
Line-by-line Enel Kansas LLC 50.00% 50.00%
\n
Osage Wind LLC Wilmington US - USD
\n
Line-by-line
\n
Osage Wind
\n
Holdings LLC
\n
100.00% 50.00%
\n
Ossining Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Ovacik Eol\u00edko Enerj\u00ed
\n
Elektr\u00edk \u00dcret\u00edm Ve
\n
T\u00edcaret Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 2,925,900.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Oxagesa AIE in
\n
liquidation
\n
Alca\u00f1iz ES 6,010.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Oyster Bay Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Padoma Wind Power
\n
LLC
\n
Elida US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Painted Rose Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Palo Alto Farms Wind
\n
Project LLC
\n
Dallas US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pampinus PV Farm
\n
01 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Paradise Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Paravento SL Lugo ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Parc E\u00f2lic La Tossa-La
\n
Mola d\u2019en Pascual SL
\n
Madrid ES 1,183,100.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parc E\u00f2lic Los Aligars
\n
SL
\n
Madrid ES 1,313,100.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Parco Eolico Monti
\n
Sicani Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Parque Amistad II SA
\n
de Cv
\n
Mexico City MX 1,413,533,480.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad III SA
\n
de Cv
\n
Mexico City MX 931,692,540.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad IV SA
\n
de Cv
\n
Mexico City MX 1,489,508,400.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque E\u00f3lico A
\n
Capelada SLU
\n
A Coru\u00f1a ES 5,857,704.33 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico
\n
Belmonte SA
\n
Madrid ES 120,400.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.17% 35.18%
\n
Parque E\u00f3lico BR-1
\n
SAPI de Cv
\n
Mexico City MX - MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.50%
\n
25.50%
\n
Enel Rinnovabile SA
\n
de Cv
\n
25.00%
\n
Parque E\u00f3lico
\n
Carretera de Arinaga
\n
SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 1,603,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
Parque E\u00f3lico de
\n
Barbanza SA
\n
A Coru\u00f1a ES 3,606,072.60 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.00%
\n
52.59%
\n
Parque E\u00f3lico de
\n
Barbanza SA
\n
0.00%
\n
Parque E\u00f3lico de San
\n
Andr\u00e9s SA
\n
A Coru\u00f1a ES 552,920.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
82.00% 57.50%
\n
Parque E\u00f3lico de Santa
\n
Luc\u00eda SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 901,500.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
65.67%
\n
46.51%
\n
Parque E\u00f3lico de
\n
Santa Luc\u00eda SA
\n
1.00%
\n
Parque E\u00f3lico Finca de
\n
Mog\u00e1n SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 3,810,340.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.11%
\n
Parque E\u00f3lico Montes
\n
de las Navas SA
\n
Madrid ES 6,540,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.50% 52.94%
\n
Parque E\u00f3lico Muniesa
\n
SLU
\n
Madrid ES 3,006.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico Palmas
\n
dos Ventos Ltda
\n
Salvador BR 4,096,626.00 BRL
\n
Line-by-line
\n
Enel Brasil SA 100.00%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Parque E\u00f3lico Pampa
\n
SA
\n
Buenos Aires AR 477,139,364.00 ARS
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Parque E\u00f3lico Punta de
\n
Teno SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 528,880.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
52.00% 36.46%
\n
Parque E\u00f3lico Sierra del
\n
Madero SA
\n
Madrid ES 7,193,970.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
58.00% 40.67%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parque Salitrillos SA
\n
de Cv
\n
Mexico City MX 100.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Solar Cauchari
\n
IV SA
\n
San Salvador
\n
de Jujuy
\n
AR 500,000.00 ARS
\n
Line-by-line
\n
Enel Green Power
\n
Argentina SA
\n
95.00%
\n
82.27%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
5.00%
\n
Parque Solar Don Jos\u00e9
\n
SA de Cv
\n
Mexico City MX 100.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Solar Villanueva
\n
Tres SA de Cv
\n
Mexico City MX 306,024,631.13 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Parque Talinay Oriente
\n
SA
\n
Santiago de
\n
Chile
\n
CL 66,092,165,170.93 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
60.91%
\n
78.64%
\n
Enel Green Power
\n
SpA
\n
39.09%
\n
Pastis - Centro
\n
Nazionale per la
\n
ricerca e lo sviluppo
\n
dei materiali SCPA in
\n
liquidation
\n
Brindisi IT 2,065,000.00 EUR
\n
- Enel Italia SpA 1.14% 1.14%
\n
Paynesville Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
PayTipper Network Srl Cascina IT 40,000.00 EUR
\n
Equity PayTipper SpA 100.00% 50.00%
\n
PayTipper SpA Milan IT 3,000,000.00 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
PDP Technologies Ltd Israel IL 1,129,252.00 ILS
\n
- Enel Grids Srl 5.72% 5.72%
\n
Pearl Star Wind Limited
\n
Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Pebble Stream Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pegop - Energia
\n
El\u00e9ctrica SA
\n
Pego PT 50,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
0.02%
\n
35.06%
\n
Endesa Generaci\u00f3n
\n
SAU
\n
49.98%
\n
PH Chucas SA San Jos\u00e9 CR 100,000.00 CRC
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
24.69%
\n
30.67%
\n
Enel Costa Rica
\n
CAM SA
\n
40.31%
\n
PH Don Pedro SA San Jos\u00e9 CR 100,001.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
33.44%
\n
18.92%
\n
Globyte SA 66.54%
\n
PH R\u00edo Volc\u00e1n SA San Jos\u00e9 CR 100,001.00 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
34.32%
\n
19.29%
\n
Globyte SA 65.66%
\n
Piebald Hill Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pike Den Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pilesgrove Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Pincher Creek LP Alberta CA - CAD Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
51.00%
\n
51.00%
\n
Enel Green Power
\n
Canada Inc.
