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\n

\n

\n

\n

\n
1. Form and content of the consolidated financial statements
\n\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

\n\n\n\n\n\n\n\n\n\n\n\n\n\n\n\n
There were no changes in the company name in 2023.
\n

\n\n\n\n\n\n\n\n\n\n\n\n\n\n\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\n\n\n\n\n\n\n\n\n
The consolidated financial statements of the Group as at
\n
and for the year ended December 31, 2023 comprise the
\n
financial statements of Enel SpA, its subsidiaries and Group
\n
holdings in associates and joint ventures, as well as the
\n
Group\u2019s share of the assets, liabilities, costs and revenue of
\n
joint operations (\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 21, 2024.
\n

\n\n\n\n\n
These consolidated financial statements have been audited
\n
by KPMG SpA.
\n\n

\n

\n
Basis of presentation
\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2023 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
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

\n\n\n\n\n\n\n\n\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
\n
their nature, with separate reporting of profit/(loss) from
\n
continuing operations and profit/(loss) from discontinued
\n
operations attributable to owners of the Parent and to
\n
non-controlling 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
In particular, although the Group does not diverge from the
\n
provisions of IAS 7 in the classification of items:
\n
\u2022
\n
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
\n
investing activities comprise investments in property,
\n
plant and equipment and intangible assets and dispos-
\n
als of such assets and contract assets related to service
\n
concession arrangements. They include, also, the effects
\n
of business combinations in which the Group acquires
\n
or loses control of companies, as well as other minor in-
\n
vestments;
\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\n\n\n\n\n\n\n\n\n\n

\n\n

\n\n
\u2022
\n
cash flows from financing activities include cash flows
\n
generated by liability management transactions and
\n
leases, dividends and interim dividends paid to owners of
\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
\n
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 note 46 \u201cCash flows\u201d.
\n

\n\n\n\n\n\n\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 dis-
\n
posal groups classified as held for sale, which are measured
\n
at the lower of their carrying amount and fair value less
\n
costs to sell.
\n
The consolidated financial statements are presented in
\n
euro, the functional currency of the Parent Enel SpA. All fig-
\n
ures are shown in millions of euro unless stated otherwise.
\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 definition
\n
of which is given in note 2.2 \u201cMaterial accounting policies\u201d.
\n
The consolidated financial statements provide comparative
\n
information in respect of the previous year.
\n

\n\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1064": { "value": "\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

\n\n\n\n\n\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1065": { "value": "Enel SpA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1067": { "value": "137Viale Regina Margherita ", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1066": { "value": "Italy", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1068": { "value": "\n
There were no changes in the company name in 2023.
\n

\n\n\n\n\n\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:ExplanationOfChangeInNameOfReportingEntityOrOtherMeansOfIdentificationFromEndOfPrecedingReportingPeriod", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1069": { "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\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1070": { "value": "Europe and Latin America", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1071": { "value": "SpA", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1072": { "value": "\n
These consolidated financial statements were approved
\n
and authorized for publication by the Board of Directors on
\n
March 21, 2024.
\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, 2023, 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 Flavio Cattaneo and Stefano De Ange-
\n
lis, in their respective capacities as Chief Executive Of-
\n
ficer and officer in charge of financial reporting of Enel
\n
SpA, hereby certify, taking account of the provisions of
\n
Article 154-bis, paragraphs 3 and 4, of Legislative De-
\n
cree 58 of February 24, 1998:
\n
a. the appropriateness with respect to the characteristi-
\n
cs of the Enel Group and
\n
b. the effective adoption of the administrative and ac-
\n
counting procedures for the preparation of the con-
\n
solidated financial statements of the Enel Group in
\n
the period between January 1, 2023 and December
\n
31, 2023.
\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
\n
the consolidated financial statements of the Enel
\n
Group has been verified in an assessment of the
\n
internal control system for financial reporting. The
\n
assessment was carried out on the basis of the gui-
\n
delines set out in the \u201cInternal Controls - Integrated
\n
Framework\u201d issued by the Committee of Sponsoring
\n
Organizations 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, 2023:
\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
\n
other 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, 2023, contains a re-
\n
liable 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
\n
exposed.
\n
Rome, March 21, 2024
\n
Flavio Cattaneo Stefano De Angelis
\n
Chief Executive Officer of Enel SpA Officer in charge of financial
\n
reporting of Enel SpA
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1073": { "value": "\n

\n

\n
Basis of presentation
\n\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2023 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
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

\n\n\n\n\n\n\n\n\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
\n
their nature, with separate reporting of profit/(loss) from
\n
continuing operations and profit/(loss) from discontinued
\n
operations attributable to owners of the Parent and to
\n
non-controlling 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
In particular, although the Group does not diverge from the
\n
provisions of IAS 7 in the classification of items:
\n
\u2022
\n
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
\n
investing activities comprise investments in property,
\n
plant and equipment and intangible assets and dispos-
\n
als of such assets and contract assets related to service
\n
concession arrangements. They include, also, the effects
\n
of business combinations in which the Group acquires
\n
or loses control of companies, as well as other minor in-
\n
vestments;
\n

\n\n\n\n\n\n\n\n\n

\n

\n\n\n\n\n\n\n\n\n

\n\n
\u2022
\n
cash flows from financing activities include cash flows
\n
generated by liability management transactions and
\n
leases, dividends and interim dividends paid to owners of
\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
\n
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 note 46 \u201cCash flows\u201d.
\n

\n\n\n\n\n\n\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 dis-
\n
posal groups classified as held for sale, which are measured
\n
at the lower of their carrying amount and fair value less
\n
costs to sell.
\n
The consolidated financial statements are presented in
\n
euro, the functional currency of the Parent Enel SpA. All fig-
\n
ures are shown in millions of euro unless stated otherwise.
\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 definition
\n
of which is given in note 2.2 \u201cMaterial accounting policies\u201d.
\n
The consolidated financial statements provide comparative
\n
information in respect of the previous year.
\n

\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1074": { "value": "\n
The consolidated financial statements as at and for the year
\n
ended December 31, 2023 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
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

\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1075": { "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
In particular, although the Group does not diverge from the
\n
provisions of IAS 7 in the classification of items:
\n
\u2022
\n
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
\n
investing activities comprise investments in property,
\n
plant and equipment and intangible assets and dispos-
\n
als of such assets and contract assets related to service
\n
concession arrangements. They include, also, the effects
\n
of business combinations in which the Group acquires
\n
or loses control of companies, as well as other minor in-
\n
vestments;
\n

\n\n\n\n\n\n\n\n\n
\u2022
\n
cash flows from financing activities include cash flows
\n
generated by liability management transactions and
\n
leases, dividends and interim dividends paid to owners of
\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
\n
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 note 46 \u201cCash flows\u201d.
\n

\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCashFlowsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1076": { "value": "The consolidated financial statements have been prepared on a going concern basis", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1077": { "value": "Enel SpA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1078": { "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 re-
\n
lated disclosures concerning the items involved as well as
\n
contingent assets and liabilities. The estimates and man-
\n
agement\u2019s judgments are based on previous experience
\n
and other factors considered reasonable in the circum-
\n
stances. They are formulated when the carrying amount
\n
of assets and liabilities is not easily determined from other
\n
sources. The actual results may therefore differ from these
\n
estimates. The estimates and assumptions are periodical-
\n
ly revised and the effects of any changes are reflected
\n
through profit or loss if they only involve that period. If the
\n
revision involves both the current and future periods, the
\n
change is recognized in the period in which the revision is
\n
made and in the related future periods.
\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 anal-
\n
ysis carried out in accordance with the requirements of
\n
Practice Statement 2 \u201cMaking Materiality Judgments\u201d, is-
\n
sued by the International Accounting Standards Board
\n
(IASB).
\n
\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 management.
\n
In this regard, the main items included in the consolidat-
\n
ed financial statements at December 31, 2023 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 generation
\n
plants. For further details on these items, please see note
\n
19 \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
\n
and includes, in addition to amounts invoiced on the ba-
\n
sis of electricity consumption measured through periodic
\n
(and pertaining to the year) meter readings or on the vol-
\n
umes notified by distributors and transporters, an estimate
\n
of the electricity and gas delivered during the period but
\n
not yet invoiced that is equal to the difference between the
\n
amount of electricity and gas delivered to the distribution
\n
network and that invoiced in the period, taking account
\n
of any network losses. Revenue between the date of the
\n

\n\n\n\n\n\n
last meter reading and the year-end is based on estimates
\n
of the daily consumption of individual customers, primar-
\n
ily determined on their historical information, adjusted to
\n
reflect the climate factors or other matters that may affect
\n
the estimated consumption.
\n
For more details on such revenue, please see note 11.a
\n
\u201cRevenue 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 measured at cost, intangible
\n
assets, right-of-use assets, goodwill and investments in
\n
associates/joint ventures exceeds its recoverable amount,
\n
which is the higher of the fair value less costs to sell and
\n
the value in use, the assets are impaired.
\n
Verification of the recoverable amount of such assets is
\n
performed in accordance with the provisions of IAS 36, as
\n
described in greater detail in note 24 \u201cGoodwill\u201d.
\n
In order to determine the recoverable amount, the Group
\n
generally adopts the value in use criterion, intended as the
\n
present value of the estimated future cash flows generat-
\n
ed by the asset, discounted using a pre-tax discount rate
\n
that reflects the current market assessment of the time
\n
value of money and of the specific risks of the asset.
\n
Future cash flows used to determine value in use are
\n
based on the most recent Business Plan, approved by the
\n
management, containing forecasts for volumes, revenue,
\n
operating costs and investments. These projections cov-
\n
er the next three years. For subsequent years, account is
\n
taken of:
\n
\u2022
\n
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
\n
a long-term growth rate equal to the long-term growth
\n
of electricity demand and/or inflation (depending on
\n
the country and business) that does not in any case ex-
\n
ceed the average long-term growth rate of the market
\n
involved.
\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 of such amounts could gen-
\n
erate different recoverable amounts. The analysis of each
\n
group of non-financial assets is unique and requires man-
\n
agement to use estimates and assumptions considered
\n
prudent and reasonable in the specific circumstances.
\n
In line with its business model and in the context of the
\n
energy transition process, the Group has also carefully as-
\n
sessed whether climate change issues have affected the
\n
reasonable and supportable assumption used to estimate
\n
expected cash flows. In this regard, where necessary, the
\n
Group has also taken account of the long-term impact of
\n
climate change, in particular by considering in the estima-
\n
tion of the terminal value a long-term growth rate in line
\n
with the change in electricity demand determined using
\n
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 recogniz-
\n
es a loss allowance for expected credit losses on trade
\n
receivables and other financial assets measured at amor-
\n
tized cost, debt instruments measured at fair value through
\n
other comprehensive income, contract assets and all other
\n
assets in scope.
\n
Loss allowances for financial assets are based on as-
\n
sumptions about risk of default and on the measurement
\n
of expected credit losses. Management uses judgment in
\n
making 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 (ECL) \u2013 determined considering
\n
probability of default (PD), loss given default (LGD), and
\n
exposure at default (EAD) \u2013 is the difference between all
\n
contractual cash flows that are due in accordance with the
\n
contract and all cash flows that are expected to be received
\n
(including all shortfalls) discounted at the original effective
\n
interest rate (EIR).
\n
For additional details on the general simplified approach
\n
used to determine expected credit losses, please see note
\n
48 \u201cFinancial instruments by category\u201d.
\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 trade receivables, contract assets and
\n
lease receivables, the Group mainly applies a default defi-
\n
nition of 180 days past due to determine expected cred-
\n
it losses, as this is considered an effective indication of
\n
a significant increase in credit risk. Accordingly, financial
\n
assets that are more than 90 days past due are generally
\n
not considered to be in default, except for some specific
\n
regulated markets.
\n
For trade receivables and contract assets the Group mainly
\n
applies a collective approach based on grouping them into
\n
specific clusters, taking into account the specific regulato-
\n
ry and business context. Only if the trade receivables are
\n
deemed to be individually significant by management and
\n
there is specific information about any significant increase
\n
in credit risk, does the Group apply an analytical approach.
\n
Based on specific management evaluations, the for-
\n
ward-looking adjustment can be applied considering
\n

\n\n\n\n\n\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 cat-
\n
egory\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 Group \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
\n
for growth\u201d (published in the Gazzetta Ufficiale of August
\n
11, 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
\n
of 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 hold-
\n
er, in exchange for payment of a price to be determined
\n
in negotiations between the departing concession holder
\n
and the grantor agency, taking due account of the follow-
\n
ing elements:
\n
\u2022
\n
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
\n
of charge (Article 25 of Royal Decree 1775 of Decem-
\n
ber 11, 1933), the revalued cost less government capital
\n
grants, also revalued, received by the concession hold-
\n
er for the construction of such works, depreciated for
\n
ordinary wear and tear;
\n
\u2022
\n
for other property, plant and equipment, the market
\n
value, meaning replacement value, reduced by estimat-
\n
ed 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
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), cal-
\n
culating depreciation no longer over the term of the con-
\n
cession but, if longer, over the useful life of the individual
\n
assets. If additional information becomes available to en-
\n
able the calculation of residual value, the carrying amounts
\n
of 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

\n\n\n\n\n\n

\n

\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.
\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 oth-
\n
er 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 es-
\n
timation that are considered include mortality and retire-
\n
ment rates as well as assumptions concerning future devel-
\n
opments in discount rates, the rate of wage increases, the
\n
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 expenses.
\n
For more details on the main actuarial assumptions adopt-
\n
ed, please see note 39 \u201cEmployee benefits\u201d.
\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
\n
tax disputes connected with the normal pursuit of its
\n
activities that could give rise to significant liabilities. It is
\n
not always objectively possible to predict the outcome of
\n
these disputes. The assessment of the risks associated
\n
with this litigation is based on complex factors whose very
\n
nature requires recourse to management judgments, even
\n
when taking account of the contribution of external advi-
\n
sors assisting the Group, about whether to classify them
\n
as contingent 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 operator
\n
with regard to future interventions that will have to be per-
\n
formed following the end of the operating life of the 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
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
\n
is located. That liability is quantified by management on
\n
the basis of the technology existing at the measurement
\n
date and is reviewed each year, taking account of devel-
\n
opments in storage, decommissioning and site restoration
\n
technology, as well as the ongoing evolution of the leg-
\n
islative framework governing health and environmental
\n
protection.
\n
Subsequently, the value of the obligation is adjusted to re-
\n
flect the passage of time and any changes in estimates.
\n
For more information, please see note 40 \u201cProvisions for
\n
risks and charges\u201d.
\n

\n

\n\n\n\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
Leases
\n
When the interest rate implicit in the lease cannot be
\n
readily determined, the Group uses the incremental bor-
\n
rowing rate (IBR) at the lease commencement date to cal-
\n
culate the present value of the lease payments. This is the
\n
interest rate that the lessee would have to pay to borrow
\n
over a similar term, and with a similar security, the funds
\n
necessary to obtain an asset of a similar value to the righ-
\n
tofuse asset in a similar economic environment. When no
\n
observable inputs are available, the Group estimates the
\n
IBR making assumptions to reflect the terms and condi-
\n
tions of the lease and certain lessee-specific estimates.
\n

\n\n\n\n\n\n
One of the most significant judgments for the Group is
\n
determining this IBR necessary to calculate the present
\n
value of the lease payments required to be paid to the les-
\n
sor. The Group approach to determine an IBR is based on
\n
the assessment of the following three key components:
\n
\u2022
\n
the risk-free rate, that consider the currency flows of
\n
the lease payments, the economic environment where
\n
the lease contract has been negotiated and also the
\n
lease term;
\n
\u2022
\n
the credit spread adjustment, in order to calculate an
\n
IBR that is specific for the lessee considering any un-
\n
derlying Parent or other guarantee;
\n
\u2022
\n
the lease related adjustments, in order to reflect into
\n
the IBR calculation the fact that the discount rate is di-
\n
rectly linked to the type of the underlying asset, rath-
\n
er than being a general incremental borrowing rate. In
\n
particular, the risk of default is mitigated for the lessors
\n
as they have the right to reclaim the underlying asset
\n
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, 2023, 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
\n
be 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 details on 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 operating segments
\n
In accordance with the requirements of IFRS 8, the Group\u2019s
\n
operating segments are represented by the business lines,
\n
identified as components:
\n
\u2022
\n
that engage in business activities from which they may
\n
earn revenue and incur expenses (including revenue
\n
and expenses relating to transactions with other com-
\n
ponents of the same entity);
\n
\u2022
\n
whose operating results are regularly reviewed by man-
\n
agement to make decisions about resources to be allo-
\n
cated to the segment and assess their performance; and
\n
\u2022
\n
for which discrete financial information is available.
\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 identifies
\n
the smallest group of assets that generate largely inde-
\n
pendent cash inflows. The smallest group of assets that
\n
generates cash inflows that are largely independent of the
\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.). The assets of each CGU are
\n
also identified on the basis of the manner in which man-
\n
agement manages and monitors those assets, as well as
\n
the evidence that the cash inflows of the group of assets
\n
are largely independent of those associated with other as-
\n
sets (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. In particular, the number and scope of the
\n
CGUs are updated systematically to reflect the impact of
\n
new business combinations and reorganizations carried
\n
out by the Group.
\n
The CGUs identified by management to which the goodwill
\n
recognized in these consolidated financial statements has
\n
been allocated are reported 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

\n\n\n\n\n\n
concerned, the Group has taken account of its commit-
\n
ment under the Paris Agreement. For more information,
\n
please see note 19 \u201cProperty, plant and equipment\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 abili-
\n
ty to affect those returns through its power over the in-
\n
vestee. Power is defined as the current ability to direct the
\n
relevant activities of the investee based on existing sub-
\n
stantive 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
Following such analysis of the existence of control, in ap-
\n
plication of IFRS 10 the Group consolidated certain com-
\n
panies on a line-by-line basis even though it did not hold
\n
more than half of the voting rights, determining that the
\n
requirements for de facto control existed.
\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
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
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 arrange-
\n
ment, the terms agreed by the parties in the contractual
\n
arrangement and, when relevant, other facts and circum-
\n
stances.
\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
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 influ-
\n
ence, management must apply judgment and consider all
\n
facts 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
\n
in associates, please see note 26 \u201cEquity-accounted in-
\n
vestments\u201d.
\n
Determination of non-current assets (or disposal groups)
\n
held for sale and discontinued operations
\n
An asset is classified as \u201cheld for sale\u201d when its sale is
\n
highly probable.
\n
To determine whether a sale is highly probable, the Group
\n
considers whether:
\n
\u2022
\n
management is committed to a plan to sell the asset
\n
(or disposal group), and an active program to locate a
\n
buyer and complete the plan has been initiated;
\n
\u2022
\n
the sale should be expected to qualify for recognition
\n
as a completed sale within one year from the date of
\n
\n\n
classification, except where the delay is caused by
\n
events or circumstances beyond the Group\u2019s control
\n
and there is sufficient evidence that the Group remains
\n
committed to its plan to sell the asset;
\n
\u2022
\n
the actions required to complete the plan should in-
\n
dicate that it is unlikely that significant changes to the
\n
plan will be made or that the plan will be withdrawn.
\n
In addition, an asset (or group of assets) shall be presented
\n
as a discontinued operation when it is classified as held for
\n
sale and:
\n
\u2022
\n
represents a separate major business line or geograph-
\n
ical area of operations;
\n
\u2022
\n
is part of a single coordinated plan to dispose of a sep-
\n
arate major business line or geographical area of op-
\n
erations; or
\n
\u2022
\n
is a subsidiary acquired exclusively with a view to resale.
\n
Application of \u201cIFRIC 12 - Service Concession
\n
Arrangements\u201d to concessions
\n
The Group, as operator, applies IFRIC 12 to \u201cpublic-to-pri-
\n
vate\u201d service concession arrangements, under which a
\n
public entity (the grantor) conveys to an operator the right
\n
to manage the infrastructure used to provide services.
\n
More specifically, management assesses whether \u201cpub-
\n
lic-to-private\u201d service concession arrangements are with-
\n
in the scope of IFRIC 12 on the basis of whether:
\n
\u2022
\n
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
\n
the grantor controls \u2013 through ownership, beneficial
\n
entitlement or otherwise \u2013 any significant residual in-
\n
terest in the infrastructure at the end of the term of the
\n
arrangement.
\n
On the basis of that analysis, the provisions of IFRIC 12 are
\n
applicable to the service concession arrangements of a
\n
number of companies that operate primarily in Brazil.
\n
Further details about service concession arrangements in
\n
the scope of IFRIC 12 are provided in note 20 \u201cInfrastruc-
\n
ture within the scope of \u2018IFRIC 12 - Service Concession
\n
Arrangements\u2019\u201d.
\n
Revenue from contracts with customers
\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
\n
services, in order to assess if they should be accounted
\n
for separately or as a group, the Group considers both the
\n
individual characteristics of goods/services (i.e. whether
\n
they are distinct or are a series of distinct goods or ser-
\n
vices that are substantially the same and that have the
\n
same pattern of transfer to the customer), and the nature
\n
of the promise within the context of the contract. To this
\n
end, it is necessary to evaluate all the facts and circum-
\n
stances relating to the specific contract under the rele-
\n
vant legal and regulatory framework. To evaluate when a
\n
performance obligation is satisfied, the Group evaluates
\n
when the control of the goods or services is transferred
\n
to the customer, assessed primarily from the perspective
\n
of the customer.
\n
For each performance obligation, and in relation to the
\n
type of transaction:
\n
\u2022
\n
revenue is recognized over time on the basis of the
\n
progress towards complete satisfaction of the per-
\n
formance obligation, as in the case of the provision
\n
of services. The measurement of progress towards
\n
complete satisfaction of a performance obligation is
\n
carried out consistently for performance obligations
\n
and similar circumstances using an \u201coutput\u201d or \u201cinput\u201d
\n
method. In particular, the cost incurred method (cost-
\n
to-cost method) is considered appropriate for mea-
\n
suring progress except when a specific analysis of the
\n
contract counsels the use of an alternative method. If it
\n
should prove impossible to reasonably assess progress
\n
towards satisfaction of the performance obligation, the
\n
Group recognizes revenue only to the extent of the in-
\n
curred costs that are considered recoverable;
\n
\u2022
\n
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 depends
\n
upon the occurrence or non-occurrence of a future
\n
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 through-
\n
out the contract and for similar contracts, also consider-
\n
ing all available information, and updating such estimates
\n
until the uncertainly is resolved. The Group includes the
\n
estimated variable consideration in the transaction price
\n
only to the extent that it is highly probable that a signifi-
\n
cant reversal in the cumulative revenue recognized will not
\n
occur when the uncertainty is resolved.
\n
The Group considers that it is an agent in some contracts
\n
in which it is not primarily responsible for fulfilling the
\n
contract and therefore it does not control goods or ser-
\n
vices before they are being transferred to customers. For
\n
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

\n\n\n\n\n\n\n\n\n\n\n

\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
\n
costs of obtaining a contract either on a contract-by-con-
\n
tract basis, or for a group of contracts if those costs are
\n
associated with the group of contracts.
\n
The Group supports the recoverability of such costs on the
\n
basis of its experience with other similar transactions and
\n
evaluating various factors, including potential renewals,
\n
amendments and follow-on contracts with the same cus-
\n
tomer.
\n
The Group amortizes such costs over the average customer
\n
term. In order to determine this expected period of benefit
\n
from the contract, the Group considers its past experience
\n
(e.g., \u201cchurn rate\u201d), the predictive evidence from similar con-
\n
tracts and available information about the market.
\n

\n\n\n\n\n\n\n\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 as
\n
financial assets at amortized cost, at fair value through oth-
\n
er comprehensive income and at fair value through profit
\n
or loss, management assesses both the contractual cash
\n
flow characteristics of the instrument and the business
\n
model for managing financial assets in order to generate
\n
cash flows.
\n
In order to evaluate the contractual cash flow characteristics
\n
of the instrument, management performs the SPPI test at
\n
an instrument level, in order to determine if it gives rise to
\n
cash flows that are solely payments of principal and interest
\n
(SPPI) on the principal amount outstanding, performing spe-
\n
cific assessment on the contractual clauses of the financial
\n
instruments, as well as quantitative analysis, if required.
\n
The business model determines whether cash flows will re-
\n
sult from collecting contractual cash flows, selling the finan-
\n
cial 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 the Group\u2019s
\n
risk management 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 effective-
\n
ness assessment based on the existence of an econom-
\n
ic relationship between the hedging instruments and the
\n
hedged items, the dominance of credit risk in the chang-
\n
es in fair value and the hedge ratio, as well as the mea-
\n
surement of the ineffectiveness, is evaluated through a
\n
qualitative assessment or a quantitative computation, de-
\n
pending on the specific facts and circumstances and on
\n
the characteristics of the hedged items and the hedging
\n
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 see 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
\n
the application of the definition of a lease to the cases
\n
typical of the sectors in which the Group operates;
\n
\u2022
\n
the identification of the non-lease component into the
\n
lease arrangements;
\n
\u2022
\n
the evaluation of any renewable and termination op-
\n
tions included in the lease in order to determine the
\n
term of leases, also considering the probability of their
\n
exercise and any significant leasehold improvements on
\n

\n\n\n\n\n\n\n\n\n\n\n
the underlying asset;
\n
\u2022
\n
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
\n
the estimate of the discount rate to calculate the pres-
\n
ent value of the lease payments; further details on
\n
assumptions about this rate are provided in the para-
\n
graph \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 likely
\n
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
\n
event of a change in facts and circumstances that could
\n
change its assessment of the acceptability of a specific
\n
tax treatment or the estimate of the effects of uncertainty,
\n
or both.
\n
For more information on income taxes, please see note 17
\n
\u201cIncome taxes\u201d.
\n

\n\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1079": { "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
\n
tax disputes connected with the normal pursuit of its
\n
activities that could give rise to significant liabilities. It is
\n
not always objectively possible to predict the outcome of
\n
these disputes. The assessment of the risks associated
\n
with this litigation is based on complex factors whose very
\n
nature requires recourse to management judgments, even
\n
when taking account of the contribution of external advi-
\n
sors assisting the Group, about whether to classify them
\n
as contingent 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 operator
\n
with regard to future interventions that will have to be per-
\n
formed following the end of the operating life of the 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
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
\n
is located. That liability is quantified by management on
\n
the basis of the technology existing at the measurement
\n
date and is reviewed each year, taking account of devel-
\n
opments in storage, decommissioning and site restoration
\n
technology, as well as the ongoing evolution of the leg-
\n
islative framework governing health and environmental
\n
protection.
\n
Subsequently, the value of the obligation is adjusted to re-
\n
flect the passage of time and any changes in estimates.
\n
For more information, please see note 40 \u201cProvisions for
\n
risks and charges\u201d.
\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag22": { "value": "\n
The Group assesses recoverability of the incremental
\n
costs of obtaining a contract either on a contract-by-con-
\n
tract basis, or for a group of contracts if those costs are
\n
associated with the group of contracts.
\n
The Group supports the recoverability of such costs on the
\n
basis of its experience with other similar transactions and
\n
evaluating various factors, including potential renewals,
\n
amendments and follow-on contracts with the same cus-
\n
tomer.
\n
The Group amortizes such costs over the average customer
\n
term. In order to determine this expected period of benefit
\n
from the contract, the Group considers its past experience
\n
(e.g., \u201cchurn rate\u201d), the predictive evidence from similar con-
\n
tracts and available information about the market.
\n

\n\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCustomerAcquisitionCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag23": { "value": "\n

\n

\n
2.2 Material accounting policies
\n\n

\n
Related parties
\n
Pursuant to IAS 24, related parties are mainly those that
\n
share the same controlling entity with Enel SpA, the com-
\n
panies that directly or indirectly are controlled by Enel
\n
SpA, the associates or joint ventures (including their sub-
\n
sidiaries) of Enel SpA, or the associates or joint ventures
\n
(including their subsidiaries) of any Group company. Relat-
\n\n
ed parties also include entities that operate post-employ-
\n
ment benefit plans for employees of Enel SpA or its as-
\n
sociates (specifically, the FOPEN and FONDENEL pension
\n
funds), as well as the members of the boards of statutory
\n
auditors, and their immediate family, and the key manage-
\n
ment personnel, and their immediate family, of Enel SpA
\n
and its subsidiaries. Key management personnel comprise
\n
management personnel who have the power and direct or
\n
indirect responsibility for the planning, management and
\n
control of the activities of the Company. They include di-
\n
rectors (whether executive or not).
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n\n\n

\n

\n\n

\n
Subsidiaries
\n
Pursuant to IFRS 10, subsidiaries are all entities over which
\n
the Group has control. For more information on the defi-
\n
nition of control, please see section \u201cDetermination of the
\n
existence of control\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2023 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
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
Profit or loss for the year and the other comprehensive in-
\n
come are attributed to owners of the Parent and non-con-
\n
trolling interests, even if this results in a loss for non-con-
\n
trolling interests.
\n
All intercompany assets and liabilities, equity item, reve-
\n
nue, expenses and cash flows relating to transactions be-
\n
tween 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\n\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

\n\n

\n\n
Investments in associates and joint ventures
\n
In the consolidated financial statements, investments in as-
\n
sociated companies and joint arrangements are measured
\n
in accordance with the requirements established by \u201cIAS 28
\n
- Investments in Associates and Joint Ventures\u201d and \u201cIFRS
\n
11 - Joint Arrangements\u201d.
\n
In this respect, an associate is an entity over which the
\n
Group has significant influence, while a joint venture is a
\n
joint arrangement over which the Group exercises joint
\n
control and has rights to the net assets of the arrangement.
\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

\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

\n\n

\n\n

\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method, under which
\n
these investments are initially recognized at cost and any
\n
goodwill arising from the difference between the cost of
\n
the investment and the Group\u2019s share of the net fair val-
\n
ue of the investee\u2019s identifiable assets and liabilities at the
\n
acquisition date is included in the carrying amount of the
\n
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 ventures 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
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\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

\n\n\n\n\n\n\n\n
If the ownership interest in an associate or a joint venture
\n
is reduced, but the Group continues to exercise a signifi-
\n
cant influence or joint control, the Group continues to ap-
\n
ply the equity method and the share of the gain or loss
\n
that had previously been recognized in other comprehen-
\n
sive income relating to that reduction is accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\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
\n
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 combina-
\n
tion achieved in stages, with the remeasurement of the
\n
interest it held previously in the joint operation at its fair
\n
value at each acquisition date;
\n
\u2022
\n
if the Group obtains joint control (i.e. it already had an
\n
interest in a joint operation without holding joint con-
\n
trol), the interest previously held in the joint operation
\n
shall 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\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\n\n\n\n\n
Translation of foreign currency items
\n
Pursuant to \u201cIAS 21 - The Effects of Changes in Foreign
\n
Exchange Rates\u201c, transactions in currencies other than the
\n
functional currency are initially recognized at the spot ex-
\n
change rate 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 spot exchange rate prevailing
\n
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 ini-
\n
tial recognition of the transaction. Non-monetary assets
\n
and liabilities in foreign currency measured at fair value
\n
are translated using the exchange rate at the date the fair
\n
value was determined.
\n
Any exchange differences are recognized through profit
\n
or 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

\n\n\n\n\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
Pursuant to IAS 21, in order to prepare the consolidated
\n
financial statements, the financial statements of consol-
\n
idated companies with functional currencies other than
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n\n\n