\n
1.00%
\n
Pine Island Distributed
\n
Solar LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Point Rider Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pomerado Energy
\n
Storage LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Potoc Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
PowerCrop
\n
Macchiareddu Srl
\n
Bologna IT 100,000.00 EUR
\n
Equity
\n
PowerCrop
\n
SpA (formerly
\n
PowerCrop Srl)
\n
100.00% 50.00%
\n
PowerCrop Russi Srl Bologna IT 100,000.00 EUR
\n
Equity
\n
PowerCrop
\n
SpA (formerly
\n
PowerCrop Srl)
\n
100.00% 50.00%
\n
PowerCrop SpA
\n
(formerly PowerCrop
\n
Srl)
\n
Bologna IT 4,000,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Prairie Rose
\n
Transmission LLC
\n
Minneapolis US - USD
\n
Equity
\n
Prairie Rose Wind
\n
LLC
\n
100.00% 10.00%
\n
Prairie Rose Wind LLC Albany US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
Primavera Energia SA Niter\u00f3i BR 36,965,444.64 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Productive Solar
\n
Systems SLU
\n
Andorra ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Productora de Energ\u00edas
\n
SA
\n
Barcelona ES 60,101.22 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.04%
\n
Productora El\u00e9ctrica
\n
Urgellenca SA
\n
L\u00e9rida ES 8,400,000.00 EUR
\n
- Endesa SA 8.43% 5.91%
\n
Progreso Solar 20
\n
MW SA
\n
Panama City PA 10,000.00 USD
\n
Line-by-line
\n
Enel Panam\u00e1 CAM
\n
Srl
\n
100.00% 47.19%
\n
Promociones
\n
Energ\u00e9ticas del Bierzo
\n
SLU
\n
Madrid ES 12,020.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Promotores Mud\u00e9jar
\n
400 kV SL
\n
Zaragoza ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
24.75%
\n
26.08%
\n
Renovables La
\n
Pedrera SLU
\n
6.75%
\n
Renovables
\n
Mediavilla SLU
\n
5.69%
\n
Proveedora de
\n
Electricidad de
\n
Occidente S de RL
\n
de Cv
\n
Mexico City MX 89,708,835.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
99.99% 99.99%
\n
Prowind Windfarm
\n
Bogdanesti Srl
\n
Bucharest RO 118,460,800.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Prowind Windfarm
\n
Deleni Srl
\n
Bucharest RO 202,009,300.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Prowind Windfarm
\n
Ivesti Srl
\n
Bucharest RO 720,455,300.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Prowind Windfarm
\n
Viisoara Srl
\n
Bucharest RO 142,540,400.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Proyectos
\n
Universitarios de
\n
Energ\u00edas Renovables SL
\n
Alicante ES 27,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Proyectos y Soluciones
\n
Renovables SAC
\n
San Miguel PE 1,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
99.90%
\n
99.98%
\n
Energ\u00eda y Servicios
\n
South America SpA
\n
0.10%
\n
PSG Energy Private
\n
Limited
\n
Hyderabad IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
PT Enel Green Power
\n
Optima Way Ratai
\n
Jakarta ID 10,002,740.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
90.00% 90.00%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda I SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Puerto Santa Mar\u00eda
\n
Energ\u00eda II SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Pulida Energy (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
52.70% 52.70%
\n
Pumpkin Vine Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Quatiara Energia SA Niter\u00f3i BR 13,766,118.96 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Queens Energy
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Raleigh Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ranchland Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Wind
\n
Storage LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rattlesnake Creek
\n
Holdings LLC
\n
Delaware US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rausch Creek Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
RC Wind Srl Milan IT 10,000.00 EUR
\n
-
\n
Enel Green Power
\n
Italia Srl
\n
0.50% 0.50%
\n
RE Arroyo LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Reaktortest SRO Trnava SK 66,389.00 EUR
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
49.00% 16.17%
\n
Rebuilding Agente
\n
Rehabilitador SL
\n
Madrid ES 250,000.00 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
50.00% 35.06%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Red Cardinal Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Centroamericana
\n
de Telecomunicaciones
\n
SA
\n
Panama City PA 2,700,000.00 USD
\n
- Enel SpA 11.11% 11.11%
\n
Red Dirt Wind Holdings
\n
I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Red Dirt Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Dirt Wind Project
\n
LLC
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Red Dirt Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Red Fox Wind Project
\n
LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Stag Energy
\n
Storage Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Top Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Redes y
\n
Telecomunicaciones S
\n
de RL de Cv
\n
San Pedro Sula HN 82,395,000.00 HNL
\n
- Livister Latam SLU 95.00% 18.53%
\n
Regal Rising Solar
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Ren Wave Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Renovables Andorra
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Brovales
\n
400 kV SL
\n
Seville ES 5,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 6.24%
\n
44.98%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
6.24%
\n
Emintegral Cycle
\n
SLU
\n
16.99%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
22.20%
\n
Furatena Solar 1
\n
SLU
\n
6.24%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
6.24%
\n
Renovables de
\n
Guatemala SA
\n
Guatemala City GT 1,924,465,600.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%
\n
Enel Guatemala SA 0.00%
\n
Renovables La Pedrera
\n
SLU
\n
Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables
\n
Manzanares 400 kV SL
\n
Madrid ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
27.86%
\n
30.84%
\n
Stonewood
\n
Desarrollos SLU
\n
16.12%
\n
Renovables Mediavilla
\n
SLU
\n
Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Teruel SLU Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Ribina Renovables
\n
400 SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
39.24% 27.51%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Riverbend Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Riverview LP Alberta CA - CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
51.00%
\n
51.00%
\n
Enel Green Power
\n
Canada Inc.