\n

\n\n
the presentation currency used in the consolidated finan-
\n
cial statements are translated into euros by applying the
\n
closing exchange rate to the assets and liabilities, includ-
\n
ing goodwill and consolidation adjustments, and the aver-
\n
age exchange rate for the period to the income statement
\n
items on the condition it approximates the exchange rates
\n
prevailing at the date of 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 \u201cIAS
\n
29 - Financial Reporting in Hyperinflationary Economies\u201c
\n
before applying the specific conversion method set out
\n
below.
\n
In order to consider the impact of hyperinflation on the lo-
\n
cal currency exchange rate, the financial position and per-
\n
formance (i.e. assets, liabilities, equity items, revenue and
\n
expenses) of a company of the Group whose functional
\n
currency is the currency of a hyperinflationary economy
\n
are translated into the Group\u2019s presentation currency (the
\n
euro) using the exchange rate prevailing at the reporting
\n
date, except for comparative amounts presented in the
\n
previous year\u2019s financial statements which are not adjust-
\n
ed for subsequent changes in the price level or subse-
\n
quent changes in exchange rates.
\n

\n\n\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
and is recognized in the consolidated financial statements
\n
as at the date of acquisition of control of the business.
\n
To this end, the Group recognizes business combinations
\n
using:
\n
\u2022
\n
the \u201cpurchase method\u201d, for all business combinations
\n
initiated before January 1, 2010 and completed within
\n
that financial year on the basis of IFRS 3 (2004), where
\n
the purchase cost is equal to the fair value at the date
\n
of the exchange of the assets acquired and the liabil-
\n
ities incurred or assumed, plus costs directly attrib-
\n
utable to the acquisition. This cost was allocated by
\n
recognizing the assets, liabilities and identifiable con-
\n
tingent 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 owners of the Parent was recognized as
\n
goodwill. The carrying amount of non-controlling inter-
\n
ests was determined in proportion to the interest held
\n
by non-controlling shareholders in the net assets. In the
\n
case of business combinations achieved in stages, at
\n
the date of acquisition any adjustment to the fair value
\n
of the net assets acquired previously was recognized
\n
in equity; the amount of goodwill was determined for
\n
each transaction separately based on the fair values of
\n
the acquiree\u2019s net assets at the date of each exchange
\n
transaction;
\n
\u2022
\n
the \u201cacquisition method\u201d, for all business combinations
\n
carried out as from January 1, 2010 that are recognized
\n
on the basis of IFRS 3 (2008), which is referred to as
\n
IFRS 3 (Revised) hereafter, where the purchase cost (the
\n
consideration transferred) is equal to the fair value at the
\n
purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments
\n
issued by the purchaser. The purchase cost includes
\n
the fair value of any asset or liability resulting from a
\n
contingent consideration arrangement. The consider-
\n
ation transferred is allocated by recognizing the assets,
\n
liabilities and identifiable contingent liabilities of the ac-
\n
quired company at their fair values as at the acquisition
\n
date. In this regard, goodwill is defined as the excess
\n
of the consideration transferred, measured at fair value
\n
as at the acquisition date, the amount of any non-con-
\n
trolling interest in the acquiree plus the fair value of any
\n
equity interest in the acquiree previously held by the
\n
Group (in a business combination achieved in stages)
\n
over the net amount of the identifiable assets acquired
\n
and the liabilities incurred or assumed measured at fair
\n
value. The carrying amount of non-controlling interests
\n\n
is determined either in proportion to the interest held
\n
by non-controlling shareholders in the net identifiable
\n
assets of the acquiree or at their fair value as at the
\n
acquisition date.
\n

\n\n\n\n
IFRS 3 (Revised) requires, among other things, the following:
\n
\u2022
\n
costs directly attributable to the acquisition are recog-
\n
nized through profit or loss;
\n
\u2022
\n
in the case of business combinations achieved in stag-
\n
es, at the date of acquisition of control the previously
\n
held equity interest in the acquiree is remeasured to
\n
fair value and any positive or negative difference is rec-
\n
ognized in profit or loss;
\n
\u2022
\n
any contingent consideration is recognized at fair val-
\n
ue at the acquisition date. Subsequent changes to the
\n
fair value of the contingent consideration classified as
\n
an asset or a liability, or as a financial instrument within
\n
the scope of IFRS 9, are recognized in profit or loss. If
\n
the contingent consideration is not within the scope of
\n
IFRS 9, it is measured in accordance with the appro-
\n
priate IFRS-IAS. Contingent consideration that is clas-
\n
sified as equity is not re-measured, and its subsequent
\n
settlement is accounted for within equity;
\n
\u2022
\n
if the fair values of the assets, liabilities and contingent
\n
liabilities can only be calculated on a provisional basis,
\n
the business combination is recognized using such
\n
provisional values. Any adjustments resulting from the
\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\n\n\n

\n\n\n\n\n\n\n\n\n\n

\n

\n

\n\n

\n\n

\n\n
completion of the measurement process are recog-
\n
nized within 12 months of the date of acquisition, re-
\n
stating comparative figures.
\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.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU or group of
\n
CGUs that is expected to benefit from the synergies of the
\n
combination.
\n
For more information, please see the section \u201cImpairment
\n
of non-financial assets\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\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\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n\n
Fair value measurement
\n
For all fair value measurements and disclosures of fair
\n
value, that are either required or permitted by IFRS, the
\n
Group 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 transac-
\n
tion to sell an asset or transfer a liability takes place in the
\n
principal market, i.e. the market with the greatest volume
\n
and level of activity for the asset or liability. In the absence
\n
of a principal market, it is assumed that the transaction
\n
takes place in the most advantageous market to which
\n
the Group has access, i.e. the market that maximizes the
\n
amount that would be received to sell the asset or mini-
\n
mizes the amount that would be paid to transfer the lia-
\n
bility.
\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
\n
for a non-financial asset, a fair value measurement
\n
takes into account a market participant\u2019s ability to
\n
generate economic benefits by using the asset in its
\n
highest and best use or by selling it to another market
\n
participant that would use the asset in its highest and
\n
best use;
\n
\u2022
\n
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
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

\n

\n

\n

\n
Property, plant and equipment
\n
Pursuant to IAS 16, property, plant and equipment is stated
\n
at cost, net of accumulated depreciation and accumulat-
\n
ed impairment losses, if any. Such cost includes expenses
\n
directly attributable to bringing the asset to the location
\n
and condition 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 or
\n
constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
For more information on changes in the estimate of these
\n
costs, the passage of time and the discount rate, please
\n
see note 2.1 \u201cUse of estimates and management judge-
\n
ment\u201d.
\n

\n\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 of
\n
the cost of the assets themselves. Borrowing costs asso-
\n
ciated 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\n\n
Certain assets that were revalued at the IFRS transition
\n
date or in previous periods are recognized at their fair val-
\n
ue, 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\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\n\n\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

\n\n\n\n

\n\n\n\n

\n\n\n\n\n\n\n\n\n\n

\n

\n\n

\n\n
preciation criteria shall be applied prospectively. Depreci-
\n
ation begins when the asset is available for use. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\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
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\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\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
\n
was calculated over the shorter of the term of the conces-
\n
sion 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 operating
\n
condition. The terms of the concessions extend up 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 and in
\n
Guatemala in 2062.
\n\n
Service concession arrangements
\n
When acting as operator under \u201cpublic-to-private\u201d ser-
\n
vice concession arrangements, the Group constructs/up-
\n
grades infrastructure used to provide a public service and/
\n
or operates and maintains that infrastructure for the years
\n
of the concession, in accordance with the terms specified
\n
in the contract.
\n
In these circumstances, the Group does not account for
\n
the infrastructure operated under a service concession
\n

\n\n\n\n

\n\n\n\n\n\n\n\n\n\n

\n

\n

\n\n
arrangement within the scope of IFRIC 12 as property,
\n
plant and equipment, recognizing and measuring 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
\n
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 to
\n
avoid payment; and/or
\n
\u2022
\n
an intangible asset, if the Group receives the right (a
\n
license) to charge users of the public service provided
\n
and thus does not have an unconditional right to re-
\n
ceive cash because the amounts are contingent on the
\n
extent that the public uses the service.
\n
If the Group (as operator) has a contractual right to re-
\n
ceive an intangible asset, borrowing costs are capitalized
\n
using the criteria specified in note 19 \u201cProperty, plant and
\n
equipment\u201d.
\n
However, for construction/upgrade services, both types
\n
of consideration are classified as a contract asset during
\n
the construction/upgrade period.
\n
For more details about such consideration, please see
\n
note 11.a \u201cRevenue from sales and services\u201d.
\n
Conversely, where the service concession arrangement
\n
provides for the infrastructure used for to operate the
\n
concessions themselves do not comply with the require-
\n
ments established by IFRIC 12 and, in particular, are owned
\n
and available to the operator or have an indefinite expiry,
\n
the carrying amount of the assets attributable to these
\n
concessions is recognized under \u201cProperty, plant and
\n
equipment\u201d and accounted for in accordance with IAS 16.
\n
Information on the main characteristics of the Group\u2019s
\n
service concession arrangements can be found in note
\n
20 \u201cInfrastructure within the scope of \u2018IFRIC 12 - Service
\n
Concession Arrangements\u2019\u201d.
\n

\n\n\n\n\n
Leases
\n
At inception of a contract, the Group assesses whether a
\n
contract is, or contains, a lease applying the definition of a
\n
lease under IFRS 16, that is met if the contract conveys the
\n
right to control the use of an identified asset for a period
\n
of time in exchange for consideration.
\n
When the Group acts as a lessee, it recognizes a right-of-
\n
use asset and a lease liability at the commencement date
\n
of the lease (i.e. the date the underlying asset is available
\n
for use).
\n
The right-of-use asset is initially measured at cost, which
\n
includes the initial amount of lease liability adjusted for any
\n
lease payments made at or before the commencement
\n
date less any lease incentives received, plus any initial di-
\n
rect costs incurred and an estimate of costs to retire and
\n
remove the underlying asset and to restore the underlying
\n
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.
\n
Average residual life
\n
(years)
\n
Buildings 8
\n
Ground rights of energy plants 32
\n
Vehicles and other means of transport 4
\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 ex-
\n
ercise a purchase option, depreciation is calculated using
\n
the estimated useful life of the underlying asset.
\n
In addition, the right-of-use assets are subject to im-
\n
pairment testing and adjusted for any remeasurement of
\n
lease liabilities.
\n
The lease liability is initially measured at the present value of
\n
lease payments to be made over the lease term, discounted
\n
using the lessee\u2019s incremental borrowing rate at the lease
\n
commencement date when the interest rate implicit in the
\n
lease 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

\n

\n\n\n\n\n

\n\n

\n
Intangible assets
\n
Pursuant to IAS 38, intangible assets are identifiable as-
\n
sets without physical substance controlled by the Group,
\n
when it is probable that the use of such assets will gener-
\n
ate future economic benefits and the related cost can be
\n
reliably determined.
\n\n
They are measured at purchase or internal development
\n
cost for internally generated assets and are recognized
\n
only when the 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

\n\n\n\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\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
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 estimat-
\n
ing useful life, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and note 23 \u201cIntangible assets\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
\n
the exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amor-
\n
tized, but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annual-
\n
ly to determine whether the indefinite useful life continues
\n
to be supportable. If not, the change in useful life from in-
\n
definite to finite is accounted for as a change in account-
\n
ing estimate.
\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 presents costs to obtain a contract with a cus-
\n
tomer capitalized in accordance with IFRS 15 as intangible
\n
assets, only if:
\n
\u2022
\n
the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group
\n
would not have incurred them if the contract had not
\n
been obtained;
\n
\u2022
\n
the Group expects to recover them, through reim-
\n
bursements (direct recoverability) or the margin (indi-
\n
rect recoverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the capi-
\n
talization 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
\n
undergo impairment testing to identify any impairment
\n
losses to the extent that the carrying amount of the asset
\n
recognized exceeds the recoverable amount.
\n
The Group amortizes the capitalized customer contract
\n
costs 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); any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n\n\n\n

\n

\n\n\n\n\n\n

\n\n
Impairment of non-financial assets
\n
Pursuant to \u201dIAS 36 - Impairment of assets\u201d, at each re-
\n
porting date, property, plant and equipment, investment
\n
property recognized at cost, intangible assets, right-of-
\n
use assets, goodwill and equity investments in associates/
\n
joint ventures are reviewed to determine whether there is
\n
evidence of impairment (using internal and external sourc-
\n
es of information).
\n
CGUs to which goodwill is allocated, intangible assets with
\n
an indefinite useful life and intangible assets not yet avail-
\n
able for use are tested for recoverability annually or more
\n
frequently if there is evidence suggesting that the assets
\n
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 individu-
\n
al asset, unless the asset do not generate cash inflows
\n
that are largely independent of those from other assets
\n
or groups of assets and therefore it is determined for the
\n
CGU to 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 re-
\n
stored through profit or loss, under \u201cDepreciation, amor-
\n
tization and other impairment losses\u201d, in an amount that
\n
shall not exceed the carrying amount that the asset would
\n
have had if the impairment loss had not been recognized.
\n
The original amount of goodwill is not restored even if in
\n
subsequent years the reasons for the impairment no lon-
\n
ger apply.
\n

\n\n\n\n\n

\n\n\n\n\n\n
Inventories
\n
Pursuant to IAS 2, inventories are measured at the low-
\n
er of cost and net realizable value except for inventories
\n
involved in trading activities, which are measured at fair
\n
value with recognition through profit or loss. Cost is de-
\n
termined on the basis of average weighted cost, which in-
\n

\n\n\n\n\n

\n\n\n\n\n\n

\n

\n\n

\n
cludes related ancillary charges. Net estimated realizable
\n
value is the estimated normal selling price net of estimat-
\n
ed costs to sell or, where 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 exam-
\n
ple, green certificates, energy efficiency certificates and
\n
European CO
\n
2
\n
emissions allowances and guarantees of
\n
origin and renewable energy certificates) not used for
\n
compliance in the reporting period. These inventories are
\n
allocated to different portfolios, distinguishing between
\n
those held for trading or non-trading purposes. For more
\n
details on inventories, please see note 58 \u201cEnvironmental
\n
programs\u201d.
\n

\n\n\n\n\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\n\n

\n
Financial instruments
\n
Financial instruments are recognized and measured in ac-
\n
cordance with \u201cIAS 32 - Financial Instruments: Presenta-
\n
tion\u201c and \u201cIFRS 9 - Financial Instruments\u201c.
\n
A financial asset or liability is recognized in the consolidated
\n
financial statements when, and only when, the Group be-
\n
comes party to the contractual provision of the instrument
\n
(i.e. the trade date).
\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 mea-
\n
sured 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:
\n
\u2022
\n
the Group\u2019s business model for managing financial as-
\n
sets, that is the way in which the Group manages its
\n
financial assets in order to generate cash flows (i.e. col-
\n
lecting contractual cash flows, selling the financial as-
\n
sets, or both); and
\n
\u2022
\n
the contractual cash flow characteristics of the instru-
\n
ment, to determine whether the instrument gives rise
\n
to cash flows that are solely payments of principal and
\n
interest based on the SPPI test.
\n
For purposes of subsequent measurement, financial as-
\n
sets are classified in four categories:
\n
\u2022
\n
financial assets measured at amortized cost (debt in-
\n
struments);
\n
\u2022
\n
financial assets at fair value through OCI with reclas-
\n
sification of cumulative gains and losses (debt instru-
\n
ments);
\n
\u2022
\n
financial assets designated at fair value through OCI
\n
with no reclassification of cumulative gains and losses
\n
upon derecognition (equity instruments); and
\n
\u2022
\n
financial assets at fair value through profit or loss.
\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
\n
are 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\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 Debt instruments
\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
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 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 re-
\n
classified to profit or loss. The Group may transfer the cu-
\n
mulative gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\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\n

\n

\n

\n\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of
\n
the cost of the investment.
\n

\n\n\n\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes:
\n
\u2022
\n
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
\n
financial assets held for trading because acquired or
\n
held principally for the purpose of selling or repurchas-
\n
ing in the short term (i.e. securities, financial invest-
\n
ments in funds, etc.);
\n
\u2022
\n
derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments;
\n
\u2022
\n
financial assets that qualify as contingent consider-
\n
ation.
\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 equity investments which the
\n
Group had not irrevocably elected to classify at fair value
\n
through OCI. Dividends on such investments are also rec-
\n
ognized as other income in the income statement when
\n
the right of payment has been established.
\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\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
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

\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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\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 mainly
\n
include:
\n
\u2022
\n
financial liabilities held for trading incurred for the pur-
\n
pose of repurchasing in the near term;
\n
\u2022
\n
derivative financial instruments entered into by the
\n
Group that are not designated as hedging instruments
\n
in hedge relationships as defined by IFRS 9;
\n
\u2022
\n
financial liabilities that qualify as contingent consider-
\n
ation.
\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
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\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\n\n

\n\n

\n

\n\n

\n

\n\n

\n\n

\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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\n\n

\n\n
Derivative financial instruments
\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 profit
\n
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 current
\n
on the basis of their maturity date and the Group intention
\n
to hold the financial instrument till maturity or not.
\n
For more details on derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n\n

\n\n\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
\u201dhost contract\u201d) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows. Embedded derivatives are
\n
separated from the host contract and accounted for as
\n
derivatives when:
\n
\u2022
\n
the host contract is not a financial instrument mea-
\n
sured at fair value through profit or loss;
\n
\u2022
\n
the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the
\n
host contract;
\n
\u2022
\n
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
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
The main Group contracts that may contain embedded de-
\n
rivatives are contracts to buy or sell energy commodities.
\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, in
\n
accordance with 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
\n
for the purpose of the physical settlement;
\n
\u2022
\n
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
\n
they can be settled net in cash; and
\n
\u2022
\n
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
\n
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
\n
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

\n

\n\n\n\n

\n\n\n\n\n

\n\n\n\n\n\n

\n

\n

\n\n

\n\n
Offsetting of financial assets and liabilities
\n
The Group offsets financial assets and liabilities when it:
\n
\u2022
\n
currently has a legally enforceable right to set off the
\n
recognized amounts; and
\n
\u2022
\n
intends either to settle on a net basis, or to realize the
\n
asset and settle the liability simultaneously.
\n

\n\n\n\n

\n\n\n\n\n
Hyperinflation
\n
Pursuant to IAS 29, in a hyperinflationary economy, the
\n
Group adjusts non-monetary items, equity and items de-
\n
riving from index-linked contracts up to the limit of recov-
\n
erable amount, using a price index that reflects changes in
\n
general purchasing 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
These provisions are applied to the Group\u2019s transactions in
\n
Argentina, whose economy has been declared hyperinfla-
\n
tionary since July 1, 2018.
\n\n

\n

\n
Non-current assets (or disposal groups)
\n
classified as held for sale and discontinued
\n
operations
\n\n
Pursuant to IFRS 5, non-current assets (or disposal groups)
\n
are classified as held for sale if their carrying amount will
\n
be recovered principally through a sale transaction, rather
\n
than through 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
For more details on the requirements for determining
\n
whether a sale is highly probable, please see note 2.1 \u201cUse
\n
of estimates and management judgment\u201d.
\n
If the Group is committed to a sale program involving loss
\n
of control of a subsidiary and the requirements provid-
\n
ed for under IFRS 5 are met, all the assets and liabilities
\n
of that subsidiary are classified as held for sale when the
\n
classification criteria are met, regardless of whether the
\n
Group will retain a non-controlling interest in its former
\n
subsidiary after the sale.
\n
The Group applies these classification criteria as envis-
\n
aged in IFRS 5 to an investment, or a portion of an invest-
\n
ment, in an associate or a joint venture. Any retained por-
\n
tion of an investment in an associate or a joint venture that
\n
has not been classified as held for sale is accounted for
\n
using the equity method until disposal of the portion that
\n
is classified 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
separately from other assets and liabilities in the consoli-
\n
dated statement 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 dispos-
\n
al groups) classified as held for sale are measured at the
\n
lower of their carrying amount and fair value less costs to
\n
sell. Impairment losses for any initial or subsequent write-
\n
down of the assets (or disposal groups) to fair value less
\n
costs to sell and gains for their reversals are recognized in
\n
profit or 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

\n

\n\n\n\n\n
If a component of the Group is a discontinued operation,
\n
the Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022
\n
the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022
\n
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\n

\n\n
Environmental certificates
\n
In the absence of specific IAS/IFRS rules, the accounting
\n
treatment adopted by the Group complies with the gen-
\n
eral rules included in the body of applicable IAS/IFRS ac-
\n
counting standards and with international best practice.
\n
In particular, the Group accounting treatment of envi-
\n
ronmental certificates reflects the business model of the
\n
entities involved and, therefore, the different features of
\n
the business conducted by these entities, distinguishing
\n
between those that generate electricity from renewable
\n
sources, obligated parties, traders and other entities that
\n
operate in the energy services sector even though they
\n
are not obligated parties.
\n
Further details on the application of this accounting model
\n
are provided in note 58 \u201cEnvironmental programs\u201d.
\n

\n\n\n\n

\n\n\n\n

\n\n\n\n\n\n

\n

\n\n

\n

\n
Employee benefits
\n
Post-employment and other long-term benefits
\n
Pursuant to IAS 19, the Group determines separately for
\n
each plan liabilities related to employee benefits paid upon
\n
or after ceasing employment or other long-term benefits
\n
accrued during the employment period. The Group uses
\n
actuarial assumptions to estimate the amount of the fu-
\n
ture benefits that employees have accrued at the report-
\n
ing date (using the projected unit credit method) and an
\n
appropriate discount rate to determine the present value
\n
of those plans.
\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 actuar-
\n
ies.
\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 Group recognizes the cumulative actuarial gains and
\n
losses from the actuarial measurement of the liabilities,
\n
the return on the plan assets (net of the associated in-
\n
terest income) and the effect of the asset ceiling (net of
\n
the associated interest) in other comprehensive income
\n
when they occur. For other long-term benefits, the re-
\n
lated actuarial gains and losses are recognized through
\n
profit or loss.
\n
In addition, the Group is involved in defined contribution
\n
plans under which it pays fixed contributions to a sepa-
\n
rate entity (a fund) and has no legal or constructive ob-
\n
ligation to pay further contributions if the fund does not
\n
hold sufficient assets to pay all employee benefits relating
\n
to employee service in the current and prior periods. Such
\n
plans are usually aimed to supplement pension benefits
\n
due to employees post-employment. The related costs
\n
are recognized through profit or loss on the basis of the
\n
amount of contributions paid in the period.
\n\n
Termination benefits
\n
Pursuant to IAS 19, liabilities for benefits due to employees
\n
for the early termination of employee service arise out of
\n
the Group\u2019s decision to terminate an employee\u2019s employ-
\n
ment before the normal retirement date or an employee\u2019s
\n
decision to accept an offer of benefits in exchange for the
\n
termination of employment.
\n
Termination
\n
benefits are recognized at the earlier of the
\n
following dates:
\n
\u2022
\n
when the entity can no longer withdraw its offer of
\n
benefits; and
\n
\u2022
\n
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.
\n

\n

\n

\n\n\n\n\n
Share-based payments
\n
The Group undertakes share-based payment transac-
\n
tions settled with equity instruments as part of the remu-
\n
neration policy adopted for the Chief Executive Officer/
\n
General 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 a
\n
monetary component (paid in cash), which will accrue if
\n
specific conditions are met.
\n
Pursuant to IFRS 2, the Group classifies the monetary
\n
component as a cash-settled transaction if it is based on
\n
the price (or value) of the equity instruments of the com-
\n
pany that issued the plan or, in other cases, as another
\n
long-term employee benefit.
\n
In order to settle the equity component through the bo-
\n
nus award of Enel shares, a program for the purchase of
\n
treasury shares to support these plans was approved. For
\n
more details on share-based incentive plans, please see
\n
note 53 \u201cShare-based payments\u201d.
\n
In particular for the equity component, the Group recog-
\n
nizes the services rendered by employees as personnel
\n
expenses over the period in which the conditions for re-
\n
maining in service and for achieving certain results must
\n
be satisfied (vesting period) and indirectly estimates their
\n
value, and the corresponding increase in a specific equity
\n
item, on the basis of the fair value of the equity instru-
\n
ments (i.e. the issuer shares) at the grant date.
\n
The overall expense recognized is adjusted at each re-
\n
porting date until the vesting date to reflect the best
\n
estimate available to the Group of the number of equity
\n
instruments for which the service and performance con-
\n
ditions other than market conditions or non-vesting con-
\n
ditions will be satisfied at the end of the vesting period.
\n
Conversely, if the incentive based on equity instruments is
\n
paid in cash, the Group recognizes the services rendered
\n
by employees as personnel expenses over the vesting
\n
period and a corresponding liability measured at the fair
\n
value of the liability incurred. Subsequently, and until its
\n
extinction, the liability is remeasured at fair value at each
\n
reporting date, considering the best possible estimate of
\n
the incentive that will vest, with changes in fair value rec-
\n
ognized under personnel expenses.
\n

\n\n\n\n

\n

\n

\n\n\n\n\n
Provisions for risks and charges
\n
Pursuant to IAS 37, provisions are recognized where there
\n
is a legal or constructive obligation as a result of a past
\n
event at the end of the reporting period, the settlement
\n
of which is expected to result in an outflow of resourc-
\n
es whose amount can be reliably estimated. Where the
\n

\n\n\n\n

\n\n\n\n\n\n

\n

\n\n

\n
impact of the time value of money is material, the accru-
\n
als are determined by discounting expected future cash
\n
flows using a pre-tax discount rate that reflects the cur-
\n
rent market assessment of the time value of money and, if
\n
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
\n
financial 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, the
\n
initial recognition of the provision is made against the relat-
\n
ed asset and the expense is then recognized in profit or loss
\n
through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of nu-
\n
clear waste and other radioactive materials, the provision is
\n
recognized against the related operating costs.
\n

\n\n\n\n
A liability for restructuring refers to a program planned and
\n
controlled by management that materially changes the
\n
scope of a business undertaken by the Group or the man-
\n
ner in which the business is conducted. Such a liability is
\n
recognized when a constructive obligation is established,
\n
i.e. when the Group has approved a detailed formal restruc-
\n
turing plan and has started to implement the plan or has
\n
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 ser-
\n
vice in addition to the assurance that the product com-
\n
plies 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, rec-
\n
ognizing the contract liability as revenue over the period
\n
the warranty service is provided and the costs associated
\n
as they are incurred.
\n
Finally, 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
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
\n
restoration resulting from changes in the timetable and
\n
costs necessary to extinguish the obligation or from a
\n
change in the discount rate. These changes increase or
\n
decrease the carrying amount of the related assets and
\n
are taken to profit or loss through depreciation. Where
\n
they increase the carrying amount of the assets, it is also
\n
determined whether the new carrying amount of the as-
\n
sets is fully recoverable. If this is not the case, a loss equal
\n
to the unrecoverable amount is recognized through profit
\n
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
\n
of property, plant and equipment, especially those asso-
\n
ciated with decommissioning nuclear power plants and
\n
storage of waste fuel and other radioactive materials,
\n
please see note 2.1 \u201cUse of estimates and management
\n
judgment\u201d.
\n

\n

\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
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
\n
identify the contract with the customer;
\n
\u2022
\n
identify the performance obligations in the contract,
\n
that is, all goods or services promised in the contract;
\n\n
\u2022
\n
determine the transaction price at inception of the
\n
contract considering any variable considerations, non-
\n
cash consideration received from a customer or pay-
\n
able to the customer, significant financing components;
\n

\n\n\n\n
\u2022
\n
allocate the transaction price, at contract inception, to
\n
each separate performance obligation;
\n
\u2022
\n
recognize revenue, when (or as) each performance obli-
\n
gation is satisfied by transferring the promised good or
\n
service to the customer.
\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 rec-
\n
ognition model is provided in note 2.1 \u201cUse of estimates
\n

\n\n\n\n

\n\n\n\n\n\n

\n

\n

\n

\n

\n

\n\n
and management judgment\u201d and in note 11.a \u201cRevenue
\n
from sales and services\u201d.
\n

\n\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
\n
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
\u2022
\n
changes in the fair value of settled contracts to sell en-
\n
ergy commodities with physical settlement, which do
\n
not qualify for the own use exemption and therefore
\n
are recognized at FVTPL in accordance with IFRS 9;
\n

\n\n\n\n
\u2022
\n
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
Pursuant to IAS 20, government grants, including
\n
non-monetary grants at fair value, are recognized where
\n
there is reasonable assurance that they will be received
\n
and that the Group will comply with all conditions attach-
\n
ing to them as set by the government, government agen-
\n
cies and similar bodies whether local, national or interna-
\n
tional.
\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 mea-
\n
sured in accordance with the requirements for financial
\n
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 intend-
\n
ed to compensate.
\n
A government grant received to compensate for costs or
\n
losses already incurred, or for the purpose of providing
\n
immediate financial support to the Group without related
\n
future costs, is recognized as income in the year in which
\n
it becomes enforceable.
\n
When government grants are received to purchase, build
\n
or otherwise acquire non-current assets (for example, an
\n
item of property, plant and equipment or an intangible as-
\n
set), they are deducted from the carrying amount of the
\n
asset and are recognized in profit or loss over the depre-
\n
ciable/amortizable life of the asset as a reduction in the
\n
depreciation/amortization charge. If there is insufficient
\n
information to enable adequate attribution to the fixed
\n
assets to which they refer, capital grants are recognized
\n
as deferred income under other liabilities, and credited to
\n
profit or loss on a systematic basis over the useful life of
\n
the asset. If a government grant is made in a period sub-
\n
sequent to that in which the depreciation of the assets
\n
began, the portion of the grant corresponding to the de-
\n
preciation recognized in previous periods is recognized
\n
directly in profit or loss.
\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

\n

\n\n\n\n\n
Net results from commodity contracts
\n
The net results from commodity contracts include:
\n
\u2022
\n
the net income or expense from commodity deriv-
\n
atives, including derivatives designated as cash flow
\n
hedges and derivatives measured at fair value through
\n
profit or loss, whether settled or outstanding at the re-
\n
porting date; and
\n
\u2022
\n
the net gain/(loss) from the measurement through prof-
\n
it or loss of energy commodity contracts with physical
\n
settlement still outstanding at the reporting date.
\n

\n\n\n\n\n
Dividends
\n
Pursuant to \u201cIFRS 9 - Financial Instruments\u201c, dividends are
\n
recognized when the unconditional right to receive pay-
\n
ment is established.
\n
Dividends and interim dividends payable to the Parent\u2019s
\n
shareholders and non-controlling interests are recog-
\n
nized as changes in equity in the period in which they are
\n
approved by the Shareholders\u2019 Meeting and the Board of
\n
Directors, respectively.
\n

\n\n\n\n\n
Income taxes
\n
IAS 12 specifies the requirements for the recognition of
\n
current and deferred tax assets and liabilities. The uncer-
\n
tainty in the determination of tax liabilities is defined in
\n
accordance with the provisions of \u201cIFRIC 23 - Uncertainty
\n
over Income Tax Treatments\u201c.
\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 enact-
\n
ed by the end of the reporting period in the countries where
\n
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\n\n\n

\n\n\n\n\n\n

\n\n

\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: (i)
\n
from the initial recognition of goodwill; or (ii) from the
\n
initial recognition of an asset or a liability in a transaction
\n
which is not a business combination and, at the time of
\n
the transaction, affects neither accounting profit nor tax-
\n
able profit (tax loss); and does not give rise to equal taxable
\n
and deductible temporary differences; or (iii) in respect
\n
of taxable temporary differences associated with invest-
\n
ments in subsidiaries, associates and joint ventures, when
\n
the Group can control the timing of the reversal of the
\n
temporary differences and it is probable that the tempo-
\n
rary differences 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 eq-
\n
uity.
\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\n\n
Uncertainty over income tax treatments
\n
In defining \u201cuncertainty\u201c, 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\u201c is
\n
defined as \u201cmore likely than not\u201c), 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 in-
\n
come tax purposes, the Group reflects the uncertainty in
\n
the manner that best predicts the resolution of the uncer-
\n
tain tax treatment.
\n
For more information on uncertainty over tax treatments,
\n
please see note 2.1 \u201cUse of estimates and management
\n
judgment\u201d.
\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\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag24": { "value": "\n

\n
Related parties
\n
Pursuant to IAS 24, related parties are mainly those that
\n
share the same controlling entity with Enel SpA, the com-
\n
panies that directly or indirectly are controlled by Enel
\n
SpA, the associates or joint ventures (including their sub-
\n
sidiaries) of Enel SpA, or the associates or joint ventures
\n
(including their subsidiaries) of any Group company. Relat-
\n\n
ed parties also include entities that operate post-employ-
\n
ment benefit plans for employees of Enel SpA or its as-
\n
sociates (specifically, the FOPEN and FONDENEL pension
\n
funds), as well as the members of the boards of statutory
\n
auditors, and their immediate family, and the key manage-
\n
ment personnel, and their immediate family, of Enel SpA
\n
and its subsidiaries. Key management personnel comprise
\n
management personnel who have the power and direct or
\n
indirect responsibility for the planning, management and
\n
control of the activities of the Company. They include di-
\n
rectors (whether executive or not).
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithRelatedPartiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag25": { "value": "Relat-\n
ed parties also include entities that operate post-employ-
\n
ment benefit plans for employees of Enel SpA or its as-
\n
sociates (specifically, the FOPEN and FONDENEL pension
\n
funds), as well as the members of the boards of statutory
\n
auditors, and their immediate family, and the key manage-
\n
ment personnel, and their immediate family, of Enel SpA
\n
and its subsidiaries. Key management personnel comprise
\n
management personnel who have the power and direct or
\n
indirect responsibility for the planning, management and
\n
control of the activities of the Company. They include di-
\n
rectors (whether executive or not).
\n

\n\n\n\n\n\n\n\n
With regard to disclosures on the remuneration of di-
\n
rectors, members of the Board of Statutory Auditors, the
\n
General Manager and key management personnel, provid-
\n
ed for under IAS 24, please see the following tables.
\n
Millions of euro
\n
2023 2022 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
Termination benefits 5 - 5 -
\n
Share-based payments 1 1 - -
\n
Total 11 6 5 83.3%
\n
Millions of euro
\n
2023 2022 Change
\n
Remuneration of key management personnel
\n
Short-term employee benefits 8 13 (5) -38.5%
\n
Termination benefits 4 - 4 -
\n
Share-based payments 1 2 (1) -50.0%
\n
Total 13 15 (2) -13.3%
\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 (Enel Procedure for Trans-
\n
actions with Related Parties). The procedure (available at
\n
https://www.enel.com/investors/bylaws-rules-and-pol-
\n
icies/transactions-with-related-parties/) sets out rules
\n
designed to ensure the transparency and procedural and
\n
substantive propriety of transactions with related parties.
\n
It was adopted in implementation of the provisions of Arti-
\n
cle 2391-bis of the Italian Civil Code and the implementing
\n
regulations issued by CONSOB with Resolution no. 17221
\n
of March 12, 2010, as amended (\u201cCONSOB Regulation\u201d).
\n
No related-party transactions requiring disclosure in the
\n
financial statements pursuant to the CONSOB Regulation
\n
were carried out in 2023.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag26": { "value": "\n

\n

\n\n

\n
Subsidiaries
\n
Pursuant to IFRS 10, subsidiaries are all entities over which
\n
the Group has control. For more information on the defi-
\n
nition of control, please see section \u201cDetermination of the
\n
existence of control\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2023 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
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
Profit or loss for the year and the other comprehensive in-
\n
come are attributed to owners of the Parent and non-con-
\n
trolling interests, even if this results in a loss for non-con-
\n
trolling interests.
\n
All intercompany assets and liabilities, equity item, reve-
\n
nue, expenses and cash flows relating to transactions be-
\n
tween 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\n\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

\n\n

\n\n
Investments in associates and joint ventures
\n
In the consolidated financial statements, investments in as-
\n
sociated companies and joint arrangements are measured
\n
in accordance with the requirements established by \u201cIAS 28
\n
- Investments in Associates and Joint Ventures\u201d and \u201cIFRS
\n
11 - Joint Arrangements\u201d.
\n
In this respect, an associate is an entity over which the
\n
Group has significant influence, while a joint venture is a
\n
joint arrangement over which the Group exercises joint
\n
control and has rights to the net assets of the arrangement.
\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

\n\n\n\n\n\n\n\n

\n\n

\n\n

\n\n

\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method, under which
\n
these investments are initially recognized at cost and any
\n
goodwill arising from the difference between the cost of
\n
the investment and the Group\u2019s share of the net fair val-
\n
ue of the investee\u2019s identifiable assets and liabilities at the
\n
acquisition date is included in the carrying amount of the
\n
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 ventures 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
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\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

\n\n\n\n\n\n\n\n
If the ownership interest in an associate or a joint venture
\n
is reduced, but the Group continues to exercise a signifi-
\n
cant influence or joint control, the Group continues to ap-
\n
ply the equity method and the share of the gain or loss
\n
that had previously been recognized in other comprehen-
\n
sive income relating to that reduction is accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\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
\n
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 combina-
\n
tion achieved in stages, with the remeasurement of the
\n
interest it held previously in the joint operation at its fair
\n
value at each acquisition date;
\n
\u2022
\n
if the Group obtains joint control (i.e. it already had an
\n
interest in a joint operation without holding joint con-
\n
trol), the interest previously held in the joint operation
\n
shall 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\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\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag27": { "value": "\n

\n
Subsidiaries
\n
Pursuant to IFRS 10, subsidiaries are all entities over which
\n
the Group has control. For more information on the defi-
\n
nition of control, please see section \u201cDetermination of the
\n
existence of control\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\n
The financial statements of subsidiaries used to prepare
\n
the consolidated financial statements were prepared at
\n
December 31, 2023 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
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
Profit or loss for the year and the other comprehensive in-
\n
come are attributed to owners of the Parent and non-con-
\n
trolling interests, even if this results in a loss for non-con-
\n
trolling interests.
\n
All intercompany assets and liabilities, equity item, reve-
\n
nue, expenses and cash flows relating to transactions be-
\n
tween 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\n\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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag28": { "value": "\n
Profit or loss for the year and the other comprehensive in-
\n
come are attributed to owners of the Parent and non-con-
\n
trolling interests, even if this results in a loss for non-con-
\n
trolling interests.
\n
All intercompany assets and liabilities, equity item, reve-
\n
nue, expenses and cash flows relating to transactions be-
\n
tween 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\n\n\n\nThe carrying amount of non-controlling inter-ests was determined in proportion to the interest held by non-controlling shareholders in the net assets.The carrying amount of non-controlling interests \n
is determined either in proportion to the interest held
\n
by non-controlling shareholders in the net identifiable
\n
assets of the acquiree or at their fair value as at the
\n
acquisition date.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag29": { "value": "\n

\n\n

\n\n
Investments in associates and joint ventures
\n
In the consolidated financial statements, investments in as-
\n
sociated companies and joint arrangements are measured
\n
in accordance with the requirements established by \u201cIAS 28
\n
- Investments in Associates and Joint Ventures\u201d and \u201cIFRS
\n
11 - Joint Arrangements\u201d.
\n
In this respect, an associate is an entity over which the
\n
Group has significant influence, while a joint venture is a
\n
joint arrangement over which the Group exercises joint
\n
control and has rights to the net assets of the arrangement.
\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

\n\n

\n\n

\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method, under which
\n
these investments are initially recognized at cost and any
\n
goodwill arising from the difference between the cost of
\n
the investment and the Group\u2019s share of the net fair val-
\n
ue of the investee\u2019s identifiable assets and liabilities at the
\n
acquisition date is included in the carrying amount of the
\n
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 ventures 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
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\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

\n\n\n\n\n\n\n\n
If the ownership interest in an associate or a joint venture
\n
is reduced, but the Group continues to exercise a signifi-
\n
cant influence or joint control, the Group continues to ap-
\n
ply the equity method and the share of the gain or loss
\n
that had previously been recognized in other comprehen-
\n
sive income relating to that reduction is accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\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
\n
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 combina-
\n
tion achieved in stages, with the remeasurement of the
\n
interest it held previously in the joint operation at its fair
\n
value at each acquisition date;
\n
\u2022
\n
if the Group obtains joint control (i.e. it already had an
\n
interest in a joint operation without holding joint con-
\n
trol), the interest previously held in the joint operation
\n
shall 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\n\n

\n

\n\n\n\n\n\n\n\n

\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag30": { "value": "\n

\n\n
Investments in associates and joint ventures
\n
In the consolidated financial statements, investments in as-
\n
sociated companies and joint arrangements are measured
\n
in accordance with the requirements established by \u201cIAS 28
\n
- Investments in Associates and Joint Ventures\u201d and \u201cIFRS
\n
11 - Joint Arrangements\u201d.
\n
In this respect, an associate is an entity over which the
\n
Group has significant influence, while a joint venture is a
\n
joint arrangement over which the Group exercises joint
\n
control and has rights to the net assets of the arrangement.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\n

\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method, under which
\n
these investments are initially recognized at cost and any
\n
goodwill arising from the difference between the cost of
\n
the investment and the Group\u2019s share of the net fair val-
\n
ue of the investee\u2019s identifiable assets and liabilities at the
\n
acquisition date is included in the carrying amount of the
\n
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 ventures 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
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\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

\n\n\n\n\n\n\n\n
If the ownership interest in an associate or a joint venture
\n
is reduced, but the Group continues to exercise a signifi-
\n
cant influence or joint control, the Group continues to ap-
\n
ply the equity method and the share of the gain or loss
\n
that had previously been recognized in other comprehen-
\n
sive income relating to that reduction is accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\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
\n
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 combina-
\n
tion achieved in stages, with the remeasurement of the
\n
interest it held previously in the joint operation at its fair
\n
value at each acquisition date;
\n
\u2022
\n
if the Group obtains joint control (i.e. it already had an
\n
interest in a joint operation without holding joint con-
\n
trol), the interest previously held in the joint operation
\n
shall 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\n\n

\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociates", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag31": { "value": "\n
Investments in associates and joint ventures
\n
In the consolidated financial statements, investments in as-
\n
sociated companies and joint arrangements are measured
\n
in accordance with the requirements established by \u201cIAS 28
\n
- Investments in Associates and Joint Ventures\u201d and \u201cIFRS
\n
11 - Joint Arrangements\u201d.
\n
In this respect, an associate is an entity over which the
\n
Group has significant influence, while a joint venture is a
\n
joint arrangement over which the Group exercises joint
\n
control and has rights to the net assets of the arrangement.
\n

\n\n\n\n\n\n\n\n

\n
The Group\u2019s investments in associates and joint ventures
\n
are accounted for using the equity method, under which
\n
these investments are initially recognized at cost and any
\n
goodwill arising from the difference between the cost of
\n
the investment and the Group\u2019s share of the net fair val-
\n
ue of the investee\u2019s identifiable assets and liabilities at the
\n
acquisition date is included in the carrying amount of the
\n
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 ventures 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
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\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

\n\n\n\n\n\n\n\n
If the ownership interest in an associate or a joint venture
\n
is reduced, but the Group continues to exercise a signifi-
\n
cant influence or joint control, the Group continues to ap-
\n
ply the equity method and the share of the gain or loss
\n
that had previously been recognized in other comprehen-
\n
sive income relating to that reduction is accounted for as
\n
if the Group had directly disposed of the related assets or
\n
liabilities.
\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
\n
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 combina-
\n
tion achieved in stages, with the remeasurement of the
\n
interest it held previously in the joint operation at its fair
\n
value at each acquisition date;
\n
\u2022
\n
if the Group obtains joint control (i.e. it already had an
\n
interest in a joint operation without holding joint con-
\n
trol), the interest previously held in the joint operation
\n
shall 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\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag32": { "value": "\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

\n\n\n\n\n\n\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 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 re-
\n
classified to profit or loss. The Group may transfer the cu-
\n
mulative gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n

\n\n\n\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of
\n
the cost of the investment.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsOtherThanInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag33": { "value": "\n
Translation of foreign currency items
\n
Pursuant to \u201cIAS 21 - The Effects of Changes in Foreign
\n
Exchange Rates\u201c, transactions in currencies other than the
\n
functional currency are initially recognized at the spot ex-
\n
change rate 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 spot exchange rate prevailing
\n
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 ini-
\n
tial recognition of the transaction. Non-monetary assets
\n
and liabilities in foreign currency measured at fair value
\n
are translated using the exchange rate at the date the fair
\n
value was determined.
\n
Any exchange differences are recognized through profit
\n
or 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

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "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
Pursuant to IAS 21, in order to prepare the consolidated
\n
financial statements, the financial statements of consol-
\n
idated companies with functional currencies other than
\n

\n\n\n\n\n\n\n\n
the presentation currency used in the consolidated finan-
\n
cial statements are translated into euros by applying the
\n
closing exchange rate to the assets and liabilities, includ-
\n
ing goodwill and consolidation adjustments, and the aver-
\n
age exchange rate for the period to the income statement
\n
items on the condition it approximates the exchange rates
\n
prevailing at the date of 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 \u201cIAS
\n
29 - Financial Reporting in Hyperinflationary Economies\u201c
\n
before applying the specific conversion method set out
\n
below.
\n
In order to consider the impact of hyperinflation on the lo-
\n
cal currency exchange rate, the financial position and per-
\n
formance (i.e. assets, liabilities, equity items, revenue and
\n
expenses) of a company of the Group whose functional
\n
currency is the currency of a hyperinflationary economy
\n
are translated into the Group\u2019s presentation currency (the
\n
euro) using the exchange rate prevailing at the reporting
\n
date, except for comparative amounts presented in the
\n
previous year\u2019s financial statements which are not adjust-
\n
ed for subsequent changes in the price level or subse-
\n
quent changes in exchange rates.
\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag35": { "value": "\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
and is recognized in the consolidated financial statements
\n
as at the date of acquisition of control of the business.
\n
To this end, the Group recognizes business combinations
\n
using:
\n
\u2022
\n
the \u201cpurchase method\u201d, for all business combinations
\n
initiated before January 1, 2010 and completed within
\n
that financial year on the basis of IFRS 3 (2004), where
\n
the purchase cost is equal to the fair value at the date
\n
of the exchange of the assets acquired and the liabil-
\n
ities incurred or assumed, plus costs directly attrib-
\n
utable to the acquisition. This cost was allocated by
\n
recognizing the assets, liabilities and identifiable con-
\n
tingent 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 owners of the Parent was recognized as
\n
goodwill. The carrying amount of non-controlling inter-
\n
ests was determined in proportion to the interest held
\n
by non-controlling shareholders in the net assets. In the
\n
case of business combinations achieved in stages, at
\n
the date of acquisition any adjustment to the fair value
\n
of the net assets acquired previously was recognized
\n
in equity; the amount of goodwill was determined for
\n
each transaction separately based on the fair values of
\n
the acquiree\u2019s net assets at the date of each exchange
\n
transaction;
\n
\u2022
\n
the \u201cacquisition method\u201d, for all business combinations
\n
carried out as from January 1, 2010 that are recognized
\n
on the basis of IFRS 3 (2008), which is referred to as
\n
IFRS 3 (Revised) hereafter, where the purchase cost (the
\n
consideration transferred) is equal to the fair value at the
\n
purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments
\n
issued by the purchaser. The purchase cost includes
\n
the fair value of any asset or liability resulting from a
\n
contingent consideration arrangement. The consider-
\n
ation transferred is allocated by recognizing the assets,
\n
liabilities and identifiable contingent liabilities of the ac-
\n
quired company at their fair values as at the acquisition
\n
date. In this regard, goodwill is defined as the excess
\n
of the consideration transferred, measured at fair value
\n
as at the acquisition date, the amount of any non-con-
\n
trolling interest in the acquiree plus the fair value of any
\n
equity interest in the acquiree previously held by the
\n
Group (in a business combination achieved in stages)
\n
over the net amount of the identifiable assets acquired
\n
and the liabilities incurred or assumed measured at fair
\n
value. The carrying amount of non-controlling interests
\n\n
is determined either in proportion to the interest held
\n
by non-controlling shareholders in the net identifiable
\n
assets of the acquiree or at their fair value as at the
\n
acquisition date.
\n

\n\n\n\n
IFRS 3 (Revised) requires, among other things, the following:
\n
\u2022
\n
costs directly attributable to the acquisition are recog-
\n
nized through profit or loss;
\n
\u2022
\n
in the case of business combinations achieved in stag-
\n
es, at the date of acquisition of control the previously
\n
held equity interest in the acquiree is remeasured to
\n
fair value and any positive or negative difference is rec-
\n
ognized in profit or loss;
\n
\u2022
\n
any contingent consideration is recognized at fair val-
\n
ue at the acquisition date. Subsequent changes to the
\n
fair value of the contingent consideration classified as
\n
an asset or a liability, or as a financial instrument within
\n
the scope of IFRS 9, are recognized in profit or loss. If
\n
the contingent consideration is not within the scope of
\n
IFRS 9, it is measured in accordance with the appro-
\n
priate IFRS-IAS. Contingent consideration that is clas-
\n
sified as equity is not re-measured, and its subsequent
\n
settlement is accounted for within equity;
\n
\u2022
\n
if the fair values of the assets, liabilities and contingent
\n
liabilities can only be calculated on a provisional basis,
\n
the business combination is recognized using such
\n
provisional values. Any adjustments resulting from the
\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\n\n\n

\n\n

\n\n
completion of the measurement process are recog-
\n
nized within 12 months of the date of acquisition, re-
\n
stating comparative figures.
\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.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU or group of
\n
CGUs that is expected to benefit from the synergies of the
\n
combination.
\n
For more information, please see the section \u201cImpairment
\n
of non-financial assets\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\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\n\n\n\n\n\n\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag36": { "value": "\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
and is recognized in the consolidated financial statements
\n
as at the date of acquisition of control of the business.
\n
To this end, the Group recognizes business combinations
\n
using:
\n
\u2022
\n
the \u201cpurchase method\u201d, for all business combinations
\n
initiated before January 1, 2010 and completed within
\n
that financial year on the basis of IFRS 3 (2004), where
\n
the purchase cost is equal to the fair value at the date
\n
of the exchange of the assets acquired and the liabil-
\n
ities incurred or assumed, plus costs directly attrib-
\n
utable to the acquisition. This cost was allocated by
\n
recognizing the assets, liabilities and identifiable con-
\n
tingent 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 owners of the Parent was recognized as
\n
goodwill. The carrying amount of non-controlling inter-
\n
ests was determined in proportion to the interest held
\n
by non-controlling shareholders in the net assets. In the
\n
case of business combinations achieved in stages, at
\n
the date of acquisition any adjustment to the fair value
\n
of the net assets acquired previously was recognized
\n
in equity; the amount of goodwill was determined for
\n
each transaction separately based on the fair values of
\n
the acquiree\u2019s net assets at the date of each exchange
\n
transaction;
\n
\u2022
\n
the \u201cacquisition method\u201d, for all business combinations
\n
carried out as from January 1, 2010 that are recognized
\n
on the basis of IFRS 3 (2008), which is referred to as
\n
IFRS 3 (Revised) hereafter, where the purchase cost (the
\n
consideration transferred) is equal to the fair value at the
\n
purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments
\n
issued by the purchaser. The purchase cost includes
\n
the fair value of any asset or liability resulting from a
\n
contingent consideration arrangement. The consider-
\n
ation transferred is allocated by recognizing the assets,
\n
liabilities and identifiable contingent liabilities of the ac-
\n
quired company at their fair values as at the acquisition
\n
date. In this regard, goodwill is defined as the excess
\n
of the consideration transferred, measured at fair value
\n
as at the acquisition date, the amount of any non-con-
\n
trolling interest in the acquiree plus the fair value of any
\n
equity interest in the acquiree previously held by the
\n
Group (in a business combination achieved in stages)
\n
over the net amount of the identifiable assets acquired
\n
and the liabilities incurred or assumed measured at fair
\n
value. The carrying amount of non-controlling interests
\n\n
is determined either in proportion to the interest held
\n
by non-controlling shareholders in the net identifiable
\n
assets of the acquiree or at their fair value as at the
\n
acquisition date.
\n

\n\n\n\n
IFRS 3 (Revised) requires, among other things, the following:
\n
\u2022
\n
costs directly attributable to the acquisition are recog-
\n
nized through profit or loss;
\n
\u2022
\n
in the case of business combinations achieved in stag-
\n
es, at the date of acquisition of control the previously
\n
held equity interest in the acquiree is remeasured to
\n
fair value and any positive or negative difference is rec-
\n
ognized in profit or loss;
\n
\u2022
\n
any contingent consideration is recognized at fair val-
\n
ue at the acquisition date. Subsequent changes to the
\n
fair value of the contingent consideration classified as
\n
an asset or a liability, or as a financial instrument within
\n
the scope of IFRS 9, are recognized in profit or loss. If
\n
the contingent consideration is not within the scope of
\n
IFRS 9, it is measured in accordance with the appro-
\n
priate IFRS-IAS. Contingent consideration that is clas-
\n
sified as equity is not re-measured, and its subsequent
\n
settlement is accounted for within equity;
\n
\u2022
\n
if the fair values of the assets, liabilities and contingent
\n
liabilities can only be calculated on a provisional basis,
\n
the business combination is recognized using such
\n
provisional values. Any adjustments resulting from the
\n

\n

\n\n\n\n\n\n\n\n

\n

\n\n\n\n\n\n\n\n

\n\n
completion of the measurement process are recog-
\n
nized within 12 months of the date of acquisition, re-
\n
stating comparative figures.
\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.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU or group of
\n
CGUs that is expected to benefit from the synergies of the
\n
combination.
\n
For more information, please see the section \u201cImpairment
\n
of non-financial assets\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\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\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag37": { "value": "\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
and is recognized in the consolidated financial statements
\n
as at the date of acquisition of control of the business.
\n
To this end, the Group recognizes business combinations
\n
using:
\n
\u2022
\n
the \u201cpurchase method\u201d, for all business combinations
\n
initiated before January 1, 2010 and completed within
\n
that financial year on the basis of IFRS 3 (2004), where
\n
the purchase cost is equal to the fair value at the date
\n
of the exchange of the assets acquired and the liabil-
\n
ities incurred or assumed, plus costs directly attrib-
\n
utable to the acquisition. This cost was allocated by
\n
recognizing the assets, liabilities and identifiable con-
\n
tingent 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 owners of the Parent was recognized as
\n
goodwill. The carrying amount of non-controlling inter-
\n
ests was determined in proportion to the interest held
\n
by non-controlling shareholders in the net assets. In the
\n
case of business combinations achieved in stages, at
\n
the date of acquisition any adjustment to the fair value
\n
of the net assets acquired previously was recognized
\n
in equity; the amount of goodwill was determined for
\n
each transaction separately based on the fair values of
\n
the acquiree\u2019s net assets at the date of each exchange
\n
transaction;
\n
\u2022
\n
the \u201cacquisition method\u201d, for all business combinations
\n
carried out as from January 1, 2010 that are recognized
\n
on the basis of IFRS 3 (2008), which is referred to as
\n
IFRS 3 (Revised) hereafter, where the purchase cost (the
\n
consideration transferred) is equal to the fair value at the
\n
purchase date of the assets acquired and the liabilities
\n
incurred or assumed, as well as any equity instruments
\n
issued by the purchaser. The purchase cost includes
\n
the fair value of any asset or liability resulting from a
\n
contingent consideration arrangement. The consider-
\n
ation transferred is allocated by recognizing the assets,
\n
liabilities and identifiable contingent liabilities of the ac-
\n
quired company at their fair values as at the acquisition
\n
date. In this regard, goodwill is defined as the excess
\n
of the consideration transferred, measured at fair value
\n
as at the acquisition date, the amount of any non-con-
\n
trolling interest in the acquiree plus the fair value of any
\n
equity interest in the acquiree previously held by the
\n
Group (in a business combination achieved in stages)
\n
over the net amount of the identifiable assets acquired
\n
and the liabilities incurred or assumed measured at fair
\n
value. The carrying amount of non-controlling interests
\n\n
is determined either in proportion to the interest held
\n
by non-controlling shareholders in the net identifiable
\n
assets of the acquiree or at their fair value as at the
\n
acquisition date.
\n

\n\n\n\n
IFRS 3 (Revised) requires, among other things, the following:
\n
\u2022
\n
costs directly attributable to the acquisition are recog-
\n
nized through profit or loss;
\n
\u2022
\n
in the case of business combinations achieved in stag-
\n
es, at the date of acquisition of control the previously
\n
held equity interest in the acquiree is remeasured to
\n
fair value and any positive or negative difference is rec-
\n
ognized in profit or loss;
\n
\u2022
\n
any contingent consideration is recognized at fair val-
\n
ue at the acquisition date. Subsequent changes to the
\n
fair value of the contingent consideration classified as
\n
an asset or a liability, or as a financial instrument within
\n
the scope of IFRS 9, are recognized in profit or loss. If
\n
the contingent consideration is not within the scope of
\n
IFRS 9, it is measured in accordance with the appro-
\n
priate IFRS-IAS. Contingent consideration that is clas-
\n
sified as equity is not re-measured, and its subsequent
\n
settlement is accounted for within equity;
\n
\u2022
\n
if the fair values of the assets, liabilities and contingent
\n
liabilities can only be calculated on a provisional basis,
\n
the business combination is recognized using such
\n
provisional values. Any adjustments resulting from the
\n

\n

\n\n\n\n\n\n\n\n
completion of the measurement process are recog-
\n
nized within 12 months of the date of acquisition, re-
\n
stating comparative figures.
\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.
\n
For the purpose of impairment testing, goodwill is allocat-
\n
ed, from the acquisition date, to each CGU or group of
\n
CGUs that is expected to benefit from the synergies of the
\n
combination.
\n
For more information, please see the section \u201cImpairment
\n
of non-financial assets\u201d in note 2.1 \u201cUse of estimates and
\n
management judgment\u201d.
\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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag38": { "value": "\n
Fair value measurement
\n
For all fair value measurements and disclosures of fair
\n
value, that are either required or permitted by IFRS, the
\n
Group 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 transac-
\n
tion to sell an asset or transfer a liability takes place in the
\n
principal market, i.e. the market with the greatest volume
\n
and level of activity for the asset or liability. In the absence
\n
of a principal market, it is assumed that the transaction
\n
takes place in the most advantageous market to which
\n
the Group has access, i.e. the market that maximizes the
\n
amount that would be received to sell the asset or mini-
\n
mizes the amount that would be paid to transfer the lia-
\n
bility.
\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
\n
for a non-financial asset, a fair value measurement
\n
takes into account a market participant\u2019s ability to
\n
generate economic benefits by using the asset in its
\n
highest and best use or by selling it to another market
\n
participant that would use the asset in its highest and
\n
best use;
\n
\u2022
\n
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
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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag39": { "value": "\n

\n

\n

\n

\n
Property, plant and equipment
\n
Pursuant to IAS 16, property, plant and equipment is stated
\n
at cost, net of accumulated depreciation and accumulat-
\n
ed impairment losses, if any. Such cost includes expenses
\n
directly attributable to bringing the asset to the location
\n
and condition 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 or
\n
constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
For more information on changes in the estimate of these
\n
costs, the passage of time and the discount rate, please
\n
see note 2.1 \u201cUse of estimates and management judge-
\n
ment\u201d.
\n

\n\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 of
\n
the cost of the assets themselves. Borrowing costs asso-
\n
ciated 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\n\n
Certain assets that were revalued at the IFRS transition
\n
date or in previous periods are recognized at their fair val-
\n
ue, 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\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\n\n\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

\n\n\n\n

\n\n\n\n

\n\n
preciation criteria shall be applied prospectively. Depreci-
\n
ation begins when the asset is available for use. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\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
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\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\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag40": { "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 or
\n
constructive obligation to do so. The corresponding lia-
\n
bility is recognized under provisions for risks and charges.
\n
For more information on changes in the estimate of these
\n
costs, the passage of time and the discount rate, please
\n
see note 2.1 \u201cUse of estimates and management judge-
\n
ment\u201d.
\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

\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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\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 mainly
\n
include:
\n
\u2022
\n
financial liabilities held for trading incurred for the pur-
\n
pose of repurchasing in the near term;
\n
\u2022
\n
derivative financial instruments entered into by the
\n
Group that are not designated as hedging instruments
\n
in hedge relationships as defined by IFRS 9;
\n
\u2022
\n
financial liabilities that qualify as contingent consider-
\n
ation.
\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
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\n\n\n\n

\n\n\n\n

\n\n\n\n

\n\n\n\n

\n

\n\n

\n\n

\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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\n\n

\n\n
Derivative financial instruments
\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 profit
\n
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 current
\n
on the basis of their maturity date and the Group intention
\n
to hold the financial instrument till maturity or not.
\n
For more details on derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n\n

\n\n\n\n

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

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag41": { "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 of
\n
the cost of the assets themselves. Borrowing costs asso-
\n
ciated 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\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag42": { "value": "\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\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRepairsAndMaintenanceExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag43": { "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

\n\n\n\n
preciation criteria shall be applied prospectively. Depreci-
\n
ation begins when the asset is available for use. For more
\n
information on estimating useful life, please see note 2.1
\n
\u201cUse of estimates and management judgment\u201d.
\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
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\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag44": { "value": "\n
Service concession arrangements
\n
When acting as operator under \u201cpublic-to-private\u201d ser-
\n
vice concession arrangements, the Group constructs/up-
\n
grades infrastructure used to provide a public service and/
\n
or operates and maintains that infrastructure for the years
\n
of the concession, in accordance with the terms specified
\n
in the contract.
\n
In these circumstances, the Group does not account for
\n
the infrastructure operated under a service concession
\n

\n\n\n\n
arrangement within the scope of IFRIC 12 as property,
\n
plant and equipment, recognizing and measuring 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
\n
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 to
\n
avoid payment; and/or
\n
\u2022
\n
an intangible asset, if the Group receives the right (a
\n
license) to charge users of the public service provided
\n
and thus does not have an unconditional right to re-
\n
ceive cash because the amounts are contingent on the
\n
extent that the public uses the service.
\n
If the Group (as operator) has a contractual right to re-
\n
ceive an intangible asset, borrowing costs are capitalized
\n
using the criteria specified in note 19 \u201cProperty, plant and
\n
equipment\u201d.
\n
However, for construction/upgrade services, both types
\n
of consideration are classified as a contract asset during
\n
the construction/upgrade period.
\n
For more details about such consideration, please see
\n
note 11.a \u201cRevenue from sales and services\u201d.
\n
Conversely, where the service concession arrangement
\n
provides for the infrastructure used for to operate the
\n
concessions themselves do not comply with the require-
\n
ments established by IFRIC 12 and, in particular, are owned
\n
and available to the operator or have an indefinite expiry,
\n
the carrying amount of the assets attributable to these
\n
concessions is recognized under \u201cProperty, plant and
\n
equipment\u201d and accounted for in accordance with IAS 16.
\n
Information on the main characteristics of the Group\u2019s
\n
service concession arrangements can be found in note
\n
20 \u201cInfrastructure within the scope of \u2018IFRIC 12 - Service
\n
Concession Arrangements\u2019\u201d.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForServiceConcessionArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag45": { "value": "\n
Leases
\n
At inception of a contract, the Group assesses whether a
\n
contract is, or contains, a lease applying the definition of a
\n
lease under IFRS 16, that is met if the contract conveys the
\n
right to control the use of an identified asset for a period
\n
of time in exchange for consideration.
\n
When the Group acts as a lessee, it recognizes a right-of-
\n
use asset and a lease liability at the commencement date
\n
of the lease (i.e. the date the underlying asset is available
\n
for use).
\n
The right-of-use asset is initially measured at cost, which
\n
includes the initial amount of lease liability adjusted for any
\n
lease payments made at or before the commencement
\n
date less any lease incentives received, plus any initial di-
\n
rect costs incurred and an estimate of costs to retire and
\n
remove the underlying asset and to restore the underlying
\n
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.
\n
Average residual life
\n
(years)
\n
Buildings 8
\n
Ground rights of energy plants 32
\n
Vehicles and other means of transport 4
\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 ex-
\n
ercise a purchase option, depreciation is calculated using
\n
the estimated useful life of the underlying asset.
\n
In addition, the right-of-use assets are subject to im-
\n
pairment testing and adjusted for any remeasurement of
\n
lease liabilities.
\n
The lease liability is initially measured at the present value of
\n
lease payments to be made over the lease term, discounted
\n
using the lessee\u2019s incremental borrowing rate at the lease
\n
commencement date when the interest rate implicit in the
\n
lease 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