\n
1.00%
\n
Riverview Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Solar
\n
Project LLC
\n
Andover US 100.00 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Storage
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rochelle Solar LLC Coral Springs US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings II LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings
\n
II LLC
\n
100.00% 100.00%
\n
Rock Creek Wind
\n
Project LLC
\n
Clayton US 1.00 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Prairie Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Ranchland
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rocky Caney Holdings
\n
LLC
\n
Oklahoma City US 1.00 USD
\n
Equity Enel Kansas LLC 10.00% 10.00%
\n
Rocky Caney Wind LLC Albany US - USD
\n
Equity
\n
Rocky Caney
\n
Holdings LLC
\n
100.00% 10.00%
\n
Rocky Ridge Wind
\n
Project LLC
\n
Oklahoma City US - USD
\n
Equity
\n
Rocky Caney Wind
\n
LLC
\n
100.00% 10.00%
\n
Rodnikovskaya WPS Moscow RU 6,010,000.00 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Roha Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Rolling Farms Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Rosy Range Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rusenergosbyt LLC Moscow RU 18,000,000.00 RUB
\n
Equity Enel SpA 49.50% 49.50%
\n
Rusenergosbyt Siberia
\n
LLC
\n
Krasnoyarsk
\n
City
\n
RU 4,600,000.00 RUB
\n
Equity Rusenergosbyt LLC 50.00% 24.75%
\n
Ruthton Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,000.00 PLN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Saburoy SA Montevideo UY 100,000.00 UYU - IFX Networks LLC 100.00% 19.50%
\n
Sacme SA Buenos Aires AR 12,000.00 ARS
\n
Equity
\n
Empresa
\n
Distribuidora Sur
\n
SA - Edesur
\n
50.00% 29.66%
\n
Saddle House Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Salt Springs Wind
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Salto de San Rafael SL Seville ES 462,185.98 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
San Francisco de
\n
Borja SA
\n
Zaragoza ES 60,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.75%
\n
San Juan Mesa Wind
\n
Project II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind
\n
Power LLC
\n
100.00% 100.00%
\n
Sanosari Energy Private
\n
Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Santo Rostro
\n
Cogeneraci\u00f3n SA in
\n
liquidation
\n
Seville ES 207,340.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Sardhy Green
\n
Hydrogen Srl
\n
Sarroch IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Saugus River Energy
\n
Storage LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Savanna Power Solar
\n
10 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
12 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
13 SLU
\n
Seville ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
4 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
5 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
6 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar
\n
9 SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Se Slu\u017eby In\u017einierskych
\n
Stavieb SRO
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 200,000.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Seccionadora
\n
Almod\u00f3var Renovables
\n
SL
\n
Malaga ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
37.50% 26.29%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
Madrid ES 3,010.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Servizio Elettrico
\n
Nazionale SpA
\n
Rome IT 10,000,000.00 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Set Carmona 400 kV
\n
Renovables SL
\n
Seville ES 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
16.00% 11.22%
\n
Setyl Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 27.50% 27.50%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Seven Cowboy PPA LLC Andover US 1.00 USD Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project II LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Seven Cowboy
\n
Wind Project
\n
Holdings LLC
\n
100.00% 100.00%
\n
Seven Cowboys Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shark Power REN 10
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 4
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 5
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 6
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 7
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 8
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power REN 9
\n
SLU
\n
Madrid ES 3,000.00 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power SLU Seville ES 143,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Shepherd Pass Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shiawassee Wind
\n
Project LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shield Energy Storage
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Shikhar Surya (One)
\n
Private Limited
\n
Gurugram IN 340,100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
SIET - Societ\u00e0
\n
Informazioni
\n
Esperienze
\n
Termoidrauliche SpA
\n
Piacenza IT 697,820.00 EUR
\n
Equity
\n
Enel Innovation
\n
Hubs Srl
\n
41.55% 41.55%
\n
Silt Solar I LLC Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Silver Dollar Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Silverware Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sinergia GP6 Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Sinergia GP7 Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Sistema El\u00e9ctrico de
\n
Conexi\u00f3n Valcaire SL
\n
Madrid ES 175,200.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
28.13% 19.72%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Sistemas Energ\u00e9ticos
\n
Ma\u00f1\u00f3n Ortigueira SA
\n
A Coru\u00f1a ES 2,007,750.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
96.00% 67.31%
\n
Skyview Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Skyview Wind Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
SL Energy SAC Lima PE 1,000.00 PEN
\n
Line-by-line
\n
Enel Green Power
\n
Per\u00fa SAC
\n
99.90%
\n
82.27%
\n
Enel Per\u00fa SAC 0.10%
\n
Sleep Hollow Solar
\n
I LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Slovak Power Holding
\n
BV
\n
Amsterdam NL 25,010,000.00 EUR
\n
Equity
\n
Enel Produzione
\n
SpA
\n
50.00% 50.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
- Energetick\u00e9 Slu\u017eby
\n
SRO
\n
Bratislava SK 4,505,000.00 EUR
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
Bratislava SK 1,269,295,724.66 EUR
\n
Equity
\n
Slovak Power
\n
Holding BV
\n
66.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne
\n
\u010cesk\u00e1 Republika SRO
\n
Moravsk\u00e1
\n
Ostrava
\n
CZ 295,819.00 CZK
\n
Equity
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
100.00% 33.00%
\n
Smoky Hill Holdings
\n
II LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Smoky Hills Wind Farm
\n
LLC
\n
Topeka US - USD
\n
Line-by-line
\n
EGPNA Project
\n
HoldCo 1 LLC
\n
100.00% 100.00%
\n
Smoky Hills Wind
\n
Project II LLC
\n
Lenexa US - USD
\n
Line-by-line
\n
EGPNA Project
\n
HoldCo 1 LLC
\n
100.00% 100.00%
\n
Snowy Knoll Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Snyder Wind Farm LLC Hermleigh US - USD
\n
Line-by-line Texkan Wind LLC 100.00% 100.00%
\n
Socibe Energia SA Niter\u00f3i BR 12,969,032.25 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Sociedad Agr\u00edcola de
\n
Cameros Ltda
\n
Santiago de
\n
Chile
\n
CL 5,738,046,495.00 CLP
\n
Line-by-line Enel Chile SA 57.50% 37.33%
\n
Sociedad E\u00f3lica de
\n
Andaluc\u00eda SA
\n
Seville ES 4,507,590.78 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
64.75% 45.40%
\n
Sociedad E\u00f3lica El
\n
Puntal SL
\n
Seville ES 1,643,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
Sociedad E\u00f3lica Los
\n
Lances SA
\n
Seville ES 2,404,048.42 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Sociedad para el
\n
Desarrollo de Sierra
\n
Morena Cordobesa SA
\n
Cordoba ES 86,063.20 EUR
\n
-
\n
Endesa Generaci\u00f3n
\n
SAU
\n
1.82% 1.27%
\n
Sociedad Portuaria
\n
Central Cartagena SA
\n
Bogot\u00e1 CO 89,714,600.00 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
94.94%
\n
47.17%
\n
Enel X Colombia
\n
SAS ESP
\n
5.05%
\n
Societ\u00e0 Elettrica Trigno
\n
Srl
\n
Trivento IT 100,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Soetwater Wind Farm
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 1,000.00 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Solana Renovables SL Madrid ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
49.84% 34.95%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Solas Electricity Srl Bucharest RO 17,740,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Soliloquoy Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Sona Enerj\u00ed \u00dcret\u00edm
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 50,000.00 TRY
\n
Line-by-line
\n
Enel Green Power
\n
Turkey Enerj\u00ed
\n
Yatirimlari
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
100.00% 100.00%
\n
Sonak Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Sotavento Galicia SA
\n
Santiago de
\n
Compostela
\n
ES 601,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.00% 25.24%
\n
South Italy Green
\n
Hydrogen Srl
\n
Rome IT 10,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
South Rock Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
South Wind Energy Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Southwest
\n
Transmission LLC
\n
Cedar Bluff US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
100.00% 100.00%
\n
Southwestern Rays
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Spartan Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Spinazzola SPV Srl Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Spring Wheat Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Square Dance Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sreeja Infrastructure
\n
Private Limited
\n
Hyderabad IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Stable Brook Storage
\n
Project Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta
\n
Storage Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Stampede Solar
\n
Holdings LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
Stampede Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Stampede Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Enel Kansas
\n
Development
\n
Holdings LLC
\n
100.00% 100.00%
\n
Star Catcher Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Star Energy Single
\n
Member P.C.