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag46": { "value": "\n

\n\n

\n
Intangible assets
\n
Pursuant to IAS 38, intangible assets are identifiable as-
\n
sets without physical substance controlled by the Group,
\n
when it is probable that the use of such assets will gener-
\n
ate future economic benefits and the related cost can be
\n
reliably determined.
\n\n
They are measured at purchase or internal development
\n
cost for internally generated assets and are recognized
\n
only when the 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

\n\n\n\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n

\n\n\n\n

\n\n\n\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 estimat-
\n
ing useful life, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and note 23 \u201cIntangible assets\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
\n
the exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amor-
\n
tized, but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annual-
\n
ly to determine whether the indefinite useful life continues
\n
to be supportable. If not, the change in useful life from in-
\n
definite to finite is accounted for as a change in account-
\n
ing estimate.
\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 presents costs to obtain a contract with a cus-
\n
tomer capitalized in accordance with IFRS 15 as intangible
\n
assets, only if:
\n
\u2022
\n
the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group
\n
would not have incurred them if the contract had not
\n
been obtained;
\n
\u2022
\n
the Group expects to recover them, through reim-
\n
bursements (direct recoverability) or the margin (indi-
\n
rect recoverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the capi-
\n
talization 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
\n
undergo impairment testing to identify any impairment
\n
losses to the extent that the carrying amount of the asset
\n
recognized exceeds the recoverable amount.
\n
The Group amortizes the capitalized customer contract
\n
costs 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); any changes in amortization policies
\n
are reflected on a prospective basis.
\n

\n

\n\n\n\n\n

\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag47": { "value": "\n

\n
Intangible assets
\n
Pursuant to IAS 38, intangible assets are identifiable as-
\n
sets without physical substance controlled by the Group,
\n
when it is probable that the use of such assets will gener-
\n
ate future economic benefits and the related cost can be
\n
reliably determined.
\n\n
They are measured at purchase or internal development
\n
cost for internally generated assets and are recognized
\n
only when the 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

\n\n\n\n
The cost includes any directly attributable expenses nec-
\n
essary to make the assets ready for their intended use.
\n

\n\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 estimat-
\n
ing useful life, please see note 2.1 \u201cUse of estimates and
\n
management judgment\u201d and note 23 \u201cIntangible assets\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
\n
the exception of a number of concessions and goodwill.
\n
Intangible assets with indefinite useful lives are not amor-
\n
tized, but are tested for impairment annually.
\n
The assessment of indefinite useful life is reviewed annual-
\n
ly to determine whether the indefinite useful life continues
\n
to be supportable. If not, the change in useful life from in-
\n
definite to finite is accounted for as a change in account-
\n
ing estimate.
\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 presents costs to obtain a contract with a cus-
\n
tomer capitalized in accordance with IFRS 15 as intangible
\n
assets, only if:
\n
\u2022
\n
the costs are incremental, that is they are directly at-
\n
tributable to an identified contract and the Group
\n
would not have incurred them if the contract had not
\n
been obtained;
\n
\u2022
\n
the Group expects to recover them, through reim-
\n
bursements (direct recoverability) or the margin (indi-
\n
rect recoverability).
\n
In particular, the Group generally capitalizes trade fees and
\n
commissions paid to agents for such contracts if the capi-
\n
talization 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
\n
undergo impairment testing to identify any impairment
\n
losses to the extent that the carrying amount of the asset
\n
recognized exceeds the recoverable amount.
\n
The Group amortizes the capitalized customer contract
\n
costs 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); 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag48": { "value": "\n
They are measured at purchase or internal development
\n
cost for internally generated assets and are recognized
\n
only when the 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

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForResearchAndDevelopmentExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag50": { "value": "\n

\n\n
Impairment of non-financial assets
\n
Pursuant to \u201dIAS 36 - Impairment of assets\u201d, at each re-
\n
porting date, property, plant and equipment, investment
\n
property recognized at cost, intangible assets, right-of-
\n
use assets, goodwill and equity investments in associates/
\n
joint ventures are reviewed to determine whether there is
\n
evidence of impairment (using internal and external sourc-
\n
es of information).
\n
CGUs to which goodwill is allocated, intangible assets with
\n
an indefinite useful life and intangible assets not yet avail-
\n
able for use are tested for recoverability annually or more
\n
frequently if there is evidence suggesting that the assets
\n
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 individu-
\n
al asset, unless the asset do not generate cash inflows
\n
that are largely independent of those from other assets
\n
or groups of assets and therefore it is determined for the
\n
CGU to 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 re-
\n
stored through profit or loss, under \u201cDepreciation, amor-
\n
tization and other impairment losses\u201d, in an amount that
\n
shall not exceed the carrying amount that the asset would
\n
have had if the impairment loss had not been recognized.
\n
The original amount of goodwill is not restored even if in
\n
subsequent years the reasons for the impairment no lon-
\n
ger apply.
\n

\n\n\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\n

\n

\n\n\n\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag49": { "value": "\n
Impairment of non-financial assets
\n
Pursuant to \u201dIAS 36 - Impairment of assets\u201d, at each re-
\n
porting date, property, plant and equipment, investment
\n
property recognized at cost, intangible assets, right-of-
\n
use assets, goodwill and equity investments in associates/
\n
joint ventures are reviewed to determine whether there is
\n
evidence of impairment (using internal and external sourc-
\n
es of information).
\n
CGUs to which goodwill is allocated, intangible assets with
\n
an indefinite useful life and intangible assets not yet avail-
\n
able for use are tested for recoverability annually or more
\n
frequently if there is evidence suggesting that the assets
\n
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 individu-
\n
al asset, unless the asset do not generate cash inflows
\n
that are largely independent of those from other assets
\n
or groups of assets and therefore it is determined for the
\n
CGU to 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 re-
\n
stored through profit or loss, under \u201cDepreciation, amor-
\n
tization and other impairment losses\u201d, in an amount that
\n
shall not exceed the carrying amount that the asset would
\n
have had if the impairment loss had not been recognized.
\n
The original amount of goodwill is not restored even if in
\n
subsequent years the reasons for the impairment no lon-
\n
ger apply.
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag51": { "value": "\n
Inventories
\n
Pursuant to IAS 2, inventories are measured at the low-
\n
er of cost and net realizable value except for inventories
\n
involved in trading activities, which are measured at fair
\n
value with recognition through profit or loss. Cost is de-
\n
termined on the basis of average weighted cost, which in-
\n

\n\n\n\n\n

\n
cludes related ancillary charges. Net estimated realizable
\n
value is the estimated normal selling price net of estimat-
\n
ed costs to sell or, where 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 exam-
\n
ple, green certificates, energy efficiency certificates and
\n
European CO
\n
2
\n
emissions allowances and guarantees of
\n
origin and renewable energy certificates) not used for
\n
compliance in the reporting period. These inventories are
\n
allocated to different portfolios, distinguishing between
\n
those held for trading or non-trading purposes. For more
\n
details on inventories, please see note 58 \u201cEnvironmental
\n
programs\u201d.
\n

\n\n\n\n\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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag52": { "value": "\n
Inventories include environmental certificates (for exam-
\n
ple, green certificates, energy efficiency certificates and
\n
European CO
\n
2
\n
emissions allowances and guarantees of
\n
origin and renewable energy certificates) not used for
\n
compliance in the reporting period. These inventories are
\n
allocated to different portfolios, distinguishing between
\n
those held for trading or non-trading purposes. For more
\n
details on inventories, please see note 58 \u201cEnvironmental
\n
programs\u201d.
\n

\n\n\n\n\n

\n\n
Environmental certificates
\n
In the absence of specific IAS/IFRS rules, the accounting
\n
treatment adopted by the Group complies with the gen-
\n
eral rules included in the body of applicable IAS/IFRS ac-
\n
counting standards and with international best practice.
\n
In particular, the Group accounting treatment of envi-
\n
ronmental certificates reflects the business model of the
\n
entities involved and, therefore, the different features of
\n
the business conducted by these entities, distinguishing
\n
between those that generate electricity from renewable
\n
sources, obligated parties, traders and other entities that
\n
operate in the energy services sector even though they
\n
are not obligated parties.
\n
Further details on the application of this accounting model
\n
are provided in note 58 \u201cEnvironmental programs\u201d.
\n

\n\n\n\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmissionRightsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag53": { "value": "\n

\n
Financial instruments
\n
Financial instruments are recognized and measured in ac-
\n
cordance with \u201cIAS 32 - Financial Instruments: Presenta-
\n
tion\u201c and \u201cIFRS 9 - Financial Instruments\u201c.
\n
A financial asset or liability is recognized in the consolidated
\n
financial statements when, and only when, the Group be-
\n
comes party to the contractual provision of the instrument
\n
(i.e. the trade date).
\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 mea-
\n
sured 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:
\n
\u2022
\n
the Group\u2019s business model for managing financial as-
\n
sets, that is the way in which the Group manages its
\n
financial assets in order to generate cash flows (i.e. col-
\n
lecting contractual cash flows, selling the financial as-
\n
sets, or both); and
\n
\u2022
\n
the contractual cash flow characteristics of the instru-
\n
ment, to determine whether the instrument gives rise
\n
to cash flows that are solely payments of principal and
\n
interest based on the SPPI test.
\n
For purposes of subsequent measurement, financial as-
\n
sets are classified in four categories:
\n
\u2022
\n
financial assets measured at amortized cost (debt in-
\n
struments);
\n
\u2022
\n
financial assets at fair value through OCI with reclas-
\n
sification of cumulative gains and losses (debt instru-
\n
ments);
\n
\u2022
\n
financial assets designated at fair value through OCI
\n
with no reclassification of cumulative gains and losses
\n
upon derecognition (equity instruments); and
\n
\u2022
\n
financial assets at fair value through profit or loss.
\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
\n
are 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\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 Debt instruments
\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
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 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 re-
\n
classified to profit or loss. The Group may transfer the cu-
\n
mulative gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n

\n\n\n\n

\n\n\n\n

\n

\n\n\n\n\n

\n

\n\n

\n

\n

\n\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of
\n
the cost of the investment.
\n

\n\n\n\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes:
\n
\u2022
\n
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
\n
financial assets held for trading because acquired or
\n
held principally for the purpose of selling or repurchas-
\n
ing in the short term (i.e. securities, financial invest-
\n
ments in funds, etc.);
\n
\u2022
\n
derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments;
\n
\u2022
\n
financial assets that qualify as contingent consider-
\n
ation.
\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 equity investments which the
\n
Group had not irrevocably elected to classify at fair value
\n
through OCI. Dividends on such investments are also rec-
\n
ognized as other income in the income statement when
\n
the right of payment has been established.
\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\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
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

\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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\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 mainly
\n
include:
\n
\u2022
\n
financial liabilities held for trading incurred for the pur-
\n
pose of repurchasing in the near term;
\n
\u2022
\n
derivative financial instruments entered into by the
\n
Group that are not designated as hedging instruments
\n
in hedge relationships as defined by IFRS 9;
\n
\u2022
\n
financial liabilities that qualify as contingent consider-
\n
ation.
\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
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\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

\n\n

\n\n

\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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\n\n

\n\n
Derivative financial instruments
\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 profit
\n
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 current
\n
on the basis of their maturity date and the Group intention
\n
to hold the financial instrument till maturity or not.
\n
For more details on derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n\n

\n\n\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
\u201dhost contract\u201d) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows. Embedded derivatives are
\n
separated from the host contract and accounted for as
\n
derivatives when:
\n
\u2022
\n
the host contract is not a financial instrument mea-
\n
sured at fair value through profit or loss;
\n
\u2022
\n
the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the
\n
host contract;
\n
\u2022
\n
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
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
The main Group contracts that may contain embedded de-
\n
rivatives are contracts to buy or sell energy commodities.
\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, in
\n
accordance with 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
\n
for the purpose of the physical settlement;
\n
\u2022
\n
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
\n
they can be settled net in cash; and
\n
\u2022
\n
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
\n
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
\n
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

\n

\n\n\n\n

\n\n\n\n\n

\n\n
Offsetting of financial assets and liabilities
\n
The Group offsets financial assets and liabilities when it:
\n
\u2022
\n
currently has a legally enforceable right to set off the
\n
recognized amounts; and
\n
\u2022
\n
intends either to settle on a net basis, or to realize the
\n
asset and settle the liability simultaneously.
\n

\n\n\n\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag54": { "value": "\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
\n
are 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\n\n
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 Debt instruments
\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
Financial assets at fair value through other
\n
comprehensive income (FVOCI) \u2013 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 re-
\n
classified to profit or loss. The Group may transfer the cu-
\n
mulative gain or loss within equity.
\n
Equity instruments designated at fair value through OCI
\n
are not subject to impairment testing.
\n

\n\n\n\n

\n\n\n\n

\n

\n

\n\n
Dividends on such investments are recognized in profit or
\n
loss unless they clearly represent a recovery of a part of
\n
the cost of the investment.
\n

\n\n\n\n\n
Financial assets at fair value through profit or loss
\n
This category mainly includes:
\n
\u2022
\n
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
\n
financial assets held for trading because acquired or
\n
held principally for the purpose of selling or repurchas-
\n
ing in the short term (i.e. securities, financial invest-
\n
ments in funds, etc.);
\n
\u2022
\n
derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments;
\n
\u2022
\n
financial assets that qualify as contingent consider-
\n
ation.
\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 equity investments which the
\n
Group had not irrevocably elected to classify at fair value
\n
through OCI. Dividends on such investments are also rec-
\n
ognized as other income in the income statement when
\n
the right of payment has been established.
\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\n

\n

\n\n\n\n

\n

\n\n\n\n

\n

\n\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
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\n\n\n\n

\n\n\n\n

\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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
Derivative financial instruments
\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 profit
\n
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 current
\n
on the basis of their maturity date and the Group intention
\n
to hold the financial instrument till maturity or not.
\n
For more details on derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag55": { "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
\n
are 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\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\n

\n

\n\n\n\n

\n

\n\n\n\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag56": { "value": "\n
Financial assets at fair value through profit or loss
\n
This category mainly includes:
\n
\u2022
\n
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
\n
financial assets held for trading because acquired or
\n
held principally for the purpose of selling or repurchas-
\n
ing in the short term (i.e. securities, financial invest-
\n
ments in funds, etc.);
\n
\u2022
\n
derivatives, including separated embedded derivatives,
\n
held for trading or not designated as effective hedging
\n
instruments;
\n
\u2022
\n
financial assets that qualify as contingent consider-
\n
ation.
\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 equity investments which the
\n
Group had not irrevocably elected to classify at fair value
\n
through OCI. Dividends on such investments are also rec-
\n
ognized as other income in the income statement when
\n
the right of payment has been established.
\n

\n\n\n\n
Financial liabilities at fair value through profit or loss
\n
Financial liabilities at fair value through profit or loss mainly
\n
include:
\n
\u2022
\n
financial liabilities held for trading incurred for the pur-
\n
pose of repurchasing in the near term;
\n
\u2022
\n
derivative financial instruments entered into by the
\n
Group that are not designated as hedging instruments
\n
in hedge relationships as defined by IFRS 9;
\n
\u2022
\n
financial liabilities that qualify as contingent consider-
\n
ation.
\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, in
\n
accordance with 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
\n
for the purpose of the physical settlement;
\n
\u2022
\n
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
\n
they can be settled net in cash; and
\n
\u2022
\n
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
\n
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
\n
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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag57": { "value": "\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
The impairment model adopted by the Group in compli-
\n
ance with IFRS 9 is based on the determination of expect-
\n
ed credit losses (ECL) using a forward-looking approach.
\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 recog-
\n
nition.
\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.
\n
The Group applies the low credit risk exemption, avoiding
\n
the recognition of loss allowances at an amount equal to
\n
lifetime expected credit losses due to a significant increase
\n
in credit risk of debt securities at fair value through OCI,
\n
whose counterparty has a strong financial capacity to meet
\n
its contractual cash flow obligations (e.g., investment grade).
\n
For more information on the impairment of financial assets,
\n
please see note 48 \u201cFinancial instruments by category\u201d.
\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
\n
the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receiv-
\n
ables. This approach, based on an assessment of any
\n
significant increase in credit risk since initial recogni-
\n
tion, is performed comparing the PD at origination with
\n
PD at the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss
\n
allowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e. staging):
\n
\u2013
\n
12-month ECL, for financial assets for which there
\n
has not been a significant increase in credit risk
\n
since initial recognition;
\n
\u2013
\n
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
\n
the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a signifi-
\n
cant financing component, based on lifetime ECL with-
\n
out 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
\n
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
\n
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
\n
right to cash flows is legally or contractually extinguished,
\n
transferred or expired).
\n

\n

\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag58": { "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\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag59": { "value": "\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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\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 mainly
\n
include:
\n
\u2022
\n
financial liabilities held for trading incurred for the pur-
\n
pose of repurchasing in the near term;
\n
\u2022
\n
derivative financial instruments entered into by the
\n
Group that are not designated as hedging instruments
\n
in hedge relationships as defined by IFRS 9;
\n
\u2022
\n
financial liabilities that qualify as contingent consider-
\n
ation.
\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
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\n\n\n\n

\n\n\n\n

\n\n\n\n

\n\n

\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag60": { "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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\n

\n\n\n\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag61": { "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 val-
\n
ue adjusted for directly attributable transaction costs. Fi-
\n
nancial liabilities are subsequently measured at amortized
\n
cost using the effective interest rate method. The effective
\n
interest rate is the rate that exactly discounts the estimat-
\n
ed future cash payments or receipts over the expected
\n
life of the financial instrument or a shorter period, where
\n
appropriate, to the carrying amount of the financial asset
\n
or liability.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag62": { "value": "\n
Derecognition of financial assets and liabilities
\n
Financial assets are derecognized whenever one of the
\n
following conditions is met:
\n
\u2022
\n
the contractual right to receive the cash flows associat-
\n
ed with the asset expires;
\n
\u2022
\n
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
\n
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

\n\n\n\n
On derecognition of a financial asset, the Group recog-
\n
nizes the difference between the carrying amount (mea-
\n
sured at the date of derecognition) and the consideration
\n
received through profit or loss.
\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 anoth-
\n
er from the same lender on substantially different terms,
\n
or the terms of an existing liability are substantially mod-
\n
ified, 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:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag63": { "value": "\n

\n\n
Derivative financial instruments
\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 profit
\n
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 current
\n
on the basis of their maturity date and the Group intention
\n
to hold the financial instrument till maturity or not.
\n
For more details on derivatives and hedge accounting,
\n
please see note 51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag64": { "value": "\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
\u201dhost contract\u201d) and gives rise to some or all of the com-
\n
bined contract\u2019s cash flows. Embedded derivatives are
\n
separated from the host contract and accounted for as
\n
derivatives when:
\n
\u2022
\n
the host contract is not a financial instrument mea-
\n
sured at fair value through profit or loss;
\n
\u2022
\n
the economic risks and characteristics of the embed-
\n
ded derivative are not closely related to those of the
\n
host contract;
\n
\u2022
\n
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
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
The main Group contracts that may contain embedded de-
\n
rivatives are contracts to buy or sell energy commodities.
\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, in
\n
accordance with 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
\n
for the purpose of the physical settlement;
\n
\u2022
\n
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
\n
they can be settled net in cash; and
\n
\u2022
\n
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
\n
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
\n
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

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag65": { "value": "\n
Offsetting of financial assets and liabilities
\n
The Group offsets financial assets and liabilities when it:
\n
\u2022
\n
currently has a legally enforceable right to set off the
\n
recognized amounts; and
\n
\u2022
\n
intends either to settle on a net basis, or to realize the
\n
asset and settle the liability simultaneously.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOffsettingOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag66": { "value": "\n

\n

\n
Non-current assets (or disposal groups)
\n
classified as held for sale and discontinued
\n
operations
\n\n
Pursuant to IFRS 5, non-current assets (or disposal groups)
\n
are classified as held for sale if their carrying amount will
\n
be recovered principally through a sale transaction, rather
\n
than through 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
For more details on the requirements for determining
\n
whether a sale is highly probable, please see note 2.1 \u201cUse
\n
of estimates and management judgment\u201d.
\n
If the Group is committed to a sale program involving loss
\n
of control of a subsidiary and the requirements provid-
\n
ed for under IFRS 5 are met, all the assets and liabilities
\n
of that subsidiary are classified as held for sale when the
\n
classification criteria are met, regardless of whether the
\n
Group will retain a non-controlling interest in its former
\n
subsidiary after the sale.
\n
The Group applies these classification criteria as envis-
\n
aged in IFRS 5 to an investment, or a portion of an invest-
\n
ment, in an associate or a joint venture. Any retained por-
\n
tion of an investment in an associate or a joint venture that
\n
has not been classified as held for sale is accounted for
\n
using the equity method until disposal of the portion that
\n
is classified 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
separately from other assets and liabilities in the consoli-
\n
dated statement 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 dispos-
\n
al groups) classified as held for sale are measured at the
\n
lower of their carrying amount and fair value less costs to
\n
sell. Impairment losses for any initial or subsequent write-
\n
down of the assets (or disposal groups) to fair value less
\n
costs to sell and gains for their reversals are recognized in
\n
profit or 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

\n

\n\n\n\n\n
If a component of the Group is a discontinued operation,
\n
the Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022
\n
the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022
\n
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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag67": { "value": "\n
Pursuant to IFRS 5, non-current assets (or disposal groups)
\n
are classified as held for sale if their carrying amount will
\n
be recovered principally through a sale transaction, rather
\n
than through 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
For more details on the requirements for determining
\n
whether a sale is highly probable, please see note 2.1 \u201cUse
\n
of estimates and management judgment\u201d.
\n
If the Group is committed to a sale program involving loss
\n
of control of a subsidiary and the requirements provid-
\n
ed for under IFRS 5 are met, all the assets and liabilities
\n
of that subsidiary are classified as held for sale when the
\n
classification criteria are met, regardless of whether the
\n
Group will retain a non-controlling interest in its former
\n
subsidiary after the sale.
\n
The Group applies these classification criteria as envis-
\n
aged in IFRS 5 to an investment, or a portion of an invest-
\n
ment, in an associate or a joint venture. Any retained por-
\n
tion of an investment in an associate or a joint venture that
\n
has not been classified as held for sale is accounted for
\n
using the equity method until disposal of the portion that
\n
is classified 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
separately from other assets and liabilities in the consoli-
\n
dated statement 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 dispos-
\n
al groups) classified as held for sale are measured at the
\n
lower of their carrying amount and fair value less costs to
\n
sell. Impairment losses for any initial or subsequent write-
\n
down of the assets (or disposal groups) to fair value less
\n
costs to sell and gains for their reversals are recognized in
\n
profit or 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

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag68": { "value": "\n
If a component of the Group is a discontinued operation,
\n
the Group presents, in a separate line item of the income
\n
statement, a single amount comprising the total of:
\n
\u2022
\n
the post-tax profit or loss of discontinued operations;
\n
and
\n
\u2022
\n
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", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag69": { "value": "\n
Environmental certificates
\n
In the absence of specific IAS/IFRS rules, the accounting
\n
treatment adopted by the Group complies with the gen-
\n
eral rules included in the body of applicable IAS/IFRS ac-
\n
counting standards and with international best practice.
\n
In particular, the Group accounting treatment of envi-
\n
ronmental certificates reflects the business model of the
\n
entities involved and, therefore, the different features of
\n
the business conducted by these entities, distinguishing
\n
between those that generate electricity from renewable
\n
sources, obligated parties, traders and other entities that
\n
operate in the energy services sector even though they
\n
are not obligated parties.
\n
Further details on the application of this accounting model
\n
are provided in note 58 \u201cEnvironmental programs\u201d.
\n

\n\n\n\n
58.2 Accounting policies
\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:
\n
\u2022
\n
any environmental certificates received free of charge
\n
and those self-produced as a result of Group\u2019s oper-
\n
ations that will be used for compliance purposes are
\n
recognized at nominal value (nil);
\n
\u2022
\n
charges incurred for obtaining (in the market or in
\n
some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the
\n
reporting period are recognized through profit or loss
\n
under other operating costs, as they represent \u201csystem
\n
charges\u201d consequent to compliance with a regulatory
\n
requirement;
\n
\u2022
\n
if the number of environmental certificates available at
\n
the reporting date is not sufficient to fulfill the related
\n
obligation (a certificate \u201cdeficit\u201d), a provision is accrued
\n
under \u201cprovisions for risks and charges\u201d. Conversely,
\n
any \u201csurplus\u201d of certificates purchased at the reporting
\n
date is recognized in \u201cinventories\u201d in accordance with
\n
the general principles referred to in note 2.2 \u201cMaterial
\n
accounting policies\u201d.
\n
Some types of environmental certificates accrue in pro-
\n
portion to:
\n
\u2022
\n
electricity generated by plants that use renewable re-
\n
sources (for example, guarantees of origin and renew-
\n
able energy certificates);
\n
\u2022
\n
energy savings certified by the competent authority
\n
(energy efficiency certificates).
\n
In these cases, the right to obtain such certificates can be
\n
treated as a non-monetary government operating grant
\n
and, as such, the Group recognizes that right at fair value
\n
under \u201cother non-current/current non-financial assets\u201d.
\n
When the certificates are credited to the ownership ac-
\n
count, they are reclassified from other assets to invento-
\n
ries.
\n
The corresponding income is recognized under other op-
\n
erating profit.
\n
For Group companies involved in trading activities, envi-
\n
ronmental certificates represent goods exchanged as part
\n
of their normal business activity and, as such, the pur-
\n
chased certificates are recognized under \u201cservices and
\n
other materials\u201d.
\n
Revenue from the sale of such certificates is recognized
\n
under \u201crevenue\u201d, with a corresponding decrease in inven-
\n
tories.
\n
Contracts for the purchase or sale of environmental cer-
\n
tificates settled at a future date (for example, forward con-
\n
tracts, etc.) that comply with the definition of derivative are
\n
recognized and measured in accordance with the \u201cown
\n
use exemption\u201d, at fair value through profit or loss, or with
\n
hedge accounting rules based on specific circumstanc-
\n
es. For further details, please see note 51 \u201cDerivatives and
\n
hedge accounting\u201d.
\n
\n
\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEnvironmentRelatedExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag70": { "value": "\n

\n

\n
Employee benefits
\n
Post-employment and other long-term benefits
\n
Pursuant to IAS 19, the Group determines separately for
\n
each plan liabilities related to employee benefits paid upon
\n
or after ceasing employment or other long-term benefits
\n
accrued during the employment period. The Group uses
\n
actuarial assumptions to estimate the amount of the fu-
\n
ture benefits that employees have accrued at the report-
\n
ing date (using the projected unit credit method) and an
\n
appropriate discount rate to determine the present value
\n
of those plans.
\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 actuar-
\n
ies.
\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 Group recognizes the cumulative actuarial gains and
\n
losses from the actuarial measurement of the liabilities,
\n
the return on the plan assets (net of the associated in-
\n
terest income) and the effect of the asset ceiling (net of
\n
the associated interest) in other comprehensive income
\n
when they occur. For other long-term benefits, the re-
\n
lated actuarial gains and losses are recognized through
\n
profit or loss.
\n
In addition, the Group is involved in defined contribution
\n
plans under which it pays fixed contributions to a sepa-
\n
rate entity (a fund) and has no legal or constructive ob-
\n
ligation to pay further contributions if the fund does not
\n
hold sufficient assets to pay all employee benefits relating
\n
to employee service in the current and prior periods. Such
\n
plans are usually aimed to supplement pension benefits
\n
due to employees post-employment. The related costs
\n
are recognized through profit or loss on the basis of the
\n
amount of contributions paid in the period.
\n\n
Termination benefits
\n
Pursuant to IAS 19, liabilities for benefits due to employees
\n
for the early termination of employee service arise out of
\n
the Group\u2019s decision to terminate an employee\u2019s employ-
\n
ment before the normal retirement date or an employee\u2019s
\n
decision to accept an offer of benefits in exchange for the
\n
termination of employment.
\n
Termination
\n
benefits are recognized at the earlier of the
\n
following dates:
\n
\u2022
\n
when the entity can no longer withdraw its offer of
\n
benefits; and
\n
\u2022
\n
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.
\n

\n

\n

\n\n\n\n\n
Share-based payments
\n
The Group undertakes share-based payment transac-
\n
tions settled with equity instruments as part of the remu-
\n
neration policy adopted for the Chief Executive Officer/
\n
General 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 a
\n
monetary component (paid in cash), which will accrue if
\n
specific conditions are met.
\n
Pursuant to IFRS 2, the Group classifies the monetary
\n
component as a cash-settled transaction if it is based on
\n
the price (or value) of the equity instruments of the com-
\n
pany that issued the plan or, in other cases, as another
\n
long-term employee benefit.
\n
In order to settle the equity component through the bo-
\n
nus award of Enel shares, a program for the purchase of
\n
treasury shares to support these plans was approved. For
\n
more details on share-based incentive plans, please see
\n
note 53 \u201cShare-based payments\u201d.
\n
In particular for the equity component, the Group recog-
\n
nizes the services rendered by employees as personnel
\n
expenses over the period in which the conditions for re-
\n
maining in service and for achieving certain results must
\n
be satisfied (vesting period) and indirectly estimates their
\n
value, and the corresponding increase in a specific equity
\n
item, on the basis of the fair value of the equity instru-
\n
ments (i.e. the issuer shares) at the grant date.
\n
The overall expense recognized is adjusted at each re-
\n
porting date until the vesting date to reflect the best
\n
estimate available to the Group of the number of equity
\n
instruments for which the service and performance con-
\n
ditions other than market conditions or non-vesting con-
\n
ditions will be satisfied at the end of the vesting period.
\n
Conversely, if the incentive based on equity instruments is
\n
paid in cash, the Group recognizes the services rendered
\n
by employees as personnel expenses over the vesting
\n
period and a corresponding liability measured at the fair
\n
value of the liability incurred. Subsequently, and until its
\n
extinction, the liability is remeasured at fair value at each
\n
reporting date, considering the best possible estimate of
\n
the incentive that will vest, with changes in fair value rec-
\n
ognized under personnel expenses.
\n

\n\n\n\n

\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag71": { "value": "\n
Termination benefits
\n
Pursuant to IAS 19, liabilities for benefits due to employees
\n
for the early termination of employee service arise out of
\n
the Group\u2019s decision to terminate an employee\u2019s employ-
\n
ment before the normal retirement date or an employee\u2019s
\n
decision to accept an offer of benefits in exchange for the
\n
termination of employment.
\n
Termination
\n
benefits are recognized at the earlier of the
\n
following dates:
\n
\u2022
\n
when the entity can no longer withdraw its offer of
\n
benefits; and
\n
\u2022
\n
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.
\n