\n
Maroussi GR 28,010.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 100.00%
\n
Station Tales Solar
\n
Limited Partnership
\n
Calgary CA 100.00 CAD
\n
Line-by-line
\n
Enel Alberta Solar
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Sterling and Wilson
\n
Enel X e-Mobility
\n
Private Limited
\n
Mumbai IN 90,000,000.00 INR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Stillman Valley Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Stillwater Woods Hill
\n
Holdings LLC
\n
Wilmington US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stipa Naya\u00e1 SA de Cv Mexico City MX 1,811,016,348.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
55.21%
\n
95.37%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
40.16%
\n
Stockyard Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stonewood Desarrollos
\n
SLU
\n
Madrid ES 4,053,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Storey Plains Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stormy Hills Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Strinestown Solar I LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Suave Energ\u00eda S de RL
\n
de Cv
\n
Mexico City MX 1,000.00 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL
\n
de Cv
\n
0.10%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.90%
\n
Sublunary Trading (RF)
\n
(Pty) Ltd
\n
Bryanston ZA 13,750,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
57.00% 57.00%
\n
Sugar Pine Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Suggestion Power
\n
Unipessoal Ltda
\n
Pa\u00e7o de Arcos PT 50,000.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
100.00% 70.12%
\n
Suministradora
\n
El\u00e9ctrica de C\u00e1diz SA
\n
Cadiz ES 12,020,240.00 EUR
\n
Equity Endesa Red SAU 33.50% 23.49%
\n
Suministro de Luz y
\n
Fuerza SL
\n
Barcelona ES 2,800,000.00 EUR
\n
Line-by-line
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
60.00% 42.07%
\n
Summit Energy
\n
Storage Inc.
\n
Wilmington US 1,000.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
75.00% 75.00%
\n
Sun River LLC Bend US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Sun4 Koryta Sp\u00f3\u0142ka
\n
Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,750.00 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z
\n
Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
80.00% 80.00%
\n
Sun4 Torzym Sp\u00f3\u0142ka
\n
Z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,750.00 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka Z
\n
Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
80.00% 80.00%
\n
Sundance Wind
\n
Project LLC
\n
Dover US 100.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sunflower Prairie Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Swather Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sweet Apple Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
TAE Technologies Inc.
\n
Pauling US 53,207,936.00 USD
\n
-
\n
Enel Produzione
\n
SpA
\n
1.12%
\n
1.12%
\n
TAE Technologies
\n
Inc.
\n
0.00%
\n
Tasseling Jewel Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tauste Energ\u00eda
\n
Distribuida SL
\n
Zaragoza ES 60,508.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Tecnatom do Brasil
\n
Enghenaria e Servi\u00e7os
\n
Ltda
\n
Rio de Janeiro BR 1,600,000.00 BRL
\n
Equity Tecnatom SA 90.00% 28.40%
\n
Tecnatom France SAS
\n
Saint Loup de
\n
Varennes
\n
FR 1,888,870.38 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom M\u00e9xico SA
\n
de Cv
\n
Veracruz MX 6,000,000.00 MXN
\n
Equity
\n
Inspectores y
\n
Consultores Ibercal
\n
SLU
\n
0.17%
\n
31.56%
\n
Tecnatom SA 99.83%
\n
Tecnatom Servicios
\n
T\u00e9cnicos y Consultor\u00eda
\n
SLU
\n
Sebasti\u00e1n de
\n
los Reyes
\n
ES 3,000.00 EUR
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom UK Ltd London GB 1.00 GBP
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom USA
\n
Corporation
\n
Wilmington US 3,000.00 USD
\n
Equity Tecnatom SA 100.00% 31.56%
\n
Tecnatom SA Madrid ES 4,025,700.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
45.00% 31.56%
\n
Tecnoguat SA Guatemala City GT 30,948,000.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
75.00% 35.38%
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica SA
\n
Lisbon PT 5,025,000.00 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
43.75% 30.68%
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y Viento
\n
SAPI de Cv
\n
Mexico City MX 2,892,643,576.00 MXN
\n
Equity
\n
Enel Green Power
\n
SpA
\n
32.89% 32.90%
\n
Tera Renewables India
\n
Private Limited
\n
Gurugram IN 100,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Termica Colleferro SpA Bologna IT 6,100,000.00 EUR
\n
Equity Cogenio Srl 60.00% 12.00%
\n
Termoel\u00e9ctrica Jos\u00e9 de
\n
San Mart\u00edn SA
\n
Buenos Aires AR 7,078,298.00 ARS
\n
-
\n
Central Dock Sud
\n
SA
\n
0.42%
\n
4.22%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.68%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
5.60%
\n
Termoel\u00e9ctrica Manuel
\n
Belgrano SA
\n
Buenos Aires AR 7,078,307.00 ARS
\n
-
\n
Central Dock Sud
\n
SA
\n
0.47%
\n
4.71%
\n
Enel Generaci\u00f3n
\n
Costanera SA
\n
1.89%
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