\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTerminationBenefits", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag72": { "value": "\n
Share-based payments
\n
The Group undertakes share-based payment transac-
\n
tions settled with equity instruments as part of the remu-
\n
neration policy adopted for the Chief Executive Officer/
\n
General 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 a
\n
monetary component (paid in cash), which will accrue if
\n
specific conditions are met.
\n
Pursuant to IFRS 2, the Group classifies the monetary
\n
component as a cash-settled transaction if it is based on
\n
the price (or value) of the equity instruments of the com-
\n
pany that issued the plan or, in other cases, as another
\n
long-term employee benefit.
\n
In order to settle the equity component through the bo-
\n
nus award of Enel shares, a program for the purchase of
\n
treasury shares to support these plans was approved. For
\n
more details on share-based incentive plans, please see
\n
note 53 \u201cShare-based payments\u201d.
\n
In particular for the equity component, the Group recog-
\n
nizes the services rendered by employees as personnel
\n
expenses over the period in which the conditions for re-
\n
maining in service and for achieving certain results must
\n
be satisfied (vesting period) and indirectly estimates their
\n
value, and the corresponding increase in a specific equity
\n
item, on the basis of the fair value of the equity instru-
\n
ments (i.e. the issuer shares) at the grant date.
\n
The overall expense recognized is adjusted at each re-
\n
porting date until the vesting date to reflect the best
\n
estimate available to the Group of the number of equity
\n
instruments for which the service and performance con-
\n
ditions other than market conditions or non-vesting con-
\n
ditions will be satisfied at the end of the vesting period.
\n
Conversely, if the incentive based on equity instruments is
\n
paid in cash, the Group recognizes the services rendered
\n
by employees as personnel expenses over the vesting
\n
period and a corresponding liability measured at the fair
\n
value of the liability incurred. Subsequently, and until its
\n
extinction, the liability is remeasured at fair value at each
\n
reporting date, considering the best possible estimate of
\n
the incentive that will vest, with changes in fair value rec-
\n
ognized under personnel expenses.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag73": { "value": "\n
Provisions for risks and charges
\n
Pursuant to IAS 37, provisions are recognized where there
\n
is a legal or constructive obligation as a result of a past
\n
event at the end of the reporting period, the settlement
\n
of which is expected to result in an outflow of resourc-
\n
es whose amount can be reliably estimated. Where the
\n

\n\n\n\n

\n
impact of the time value of money is material, the accru-
\n
als are determined by discounting expected future cash
\n
flows using a pre-tax discount rate that reflects the cur-
\n
rent market assessment of the time value of money and, if
\n
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
\n
financial 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, the
\n
initial recognition of the provision is made against the relat-
\n
ed asset and the expense is then recognized in profit or loss
\n
through the depreciation of the asset involved.
\n
Where the liability regards the treatment and storage of nu-
\n
clear waste and other radioactive materials, the provision is
\n
recognized against the related operating costs.
\n

\n\n\n\n
A liability for restructuring refers to a program planned and
\n
controlled by management that materially changes the
\n
scope of a business undertaken by the Group or the man-
\n
ner in which the business is conducted. Such a liability is
\n
recognized when a constructive obligation is established,
\n
i.e. when the Group has approved a detailed formal restruc-
\n
turing plan and has started to implement the plan or has
\n
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 ser-
\n
vice in addition to the assurance that the product com-
\n
plies 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, rec-
\n
ognizing the contract liability as revenue over the period
\n
the warranty service is provided and the costs associated
\n
as they are incurred.
\n
Finally, 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
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
\n
restoration resulting from changes in the timetable and
\n
costs necessary to extinguish the obligation or from a
\n
change in the discount rate. These changes increase or
\n
decrease the carrying amount of the related assets and
\n
are taken to profit or loss through depreciation. Where
\n
they increase the carrying amount of the assets, it is also
\n
determined whether the new carrying amount of the as-
\n
sets is fully recoverable. If this is not the case, a loss equal
\n
to the unrecoverable amount is recognized through profit
\n
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
\n
of property, plant and equipment, especially those asso-
\n
ciated with decommissioning nuclear power plants and
\n
storage of waste fuel and other radioactive materials,
\n
please see note 2.1 \u201cUse of estimates and management
\n
judgment\u201d.
\n

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag74": { "value": "\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
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
\n
identify the contract with the customer;
\n
\u2022
\n
identify the performance obligations in the contract,
\n
that is, all goods or services promised in the contract;
\n\n
\u2022
\n
determine the transaction price at inception of the
\n
contract considering any variable considerations, non-
\n
cash consideration received from a customer or pay-
\n
able to the customer, significant financing components;
\n

\n\n\n\n
\u2022
\n
allocate the transaction price, at contract inception, to
\n
each separate performance obligation;
\n
\u2022
\n
recognize revenue, when (or as) each performance obli-
\n
gation is satisfied by transferring the promised good or
\n
service to the customer.
\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 rec-
\n
ognition model is provided in note 2.1 \u201cUse of estimates
\n

\n\n\n\n
and management judgment\u201d and in note 11.a \u201cRevenue
\n
from sales and services\u201d.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag75": { "value": "\n
\u2022
\n
determine the transaction price at inception of the
\n
contract considering any variable considerations, non-
\n
cash consideration received from a customer or pay-
\n
able to the customer, significant financing components;
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDiscountsAndRebatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag76": { "value": "\n
\u2022
\n
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
\u2022
\n
changes in the fair value of settled contracts to sell en-
\n
ergy commodities with physical settlement, which do
\n
not qualify for the own use exemption and therefore
\n
are recognized at FVTPL in accordance with IFRS 9;
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradingIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag77": { "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
Pursuant to IAS 20, government grants, including
\n
non-monetary grants at fair value, are recognized where
\n
there is reasonable assurance that they will be received
\n
and that the Group will comply with all conditions attach-
\n
ing to them as set by the government, government agen-
\n
cies and similar bodies whether local, national or interna-
\n
tional.
\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 mea-
\n
sured in accordance with the requirements for financial
\n
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 intend-
\n
ed to compensate.
\n
A government grant received to compensate for costs or
\n
losses already incurred, or for the purpose of providing
\n
immediate financial support to the Group without related
\n
future costs, is recognized as income in the year in which
\n
it becomes enforceable.
\n
When government grants are received to purchase, build
\n
or otherwise acquire non-current assets (for example, an
\n
item of property, plant and equipment or an intangible as-
\n
set), they are deducted from the carrying amount of the
\n
asset and are recognized in profit or loss over the depre-
\n
ciable/amortizable life of the asset as a reduction in the
\n
depreciation/amortization charge. If there is insufficient
\n
information to enable adequate attribution to the fixed
\n
assets to which they refer, capital grants are recognized
\n
as deferred income under other liabilities, and credited to
\n
profit or loss on a systematic basis over the useful life of
\n
the asset. If a government grant is made in a period sub-
\n
sequent to that in which the depreciation of the assets
\n
began, the portion of the grant corresponding to the de-
\n
preciation recognized in previous periods is recognized
\n
directly in profit or loss.
\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

\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGovernmentGrants", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag78": { "value": "\n
Net results from commodity contracts
\n
The net results from commodity contracts include:
\n
\u2022
\n
the net income or expense from commodity deriv-
\n
atives, including derivatives designated as cash flow
\n
hedges and derivatives measured at fair value through
\n
profit or loss, whether settled or outstanding at the re-
\n
porting date; and
\n
\u2022
\n
the net gain/(loss) from the measurement through prof-
\n
it or loss of energy commodity contracts with physical
\n
settlement still outstanding at the reporting date.
\n

\n\n\n", "dimensions": { "concept": "enel:AccountingPolicyofNetResultsFromCommodityContracts", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag79": { "value": "\n
Dividends
\n
Pursuant to \u201cIFRS 9 - Financial Instruments\u201c, dividends are
\n
recognized when the unconditional right to receive pay-
\n
ment is established.
\n
Dividends and interim dividends payable to the Parent\u2019s
\n
shareholders and non-controlling interests are recog-
\n
nized as changes in equity in the period in which they are
\n
approved by the Shareholders\u2019 Meeting and the Board of
\n
Directors, respectively.
\n

\n\n\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag80": { "value": "\n
Income taxes
\n
IAS 12 specifies the requirements for the recognition of
\n
current and deferred tax assets and liabilities. The uncer-
\n
tainty in the determination of tax liabilities is defined in
\n
accordance with the provisions of \u201cIFRIC 23 - Uncertainty
\n
over Income Tax Treatments\u201c.
\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 enact-
\n
ed by the end of the reporting period in the countries where
\n
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\n\n\n