6.23%
\n
Termotec Energ\u00eda AIE
\n
in liquidation
\n
La Pobla de
\n
Vallbona
\n
ES 481,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Terrer Renovables SL Madrid ES 5,000.00 EUR
\n
Equity
\n
Baylio Solar SLU 11.66%
\n
20.73%
\n
Dehesa de los
\n
Guadalupes Solar
\n
SLU
\n
8.83%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
9.08%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Texas Sage Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Texkan Wind LLC Andover US - USD
\n
Line-by-line Enel Texkan Inc. 100.00% 100.00%
\n
Thar Surya 1 Private
\n
Limited
\n
Gurgaon IN 200,000.00 INR
\n
Equity
\n
Avikiran Surya India
\n
Private Limited
\n
100.00% 51.00%
\n
Thunder Ranch Wind
\n
Holdings I LLC
\n
Dover US 100.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Thunder Ranch Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Thunder Ranch Wind
\n
Project LLC
\n
Dover US 1.00 USD
\n
Line-by-line
\n
Thunder Ranch
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Thunderegg Storage
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Thunderegg Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tico Solar 1 SLU Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tico Solar 2 SLU Zaragoza ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tieton Storage Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tobivox (RF) (Pty) Ltd Johannesburg ZA 10,000,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
60.00% 60.00%
\n
Toledo PV AIE Madrid ES 26,887.96 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Toplet Power Park Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Topwind Energy Srl Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Toro Renovables 400
\n
kV SL
\n
Madrid ES 3,000.00 EUR
\n
Equity
\n
FRV Zamora Solar
\n
1 SLU
\n
8.28% 5.81%
\n
Torrepalma Energy
\n
1 SLU
\n
Madrid ES 3,100.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tradewind Energy Inc. Wilmington US 1,000.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trading Post Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trail Ride Canyon Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Transformadora
\n
Almod\u00f3var Renovables
\n
SL
\n
Seville ES 5,000.00 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.53% 42.44%
\n
Transmisora de Energ\u00eda
\n
Renovable SA
\n
Guatemala City GT 233,561,800.00 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47.18%Enel Guatemala SA 0.00%
\n
Generadora
\n
Montecristo SA
\n
0.00%
\n
Transportadora de
\n
Energ\u00eda SA - TESA
\n
Buenos Aires AR 2,584,473,416.00 ARS
\n
Line-by-line
\n
Enel Argentina SA 0.00%
\n
82.27%Enel Brasil SA 60.15%
\n
Enel CIEN SA 39.85%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Transportes y
\n
Distribuciones
\n
El\u00e9ctricas SA in
\n
liquidation
\n
Girona ES 72,121.45 EUR
\n
Line-by-line
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
73.33% 51.42%
\n
Tr\u00e9vago Renovables SL Madrid ES 3,000.00 EUR
\n
Equity
\n
Furatena Solar 1
\n
SLU
\n
17.73%
\n
24.89%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
17.77%
\n
Tsar Nicholas LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Tula WPS LLC Tula RU - RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Tulip Grove Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tumbleweed Flat Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tunga Renewable
\n
Energy Private Limited
\n
Gurugram IN 96,300,000.00 INR
\n
Line-by-line
\n
Avikiran Energy
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
TWE Franklin Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
TWE ROT DA LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Twin Lake Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
Twin Saranac Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Tyme Srl Bergamo IT 100,000.00 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
Ufinet Argentina SA Buenos Aires AR 9,745,583.00 ARS
\n
-
\n
Ufinet Latam SLU 99.95%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.05%
\n
Ufinet Brasil
\n
Participa\u00e7\u00f5es Ltda
\n
Santo Andr\u00e9 BR 120,784,639.00 BRL
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
19.50%
\n
Ufinet Latam SLU 100.00%
\n
Ufinet Brasil SA Barueri BR 51,766,147.00 BRL
\n
-
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o
\n
Ltda
\n
80.00% 15.60%
\n
Ufinet Brasil
\n
Telecomunica\u00e7\u00e3o Ltda
\n
Santo Andr\u00e9 BR 120,784,638.00 BRL
\n
-
\n
Ufinet Brasil
\n
Participa\u00e7\u00f5es Ltda
\n
100.00% 19.50%
\n
Ufinet Chile SpA
\n
Santiago de
\n
Chile
\n
CL 233,750,000.00 CLP
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Colombia
\n
Participaciones SAS
\n
Bogot\u00e1 CO 10,001,001,000.00 COP
\n
- Ufinet Colombia SA 100.00% 17.55%
\n
Ufinet Colombia SA Bogot\u00e1 CO 1,180,000,000.00 COP
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
17.55%
\n
Ufinet Honduras SA 0.00%
\n
Ufinet Latam SLU 90.00%
\n
Ufinet Panam\u00e1 SA 0.00%
\n
Ufinet Costa Rica SA San Jos\u00e9 CR 25,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Ecuador Ufiec
\n
SA
\n
Quito EC 9,865,110.00 USD
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.00%
\n
14.04%
\n
Ufinet Latam SLU 71.97%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ufinet El Salvador SA
\n
de Cv
\n
San Salvador SV 10,000.00 USD
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.01%
\n
19.50%
\n
Ufinet Latam SLU 99.99%
\n
Ufinet FTTH Guatemala
\n
Ltda
\n
Guatemala City GT 7,007,000.00 GTQ
\n
- Ufinet Latam SLU 51.00% 9.94%
\n
Ufinet Guatemala SA Guatemala City GT 3,000,000.00 GTQ
\n
-
\n
Ufinet Latam SLU 99.99%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.01%
\n
Ufinet Honduras SA Tegucigalpa HN 194,520.00 HNL
\n
-
\n
Ufinet Latam SLU 99.99%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.01%
\n
Ufinet Latam SLU Madrid ES 15,906,312.00 EUR
\n
- Zacapa S\u00e0rl 100.00% 19.50%
\n
Ufinet M\u00e9xico S de RL
\n
de Cv
\n
Mexico City MX 7,635,430.00 MXN
\n
-
\n
Ufinet Guatemala
\n
SA
\n
1.31%
\n
19.50%
\n
Ufinet Latam SLU 98.69%
\n
Ufinet Nicaragua SA Managua NI 2,800,000.00 NIO
\n
-
\n
Ufinet Guatemala
\n
SA
\n
0.50%
\n
19.50%
\n
Ufinet Latam SLU 99.00%
\n
Ufinet Panam\u00e1 SA 0.50%
\n
Ufinet Panam\u00e1 SA Panama City PA 1,275,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Ufinet Paraguay SA Asunci\u00f3n PY 79,488,240,000.00 PYG
\n
- Ufinet Latam SLU 75.00% 14.63%
\n
Ufinet Per\u00fa SAC Lima PE 2,836,474.00 PEN
\n
-
\n
Ufinet Latam SLU 100.00%
\n
19.50%
\n
Ufinet Panam\u00e1 SA 0.00%
\n
Ufinet US LLC Wilmington US 1,000.00 USD
\n
- Ufinet Latam SLU 100.00% 19.50%
\n
Uni\u00f3n El\u00e9ctrica de
\n
Canarias Generaci\u00f3n
\n
SAU
\n
Las Palmas de
\n
Gran Canaria
\n
ES 190,171,520.00 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Upington Solar (Pty) Ltd Johannesburg ZA 1,000.00 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty)
\n
Ltd
\n
100.00% 100.00%
\n
Usina E\u00f3lica Pedra
\n
Pintada A Ltda
\n
Rio de Janeiro BR 653,327.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada B Ltda
\n
Rio de Janeiro BR 748,697.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada C Ltda
\n
Rio de Janeiro BR 805,024.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra
\n
Pintada D Ltda
\n
Rio de Janeiro BR 653,327.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 11 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 12 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 13 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 14 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 15 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 16 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Usina Fotovoltaica
\n
Arinos E 17 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 21 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 22 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 23 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica
\n
Arinos E 24 Ltda
\n
Rio de Janeiro BR 221,724,006.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
USME ZE SAS Bogot\u00e1 CO 104,872,000.00 COP
\n
AFS Bogot\u00e1 ZE SAS 100.00% 47.18%
\n
Ustav Jadern\u00e9ho
\n
V\u00fdzkumu Rez AS
\n
\u0158e\u017e CZ 524,139,000.00 CZK
\n
-
\n
Slovensk\u00e9
\n
elektr\u00e1rne AS
\n
27.77% 9.17%
\n
Vayu (Project 1) Private
\n
Limited
\n
Gurugram IN 30,000,000.00 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private
\n
Limited
\n
100.00% 100.00%
\n
Vekt\u00f6r Enerj\u00ed \u00dcret\u00edm
\n
Anon\u00edm \u015e\u00edrket\u00ed
\n
Istanbul TR 3,500,000.00 TRY
\n
AFS Enel SpA 100.00% 100.00%
\n
Ventos de Santa
\n
\u00c2ngela Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 7,315,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santa
\n
Esperan\u00e7a Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 4,727,414.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santo
\n
Orestes Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 1,754,031.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o Cirilo
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,572,010.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o M\u00e1rio
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,492,000.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o Roque
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 10,188,722.00 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Vientos del Altiplano
\n
SA de Cv
\n
Mexico City MX 1,455,854,094.00 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Villanueva Solar SA
\n
de Cv
\n
Mexico City MX 205,316,027.15 MXN
\n
Equity
\n
Tenedora de
\n
Energ\u00eda Renovable
\n
Sol y Viento SAPI
\n
de Cv
\n
60.80% 20.00%
\n
Viruleiros SL
\n
Santiago de
\n
Compostela
\n
ES 160,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
67.00% 46.98%
\n
Viva Labs AS Oslo NO 1,047,249.00 NOK
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Walking Horse Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wapella Bluffs Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Waseca Solar LLC Waseca US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Waypost Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Weber Energy Storage
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy
\n
Storage Holdings
\n
LLC (formerly EGP
\n
Energy Storage
\n
Holdings LLC)
\n
100.00% 100.00%
\n
Wespire Inc. Boston US 1,625,000.00 USD
\n
-
\n
Enel X North
\n
America Inc.