\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: (i)
\n
from the initial recognition of goodwill; or (ii) from the
\n
initial recognition of an asset or a liability in a transaction
\n
which is not a business combination and, at the time of
\n
the transaction, affects neither accounting profit nor tax-
\n
able profit (tax loss); and does not give rise to equal taxable
\n
and deductible temporary differences; or (iii) in respect
\n
of taxable temporary differences associated with invest-
\n
ments in subsidiaries, associates and joint ventures, when
\n
the Group can control the timing of the reversal of the
\n
temporary differences and it is probable that the tempo-
\n
rary differences 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 eq-
\n
uity.
\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\n\n
Uncertainty over income tax treatments
\n
In defining \u201cuncertainty\u201c, 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\u201c is
\n
defined as \u201cmore likely than not\u201c), 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 in-
\n
come tax purposes, the Group reflects the uncertainty in
\n
the manner that best predicts the resolution of the uncer-
\n
tain tax treatment.
\n
For more information on uncertainty over tax treatments,
\n
please see note 2.1 \u201cUse of estimates and management
\n
judgment\u201d.
\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:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag81": { "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: (i)
\n
from the initial recognition of goodwill; or (ii) from the
\n
initial recognition of an asset or a liability in a transaction
\n
which is not a business combination and, at the time of
\n
the transaction, affects neither accounting profit nor tax-
\n
able profit (tax loss); and does not give rise to equal taxable
\n
and deductible temporary differences; or (iii) in respect
\n
of taxable temporary differences associated with invest-
\n
ments in subsidiaries, associates and joint ventures, when
\n
the Group can control the timing of the reversal of the
\n
temporary differences and it is probable that the tempo-
\n
rary differences 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 eq-
\n
uity.
\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\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag82": { "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, 2023.
\n
\u2022
\n
\u201cAmendments to IAS 1 and IFRS Practice Statement 2
\n
\u2013 Disclosure of Accounting Policies\u201d, issued in February
\n
2021. The amendments are intended to provide support
\n
in deciding which policies to disclose. In this regard:
\n
\u2013
\n
the amendments to \u201cIAS 1 - Presentation of Finan-
\n
cial Statements\u201d require disclosures of \u201cmaterial\u201d
\n
accounting policies rather than \u201csignificant\u201d policies;
\n
\u2013
\n
the amendments to \u201cIFRS Practice Statement 2 -
\n
Making Materiality Judgements\u201d are intended to pro-
\n
vide guidance on how to apply the concept of mate-
\n
riality to accounting policy disclosures.
\n
In the absence of an IFRS definition of \u201csignificant\u201d in
\n
the context of disclosures on accounting policies, the
\n
term has been replaced with \u201cmaterial\u201d. The definition
\n
of material was modified in October 2018, and aligned
\n
with the IFRS and the Conceptual Framework and,
\n
therefore, is widely understood by primary users of fi-
\n
nancial statements. In accordance with IAS 1, informa-
\n
tion on accounting policies is material if, either individ-
\n
ually or in combination with other information, it could
\n
reasonably be expected to influence decisions that the
\n
primary users of the financial statements make on the
\n
basis of such financial statements. When assessing the
\n
materiality of the disclosures on accounting policies, it
\n
is appropriate to consider both the magnitude of the
\n
transactions, other events or conditions, and their na-
\n
ture. However, although a transaction, other event or
\n
condition to which the disclosures on accounting poli-
\n
cies refer may be material, this does not imply that the
\n
corresponding information is material for the purposes
\n
of the financial statements. In this context, the amend-
\n
ments to the IFRS Practice Statement 2 seek to provide
\n
guidance on how to determine whether disclosure of
\n
an accounting policy is material for financial statement
\n
purposes. These amendments aim to: (i) clarify that
\n
materiality judgments about disclosures of accounting
\n
policies should follow the same guidance in materiality
\n
judgments about other information, therefore consid-
\n
ering both qualitative and quantitative factors; (ii) un-
\n
derscore the importance of providing information on
\n
accounting policies that is specific to the Group; and (iii)
\n
provide examples of situations where generic or stan-
\n
dardized information, although summarizing or dupli-
\n
cating the requirements of the IFRS, can be considered
\n
disclosure of material accounting policies.
\n
The disclosures on accounting policies have been re-
\n
vised in line with the requirements established by the
\n
amendments and have been updated in note 2.2 \u201cMa-
\n
terial accounting policies\u201d.
\n
\u2022
\n
\u201cAmendments to IAS 8 \u2013 Definition of Accounting Es-
\n
timates\u201d, issued in February 2021.
\n
The amendments
\n
clarify how companies should distinguish changes in
\n
accounting policies from changes in accounting es-
\n
timates. The definition of changes in accounting esti-
\n
mates has been replaced with a definition of account-
\n
ing estimates as \u201cmonetary amounts in financial state-
\n
ments that are subject to measurement uncertainty\u201d. In
\n
order to clarify the interaction between an accounting
\n
policy and an accounting estimate, IAS 8 has been
\n
amended to state that an accounting standard may re-
\n
quire certain financial statement items to be measured
\n
at monetary amounts that cannot be directly observed,
\n
and therefore must be estimated (since they involve
\n
uncertainty in the measurement). In such circumstanc-
\n
es, accounting estimates are developed to achieve the
\n
objective set out by the accounting policy, including
\n
the use of judgments and assumptions based on the
\n
latest available, reliable information. The amendments
\n
explain how measurement techniques and inputs must
\n
be used to develop accounting estimates and estab-
\n
lish that measurement techniques include estimation
\n
techniques. In order to provide greater guidance, the
\n
amendments clarify that the effects on an accounting
\n
estimate of a change in an input or a change in a mea-
\n
surement technique are changes in accounting esti-
\n
mates unless they result from the correction of prior
\n
period errors. Changes in accounting estimates result-
\n
ing from new information are not corrections of errors.
\n
The application of the amendments did not have a
\n
material impact on these consolidated financial state-
\n
ments.
\n
\u2022
\n
\u201cAmendments to IAS 12 - Income Taxes: Deferred Tax
\n
related to Assets and Liabilities arising from a Single
\n
Transaction\u201d, issued in May 2021. The amendments
\n
clarify that the exemption from initial recognition pro-
\n
vided for by the standard no longer applies to transac-
\n
tions that give rise to taxable and deductible temporary
\n
differences of the same amount.
\n
In general, the initial recognition exemption provided
\n
for by IAS 12 prohibits the recognition of deferred as-
\n
sets and liabilities in respect of the initial recognition
\n
of assets or liabilities in a transaction that does not
\n
constitute a business combination and affects neither
\n
accounting profit nor taxable profit. As illustrated, the
\n
amendments have narrowed the scope of the excep-
\n
tion.
\n
For transactions (e.g., leases and decommissioning li-
\n
abilities) subject to the amendments, the related de-
\n
ferred assets and liabilities shall be recognized from the
\n
beginning of the first comparative period presented,
\n
with any cumulative effect recognized as an adjustment
\n
\n\n
to retained earnings (or other components of equity)
\n
as at that date. In this regard, the application of the
\n
amendments did not produce a material impact on re-
\n
tained earnings in the opening equity of the Enel Group
\n
at January 1, 2022.
\n
\u2022
\n
\u201cAmendments to IAS 12 \u2013 International Tax Reform \u2013
\n
Pillar II Model Rules\u201d, issued in May 2023. The chang-
\n
es were introduced in response to the Pillar II rules is-
\n
sued by the OECD, the aim of which is to ensure that
\n
large multinational enterprises pay a minimum level of
\n
income tax, generated in a specific period, in each ju-
\n
risdiction in which they operate. In general, these rules
\n
require the application of a top-up tax that brings the
\n
total amount of taxes paid in each jurisdiction in which
\n
they operate to a minimum of 15%.
\n
The changes introduced:
\n
\u2013
\n
a mandatory temporary exception to the accounting
\n
for and disclosure of deferred tax assets and liabil-
\n
ities arising from the implementation of the Pillar II
\n
rules; and
\n
\u2013
\n
disclosure requirements to help users of the finan-
\n
cial statements better understand an entity\u2019s expo-
\n
sure to income taxes arising from the rule.
\n
In particular, for periods in which Pillar II legislation is
\n
enacted but not yet in effect, the entity shall disclose
\n
qualitative information (such as information regarding
\n
how the entity is affected by Pillar II rules and the main
\n
jurisdictions in which exposures might exist) and quan-
\n
titative information (such as indicating the portion of
\n
profits that could be subject to Pillar II income taxes and
\n
the average effective tax rate applicable to such profits;
\n
or indicating how the entity\u2019s average effective tax rate
\n
would have changed if Pillar II legislation had been in
\n
effect).
\n
The Group has adopted the mandatory temporary ex-
\n
ception to the recognition of deferred taxation, which
\n
applies retrospectively. However, since as at December
\n
31, 2022 no new rule for the application of the top-up
\n
tax had yet been issued in any jurisdiction in which the
\n
Group operates and no related deferred tax had been
\n
recognized as of that date, retrospective application
\n
has had no impact on the Group\u2019s consolidated finan-
\n
cial statements.
\n
For more information on the disclosure requirements,
\n
please see note 4 \u201cMinimum tax\u201c.
\n
\u2022
\n
\u201cIFRS 17 \u2013 Insurance Contracts\u201d, issued in May 2017. The
\n
new standard was issued by the IASB to replace IFRS
\n
4, defining the principles for the recognition, mea-
\n
surement, presentation and disclosure of insurance
\n
contracts, including reinsurance contracts issued and
\n
held and investment contracts with discretionary par-
\n
ticipation features. The standard applies to insurance
\n
contracts compliant with the definition of IFRS 17, re-
\n
gardless of the issuer, but includes various exceptions
\n
and exemption options that allow certain types of con-
\n
tracts that meet the definition of insurance contract to
\n
be accounted for by applying another standard. Based
\n
on the analysis performed, the new standard has had
\n
no impact on the Group\u2019s consolidated financial state-
\n
ments.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag83": { "value": "\n
5. Argentina \u2013 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 \u2013 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, 2023, 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 2023 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 curren-
\n
cy (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, 2023 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
From January 1, 2023 to December 31, 2023 222.01%
\n
In 2023, the application of IAS 29 generated net financial in-
\n
come (gross of tax) of \u20ac284 million.
\n
The following tables report the effects of IAS 29 on the bal-
\n
ance at December 31, 2023 and the impact of hyperinflation
\n
on the main income statement items for 2023, 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
\n
hyperinflation effect
\n
at Dec. 31, 2022
\n
Hyperinflation effect
\n
for the period Exchange differences
\n
Change in the
\n
consolidation scope
\n
for disposal of entities
\n
Cumulative
\n
hyperinflation effect
\n
at Dec. 31, 2023
\n
Total assets 1,989 917 (1,567) (45) 1,294
\n
Total liabilities 555 314 (424) (7) 438
\n
Equity 1,434 603
\n
(1)
\n
(1,143) (38) 856
\n
(1) The figure includes profit for year equal to \u20ac110 million.
\n
Millions of euro
\n
IAS 29 effect IAS 21 effect Total effect at Dec. 31, 2023
\n
Revenue 278 (588) (310)
\n
Costs 352
\n
(1)
\n
(641)
\n
(2)
\n
(289)
\n
Operating profit (74) 53 (21)
\n
Net financial income/(expense) (39) 16 (23)
\n
Net income/(expense) from hyperinflation 284 - 284
\n
Pre-tax profit/(loss) 171 69 240
\n
Income taxes 61 126 187
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling
\n
interests)
\n
110 (57) 53
\n
Attributable to owners of the Parent 68 (83) (15)
\n
Attributable to non-controlling interests 42 26 68
\n
(1) Includes impact on depreciation, amortization and impairment losses of \u20ac55 million.
\n
(2) Includes impact on depreciation, amortization and impairment losses of \u20ac(27) million.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfHyperinflationaryReportingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag84": { "value": "\n
6. 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
\n
allocate capital to support a decarbonized electricity
\n
supply;
\n
\u2022
\n
enable the electrification of customers\u2019 energy de-
\n
mand;
\n
\u2022
\n
leverage the creation of value along the value chain;
\n
\u2022
\n
bring forward achievement of the sustainable \u201cnet-ze-
\n
ro\u201d 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 in July 2023,
\n
the Group provides explicit information in the notes to
\n
these consolidated financial statements regarding how
\n
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 associat-
\n
ed with climate change are addressed:
\n
Topic Note Content
\n
Estimates and judgments concerning
\n
climate change
\n
Note 2.1 \u201cUse of estimates and
\n
management judgment\u201d
\n
\u2022 Reference to management\u2019s use of estimates and judgments
\n
with regard to climate change (taking account of their
\n
materiality within financial reporting).
\n
\u2022 Focus on estimating expected cash flows from specific
\n
assets/CGUs (section: \u201cImpairment of non-financial assets\u201d).
\n
\u2022 Focus of the effects of the Group\u2019s commitments under the
\n
Paris Agreement and their impact on the estimation of the
\n
useful life of the assets involved (section \u201cDetermining the
\n
useful life of non-financial assets\u201d).
\n
Sustainable investment Note 19 \u201cProperty, plant and equipment\u201d
\n
\u2022 Focus on infrastructure associated with the development of
\n
the grid and investment in expanding the e-Mobility, e-City
\n
and e-Home businesses.
\n
Measurement of non-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
\n
Group in line with the Paris Agreement with regard to the
\n
measurement of non-financial assets, with particular regard
\n
to the residual useful life of certain assets and impairment
\n
testing.
\n
Provisions
\n
Note 40 \u201cProvisions for risks and
\n
charges\u201d
\n
\u2022 Focus on provisions for the impact of climate change on
\n
distribution grids and generation plants, including those
\n
for decommissioning and restoration of sites, and possible
\n
provisions for restructuring plans linked to the energy
\n
transition.
\n
Sustainability-linked finance at Enel
\n
Note 48.3 \u201cBorrowings\u201d
\n
Note 60 \u201cEvents after the reporting
\n
period\u201d
\n
\u2022 Focus on:
\n
\u2013 issues of sustainability-linked bonds connected with the
\n
achievement of sustainability objectives in line with the
\n
SDGs issued by the United Nations
\n
\u2013 green bonds used to finance specific sustainable Group
\n
projects and initiatives
\n
\u2013 sustainable loans connected with the achievement of the
\n
Sustainable Development Goals (SDGs).
\n
Share-based payments Note 53 \u201cShare-based payments\u201d
\n
\u2022 Description of long-term incentive plans anchored to
\n
achievement of specific climate-related targets.
\n
Environmental programs Note 58 \u201cEnvironmental programs\u201d
\n
\u2022 Description of costs relating to environmental compliance
\n
required by national and international regulations.
\n
\u2022 Description of costs generated by not having sufficient
\n
environmental certificates to meet environmental
\n
compliance regulations.
\n
\n", "dimensions": { "concept": "enel:DisclosureOfClimateChangeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag85": { "value": "\n
\n\n
7. Discontinued operations
\n
Within the \u201cEurope\u201d area, the Enel Group has decided to
\n
divest certain major business lines, particularly in Russia,
\n
Romania and Greece.
\n
Due to the fact that all discontinued assets represent a
\n
significant part of a geographical area in which the Group
\n
operates, the results relating to these assets have been
\n
classified in accordance with the provisions of IFRS 5 in a
\n
separate line of the consolidated income statement de-
\n
nominated \u201cProfit/(Loss) from discontinued operations\u201d.
\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 2023 and 2022.
\n
The items are shown net of intercompany transactions
\n
which have been completely eliminated.
\n
Millions of euro
\n
2023 2022 Change
\n
Revenue 2,535 3,543 (1,008)
\n
Costs 2,341 4,815 (2,474)
\n
Operating profit/(loss) 194 (1,272) 1,466
\n
Financial income/(expense) (62) (43) (19)
\n
Share of profit/(loss) of equity-accounted investments
\n
(1)
\n
58 83 (25)
\n
Pre-tax profit/(loss) from discontinued operations 190 (1,232) 1,422
\n
Income taxes 29 (52) 81
\n
Profit/(Loss) Russia, Greece and Romania 161 (1,180) 1,341
\n
Capital gains/(losses) from disposal of discontinued operations (532) (1,054) 522
\n
Profit/(Loss) from discontinued operations (371) (2,234) 1,863
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The breakdown by country is as follows.
\n
Millions of euro
\n
2023 Russia Greece Romania 2022
\n
(1)
\n
Russia
\n
(1)
\n
Greece Romania
\n
Total revenue 2,535 - 122 2,413 3,543 290 125 3,128
\n
Costs 2,126 - 75 2,051 3,585 243 70 3,272
\n
Impairment 215 - - 215 1,230 534 - 696
\n
Total costs 2,341 - 75 2,266 4,815 777 70 3,968
\n
Operating profit/(loss) 194 - 47 147 (1,272) (487) 55 (840)
\n
Financial income/(expense) (62) - (49) (13) (43) (9) (35) 1
\n
Share of profit/(loss) of equity-accounted
\n
investments
\n
58 58 - - 83 64 19 -
\n
Pre-tax profit/(loss) from discontinued
\n
operations
\n
190 58 (2) 134 (1,232) (432) 39 (839)
\n
Current income taxes 67 - 8 59 (15) 8 2 (25)
\n
Deferred income taxes (38) - - (38) (37) - - (37)
\n
Income taxes 29 - 8 21 (52) 8 2 (62)
\n
Profit/(Loss) Russia, Greece and Romania 161 58 (10) 113 (1,180) (440) 37 (777)
\n
Capital gains/(losses) from disposal of
\n
discontinued operations
\n
(532) (124) 262 (670) (1,054) (1,054) - -
\n
Profit/(Loss) from discontinued operations (371) (66) 252 (557) (2,234) (1,494) 37 (777)
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
\n\n
\n\n
\n\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 October 12, 2022, Enel SpA closed the sale of the en-
\n
tire stake held in PJSC Enel Russia. Upon completion of the
\n
sale, Enel sold all power generation assets in Russia, which
\n
include approximately 5.6 GW of conventional capacity
\n
and approximately 300 MW of wind capacity at various
\n
stages of development, ensuring continuity for its em-
\n
ployees and customers.
\n
Furthermore, on December 20, 2023, Enel SpA sold the
\n
entire stake it held in Rusenergosbyt LLC for \u20ac83 million.
\n
The operation had a negative impact of \u20ac124 million, of
\n
which \u20ac82 million related to the release of the translation
\n
reserve.
\n
Romania
\n
Following the agreements of December 14, 2022, Febru-
\n
ary 4, 2023 and March 9, 2023, on October 25, 2023 Enel
\n
SpA finalized the sale to the Greek company Public Power
\n
Corporation SA (PPC) of all the equity stakes held by Enel
\n
Group in Romania.
\n
In accordance with the terms of the agreement, PPC paid
\n
a total of \u20ac1,241 million. An earn-out mechanism is also
\n
foreseen concerning a potential further post-closing pay-
\n
ment, based on the future value of the retail business.
\n
The overall transaction had a negative impact on the
\n
Group\u2019s net profit of about \u20ac847 million, of which \u20ac655
\n
million reflecting the release of a currency translation re-
\n
serve, \u20ac15 million in respect of transaction costs connect-
\n
ed with the sale and the recognition of \u20ac177 million net of
\n
taxation in impairment losses on the assets prior to the
\n
sale.
\n
For more information, please see note 9 \u201cMain acquisi-
\n
tions and disposals during the year\u201d.
\n
Greece
\n
Following the agreement of July 26, 2023, on December
\n
29, 2023, Enel Green Power (EGP) finalized the sale of 50%
\n
of Enel Green Power Hellas (EGPH), EGP\u2019s fully-owned re-
\n
newable subsidiary in Greece, to Macquarie Asset Man-
\n
agement, acting through the Macquarie Green Investment
\n
Group Renewable Energy Fund 2, following the fulfillment
\n
of all the conditions customary for this type of transaction,
\n
including receipt of clearance from competent antitrust
\n
authorities.
\n
In line with the above agreement, the total price received
\n
by EGP was \u20ac351 million.
\n
Following the transaction\u2019s closing, EGP and Macquarie
\n
Asset Management entered into a shareholder agree-
\n
ment which envisages the joint control of EGPH in order to
\n
co-manage the company\u2019s current renewable generation
\n
portfolio alongside continuing to develop its project pipe-
\n
line, further increasing its installed capacity.
\n
The transaction generated a positive impact on Group
\n
profit of \u20ac422 million (including the remeasurement at fair
\n
value of the residual interest).
\n
For more information, please see note 9 \u201cMain acquisi-
\n
tions and disposals during the year\u201d.
\n
For more details on the financial position by business line
\n
and geographical area of assets classified as discontin-
\n
ued operations, please see the section \u201cPerformance by
\n
primary segment (Business Line) and secondary segment
\n
(Geographical 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 flow statement.
\n
Millions of euro
\n
2023 2022 Change
\n
Cash flows from operating activities - discontinued operations 132 (391) 523
\n
Cash flows used in investing activities - discontinued operations (442) (351) (91)
\n
Cash flows from/(used in) financing activities - discontinued operations (16) 656 (672)
\n
Cash flows - discontinued operations (326) (86) (240)
\n
\n\n
\n\n
36. Assets and liabilities included in disposal groups classified as held for sale \u2013 \u20ac5,919
\n
million and \u20ac2,316 million
\n
Changes in assets held for sale in 2023 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 the
\n
consolidation
\n
scope Impairment
\n
Exchange
\n
differences Investments
\n
Other
\n
changes
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Property, plant and equipment 3,304 3,574 (3,440) (263) (59) 820 (228) 3,708
\n
Intangible assets 334 719 (328) 16 (14) 29 (41) 715
\n
Goodwill - 616 (46) (1) 3 - - 572
\n
Deferred tax assets
\n
(1)
\n
217 146 (88) - (56) - (23) 196
\n
Equity-accounted investments 27 116 (142) - - - - 1
\n
Other non-current assets
\n
(2)
\n
50 37 (222) - - - 170 35
\n
Non-current financial assets
\n
and securities
\n
(2)
\n
75 - (29) - (45) - (1) -
\n
Non-current financial assets 138 - (85) - (3) - (50) -
\n
Current financial assets and
\n
securities
\n
43 1 (20) - (32) - 9 1
\n
Other current financial assets 9 2 (11) - - - - -
\n
Cash and cash equivalents 425 259 (320) - (40) - (63) 261
\n
Inventories, trade receivables
\n
and other current assets
\n
1,533 351 (1,479) - 29 - (4) 430
\n
Total
\n
(1)
\n
6,155 5,821 (6,210) (248) (217) 849 (231) 5,919
\n
(1) The figures at December 31, 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting
\n
periods beginning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
(2) At December 31, 2022, \u201cOther non-current assets\u201d included the \u201cNon-current financial assets and securities\u201d reported separately in the table above.
\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 the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Long-term borrowings 775 663 (908) (49) 249 730
\n
Provisions for risks and charges, non-current portion 33 33 (34) - 4 36
\n
Deferred tax liabilities
\n
(1)
\n
246 563 (192) (70) (42) 505
\n
Post-employment and other employee benefits 23 4 (22) (3) 3 5
\n
Non-current financial liabilities 69 - (80) (2) 23 10
\n
Non-current contract liabilities 442 - (453) - 11 -
\n
Other non-current liabilities 179 19 (149) (8) 13 54
\n
Short-term borrowings 642 217 (189) (10) (384) 276
\n
Long-term borrowings, current portion 18 100 (9) (5) 41 145
\n
Provisions for risks and charges, current portion 33 10 (64) (2) 32 9
\n
Other current financial liabilities 12 8 (17) - 6 9
\n
Trade payables and other current liabilities 894 385 (705) 11 (48) 537
\n
Total
\n
(1)
\n
3,366 2,002 (2,822) (138) (92) 2,316
\n
(1) The figures at December 31, 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting
\n
periods beginning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n
The item essentially includes assets measured at the lower of
\n
cost, understood as their net carrying amount, and the esti-
\n
mated realizable value, which, due to management decisions,
\n
meet the requirements of \u201cIFRS 5 - Non-current Assets Held
\n
for Sale and Discontinued Operations\u201d for their classification
\n
in this item.
\n
The balances of assets held for sale and associated liabilities
\n
at December 31, 2023 came to, respectively, \u20ac5,919 million
\n
and \u20ac2,316 million and mainly refer to:
\n
\u2022
\n
3SUN in Italy: on the basis of the negotiations finalized to
\n
the disposal of a 50% stake in the social capital of 3SUN
\n
Srl, its net assets have been reclassified as \u201cNon-current
\n
assets held for sale and discontinued operations\u201d, in line
\n
with IFRS 5;
\n
\u2022
\n
North America: assets relating to a renewable portfolio in
\n
the United States including about 150 MW of operational
\n
geothermal and solar plants;
\n
\u2022
\n
Peru: the electricity distribution and supply assets held by
\n
Enel Distribuci\u00f3n Per\u00fa SAA, the advanced energy services
\n
assets of Enel X Per\u00fa SAC and the generation assets held
\n
by Enel Generaci\u00f3n Per\u00fa, Compa\u00f1\u00eda Energ\u00e9tica Veracruz
\n
and Enel Generaci\u00f3n Piura as, on the basis of the negoti-
\n
ations in place, the requirements set by IFRS 5 have been
\n
met;
\n
\u2022
\n
Colombia: the Windpeshi wind farm under construction,
\n
which based on negotiations under way satisfies the re-
\n
quirements of IFRS 5.
\n
Assets previously classified as held for sale disposed of in
\n
2023 include:
\n
\u2022
\n
in the 1st Half of 2023, Enel Generaci\u00f3n Costanera, Inver-
\n
sora Dock Sud and Central Dock Sud generation compa-
\n
nies were sold in Argentina; Enel Green Power India relin-
\n
quished control of the net assets held through Avikiran
\n
Solar India Private Limited while maintaining a residual in-
\n
terest in the company of 51% of the paid-up share capital;
\n
\u2022
\n
in the 3rd Quarter of 2023, the subsidiary Enel Green
\n
Power SpA sold 50% of the two companies holding all of
\n
the Group renewable assets in Australia, specifically Enel
\n
Green Power Australia (Pty) Ltd and Enel Green Power Aus-
\n
tralia Trust, to INPEX Corporation;
\n
\u2022
\n
during the 4th Quarter of 2023, the Enel Group completed
\n
through the subsidiary Endesa Generaci\u00f3n SAU the sale of
\n
the entire stake held in Tecnatom SA.
\n
For more information on the financial effects of the above
\n
transactions, please see note 9 \u201cMain acquisitions and dis-
\n
posals during the year\u201d.
\n
Several assets previously classified as discontinued opera-
\n
tions were disposed of in 2023. In particular, in the 4th Quarter
\n
the Group completed the sale of all the stakes held in Roma-
\n
nia. Finally, the sale of a 50% stake in Enel Green Power Hellas
\n
was finalized.
\n
For more information on the financial effects of the above
\n
transactions, please see note 7 \u201cDiscontinued operations\u201d
\n
and note 9 \u201cMain acquisitions and disposals during the year\u201d.
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag86": { "value": "\n
7. Discontinued operations
\n
Within the \u201cEurope\u201d area, the Enel Group has decided to
\n
divest certain major business lines, particularly in Russia,
\n
Romania and Greece.
\n
Due to the fact that all discontinued assets represent a
\n
significant part of a geographical area in which the Group
\n
operates, the results relating to these assets have been
\n
classified in accordance with the provisions of IFRS 5 in a
\n
separate line of the consolidated income statement de-
\n
nominated \u201cProfit/(Loss) from discontinued operations\u201d.
\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 2023 and 2022.
\n
The items are shown net of intercompany transactions
\n
which have been completely eliminated.
\n
Millions of euro
\n
2023 2022 Change
\n
Revenue 2,535 3,543 (1,008)
\n
Costs 2,341 4,815 (2,474)
\n
Operating profit/(loss) 194 (1,272) 1,466
\n
Financial income/(expense) (62) (43) (19)
\n
Share of profit/(loss) of equity-accounted investments
\n
(1)
\n
58 83 (25)
\n
Pre-tax profit/(loss) from discontinued operations 190 (1,232) 1,422
\n
Income taxes 29 (52) 81
\n
Profit/(Loss) Russia, Greece and Romania 161 (1,180) 1,341
\n
Capital gains/(losses) from disposal of discontinued operations (532) (1,054) 522
\n
Profit/(Loss) from discontinued operations (371) (2,234) 1,863
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The breakdown by country is as follows.
\n
Millions of euro
\n
2023 Russia Greece Romania 2022
\n
(1)
\n
Russia
\n
(1)
\n
Greece Romania
\n
Total revenue 2,535 - 122 2,413 3,543 290 125 3,128
\n
Costs 2,126 - 75 2,051 3,585 243 70 3,272
\n
Impairment 215 - - 215 1,230 534 - 696
\n
Total costs 2,341 - 75 2,266 4,815 777 70 3,968
\n
Operating profit/(loss) 194 - 47 147 (1,272) (487) 55 (840)
\n
Financial income/(expense) (62) - (49) (13) (43) (9) (35) 1
\n
Share of profit/(loss) of equity-accounted
\n
investments
\n
58 58 - - 83 64 19 -
\n
Pre-tax profit/(loss) from discontinued
\n
operations
\n
190 58 (2) 134 (1,232) (432) 39 (839)
\n
Current income taxes 67 - 8 59 (15) 8 2 (25)
\n
Deferred income taxes (38) - - (38) (37) - - (37)
\n
Income taxes 29 - 8 21 (52) 8 2 (62)
\n
Profit/(Loss) Russia, Greece and Romania 161 58 (10) 113 (1,180) (440) 37 (777)
\n
Capital gains/(losses) from disposal of
\n
discontinued operations
\n
(532) (124) 262 (670) (1,054) (1,054) - -
\n
Profit/(Loss) from discontinued operations (371) (66) 252 (557) (2,234) (1,494) 37 (777)
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
\n\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 October 12, 2022, Enel SpA closed the sale of the en-
\n
tire stake held in PJSC Enel Russia. Upon completion of the
\n
sale, Enel sold all power generation assets in Russia, which
\n
include approximately 5.6 GW of conventional capacity
\n
and approximately 300 MW of wind capacity at various
\n
stages of development, ensuring continuity for its em-
\n
ployees and customers.
\n
Furthermore, on December 20, 2023, Enel SpA sold the
\n
entire stake it held in Rusenergosbyt LLC for \u20ac83 million.
\n
The operation had a negative impact of \u20ac124 million, of
\n
which \u20ac82 million related to the release of the translation
\n
reserve.
\n
Romania
\n
Following the agreements of December 14, 2022, Febru-
\n
ary 4, 2023 and March 9, 2023, on October 25, 2023 Enel
\n
SpA finalized the sale to the Greek company Public Power
\n
Corporation SA (PPC) of all the equity stakes held by Enel
\n
Group in Romania.
\n
In accordance with the terms of the agreement, PPC paid
\n
a total of \u20ac1,241 million. An earn-out mechanism is also
\n
foreseen concerning a potential further post-closing pay-
\n
ment, based on the future value of the retail business.
\n
The overall transaction had a negative impact on the
\n
Group\u2019s net profit of about \u20ac847 million, of which \u20ac655
\n
million reflecting the release of a currency translation re-
\n
serve, \u20ac15 million in respect of transaction costs connect-
\n
ed with the sale and the recognition of \u20ac177 million net of
\n
taxation in impairment losses on the assets prior to the
\n
sale.
\n
For more information, please see note 9 \u201cMain acquisi-
\n
tions and disposals during the year\u201d.
\n
Greece
\n
Following the agreement of July 26, 2023, on December
\n
29, 2023, Enel Green Power (EGP) finalized the sale of 50%
\n
of Enel Green Power Hellas (EGPH), EGP\u2019s fully-owned re-
\n
newable subsidiary in Greece, to Macquarie Asset Man-
\n
agement, acting through the Macquarie Green Investment
\n
Group Renewable Energy Fund 2, following the fulfillment
\n
of all the conditions customary for this type of transaction,
\n
including receipt of clearance from competent antitrust
\n
authorities.
\n
In line with the above agreement, the total price received
\n
by EGP was \u20ac351 million.
\n
Following the transaction\u2019s closing, EGP and Macquarie
\n
Asset Management entered into a shareholder agree-
\n
ment which envisages the joint control of EGPH in order to
\n
co-manage the company\u2019s current renewable generation
\n
portfolio alongside continuing to develop its project pipe-
\n
line, further increasing its installed capacity.
\n
The transaction generated a positive impact on Group
\n
profit of \u20ac422 million (including the remeasurement at fair
\n
value of the residual interest).
\n
For more information, please see note 9 \u201cMain acquisi-
\n
tions and disposals during the year\u201d.
\n
For more details on the financial position by business line
\n
and geographical area of assets classified as discontin-
\n
ued operations, please see the section \u201cPerformance by
\n
primary segment (Business Line) and secondary segment
\n
(Geographical 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 flow statement.
\n
Millions of euro
\n
2023 2022 Change
\n
Cash flows from operating activities - discontinued operations 132 (391) 523
\n
Cash flows used in investing activities - discontinued operations (442) (351) (91)
\n
Cash flows from/(used in) financing activities - discontinued operations (16) 656 (672)
\n
Cash flows - discontinued operations (326) (86) (240)
\n
\n\n
The 2022 consolidated income statement and statement
\n
of consolidated comprehensive income have been ad-
\n
justed to take account of the presentation in discontin-
\n
ued operations, as required by the \u201cIFRS 5 \u2013 Non-current
\n
Assets Held for Sale and Discontinued Operations\u201d, of the
\n
investment held in Rusenergosbyt LLC, which was sold in
\n
the 4th Quarter of 2023.
\n
For more details, please see note 7 \u201cDiscontinued opera-
\n
tions\u201d.
\n
\n\n
Impact on the consolidated income statement
\n
Millions of euro
\n
2022 IFRS 5 2022 restated
\n
Revenue 140,517 - 140,517
\n
Costs 131,689 - 131,689
\n
Net results from commodity contracts 2,365 - 2,365
\n
Operating profit 11,193 - 11,193
\n
Financial income from derivatives 3,118 - 3,118
\n
Other financial income 3,430 - 3,430
\n
Financial expense from derivatives 3,414 - 3,414
\n
Other financial expense 5,880 - 5,880
\n
Net income from hyperinflation 290 - 290
\n
Share of profit/(loss) of equity-accounted investments 4 (64) (60)
\n
Pre-tax profit 8,741 (64) 8,677
\n
Income taxes 3,523 - 3,523
\n
Profit/(Loss) from continuing operations 5,218 (64) 5,154
\n
Attributable to owners of the Parent 3,637 (64) 3,573
\n
Attributable to non-controlling interests 1,581 - 1,581
\n
Profit/(Loss) from discontinued operations (2,298) 64 (2,234)
\n
Attributable to owners of the Parent (1,955) 64 (1,891)
\n
Attributable to non-controlling interests (343) - (343)
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling
\n
interests)
\n
2,920 - 2,920
\n
Impact on the statement of consolidated comprehensive income
\n
Millions of euro
\n
2022 IFRS 5 2022 restated
\n
Profit for the year 2,920 - 2,920
\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 (1,677) - (1,677)
\n
Change in the fair value of hedging costs (70) - (70)
\n
Share of the other comprehensive income of equity-accounted
\n
investments
\n
233 - 233
\n
Change in the fair value of financial assets at FVOCI (44) - (44)
\n
Change in translation reserve 944 15 959
\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
(63) (15) (78)
\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 303 - 303
\n
Change in the fair value of equity investments in other companies 13 - 13
\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
21 - 21
\n
Total other comprehensive expense for the year (340) - (340)
\n
Comprehensive income/(expense) for the year 2,580 - 2,580
\n
Attributable to:
\n
- owners of the Parent 1,658 - 1,658
\n
- non-controlling interests 922 - 922
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag87": { "value": "\n
8. Restatement of comparative disclosures
\n
The 2022 statement of consolidated financial position
\n
has been adjusted to take account of the effects of the
\n
amendment to IAS 12 in effect for annual reporting peri-
\n
ods beginning on or after January 1, 2023, which clarifies
\n
that the exemption from initial recognition provided for by
\n
the standard no longer applies to transactions that give
\n
rise to taxable and deductible temporary differences of
\n
the same amount, such as leases and decommissioning.
\n
Impact on the consolidated financial position
\n
Millions of di euro
\n
ASSETS at Dec. 31, 2022 IAS 12
\n
at Dec. 31, 2022
\n
restated
\n
Non-current assets
\n
Property, plant and equipment 88,521 - 88,521
\n
Investment property 94 - 94
\n
Intangible assets 17,52 0 - 17,5 2 0
\n
Goodwill 13,742 - 13,742
\n
Deferred tax assets 10,925 250 11,175
\n
Equity-accounted investments 1,281 - 1,281
\n
Non-current financial derivative assets 3,970 - 3,970
\n
Non-current contract assets 508 - 508
\n
Other non-current financial assets 8,359 - 8,359
\n
Other non-current assets 2,486 - 2,486
\n
[Total] 147,406 250 147,65 6
\n
Current assets
\n
Inventories 4,853 - 4,853
\n
Trade receivables 16,605 - 16,605
\n
Current contract assets 106 - 106
\n
Tax assets 561 - 561
\n
Current financial derivative assets 14,830 - 14,830
\n
Other current financial assets 13,753 - 13,753
\n
Other current assets 4,314 - 4,314
\n
Cash and cash equivalents 11,041 - 11,041
\n
[Total] 66,063 - 66,063
\n
Assets classified as held for sale 6,149 6 6,155
\n
TOTAL ASSETS 219,618 256 219,874
\n
\n\n
\n
Millions of euro
\n
LIABILITIES AND EQUITY at Dec. 31, 2022 IAS 12
\n
at Dec. 31, 2022
\n
restated
\n
Equity attributable to owners of the Parent
\n
Share capital 10,167 - 10,167
\n
Treasury share reserve (47) - (47)
\n
Other reserves 2,740 - 2 ,740
\n
Retained earnings 15,797 (2) 15,795
\n
[Total] 28,657 (2) 28,655
\n
Non-controlling interests 13,425 - 13,425
\n
Total equity 42,082 (2) 42,080
\n
Non-current liabilities
\n
Long-term borrowings 68,191 - 68,191
\n
Employee benefits 2,202 - 2,202
\n
Provisions for risks and charges (non-current portion) 6,055 - 6,055
\n
Deferred tax liabilities 9,542 252 9,794
\n
Non-current financial derivative liabilities 5,895 - 5,895
\n
Non-current contract liabilities 5,747 - 5,747
\n
Other non-current financial liabilities - - -
\n
Other non-current liabilities 4,246 - 4,246
\n
[Total] 101,878 252 102,130
\n
Current liabilities
\n
Short-term borrowings 18,392 - 18,392
\n
Current portion of long-term borrowings 2,835 - 2,835
\n
Provisions for risks and charges (current portion) 1,325 - 1,325
\n
Trade payables 17,6 41 - 17,641
\n
Income tax liabilities 1,623 - 1,623
\n
Current financial derivative liabilities 16,141 - 16,141
\n
Current contract liabilities 1,775 - 1,775
\n
Other current financial liabilities 853 - 853
\n
Other current liabilities 11,713 - 11,713
\n
[Total] 72,298 - 72,298
\n
Liabilities included in disposal groups classified as held for sale 3,360 6 3,366
\n
Total liabilities 177,536 258 177,794
\n
TOTAL LIABILITIES AND EQUITY 219,618 256 219,874
\n\n
The 2022 consolidated income statement and statement
\n
of consolidated comprehensive income have been ad-
\n
justed to take account of the presentation in discontin-
\n
ued operations, as required by the \u201cIFRS 5 \u2013 Non-current
\n
Assets Held for Sale and Discontinued Operations\u201d, of the
\n
investment held in Rusenergosbyt LLC, which was sold in
\n
the 4th Quarter of 2023.
\n
For more details, please see note 7 \u201cDiscontinued opera-
\n
tions\u201d.
\n
\n\n
\n\n
\n\n
Impact on the consolidated income statement
\n
Millions of euro
\n
2022 IFRS 5 2022 restated
\n
Revenue 140,517 - 140,517
\n
Costs 131,689 - 131,689
\n
Net results from commodity contracts 2,365 - 2,365
\n
Operating profit 11,193 - 11,193
\n
Financial income from derivatives 3,118 - 3,118
\n
Other financial income 3,430 - 3,430
\n
Financial expense from derivatives 3,414 - 3,414
\n
Other financial expense 5,880 - 5,880
\n
Net income from hyperinflation 290 - 290
\n
Share of profit/(loss) of equity-accounted investments 4 (64) (60)
\n
Pre-tax profit 8,741 (64) 8,677
\n
Income taxes 3,523 - 3,523
\n
Profit/(Loss) from continuing operations 5,218 (64) 5,154
\n
Attributable to owners of the Parent 3,637 (64) 3,573
\n
Attributable to non-controlling interests 1,581 - 1,581
\n
Profit/(Loss) from discontinued operations (2,298) 64 (2,234)
\n
Attributable to owners of the Parent (1,955) 64 (1,891)
\n
Attributable to non-controlling interests (343) - (343)
\n
Profit/(Loss) for the year (owners of the Parent and non-controlling
\n
interests)
\n
2,920 - 2,920
\n
Impact on the statement of consolidated comprehensive income
\n
Millions of euro
\n
2022 IFRS 5 2022 restated
\n
Profit for the year 2,920 - 2,920
\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 (1,677) - (1,677)
\n
Change in the fair value of hedging costs (70) - (70)
\n
Share of the other comprehensive income of equity-accounted
\n
investments
\n
233 - 233
\n
Change in the fair value of financial assets at FVOCI (44) - (44)
\n
Change in translation reserve 944 15 959
\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
(63) (15) (78)
\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 303 - 303
\n
Change in the fair value of equity investments in other companies 13 - 13
\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
21 - 21
\n
Total other comprehensive expense for the year (340) - (340)
\n
Comprehensive income/(expense) for the year 2,580 - 2,580
\n
Attributable to:
\n
- owners of the Parent 1,658 - 1,658
\n
- non-controlling interests 922 - 922
\n
\n\n
The figures presented in the comments and the tables
\n
of the notes to these consolidated financial statements
\n
at December 31, 2023 are uniform and comparable with
\n
each other.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfReclassificationsOrChangesInPresentationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag88": { "value": "\n
9. 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
2022
\n
\u2022
\n
On January 3, 2022, Enel Produzione SpA acquired
\n
100% of ERG Hydro Srl (subsequently renamed Enel Hy-
\n
dro Appennino Centrale Srl and merged into Enel Pro-
\n
duzione SpA on December 1, 2022), owner of genera-
\n
tion plants with an installed capacity of about 527 MW
\n
and an annual output of approximately 1.5 TWh, for a
\n
consideration of about \u20ac1,267 million; in December
\n
2022, the identification of the fair value of the acquired
\n
assets and liabilities was completed, with the recogni-
\n
tion of goodwill of approximately \u20ac349 million.
\n
\u2022
\n
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 Africa with an
\n
installed capacity of about 740 MW, for about \u20ac108 mil-
\n
lion, which has been paid in full.
\n
\u2022
\n
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 stake in Enel X Financial Services,
\n
CityPoste Payment, PayTipper and Junia Insurance and
\n
their subsidiaries.
\n
\u2022
\n
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.
\n
\u2022
\n
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
\n
total of about \u20ac137 million. The transaction had a neg-
\n
ative impact on reported Group net income of around
\n
\u20ac1.5 billion, mainly reflecting the release of a currency
\n
translation of about \u20ac1 billion and an impairment ad-
\n
justment of \u20ac497 million.
\n
\u2022
\n
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
\n
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 involved the recognition of a capital
\n
gain of \u20ac261 million and the remeasurement to fair val-
\n
ue of the residual holding in the amount of \u20ac259 million.
\n
\u2022
\n
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
mainly reflecting the release of a currency translation
\n
reserve associated with the net assets sold.
\n
2023
\n
\u2022
\n
On February 17, 2023, the Enel Group, through its sub-
\n
sidiary Enel Argentina, closed the deal for the sale to
\n
energy company Central Puerto SA of the Group\u2019s stake
\n
in the thermal generation company Enel Generaci\u00f3n
\n
Costanera for \u20ac42 million, which have been collected
\n
in full. The transaction resulted in the recognition of a
\n
capital loss of \u20ac132 million.
\n
\u2022
\n
On April 14, 2023, the Enel Group completed the sale
\n
to YPF and Pan American Sur SA of the shares held in
\n
Inversora Dock Sud SA and Central Dock Sud SA, for
\n
a total of \u20ac48 million. The transaction had a negative
\n
impact on profit or loss of about \u20ac194 million.
\n
\u2022
\n
On September 29, 2023, the Enel Group, acting through
\n
its subsidiary Enel Green Power SpA, finalized the sale
\n
of 50% of the two companies that own all of the Group\u2019s
\n
renewables operations in Australia, specifically Enel
\n
\n\n
Green Power Australia (Pty) Ltd and Enel Green Power
\n
Australia Trust, to INPEX Corporation, for a total of \u20ac142
\n
million. The operation resulted in the recognition of a
\n
gain of \u20ac103 million.
\n
\u2022
\n
On October 25, 2023, Enel SpA and its listed subsidi-
\n
ary Enel Chile SA closed the sale of their entire equi-
\n
ty interests in the share capital of Arcadia Generaci\u00f3n
\n
Solar SA, a Chilean company which owns a portfolio of
\n
four operating PV plants for a total installed capacity
\n
of approximately 416 MW, to Sonnedix, an international
\n
renewable energy producer, for a total of \u20ac535 million.
\n
The transaction resulted in the recognition of a capital
\n
gain of \u20ac195 million.
\n
\u2022
\n
On October 25, 2023, the Enel Group finalized the sale
\n
to the Greek company Public Power Corporation SA of
\n
all the equity stakes held by the Enel Group in Roma-
\n
nia, for a total of \u20ac1,241 million. The transaction had a
\n
negative impact on profit or loss of the year of \u20ac847
\n
million, of which \u20ac655 million reflecting the release of a
\n
currency translation reserve.
\n
\u2022
\n
On December 29, 2023, Enel SpA, acting through its
\n
fully-owned subsidiary Enel Green Power SpA, finalized
\n
the sale of 50% of Enel Green Power Hellas, Enel Green
\n
Power\u2019s fully-owned renewable subsidiary in Greece, to
\n
Macquarie Asset Management, for a total of \u20ac351 mil-
\n
lion. The overall transaction had a positive impact on
\n
the profit or loss of the Group in 2023 of \u20ac422 million.
\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
\n
On November 24, 2023, the Enel Group, acting through
\n
the subsidiary Endesa Generaci\u00f3n SAU, finalized the
\n
sale of the entire investment in Tecnatom SA for a total
\n
of \u20ac26 million. The transaction had no impact on profit
\n
or loss.
\n
\u2022
\n
On December 20, 2023, Enel SpA sold its entire stake in
\n
Rusenergosbyt LLC for a total of \u20ac83 million. The trans-
\n
action had a negative impact of \u20ac124 million on Group
\n
profit, of which \u20ac82 million reflecting the release of a
\n
currency translation reserve.
\n
Sale of Enel Generaci\u00f3n Costanera
\n
On February 17, 2023, the Enel Group sold its stake in the
\n
thermal generation company Enel Generaci\u00f3n Costanera
\n
for \u20ac42 million, collected in full.
\n
Millions of euro
\n
Sale price 42
\n
Total net assets sold (39)
\n
Release of OCI reserve (135)
\n
Gain/(Loss) on sale (132)
\n
Sale of Inversora Dock Sud SA and Central Dock Sud SA
\n
On April 14, 2023, the Enel Group completed the sale of
\n
shares held in the thermal generation companies Inverso-
\n
ra Dock Sud SA and Central Dock Sud SA for \u20ac48 million,
\n
collected in full.
\n
Millions of euro
\n
Sale price 48
\n
Total net assets sold (48)
\n
Release of OCI reserve (194)
\n
Gain/(Loss) on sale (194)
\n
\n\n
Sale of 50% of Enel Green Power Australia
\n
On September 29, 2023, the Enel Group, acting through
\n
its subsidiary Enel Green Power SpA, finalized the sale of
\n
50% of the two companies that own all of the Group\u2019s re-
\n
newables operations in Australia, specifically Enel Green
\n
Power Australia (Pty) Ltd and Enel Green Power Australia
\n
Trust, to INPEX Corporation, for a total of \u20ac142 million, col-
\n
lected in full.
\n
Millions of euro
\n
Sale price 142
\n
Total net assets sold (63)
\n
Release of OCI reserve (55)
\n
Gain/(Loss) on sale 24
\n
Fair value remeasurement of residual interest (50%) 79
\n
Income from sale 103
\n
Sale of Arcadia Generaci\u00f3n Solar
\n
On October 25, 2023, Enel SpA and its subsidiary Enel
\n
Chile SA finalized the sale of their entire stakes in Arcadia
\n
Generaci\u00f3n Solar SA to Sonnedix, for a total consideration
\n
of \u20ac535 million, which have been collected in full.
\n
Millions of euro
\n
Sale price 535
\n
Total net assets sold (314)
\n
Release of OCI reserve 21
\n
Transaction costs (1)
\n
Goodwill (46)
\n
Gain/(Loss) on sale 195
\n
The transaction had a tax effect of \u20ac68 million.
\n
Sale of Romanian operations
\n
On October 25, 2023, the Enel Group finalized the sale to
\n
the Greek company Public Power Corporation SA of all the
\n
equity stakes held in Romania, for a total consideration of
\n
\u20ac1,241 million, collected in full.
\n
Millions of euro
\n
Sale price 1,241
\n
Total net assets sold (1,241)
\n
Release of OCI reserve (655)
\n
Transaction costs (15)
\n
Gain/(Loss) on sale (670)
\n
Adjustment of pre-sale plant value (215)
\n
Tax on value adjustment 38
\n
Financial impact (847)
\n
\n\n
Sale of 50% of Enel Green Power Hellas
\n
On December 29, 2023, Enel SpA, acting through its ful-
\n
ly-owned subsidiary Enel Green Power SpA, finalized the
\n
sale of 50% of Enel Green Power Hellas, Enel Green Pow-
\n
er\u2019s fully-owned renewable subsidiary in Greece, to Mac-
\n
quarie Asset Management, for a total consideration of
\n
\u20ac351 million, collected in full.
\n
Millions of euro
\n
Sale price 351
\n
Total net assets sold (86)
\n
Transaction costs (3)
\n
Gain/(Loss) on sale 262
\n
Fair value remeasurement of residual interest (50%) 160
\n
Income from sale 422
\n
\n", "dimensions": { "concept": "enel:DisclosureOfChangeInOwnershipInterestsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag89": { "value": "\n
\n
10. Performance and financial position by primary segment (Business
\n
Line) and secondary segment (Geographical Area)
\n\n
The representation of performance and financial position
\n
presented here is based on the approach used by man-
\n
agement in monitoring Group performance for the two
\n
periods under review. In particular, management monitors
\n
and reports on performance by business line. Accordingly,
\n
the Group has adopted the following reporting sectors:
\n
\u2022
\n
primary segment: Business Line;
\n
\u2022
\n
secondary segment: Geographical Area.
\n
The business line is therefore the main discriminant in the
\n
analyses performed and decisions taken by the manage-
\n
ment of the Enel Group, and is fully consistent with the
\n
internal reporting prepared for these purposes since the
\n
results are measured and evaluated first and foremost for
\n
each business line and only thereafter are they broken
\n
down by geographical area.
\n
\n\n
In this regard, note that the organizational simplification
\n
process begun in 2023 led to a restructuring of the busi-
\n
ness lines and geographical areas, with a consequent
\n
need to redefine the segments subject to disclosure in
\n
order to present the results of the segments based on the
\n
approach used by management to monitor and present
\n
the Group\u2019s performance to investors.
\n
In particular, in the presentation of figures by primary seg-
\n
ment (Business Line):
\n
\u2022
\n
the figures for Enel X, which in the year ended Decem-
\n
ber 31, 2022 had been presented separately, are now
\n
reported under End-user Markets;
\n
\u2022
\n
the figures for Enel X Way, which in the year ended De-
\n
cember 31, 2022 had been presented under Holding,
\n
Services and Other, are now reported under End-user
\n
Markets.
\n
In the presentation of figures by secondary segment
\n
(Geographical Area), the figures for Latin America, Europe,
\n
North America, and Africa, Asia and Oceania have merged
\n
into the \u201cRest of the World\u201d area.
\n
Following these changes, the figures for the previous year
\n
have been adjusted for comparative purposes only.
\n
\n\n
Performance by primary segment (Business Line)
\n
Results for 2023
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Revenue and other income from
\n
third parties
\n
20,152 8,459 17,206 49,748 - 95,565 - 95,565
\n
Revenue and other income from
\n
transactions with other segments
\n
20,038 3,161 3,053 2,371 2,045 30,668 (30,668) -
\n
Total revenue 40,190 11,620 20,259 52,119 2,045 126,233 (30,668) 95,565
\n
Total costs 35,140 6,377 12,798 46,038 2,659 103,012 (30,668) 72,344
\n
Net results from commodity
\n
contracts
\n
(1,983) (65) - (923) 5 (2,966) - (2,966)
\n
Depreciation and amortization 775 1,603 2,957 785 233 6,353 - 6,353
\n
Impairment losses 161 1,552 168 1,439 18 3,338 - 3,338
\n
Impairment gains (49) (19) (90) (108) (2) (268) - (268)
\n
Operating profit/(loss) 2,180 2,042 4,426 3,042 (858) 10,832 - 10,832
\n
Capital expenditure 761
\n
(2)
\n
5,345
\n
(3)
\n
5,280
\n
(4)
\n
1,138
\n
(5)
\n
190
\n
(6)
\n
12,714 - 12,714
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac14 million regarding units classified as held for sale or discontinued operations.
\n
(3) Does not include \u20ac565 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac233 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac34 million regarding units classified as held for sale or discontinued operations.
\n
(6) Does not include \u20ac3 million regarding units classified as held for sale or discontinued operations.
\n
Results for 2022
\n
(1)
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Revenue and other income from
\n
third parties
\n
53,239 6,669 19,806 60,785 18 140,517 - 140,517
\n
Revenue and other income from
\n
transactions with other segments
\n
23,096 2,498 3,226 3,565 2,032 34,417 (34,417) -
\n
Total revenue 76,335 9,167 23,032 64,350 2,050 174,934 (34,417) 140,517
\n
Total costs 71,189 5,873 13,918 64,143 2,225 157,348 (34,384) 122,964
\n
Net results from commodity
\n
contracts
\n
551 183 - 1,595 (5) 2,324 41 2,365
\n
Depreciation and amortization 802 1,456 2,852 747 229 6,086 - 6,086
\n
Impairment losses 562 53 1,047 1,296 - 2,958 - 2,958
\n
Impairment gains (52) (2) (117) (148) - (319) - (319)
\n
Operating profit/(loss) 4,385 1,970 5,332 (93) (409) 11,185 8 11,193
\n
Capital expenditure 990
\n
(2)
\n
6,386
\n
(3)
\n
5,547
\n
(4)
\n
1,205
\n
(5)
\n
219 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
Performance by secondary segment (Geographical Area)
\n
Results for 2023
\n
(1)
\n
Millions of euro Italy Iberia
\n
Rest
\n
of the
\n
World
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa,
\n
Asia and
\n
Oceania
\n
Eliminations
\n
Rest of the
\n
World
\n
Other,
\n
eliminations
\n
and
\n
adjustments Total
\n
Revenue and other income from
\n
third parties
\n
49,145 25,418 20,927 18,569 234 2,129 335 (340) 75 95,565
\n
Revenue and other income
\n
from transactions with other
\n
segments
\n
182 10 354 7 5 13 3 326 (546) -
\n
Total revenue 49,327 25,428 21,281 18,576 239 2,142 338 (14) (471) 95,565
\n
Total costs 38,792 18,578 15,091 13,563 80 1,262 200 (14) (117) 72,344
\n
Net results from commodity
\n
contracts
\n
233 (3,171) (38) 181 - (220) 1 - 10 (2,966)
\n
Depreciation and amortization 2,325 1,911 1,931 1,389 2 491 49 - 186 6,353
\n
Impairment losses 824 558 1,879 452 2 1,425 - - 77 3,338
\n
Impairment gains (22) (197) (48) (43) (1) - (4) - (1) (268)
\n
Operating profit/(loss) 7,641 1,407 2,390 3,396 156 (1,256) 94 - (606) 10,832
\n
Capital expenditure 5,763
\n
(2)
\n
2,305 4,419
\n
(3)
\n
3,302
\n
(4)
\n
2
\n
(5)
\n
1,096
\n
(6)
\n
19
\n
(7)
\n
- 227 12,714
\n
(1) Segment revenue includes both revenue from third parties and revenue from transactions with other segments.
\n
(2) Does not include \u20ac337 million regarding units classified as held for sale or discontinued operations.
\n
(3) Does not include \u20ac512 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac180 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac210 million regarding units classified as held for sale or discontinued operations.
\n
(6) Does not include \u20ac1 million regarding units classified as held for sale or discontinued operations.
\n
(7) Does not include \u20ac121 million regarding units classified as held for sale or discontinued operations.
\n
Results for 2022
\n
(1)
\n
Millions of euro Italy Iberia
\n
Rest
\n
of the
\n
World
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa,
\n
Asia and
\n
Oceania
\n
Eliminations
\n
Rest of the
\n
World
\n
Other,
\n
eliminations
\n
and
\n
adjustments Total
\n
Revenue and other income from
\n
third parties
\n
83,337 32,725 23,476 21,329 82 2,208 266 (409) 979 140,517
\n
Revenue and other income
\n
from transactions with other
\n
segments
\n
171 108 398 5 5 6 - 382 (677) -
\n
Total revenue 83,508 32,833 23,874 21,334 87 2 ,214 266 (27) 302 140,517
\n
Total costs 81,880 25,388 16,149 14,811 66 1,126 174 (28) (453) 122,964
\n
Net results from commodity
\n
contracts
\n
4,679 (2,215) (95) 56 6 (148) (9) - (4) 2,365
\n
Depreciation and amortization 2,209 1,784 1,900 1,393 2 430 75 - 193 6,086
\n
Impairment losses 886 478 1,577 1,553 1 18 5 - 17 2,958
\n
Impairment gains (39) (271) (7) (7) - - - - (2) (319)
\n
Operating profit/(loss) 3,251 3,239 4,160 3,640 24 492 3 1 543 11,193
\n
Capital expenditure 4,640 2,316 7, 16 8
\n
(2)
\n
4,289
\n
(3)
\n
224
\n
(4)
\n
2,491 164
\n
(5)
\n
- 223
\n
(6)
\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 \u20ac138 million regarding units classified as held for sale or discontinued operations.
\n
(3) Does not include \u20ac94 million regarding units classified as held for sale or discontinued operations.
\n
(4) Does not include \u20ac4 million regarding units classified as held for sale or discontinued operations.
\n
(5) Does not include \u20ac40 million regarding units classified as held for sale or discontinued operations.
\n
(6) Does not include \u20ac18 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, 2023
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Property, plant and equipment 8,340 42,757 40,490 1,142 793 93,522 (13) 93,509
\n
Intangible assets 271 5,555 20,188 4,926 443 31,383 - 31,383
\n
Non-current and current contract
\n
assets
\n
20 17 484 169 2 692 (1) 691
\n
Trade receivables 7, 287 3,471 7,7 7 1 8,373 792 27,6 9 4 (9,711) 17,983
\n
Other 5,736 290 2,738 2,489 3,134 14,387 (6,268) 8,119
\n
Operating assets 21,654
\n
(1)
\n
52,090
\n
(2)
\n
71,671
\n
(3)
\n
17,099
\n
(4)
\n
5,164
\n
(5)
\n
167,678 (15,993) 151,685
\n
Trade payables 6,741 3,797 4, 174 9,418 1,014 25,144 (8,986) 16,158
\n
Non-current and current contract
\n
liabilities
\n
112 271 7,515 59 7 7,964 (95) 7,8 6 9
\n
Sundry provisions 3,468 979 3,348 742 1,208 9,745 (63) 9,682
\n
Other 3,833 1,606 9,817 4,327 4,740 24,323 (6,164) 18,159
\n
Operating liabilities 14,154
\n
(6)
\n
6,653
\n
(7)
\n
24,854
\n
(8)
\n
14,546
\n
(9)
\n
6,969
\n
(10)
\n
67,176 (15,308) 51,868
\n
(1) Of which \u20ac640 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac2,254 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac2,469 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac84 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac9 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac142 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac265 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac207 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac19 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac3 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2022
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Property, plant and equipment 8,530 41,519 40,377 760 642 91,828 (3) 91,825
\n
Intangible assets 397 5,723 20,035 4,975 467 31,597 - 31,597
\n
Non-current and current contract
\n
assets
\n
- 50 500 109 6 665 (1) 664
\n
Trade receivables 7,667 3,730 5,706 9,003 1,197 27,303 (9,567) 17,73 6
\n
Other 7, 928 540 2,551 3,262 2,463 16,744 (7,891) 8,853
\n
Operating assets 24,522
\n
(1)
\n
51,562
\n
(2)
\n
69,169
\n
(3)
\n
18,109
\n
(4)
\n
4,775
\n
(5)
\n
168,137 (17,462) 150,675
\n
Trade payables 8,034 4,173 4,297 9,396 1,205 27, 10 5 (9,042) 18,063
\n
Non-current and current contract
\n
liabilities
\n
95 323 7,527 91 9 8,045 (81) 7,964
\n
Sundry provisions 3,979 921 3,263 488 1,088 9,739 (68) 9,671
\n
Other 3,475 1,802 6,691 7,055 4,434 23,457 (7,903) 15,554
\n
Operating liabilities 15,583
\n
(6)
\n
7, 2 19
\n
(7)
\n
21,778
\n
(8)
\n
17,030
\n
(9)
\n
6,736
\n
(10)
\n
68,346 (17,094) 51,252
\n
(1) Of which \u20ac188 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac2,146 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac1,994 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac1,241 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac32 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac92 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac308 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac866 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac801 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac15 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, 2023
\n
Millions of euro Italy Iberia
\n
Rest
\n
of the
\n
World
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa,
\n
Asia and
\n
Oceania
\n
Eliminations
\n
Rest of the
\n
World
\n
Other,
\n
eliminations
\n
and
\n
adjustments Total
\n
Property, plant and equipment 34,361 23,527 35,524 22,273 3 12,790 458 - 97 93,509
\n
Intangible assets 3,122 16,178 11,397 10,771 26 482 118 - 686 31,383
\n
Non-current and current
\n
contract assets
\n
90 80 520 473 2 40 5 - 1 691
\n
Trade receivables 8,819 4,011 5,302 4,978 29 244 78 (27) (149) 17,983
\n
Other 4,281 2,375 1,706 1,393 13 271 31 (2) (243) 8,119
\n
Operating assets 50,673
\n
(1)
\n
46,171 54,449
\n
(2)
\n
39,888
\n
(3)
\n
73 13,827
\n
(4)
\n
690
\n
(5)
\n
(29) 392 151,685
\n
Trade payables 9,001 2,888 5,011 4,075 30 849 79 (22) (742) 16,158
\n
Non-current and current
\n
contract liabilities
\n
4,318 3,537 47 47 - - - - (33) 7, 8 69
\n
Sundry provisions 3,078 3,177 2,686 2,529 1 134 21 1 741 9,682
\n
Other 6,913 3,556 6,219 4,205 37 1,932 48 (3) 1,471 18,159
\n
Operating liabilities 23,310
\n
(6)
\n
13,158 13,963
\n
(7)
\n
10,856
\n
(8)
\n
68 2 ,915
\n
(9)
\n
148
\n
(10)
\n
(24) 1,437 51,868
\n
(1) Of which \u20ac631 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac4,801 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac4,541 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac242 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac18 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac155 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac481 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac477 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac3 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac1 million regarding units classified as held for sale or discontinued operations.
\n
At December 31, 2022
\n
Millions of euro Italy Iberia
\n
Rest
\n
of the
\n
World
\n
Latin
\n
America Europe
\n
North
\n
America
\n
Africa,
\n
Asia and
\n
Oceania
\n
Eliminations
\n
Rest of the
\n
World
\n
Other,
\n
eliminations
\n
and
\n
adjustments Total
\n
Property, plant and equipment 30,327 23,167 38,220 21,099 2,397 13,722 1,002 - 111 91,825
\n
Intangible assets 3,200 16, 173 11,596 10,534 331 602 129 - 628 31,597
\n
Non-current and current
\n
contract assets
\n
73 9 576 493 48 19 16 - 6 664
\n
Trade receivables 7,086 4,369 6,470 5,037 1,127 268 66 (28) (189) 17,73 6
\n
Other 4,947 2,929 2,105 1,498 294 250 63 - (1,128) 8,853
\n
Operating assets 45,633
\n
(1)
\n
46,647 58,967
\n
(2)
\n
38,661
\n
(3)
\n
4,197
\n
(4)
\n
14,861 1,276
\n
(5)
\n
(28) (572) 150,675
\n
Trade payables 9,595 3,220 6,652 4,813 483 1,261 119 (24) (1,404) 18,063
\n
Non-current and current
\n
contract liabilities
\n
4,188 3,351 479 35 443 - 1 - (54) 7,964
\n
Sundry provisions 3,008 3,458 2,576 2,378 69 97 32 - 629 9,671
\n
Other 4,323 3,144 7, 076 4,480 637 1,893 66 - 1,011 15,554
\n
Operating liabilities 21,114
\n
(6)
\n
13,173 16,783
\n
(7)
\n
11,706
\n
(8)
\n
1,632
\n
(9)
\n
3,251 218
\n
(10)
\n
(24) 182 51,252
\n
(1) Of which \u20ac253 million regarding units classified as held for sale or discontinued operations.
\n
(2) Of which \u20ac4,968 million regarding units classified as held for sale or discontinued operations.
\n
(3) Of which \u20ac307 million regarding units classified as held for sale or discontinued operations.
\n
(4) Of which \u20ac4,108 million regarding units classified as held for sale or discontinued operations.
\n
(5) Of which \u20ac553 million regarding units classified as held for sale or discontinued operations.
\n
(6) Of which \u20ac64 million regarding units classified as held for sale or discontinued operations.
\n
(7) Of which \u20ac1,737 million regarding units classified as held for sale or discontinued operations.
\n
(8) Of which \u20ac99 million regarding units classified as held for sale or discontinued operations.
\n
(9) Of which \u20ac1,584 million regarding units classified as held for sale or discontinued operations.
\n
(10) Of which \u20ac54 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, 2023 at Dec. 31, 2022
\n
Total assets 195,224 219,874
\n
Equity-accounted investments 1,650 1,281
\n
Non-current financial derivative assets 2,383 3,970
\n
Other non-current financial assets 8,750 8,359
\n
Non-current tax assets included in \u201cOther non-current assets\u201d 1,487 1,674
\n
Other current financial assets 4,329 13,753
\n
Current financial derivative assets 6,407 14,830
\n
Cash and cash equivalents 6,801 11,041
\n
Deferred tax assets
\n
(1)
\n
9,218 11,175
\n
Tax assets 2,016 2,159
\n
Financial and tax assets of \u201cAssets classified as held for sale\u201d
\n
(1)
\n
498 957
\n
Segment assets 151,685 150,675
\n
Total liabilities 150,115 177,794
\n
Long-term borrowings 61,085 68,191
\n
Non-current financial derivative liabilities 3,373 5,895
\n
Other non-current financial liabilities 8 -
\n
Short-term borrowings 4,769 18,392
\n
Current portion of long-term borrowings 9,086 2,835
\n
Other current financial liabilities 909 853
\n
Current financial derivative liabilities 6,461 16,141
\n
Deferred tax liabilities
\n
(1)
\n
8, 217 9,794
\n
Income tax liabilities 1,573 1,623
\n
Other tax liabilities 1,034 1,048
\n
Financial and tax liabilities of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201d
\n
(1)
\n
1,732 1,770
\n
Segment liabilities 51,868 51,252
\n
(1) Figures at December 31, 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting pe-
\n
riods beginning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag90": { "value": "\n
The representation of performance and financial position
\n
presented here is based on the approach used by man-
\n
agement in monitoring Group performance for the two
\n
periods under review. In particular, management monitors
\n
and reports on performance by business line. Accordingly,
\n
the Group has adopted the following reporting sectors:
\n
\u2022
\n
primary segment: Business Line;
\n
\u2022
\n
secondary segment: Geographical Area.
\n
The business line is therefore the main discriminant in the
\n
analyses performed and decisions taken by the manage-
\n
ment of the Enel Group, and is fully consistent with the
\n
internal reporting prepared for these purposes since the
\n
results are measured and evaluated first and foremost for
\n
each business line and only thereafter are they broken
\n
down by geographical area.
\n
\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag91": { "value": "\n
\n
Revenue
\n\n
11.a Revenue from sales and services \u2013 \u20ac92,882 million
\n
Millions of euro
\n
2023 2022 Change
\n
Sale of electricity 52,465 69,340 (16,875) -24.3%
\n
Transport of electricity 11,123 11,096 27 0.2%
\n
Fees from network operators 1,142 979 163 16.6%
\n
Transfers from institutional market operators 1,570 1,667 (97) -5.8%
\n
Sale of gas 7,983 8,970 (987) -11.0%
\n
Transport of gas 68 80 (12) -15.0%
\n
Sale of fuel 3,458 5,605 (2,147) -38.3%
\n
Fees for connection to electricity and gas networks 877 826 51 6.2%
\n
Construction contracts 995 1,672 (677) -40.5%
\n
Sale of environmental certificates 283 111 172 -
\n
Sale of value-added services 1,653 1,384 269 19.4%
\n
Other sales and services 866 918 (52) -5.7%
\n
Total IFRS 15 revenue 82,483 102,648 (20,165) -19.6%
\n
Sale of commodities under contracts with physical settlement 8,875 37, 247 (28,372) -76.2%
\n
Gain/(Loss) on the measurement of commodity sales contracts with
\n
physical settlement closed during the period
\n
1,508 (4,260) 5,768 -
\n
Other revenue 16 18 (2) -11.1%
\n
Total revenue from sales and services 92,882 135,653 (42,771) -31.5%
\n
Revenue from the \u201csale of electricity\u201d amounted to
\n
\u20ac52,465 million, a decrease of \u20ac16,875 million compared
\n
with the previous year (-24.3%). The decrease mainly re-
\n
flected lower sales volumes against a background of de-
\n
creasing electricity sales prices, mainly in Italy (\u20ac9,873 mil-
\n
lion) and Spain (\u20ac6,916 million), reflecting the stabilization
\n
of markets.
\n
\u201cTransfers from institutional market operators\u201d increased
\n
by \u20ac163 million compared with the previous year, main-
\n
ly reflecting an increase in transfers in Italy (\u20ac334 million),
\n
primarily relating to the remuneration of the capacity
\n
market and the plan to maximize thermal generation from
\n
plants powered by alternative fuels to gas required by the
\n
Ministry of the Environment and Energy Security (MASE),
\n
which included a number of Enel Produzione SpA plants.
\n
The item was offset by a decrease in transfers in Argentina
\n
(\u20ac139 million) and Peru (\u20ac28 million).
\n
Revenue from the \u201csale of gas\u201d in 2023 amounted to
\n
\u20ac7,983 million (\u20ac8,970 million in 2022), a decrease of \u20ac987
\n
million compared with the previous year. The decrease is
\n
mainly attributable to a decrease in prices and the number
\n
of customers in Spain (\u20ac1,101 million), offset by the adjust-
\n
ment of offers to market prices (through indexation or re-
\n
structuring of contract conditions), partly offset by greater
\n
sales in Italy (\u20ac272 million).
\n
Revenue from the \u201csale of fuel\u201d decreased by \u20ac2,147 mil-
\n
lion due to decreasing gas sales prices in trading opera-
\n
tions. This was partially offset by higher sales in Spain.
\n
Revenue from \u201cconstruction contracts\u201d came to \u20ac995 mil-
\n
lion, a decrease of \u20ac677 million, attributable to the decline
\n
in development work on the distribution grid operated on
\n
concession basis in Brazil and mainly to the change in the
\n
Group consolidation scope following the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) in December 2022.
\n
Revenue from \u201csale of environmental certificates\u201d came to
\n
\u20ac283 million, up \u20ac172 million. The increase is mainly attrib-
\n
utable to higher sales of CO
\n
2
\n
allowances by Endesa Gen-
\n
eraci\u00f3n (\u20ac166 million).
\n
\u201cSale of value-added services\u201d came to \u20ac1,653 million,
\n
an increase of \u20ac269 million, mainly attributable to greater
\n
revenue from the sale of energy efficiency products and
\n
services connected with the maintenance, consulting,
\n
\n\n
\n\n
\n\n
repair and installation of energy efficient products in the
\n
e-Home and Vivi Meglio segments of Enel X in Italy (\u20ac123
\n
million), and greater revenue from the sale of value-added
\n
services in North America (\u20ac55 million) and Colombia (\u20ac21
\n
million).
\n
The decrease in revenue from the \u201csale of commodities
\n
under contracts with physical settlement\u201d, measured at
\n
fair value through profit or loss within the scope of IFRS
\n
9 (\u20ac28,372 million), mainly regards the sale of gas and re-
\n
flects a decrease in prices as well as in volumes handled.
\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
2023 2022 Change
\n
Fair value gain/(loss) on contracts for energy commodities with physical
\n
settlement (within the scope of IFRS 9) closed in the period
\n
Sales contracts
\n
Sale of electricity 1,550 5,436 (3,886) -71.5%
\n
Fair value gain/(loss) on closed contracts 281 (795) 1,076 -
\n
Total electricity 1,831 4,641 (2,810) -60.5%
\n
Sale of gas 7, 271 30,924 (23,653) -76.5%
\n
Fair value gain/(loss) on closed contracts 1,114 (3,600) 4,714 -
\n
Total gas 8,385 27,324 (18,939) -69.3%
\n
Sale of emissions allowances 4 875 (871) -99.5%
\n
Fair value gain/(loss) on closed contracts 109 131 (22) -16.8%
\n
Total emissions allowances 113 1,006 (893) -88.8%
\n
Sale of guarantees of origin 50 12 38 -
\n
Fair value gain/(loss) on closed contracts 4 4 - -
\n
Total guarantees of origin 54 16 38 -
\n
Total revenue 10,383 32,987 (22,604) -68.5%
\n
Purchase contracts
\n
Purchase of electricity 2,884 6,161 (3,277) -53.2%
\n
Fair value gain/(loss) on closed contracts 570 (200) 770 -
\n
Total electricity 3,454 5,961 (2,507) -42.1%
\n
Purchase of gas 8,063 33,092 (25,029) -75.6%
\n
Fair value gain/(loss) on closed contracts 1,370 (1,940) 3,310 -
\n
Total gas 9,433 31,152 (21,719) -69.7%
\n
Purchase of emissions allowances 624 843 (219) -26.0%
\n
Fair value gain/(loss) on closed contracts (31) 132 (163) -
\n
Total emissions allowances 593 975 (382) -39.2%
\n
Purchase of guarantees of origin 101 25 76 -
\n
Fair value gain/(loss) on closed contracts 32 3 29 -
\n
Total guarantees of origin 133 28 105 -
\n
Total costs 13,613 38,116 (24,503) -64.3%
\n
Net revenue/(costs) on contracts for energy commodities with physical
\n
settlement (within the scope of IFRS 9) closed in the period
\n
(3,230) (5,129) 1,899 37.0%
\n
Gain/(Loss) from measurement of outstanding contracts for energy
\n
commodities with physical settlement (within the scope of IFRS 9)
\n
Sales contracts
\n
Electricity 226 (134) 360 -
\n
Gas 136 4,841 (4,705) -97.2%
\n
Emissions allowances 23 490 (467) -95.3%
\n
Guarantees of origin 4 (15) 19 -
\n
Total 389 5,182 (4,793) -92.5%
\n
Purchase contracts
\n
Electricity 254 (124) 378 -
\n
Gas 586 3,879 (3,293) -84.9%
\n
Emissions allowances 19 627 (608) -97.0%
\n
Guarantees of origin 67 (72) 139 -
\n
Total 926 4,310 (3,384) -78.5%
\n
Gain/(Loss) from measurement of outstanding contracts for energy
\n
commodities with physical settlement (within the scope of IFRS 9)
\n
(537) 872 (1,409) -
\n
Total net revenue/(costs) on contracts with physical settlement (within the
\n
scope of IFRS 9)
\n
(3,767) (4,257) 490 11.5%
\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 table.
\n
Millions of euro 2023
\n
Italy Iberia Rest of the World
\n
Other, eliminations and
\n
adjustments Total
\n
Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time
\n
Total IFRS 15 revenue 36,982 1,169 23,063 1,973 17, 887 1,342 13 54 77,945 4,538
\n
2022
\n
Italy Iberia Rest of the World
\n
Other, eliminations and
\n
adjustments Total
\n
Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time
\n
Total IFRS 15 revenue 47,650 2,068 30,984 1,425 19,061 1,307 10 143 97,70 5 4,943
\n
The table below gives a breakdown of revenue from sales
\n
and services by geographical segment.
\n
Millions of euro
\n
2023 2022
\n
Italy 39,724 57,8 5 9
\n
Europe
\n
Iberia 21,799 30,535
\n
France 1,919 3,086
\n
Switzerland 1,936 6,791
\n
Germany 1,028 1,676
\n
Austria 75 189
\n
Slovenia 10 146
\n
Romania 4 3
\n
Greece 6 15
\n
Belgium 13 834
\n
Czech Republic 180 321
\n
Hungary 13 7
\n
Netherlands 145 38
\n
United Kingdom 4,523 11,841
\n
Other European countries 2,299 1,551
\n
Americas
\n
United States 864 779
\n
Canada 62 53
\n
Mexico 315 313
\n
Brazil 7,621 9,064
\n
Chile 4,369 4,434
\n
Peru 1,565 1,449
\n
Colombia 3,248 2,725
\n
Argentina 613 966
\n
Panama 200 177
\n
Costa Rica 17 17
\n
Guatemala 81 83
\n
Other
\n
Africa 96 132
\n
Asia 119 521
\n
Oceania 38 48
\n
Total 92,882 135,653
\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 es-
\n
timates 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
\n
these contracts with customers for the sale of electricity, the
\n
Group carefully analyzes the facts and circumstances applicable
\n
to each contract.
\n
For the sale of electricity on power exchanges, the facts
\n
and circumstances (including the intrinsic characteristics of
\n
the commodity, contractual terms, information regarding
\n
infrastructure and other delivery mechanisms) generally indicate
\n
that the performance obligation is a service in which the
\n
customer simultaneously receives and consumes the benefits
\n
of the commodity as it is delivered. Thus, the Group identifies
\n
a performance obligation satisfied over time as part of a series
\n
of distinct goods/services (i.e. each unit of commodity) that are
\n
substantially the same and have the same pattern of transfer to
\n
the customer.
\n
The Group applies an output method to recognize
\n
revenue from the sale of electricity on power exchanges,
\n
recognized over time, so as to recognize revenue in the
\n
amount to which it has a right to invoice the customer
\n
if that amount corresponds directly with the value to
\n
the customer of the performance completed to date,
\n
i.e. at the price defined in the market (without variable
\n
consideration).
\n
Network
\n
connection
\n
services
\n
The network connection fees received from customers for
\n
connecting them to the electricity/gas distribution networks
\n
require a specific Group assessment to take into consideration
\n
all terms and conditions of the connection arrangements.
\n
This assessment is intended to determine whether the contract
\n
includes other distinct goods or services, such as for example
\n
the right to obtain ongoing access to the infrastructure in order
\n
to receive the commodity or, when the connection fee is a \u201cnon-
\n
refundable up-front fee\u201d paid at or near contract inception, a