\n
11.21% 11.21%
\n
West Faribault Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
West Waconia Solar
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74.13%
\n
Western New York
\n
Wind Corporation
\n
Albany US 300.00 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Wharton-El Campo
\n
Solar Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
White Cloud Wind
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
White Cloud Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
White Cloud Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
White Peaks Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitetail Trails Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Whitney Hill Wind
\n
Power Holdings LLC
\n
Andover US 99.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitney Hill Wind
\n
Power LLC
\n
Andover US - USD
\n
Line-by-line
\n
Whitney Hill Wind
\n
Power Holdings
\n
LLC
\n
100.00% 100.00%
\n
Whittle\u2019s Ferry Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wild Ox Solar Project
\n
LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wild Run LP Alberta CA 10.00 CAD
\n
Line-by-line
\n
Enel Alberta Wind
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Wildcat Flats Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Wilderness Range
\n
Solar Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildflower Flats Battery
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildflower Flats Solar
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wind Belt Transco LLC Andover US 1.00 USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n
Wind Energy Green
\n
Park Srl
\n
Bucharest RO 2,000.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Wind Parks Anatolis -
\n
Prinias Single Member
\n
SA
\n
Maroussi GR 15,803,388.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n

\n\n
Company name Head quarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Wind Parks Katharas
\n
Single Member SA
\n
Maroussi GR 19,932,048.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Kerasias
\n
Single Member SA
\n
Maroussi GR 26,107,790.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Milias
\n
Single Member SA
\n
Maroussi GR 19,909,374.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Mitikas
\n
Single Member SA
\n
Maroussi GR 22,268,039.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Platanos
\n
Single Member SA
\n
Maroussi GR 13,342,867.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Wind Parks Spilias
\n
Single Member SA
\n
Maroussi GR 28,267,490.00 EUR
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 100.00%
\n
Windbreaker Storage
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Winter\u2019s Spawn LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota
\n
Wind LLC
\n
51.00% 51.00%
\n
WKN Basilicata
\n
Development PE1 Srl
\n
Rome IT 10,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Woods Hill Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Stillwater Woods
\n
Hill Holdings LLC
\n
100.00% 100.00%
\n
Xaloc Solar SLU Valencia ES 3,000.00 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
X-bus Italia Srl Milan IT 15,000.00 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Yacylec SA Buenos Aires AR 20,000,000.00 ARS
\n
Equity Enel Am\u00e9ricas SA 33.33% 27.42%
\n
Yedesa Cogeneraci\u00f3n
\n
SA in liquidation
\n
Almer\u00eda ES 234,394.72 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
Yellow Rose Wind
\n
Project LLC
\n
Andover US 1.00 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Yorktown Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North
\n
America Inc.
\n
100.00% 100.00%
\n
Zacapa HoldCo S\u00e0rl Luxembourg LU 76,180,812.49 EUR
\n
- Zacapa Topco S\u00e0rl 100.00% 19.50%
\n
Zacapa LLC Wilmington US 100.00 USD
\n
- Zacapa S\u00e0rl 100.00% 19.50%
\n
Zacapa S\u00e0rl Luxembourg LU 82,866,475.04 USD
\n
- Zacapa HoldCo S\u00e0rl 100.00% 19.50%
\n
Zacapa Topco S\u00e0rl Luxembourg LU 29,970,000.00 EUR
\n
-
\n
Enel X International
\n
Srl
\n
19.50% 19.50%
\n
Zephir 3 Constanta Srl Bucharest RO 1,031,260.00 RON
\n
Discontinued
\n
operations
\n
Enel Green Power
\n
Romania Srl
\n
100.00% 100.00%
\n
Zoo Solar Project LLC Andover US - USD
\n
Line-by-line
\n
Tradewind Energy
\n
Inc.
\n
100.00% 100.00%
\n

\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCompositionOfGroupExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "footnote1": { "value": "
The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote1", "language": "en" } }, "footnote5": { "value": "
Of which cash and cash equivalents equal to \u20ac11,041 million at December 31, 2022 (\u20ac8,315 million at December 31, 2021), short-term securities equal to
\n
\u20ac78 million at December 31, 2022 (\u20ac88 million at December 31, 2021) and cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of
\n
\u20ac98 million at December 31, 2022 (\u20ac44 million at December 31, 2021) and to \u201cDiscontinued operations\u201d equal to \u20ac326 million at December 31, 2022 (\u20ac543
\n
million at December 31, 2021).
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote5", "language": "en" } }, "footnote2": { "value": "
The figure for 2021 has been adjusted, for comparative purposes only, to take account of the classification under the item \u201cProfit/(Loss) from discontinued
\n
operations\u201d of profit/(loss) connected with the assets held in Russia (which were sold in the 4th Quarter of 2022), Romania and Greece as the requirements
\n
of IFRS 5 for their classification as discontinued operations have been met.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote2", "language": "en" } }, "footnote3": { "value": "
In order to improve presentation of the 2021 figures, for comparative purposes only, realized financial income and expense connected solely with loans in
\n
currencies have been reclassified under a new item \u201cCollections/(Payments) associated with derivatives connected with borrowings\u201d in the section on cash
\n
flows from financing activities.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote3", "language": "en" } }, "footnote4": { "value": "
Of which cash and cash equivalents equal to \u20ac8,315 million at January 1, 2022 (\u20ac5,266 million at January 1, 2021), short-term securities equal to \u20ac88 million
\n
at January 1, 2022 (\u20ac67 million at January 1, 2021), cash and cash equivalents pertaining to \u201cAssets held for sale\u201d in the amount of \u20ac44 million at January 1,
\n
2022 (\u20ac29 million at January 1, 2021) and cash and cash equivalents pertaining to \u201cDiscontinued operations\u201d equal to \u20ac543 million at January 1, 2022 (\u20ac640
\n
million at January 1, 2021).
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote4", "language": "en" } } } }