\n
material right that gives rise to a performance obligation.
\n
In particular, in some countries in which the Group operates, it
\n
has determined that the nature of the consideration received
\n
represents a \u201cnon-refundable up-front fee\u201d whose payment
\n
provides a material right to the customer. In order to determine
\n
if the period over which this material right should be recognized
\n
extends beyond the initial contractual period, the Group takes
\n
into consideration the applicable local legal and regulatory
\n
framework applicable to the contract and affecting the parties. In
\n
such cases, if there is an implied assignment of the material right
\n
and an obligation from the initial customer to the new customer,
\n
the Group recognizes the connection fee over a period beyond
\n
the relationship with the initial customer, considering the
\n
concession terms as the period during which the initial customer
\n
and any future customer can benefit from the ongoing access
\n
without paying an additional connection fee. As a consequence,
\n
the fee is recognized over the period for which the payment
\n
creates an obligation for the Group to make the lower prices
\n
available to future customers (i.e. the period during which the
\n
customer is expected to benefit from the ongoing access
\n
service without having to pay an \u201cup-front fee\u201d upon renewal).
\n
Revenue from monetary and in-kind fees for connection
\n
to the electricity and gas distribution network is
\n
recognized on the basis of the satisfaction of the
\n
performance obligations included in the contract. The
\n
identification of distinct goods or services requires
\n
a careful analysis of the terms and conditions of the
\n
connection arrangements, which could vary from country
\n
to country based on the local context, regulations and
\n
law. In order to finalize this assessment, the Group
\n
considers not only the characteristics of the goods/
\n
services themselves (i.e. the good or service is capable
\n
of being distinct) but also the implied promises for which
\n
the customer has a valid expectation as it views those
\n
promises as part of the negotiated exchange, that is
\n
goods/services that the customer expects to receive
\n
and has paid for (i.e. the promise to transfer the good or
\n
service to the customer is separately identifiable from
\n
other promises in the contract).
\n
Furthermore, the Group acts as an agent in some
\n
contracts for electricity/gas network connection services
\n
and other related activities, depending on local legal
\n
and regulatory framework. In such cases, it recognizes
\n
revenue on a net basis, corresponding to any fee or
\n
commission to which 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
\n
includes a single performance obligation (sale and transport
\n
of the commodity) because the Group has determined that
\n
the contract does not provide distinct goods/services and the
\n
promise is satisfied by transferring control over the commodity
\n
to the customer when it is delivered at the point of delivery.
\n
In order to determine the nature of the promise included in
\n
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
\n
provided for in a repetitive service contract, such as a
\n
supply contract for the provision of electricity/gas to end
\n
users, is typically satisfied over time (because the customer
\n
simultaneously receives and consumes the benefits of the
\n
commodity as it is delivered) as part of a series of distinct goods/
\n
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 recognize
\n
revenue from the sale and transport of electricity/gas
\n
to end users, so as to recognize revenue in the amount
\n
to which 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, i.e. the
\n
quantities provided during the period, even if these have
\n
not yet been invoiced; this revenue is determined using
\n
estimates as well as periodic meter readings. Where
\n
applicable, this revenue is based on the rates and related
\n
restrictions established by law or by the Regulatory
\n
Authority for Energy, Networks and the Environment
\n
(ARERA) and analogous foreign authorities during the
\n
applicable period.
\n
\n\n
\n\n
\n
\n\n
Construction
\n
contracts
\n
The construction contracts typically include a performance
\n
obligation satisfied over time. For these contracts, the Group
\n
generally considers it appropriate to use an input method for
\n
measuring progress, except when a specific contract analysis
\n
suggests the use of an alternative method that better depicts
\n
the Group\u2019s performance obligation fulfilled at the reporting date.
\n
For construction contracts that include a performance
\n
obligation satisfied over time, the Group recognizes
\n
revenue over time by measuring progress toward the
\n
complete satisfaction of that performance obligation.
\n
The cost-to-cost method is generally considered
\n
the best method to depict the Group\u2019s performance
\n
obligation fulfilled at the reporting date.
\n
The amount due from customers under a construction
\n
contract is presented as a contract asset; the amount
\n
due to customers under a construction contract is
\n
presented as a contract liability.
\n
Service concession
\n
arrangements
\n
(within the scope
\n
of IFRIC 12)
\n
The Group, as concession holder, provides services for the
\n
construction/upgrade of the infrastructure used for the
\n
provision of public services and/or services for the operation
\n
and maintenance of the infrastructure itself for the period of the
\n
concession.
\n
For performance obligations related to infrastructure
\n
construction and improvement, please refer to the section
\n
\u201cConstruction contracts\u201d.
\n
As far as revenue from operating services are concerned, please
\n
refer to the sections \u201cSale of electricity produced by the Group\u201d
\n
and \u201cSale/transport of electricity/gas to end users\u201d.
\n
When the Group provides construction/upgrade
\n
services, it recognizes intangible assets and/or financial
\n
assets, depending on the characteristics of the service
\n
concession arrangement.
\n
The amounts received or receivable relating to both
\n
components are initially recognized as revenue from
\n
contracts with customers. For more details on revenue
\n
recognition, please refer to the section \u201cConstruction
\n
contracts\u201d.
\n
Furthermore, the component recognized in profit or
\n
loss deriving from the remeasurement at fair value of
\n
the financial assets in respect of service concession
\n
agreements for the distribution business in Brazil is
\n
also classified as revenue, in order to adequately reflect
\n
the business model in line with the related concession
\n
agreement.
\n
Revenues from management and maintenance activities
\n
are recognized as revenue from the sale of electricity on
\n
the market or to end users (please refer to sections \u201cSale
\n
of electricity produced by the Group\u201d and \u201cSale/transport
\n
of electricity/gas to end users\u201d, respectively).
\n
\n\n\n
\n\n
11.b Other income \u2013 \u20ac2,683 million
\n
Millions of euro
\n
2023 2022 Change
\n
Grants for environmental certificates
\n
(1)
\n
346 220 126 57.3 %
\n
Other operating grants 9 28 (19) -67.9%
\n
Capital grants (electricity and gas business) 28 28 - -
\n
Sundry reimbursements 314 314 - -
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
584 1,876 (1,292) -68.9%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
44 64 (20) -31.3%
\n
Service continuity bonuses 13 31 (18) -58.1%
\n
Other income 1,345 2,303 (958) -41.6%
\n
Total 2,683 4,864 (2,181) -44.8%
\n
(1) For more on \u201cGrants for environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Gains on the disposal of entities amounted to \u20ac584 million
\n
in 2023, mainly reflecting the recognition by Enel CIEN (in
\n
Brazil) of \u20ac99 million for the end-of-concession indemni-
\n
ty received for the takeover of the concession by another
\n
entity, the overall income of \u20ac103 million from the partial
\n
sale with loss of control of assets held in Australia, the gain
\n
on the sale of Arcadia Generaci\u00f3n Solar (\u20ac195 million) and
\n
the remeasurement at fair value of the residual interest in
\n
Enel Green Power Hellas (\u20ac160 million).
\n
In 2022, the item mainly included the recognition of gains
\n
on the disposal by Enel X International of 1.1% of the in-
\n
vestment in Ufinet (\u20ac220 million), the sale by Enel X Srl of
\n
financial companies to Mooney (\u20ac67 million), the sale of
\n
50% of the investment held by Enel Grids in Gridspertise
\n
(\u20ac520 million) and the sale of Enel Chile\u2019s interest in Enel
\n
Transmisi\u00f3n Chile.
\n
\u201cOther income\u201d decreased by \u20ac958 million, mainly due to
\n
the decrease of income of Enel Generaci\u00f3n Chile (\u20ac456
\n
million), mainly in respect of the contractual agreement
\n
with Shell, the modification of which generated an in-
\n
crease in 2022; the decrease in the income connected
\n
with the electricity business recognized in Argentina (\u20ac219
\n
million) following the agreements concluded in 2022 be-
\n
\n\n
\n\n
\n\n
\n\n
\n\n
tween Edesur and the local authorities, as well as the de-
\n
crease in Enel Green Power North America in income from
\n
tax partnerships (\u20ac127 million).
\n
The following tables show a breakdown of total revenue
\n
by business line based on the approach used by manage-
\n
ment to monitor the Group\u2019s performance during the two
\n
years being compared.
\n
Millions of euro 2023
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 26,354 9,982 19,719 51,630 2,004 109,689 (27,206) 82,483
\n
Sale of commodities under
\n
contracts with physical settlement
\n
12,374 - - 6 - 12,380 (3,505) 8,875
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
1,504 - - 4 - 1,508 - 1,508
\n
Other revenue 6 3 18 1 16 44 (28) 16
\n
Total revenue from sales and
\n
services
\n
40,238 9,985 19,737 51,641 2,020 123,621 (30,739) 92,882
\n
Other income (48) 1,635 522 478 25 2,612 71 2,683
\n
TOTAL REVENUE 40,190 11,620 20,259 52,119 2,045 126,233 (30,668) 95,565
\n
Millions of euro 2022
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
(1)
\n
Holding
\n
and
\n
Services
\n
(1)
\n
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 63,476 1,993 131,340 (28,692) 102,648
\n
Sale of commodities under
\n
contracts with physical settlement
\n
42,667 - - 26 - 42,693 (5,446) 37, 247
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
(4,240) - - (20) - (4,260) - (4,260)
\n
Other revenue - 6 13 1 22 42 (24) 18
\n
Total revenue from sales and
\n
services
\n
75,581 7, 869 20,867 63,483 2,015 169,815 (34,162) 135,653
\n
Other income 754 1,298 2,165 867 35 5,119 (255) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 64,350 2,050 174,934 (34,417) 140,517
\n
(1) The figures for 2022 for the End-user Market Business Line have been adjusted to take account of the values for Enel X and Enel X Way. The latter had
\n
previously been reported under Holding, Services and Other.
\n
\n\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag92": { "value": "\n
11.a Revenue from sales and services \u2013 \u20ac92,882 million
\n
Millions of euro
\n
2023 2022 Change
\n
Sale of electricity 52,465 69,340 (16,875) -24.3%
\n
Transport of electricity 11,123 11,096 27 0.2%
\n
Fees from network operators 1,142 979 163 16.6%
\n
Transfers from institutional market operators 1,570 1,667 (97) -5.8%
\n
Sale of gas 7,983 8,970 (987) -11.0%
\n
Transport of gas 68 80 (12) -15.0%
\n
Sale of fuel 3,458 5,605 (2,147) -38.3%
\n
Fees for connection to electricity and gas networks 877 826 51 6.2%
\n
Construction contracts 995 1,672 (677) -40.5%
\n
Sale of environmental certificates 283 111 172 -
\n
Sale of value-added services 1,653 1,384 269 19.4%
\n
Other sales and services 866 918 (52) -5.7%
\n
Total IFRS 15 revenue 82,483 102,648 (20,165) -19.6%
\n
Sale of commodities under contracts with physical settlement 8,875 37, 247 (28,372) -76.2%
\n
Gain/(Loss) on the measurement of commodity sales contracts with
\n
physical settlement closed during the period
\n
1,508 (4,260) 5,768 -
\n
Other revenue 16 18 (2) -11.1%
\n
Total revenue from sales and services 92,882 135,653 (42,771) -31.5%
\n
Revenue from the \u201csale of electricity\u201d amounted to
\n
\u20ac52,465 million, a decrease of \u20ac16,875 million compared
\n
with the previous year (-24.3%). The decrease mainly re-
\n
flected lower sales volumes against a background of de-
\n
creasing electricity sales prices, mainly in Italy (\u20ac9,873 mil-
\n
lion) and Spain (\u20ac6,916 million), reflecting the stabilization
\n
of markets.
\n
\u201cTransfers from institutional market operators\u201d increased
\n
by \u20ac163 million compared with the previous year, main-
\n
ly reflecting an increase in transfers in Italy (\u20ac334 million),
\n
primarily relating to the remuneration of the capacity
\n
market and the plan to maximize thermal generation from
\n
plants powered by alternative fuels to gas required by the
\n
Ministry of the Environment and Energy Security (MASE),
\n
which included a number of Enel Produzione SpA plants.
\n
The item was offset by a decrease in transfers in Argentina
\n
(\u20ac139 million) and Peru (\u20ac28 million).
\n
Revenue from the \u201csale of gas\u201d in 2023 amounted to
\n
\u20ac7,983 million (\u20ac8,970 million in 2022), a decrease of \u20ac987
\n
million compared with the previous year. The decrease is
\n
mainly attributable to a decrease in prices and the number
\n
of customers in Spain (\u20ac1,101 million), offset by the adjust-
\n
ment of offers to market prices (through indexation or re-
\n
structuring of contract conditions), partly offset by greater
\n
sales in Italy (\u20ac272 million).
\n
Revenue from the \u201csale of fuel\u201d decreased by \u20ac2,147 mil-
\n
lion due to decreasing gas sales prices in trading opera-
\n
tions. This was partially offset by higher sales in Spain.
\n
Revenue from \u201cconstruction contracts\u201d came to \u20ac995 mil-
\n
lion, a decrease of \u20ac677 million, attributable to the decline
\n
in development work on the distribution grid operated on
\n
concession basis in Brazil and mainly to the change in the
\n
Group consolidation scope following the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) in December 2022.
\n
Revenue from \u201csale of environmental certificates\u201d came to
\n
\u20ac283 million, up \u20ac172 million. The increase is mainly attrib-
\n
utable to higher sales of CO
\n
2
\n
allowances by Endesa Gen-
\n
eraci\u00f3n (\u20ac166 million).
\n
\u201cSale of value-added services\u201d came to \u20ac1,653 million,
\n
an increase of \u20ac269 million, mainly attributable to greater
\n
revenue from the sale of energy efficiency products and
\n
services connected with the maintenance, consulting,
\n
\n\n
repair and installation of energy efficient products in the
\n
e-Home and Vivi Meglio segments of Enel X in Italy (\u20ac123
\n
million), and greater revenue from the sale of value-added
\n
services in North America (\u20ac55 million) and Colombia (\u20ac21
\n
million).
\n
The decrease in revenue from the \u201csale of commodities
\n
under contracts with physical settlement\u201d, measured at
\n
fair value through profit or loss within the scope of IFRS
\n
9 (\u20ac28,372 million), mainly regards the sale of gas and re-
\n
flects a decrease in prices as well as in volumes handled.
\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
2023 2022 Change
\n
Fair value gain/(loss) on contracts for energy commodities with physical
\n
settlement (within the scope of IFRS 9) closed in the period
\n
Sales contracts
\n
Sale of electricity 1,550 5,436 (3,886) -71.5%
\n
Fair value gain/(loss) on closed contracts 281 (795) 1,076 -
\n
Total electricity 1,831 4,641 (2,810) -60.5%
\n
Sale of gas 7, 271 30,924 (23,653) -76.5%
\n
Fair value gain/(loss) on closed contracts 1,114 (3,600) 4,714 -
\n
Total gas 8,385 27,324 (18,939) -69.3%
\n
Sale of emissions allowances 4 875 (871) -99.5%
\n
Fair value gain/(loss) on closed contracts 109 131 (22) -16.8%
\n
Total emissions allowances 113 1,006 (893) -88.8%
\n
Sale of guarantees of origin 50 12 38 -
\n
Fair value gain/(loss) on closed contracts 4 4 - -
\n
Total guarantees of origin 54 16 38 -
\n
Total revenue 10,383 32,987 (22,604) -68.5%
\n
Purchase contracts
\n
Purchase of electricity 2,884 6,161 (3,277) -53.2%
\n
Fair value gain/(loss) on closed contracts 570 (200) 770 -
\n
Total electricity 3,454 5,961 (2,507) -42.1%
\n
Purchase of gas 8,063 33,092 (25,029) -75.6%
\n
Fair value gain/(loss) on closed contracts 1,370 (1,940) 3,310 -
\n
Total gas 9,433 31,152 (21,719) -69.7%
\n
Purchase of emissions allowances 624 843 (219) -26.0%
\n
Fair value gain/(loss) on closed contracts (31) 132 (163) -
\n
Total emissions allowances 593 975 (382) -39.2%
\n
Purchase of guarantees of origin 101 25 76 -
\n
Fair value gain/(loss) on closed contracts 32 3 29 -
\n
Total guarantees of origin 133 28 105 -
\n
Total costs 13,613 38,116 (24,503) -64.3%
\n
Net revenue/(costs) on contracts for energy commodities with physical
\n
settlement (within the scope of IFRS 9) closed in the period
\n
(3,230) (5,129) 1,899 37.0%
\n
Gain/(Loss) from measurement of outstanding contracts for energy
\n
commodities with physical settlement (within the scope of IFRS 9)
\n
Sales contracts
\n
Electricity 226 (134) 360 -
\n
Gas 136 4,841 (4,705) -97.2%
\n
Emissions allowances 23 490 (467) -95.3%
\n
Guarantees of origin 4 (15) 19 -
\n
Total 389 5,182 (4,793) -92.5%
\n
Purchase contracts
\n
Electricity 254 (124) 378 -
\n
Gas 586 3,879 (3,293) -84.9%
\n
Emissions allowances 19 627 (608) -97.0%
\n
Guarantees of origin 67 (72) 139 -
\n
Total 926 4,310 (3,384) -78.5%
\n
Gain/(Loss) from measurement of outstanding contracts for energy
\n
commodities with physical settlement (within the scope of IFRS 9)
\n
(537) 872 (1,409) -
\n
Total net revenue/(costs) on contracts with physical settlement (within the
\n
scope of IFRS 9)
\n
(3,767) (4,257) 490 11.5%
\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 table.
\n
Millions of euro 2023
\n
Italy Iberia Rest of the World
\n
Other, eliminations and
\n
adjustments Total
\n
Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time
\n
Total IFRS 15 revenue 36,982 1,169 23,063 1,973 17, 887 1,342 13 54 77,945 4,538
\n
2022
\n
Italy Iberia Rest of the World
\n
Other, eliminations and
\n
adjustments Total
\n
Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time Over time
\n
Point in
\n
time
\n
Total IFRS 15 revenue 47,650 2,068 30,984 1,425 19,061 1,307 10 143 97,70 5 4,943
\n
The table below gives a breakdown of revenue from sales
\n
and services by geographical segment.
\n
Millions of euro
\n
2023 2022
\n
Italy 39,724 57,8 5 9
\n
Europe
\n
Iberia 21,799 30,535
\n
France 1,919 3,086
\n
Switzerland 1,936 6,791
\n
Germany 1,028 1,676
\n
Austria 75 189
\n
Slovenia 10 146
\n
Romania 4 3
\n
Greece 6 15
\n
Belgium 13 834
\n
Czech Republic 180 321
\n
Hungary 13 7
\n
Netherlands 145 38
\n
United Kingdom 4,523 11,841
\n
Other European countries 2,299 1,551
\n
Americas
\n
United States 864 779
\n
Canada 62 53
\n
Mexico 315 313
\n
Brazil 7,621 9,064
\n
Chile 4,369 4,434
\n
Peru 1,565 1,449
\n
Colombia 3,248 2,725
\n
Argentina 613 966
\n
Panama 200 177
\n
Costa Rica 17 17
\n
Guatemala 81 83
\n
Other
\n
Africa 96 132
\n
Asia 119 521
\n
Oceania 38 48
\n
Total 92,882 135,653
\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 es-
\n
timates 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
\n
these contracts with customers for the sale of electricity, the
\n
Group carefully analyzes the facts and circumstances applicable
\n
to each contract.
\n
For the sale of electricity on power exchanges, the facts
\n
and circumstances (including the intrinsic characteristics of
\n
the commodity, contractual terms, information regarding
\n
infrastructure and other delivery mechanisms) generally indicate
\n
that the performance obligation is a service in which the
\n
customer simultaneously receives and consumes the benefits
\n
of the commodity as it is delivered. Thus, the Group identifies
\n
a performance obligation satisfied over time as part of a series
\n
of distinct goods/services (i.e. each unit of commodity) that are
\n
substantially the same and have the same pattern of transfer to
\n
the customer.
\n
The Group applies an output method to recognize
\n
revenue from the sale of electricity on power exchanges,
\n
recognized over time, so as to recognize revenue in the
\n
amount to which it has a right to invoice the customer
\n
if that amount corresponds directly with the value to
\n
the customer of the performance completed to date,
\n
i.e. at the price defined in the market (without variable
\n
consideration).
\n
Network
\n
connection
\n
services
\n
The network connection fees received from customers for
\n
connecting them to the electricity/gas distribution networks
\n
require a specific Group assessment to take into consideration
\n
all terms and conditions of the connection arrangements.
\n
This assessment is intended to determine whether the contract
\n
includes other distinct goods or services, such as for example
\n
the right to obtain ongoing access to the infrastructure in order
\n
to receive the commodity or, when the connection fee is a \u201cnon-
\n
refundable up-front fee\u201d paid at or near contract inception, a
\n
material right that gives rise to a performance obligation.
\n
In particular, in some countries in which the Group operates, it
\n
has determined that the nature of the consideration received
\n
represents a \u201cnon-refundable up-front fee\u201d whose payment
\n
provides a material right to the customer. In order to determine
\n
if the period over which this material right should be recognized
\n
extends beyond the initial contractual period, the Group takes
\n
into consideration the applicable local legal and regulatory
\n
framework applicable to the contract and affecting the parties. In
\n
such cases, if there is an implied assignment of the material right
\n
and an obligation from the initial customer to the new customer,
\n
the Group recognizes the connection fee over a period beyond
\n
the relationship with the initial customer, considering the
\n
concession terms as the period during which the initial customer
\n
and any future customer can benefit from the ongoing access
\n
without paying an additional connection fee. As a consequence,
\n
the fee is recognized over the period for which the payment
\n
creates an obligation for the Group to make the lower prices
\n
available to future customers (i.e. the period during which the
\n
customer is expected to benefit from the ongoing access
\n
service without having to pay an \u201cup-front fee\u201d upon renewal).
\n
Revenue from monetary and in-kind fees for connection
\n
to the electricity and gas distribution network is
\n
recognized on the basis of the satisfaction of the
\n
performance obligations included in the contract. The
\n
identification of distinct goods or services requires
\n
a careful analysis of the terms and conditions of the
\n
connection arrangements, which could vary from country
\n
to country based on the local context, regulations and
\n
law. In order to finalize this assessment, the Group
\n
considers not only the characteristics of the goods/
\n
services themselves (i.e. the good or service is capable
\n
of being distinct) but also the implied promises for which
\n
the customer has a valid expectation as it views those
\n
promises as part of the negotiated exchange, that is
\n
goods/services that the customer expects to receive
\n
and has paid for (i.e. the promise to transfer the good or
\n
service to the customer is separately identifiable from
\n
other promises in the contract).
\n
Furthermore, the Group acts as an agent in some
\n
contracts for electricity/gas network connection services
\n
and other related activities, depending on local legal
\n
and regulatory framework. In such cases, it recognizes
\n
revenue on a net basis, corresponding to any fee or
\n
commission to which 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
\n
includes a single performance obligation (sale and transport
\n
of the commodity) because the Group has determined that
\n
the contract does not provide distinct goods/services and the
\n
promise is satisfied by transferring control over the commodity
\n
to the customer when it is delivered at the point of delivery.
\n
In order to determine the nature of the promise included in
\n
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
\n
provided for in a repetitive service contract, such as a
\n
supply contract for the provision of electricity/gas to end
\n
users, is typically satisfied over time (because the customer
\n
simultaneously receives and consumes the benefits of the
\n
commodity as it is delivered) as part of a series of distinct goods/
\n
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 recognize
\n
revenue from the sale and transport of electricity/gas
\n
to end users, so as to recognize revenue in the amount
\n
to which 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, i.e. the
\n
quantities provided during the period, even if these have
\n
not yet been invoiced; this revenue is determined using
\n
estimates as well as periodic meter readings. Where
\n
applicable, this revenue is based on the rates and related
\n
restrictions established by law or by the Regulatory
\n
Authority for Energy, Networks and the Environment
\n
(ARERA) and analogous foreign authorities during the
\n
applicable period.
\n
\n\n
Construction
\n
contracts
\n
The construction contracts typically include a performance
\n
obligation satisfied over time. For these contracts, the Group
\n
generally considers it appropriate to use an input method for
\n
measuring progress, except when a specific contract analysis
\n
suggests the use of an alternative method that better depicts
\n
the Group\u2019s performance obligation fulfilled at the reporting date.
\n
For construction contracts that include a performance
\n
obligation satisfied over time, the Group recognizes
\n
revenue over time by measuring progress toward the
\n
complete satisfaction of that performance obligation.
\n
The cost-to-cost method is generally considered
\n
the best method to depict the Group\u2019s performance
\n
obligation fulfilled at the reporting date.
\n
The amount due from customers under a construction
\n
contract is presented as a contract asset; the amount
\n
due to customers under a construction contract is
\n
presented as a contract liability.
\n
Service concession
\n
arrangements
\n
(within the scope
\n
of IFRIC 12)
\n
The Group, as concession holder, provides services for the
\n
construction/upgrade of the infrastructure used for the
\n
provision of public services and/or services for the operation
\n
and maintenance of the infrastructure itself for the period of the
\n
concession.
\n
For performance obligations related to infrastructure
\n
construction and improvement, please refer to the section
\n
\u201cConstruction contracts\u201d.
\n
As far as revenue from operating services are concerned, please
\n
refer to the sections \u201cSale of electricity produced by the Group\u201d
\n
and \u201cSale/transport of electricity/gas to end users\u201d.
\n
When the Group provides construction/upgrade
\n
services, it recognizes intangible assets and/or financial
\n
assets, depending on the characteristics of the service
\n
concession arrangement.
\n
The amounts received or receivable relating to both
\n
components are initially recognized as revenue from
\n
contracts with customers. For more details on revenue
\n
recognition, please refer to the section \u201cConstruction
\n
contracts\u201d.
\n
Furthermore, the component recognized in profit or
\n
loss deriving from the remeasurement at fair value of
\n
the financial assets in respect of service concession
\n
agreements for the distribution business in Brazil is
\n
also classified as revenue, in order to adequately reflect
\n
the business model in line with the related concession
\n
agreement.
\n
Revenues from management and maintenance activities
\n
are recognized as revenue from the sale of electricity on
\n
the market or to end users (please refer to sections \u201cSale
\n
of electricity produced by the Group\u201d and \u201cSale/transport
\n
of electricity/gas to end users\u201d, respectively).
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag93": { "value": "\n
\n\n
11.b Other income \u2013 \u20ac2,683 million
\n
Millions of euro
\n
2023 2022 Change
\n
Grants for environmental certificates
\n
(1)
\n
346 220 126 57.3 %
\n
Other operating grants 9 28 (19) -67.9%
\n
Capital grants (electricity and gas business) 28 28 - -
\n
Sundry reimbursements 314 314 - -
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
584 1,876 (1,292) -68.9%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
44 64 (20) -31.3%
\n
Service continuity bonuses 13 31 (18) -58.1%
\n
Other income 1,345 2,303 (958) -41.6%
\n
Total 2,683 4,864 (2,181) -44.8%
\n
(1) For more on \u201cGrants for environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Gains on the disposal of entities amounted to \u20ac584 million
\n
in 2023, mainly reflecting the recognition by Enel CIEN (in
\n
Brazil) of \u20ac99 million for the end-of-concession indemni-
\n
ty received for the takeover of the concession by another
\n
entity, the overall income of \u20ac103 million from the partial
\n
sale with loss of control of assets held in Australia, the gain
\n
on the sale of Arcadia Generaci\u00f3n Solar (\u20ac195 million) and
\n
the remeasurement at fair value of the residual interest in
\n
Enel Green Power Hellas (\u20ac160 million).
\n
In 2022, the item mainly included the recognition of gains
\n
on the disposal by Enel X International of 1.1% of the in-
\n
vestment in Ufinet (\u20ac220 million), the sale by Enel X Srl of
\n
financial companies to Mooney (\u20ac67 million), the sale of
\n
50% of the investment held by Enel Grids in Gridspertise
\n
(\u20ac520 million) and the sale of Enel Chile\u2019s interest in Enel
\n
Transmisi\u00f3n Chile.
\n
\u201cOther income\u201d decreased by \u20ac958 million, mainly due to
\n
the decrease of income of Enel Generaci\u00f3n Chile (\u20ac456
\n
million), mainly in respect of the contractual agreement
\n
with Shell, the modification of which generated an in-
\n
crease in 2022; the decrease in the income connected
\n
with the electricity business recognized in Argentina (\u20ac219
\n
million) following the agreements concluded in 2022 be-
\n
\n\n
\n\n
\n\n
tween Edesur and the local authorities, as well as the de-
\n
crease in Enel Green Power North America in income from
\n
tax partnerships (\u20ac127 million).
\n
The following tables show a breakdown of total revenue
\n
by business line based on the approach used by manage-
\n
ment to monitor the Group\u2019s performance during the two
\n
years being compared.
\n
Millions of euro 2023
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 26,354 9,982 19,719 51,630 2,004 109,689 (27,206) 82,483
\n
Sale of commodities under
\n
contracts with physical settlement
\n
12,374 - - 6 - 12,380 (3,505) 8,875
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
1,504 - - 4 - 1,508 - 1,508
\n
Other revenue 6 3 18 1 16 44 (28) 16
\n
Total revenue from sales and
\n
services
\n
40,238 9,985 19,737 51,641 2,020 123,621 (30,739) 92,882
\n
Other income (48) 1,635 522 478 25 2,612 71 2,683
\n
TOTAL REVENUE 40,190 11,620 20,259 52,119 2,045 126,233 (30,668) 95,565
\n
Millions of euro 2022
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
(1)
\n
Holding
\n
and
\n
Services
\n
(1)
\n
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 63,476 1,993 131,340 (28,692) 102,648
\n
Sale of commodities under
\n
contracts with physical settlement
\n
42,667 - - 26 - 42,693 (5,446) 37, 247
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
(4,240) - - (20) - (4,260) - (4,260)
\n
Other revenue - 6 13 1 22 42 (24) 18
\n
Total revenue from sales and
\n
services
\n
75,581 7, 869 20,867 63,483 2,015 169,815 (34,162) 135,653
\n
Other income 754 1,298 2,165 867 35 5,119 (255) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 64,350 2,050 174,934 (34,417) 140,517
\n
(1) The figures for 2022 for the End-user Market Business Line have been adjusted to take account of the values for Enel X and Enel X Way. The latter had
\n
previously been reported under Holding, Services and Other.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag94": { "value": "\n
11.b Other income \u2013 \u20ac2,683 million
\n
Millions of euro
\n
2023 2022 Change
\n
Grants for environmental certificates
\n
(1)
\n
346 220 126 57.3 %
\n
Other operating grants 9 28 (19) -67.9%
\n
Capital grants (electricity and gas business) 28 28 - -
\n
Sundry reimbursements 314 314 - -
\n
Gains on the disposal of subsidiaries, associates, joint ventures, joint
\n
operations and non-current assets held for sale
\n
584 1,876 (1,292) -68.9%
\n
Gains on the disposal of property, plant and equipment, and intangible
\n
assets
\n
44 64 (20) -31.3%
\n
Service continuity bonuses 13 31 (18) -58.1%
\n
Other income 1,345 2,303 (958) -41.6%
\n
Total 2,683 4,864 (2,181) -44.8%
\n
(1) For more on \u201cGrants for environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Gains on the disposal of entities amounted to \u20ac584 million
\n
in 2023, mainly reflecting the recognition by Enel CIEN (in
\n
Brazil) of \u20ac99 million for the end-of-concession indemni-
\n
ty received for the takeover of the concession by another
\n
entity, the overall income of \u20ac103 million from the partial
\n
sale with loss of control of assets held in Australia, the gain
\n
on the sale of Arcadia Generaci\u00f3n Solar (\u20ac195 million) and
\n
the remeasurement at fair value of the residual interest in
\n
Enel Green Power Hellas (\u20ac160 million).
\n
In 2022, the item mainly included the recognition of gains
\n
on the disposal by Enel X International of 1.1% of the in-
\n
vestment in Ufinet (\u20ac220 million), the sale by Enel X Srl of
\n
financial companies to Mooney (\u20ac67 million), the sale of
\n
50% of the investment held by Enel Grids in Gridspertise
\n
(\u20ac520 million) and the sale of Enel Chile\u2019s interest in Enel
\n
Transmisi\u00f3n Chile.
\n
\u201cOther income\u201d decreased by \u20ac958 million, mainly due to
\n
the decrease of income of Enel Generaci\u00f3n Chile (\u20ac456
\n
million), mainly in respect of the contractual agreement
\n
with Shell, the modification of which generated an in-
\n
crease in 2022; the decrease in the income connected
\n
with the electricity business recognized in Argentina (\u20ac219
\n
million) following the agreements concluded in 2022 be-
\n
\n\n
tween Edesur and the local authorities, as well as the de-
\n
crease in Enel Green Power North America in income from
\n
tax partnerships (\u20ac127 million).
\n
The following tables show a breakdown of total revenue
\n
by business line based on the approach used by manage-
\n
ment to monitor the Group\u2019s performance during the two
\n
years being compared.
\n
Millions of euro 2023
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
Holding
\n
and
\n
Services
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 26,354 9,982 19,719 51,630 2,004 109,689 (27,206) 82,483
\n
Sale of commodities under
\n
contracts with physical settlement
\n
12,374 - - 6 - 12,380 (3,505) 8,875
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
1,504 - - 4 - 1,508 - 1,508
\n
Other revenue 6 3 18 1 16 44 (28) 16
\n
Total revenue from sales and
\n
services
\n
40,238 9,985 19,737 51,641 2,020 123,621 (30,739) 92,882
\n
Other income (48) 1,635 522 478 25 2,612 71 2,683
\n
TOTAL REVENUE 40,190 11,620 20,259 52,119 2,045 126,233 (30,668) 95,565
\n
Millions of euro 2022
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power
\n
Enel
\n
Grids
\n
End-user
\n
Markets
\n
(1)
\n
Holding
\n
and
\n
Services
\n
(1)
\n
\n
Total
\n
reporting
\n
segment
\n
Eliminations
\n
and
\n
adjustments Total
\n
Total IFRS 15 revenue 37,154 7,863 20,854 63,476 1,993 131,340 (28,692) 102,648
\n
Sale of commodities under
\n
contracts with physical settlement
\n
42,667 - - 26 - 42,693 (5,446) 37, 247
\n
Gain/(Loss) on the measurement
\n
of commodity sales contracts with
\n
physical settlement closed during
\n
the period
\n
(4,240) - - (20) - (4,260) - (4,260)
\n
Other revenue - 6 13 1 22 42 (24) 18
\n
Total revenue from sales and
\n
services
\n
75,581 7, 869 20,867 63,483 2,015 169,815 (34,162) 135,653
\n
Other income 754 1,298 2,165 867 35 5,119 (255) 4,864
\n
TOTAL REVENUE 76,335 9,167 23,032 64,350 2,050 174,934 (34,417) 140,517
\n
(1) The figures for 2022 for the End-user Market Business Line have been adjusted to take account of the values for Enel X and Enel X Way. The latter had
\n
previously been reported under Holding, Services and Other.
\n
\n\n
12.f Other operating costs \u2013 \u20ac6,125 million
\n
Millions of euro
\n
2023 2022 Change
\n
System charges \u2013 Environmental certificates
\n
(1)
\n
2,603 2,510 93 3.7%
\n
Other costs connected with electrical and gas system 568 172 396 -
\n
Other taxes and duties 1,529 1,107 422 38.1%
\n
Capital losses and other costs on the disposal of equity investments 404 363 41 11.3%
\n
Extraordinary solidarity levies 208 - 208 -
\n
Other 813 533 280 52.5%
\n
Total 6,125 4,685 1,440 30.7%
\n
(1) For more on \u201cSystem charges \u2013 Environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Other operating costs increased by \u20ac1,440 million com-
\n
pared with the previous year due to the following.
\n
\u201cOther costs connected with electrical and gas system\u201d
\n
increased by \u20ac396 million, mainly due to:
\n
\u2022
\n
the increased impact of the Bono Social in Spain (\u20ac246
\n
million), mainly attributable to the recognition in 2022
\n
of an indemnity of \u20ac152 million following Supreme
\n
Court ruling no. 202/2022;
\n
\u2022
\n
an increase in indemnities and penalties connected
\n
with service quality in Italy provided for under the Regu-
\n
latory Authority for Energy, Networks and Environment
\n
(ARERA) Resolution no. 566/2019/R/eel charged to dis-
\n
tributors (\u20ac118 million).
\n
\u201cOther taxes and duties\u201d increased by \u20ac422 million, main-
\n
ly due to the clawback mechanism in Italy (\u20ac357 million)
\n
introduced with Decree Law 25 of March 28, 2022 and in
\n
Spain (\u20ac118 million) as a result of Royal Decree 17/2021.
\n
The change was partly offset by a decrease in charges for
\n
the occupation of public land in Spain (\u20ac76 million) as a
\n
result of a reduction in fees.
\n
\u201cCapital losses and other costs on the disposal of equity
\n
investments\u201d in 2023 mainly include the capital losses on
\n
the disposal of Enel Generaci\u00f3n Costanera (\u20ac132 million)
\n
and Central Dock Sud (\u20ac194 million) in Argentina and the
\n
price adjustment in respect of the disposal of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac23 million). In 2022
\n
the item mainly referred to capital losses recognized for
\n
the disposal of Enel Goi\u00e1s (\u20ac208 million) and CGT Fortale-
\n
za (\u20ac135 million) in Brazil.
\n
\u201cExtraordinary solidarity levies\u201d regard the extraordinary
\n
solidarity levy recognized, in 2023, in Spain (\u20ac208 million)
\n
following the approval of Law 38 of December 27, 2022.
\n
The increase in \u201cother\u201d operating costs is mainly attrib-
\n
utable to an increase in provisions for risks and charges
\n
recognized by Enel Insurance in response to claims con-
\n
nected with adverse weather events.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag95": { "value": "\n
\n\n
Costs
\n
12.a Electricity, gas and fuel \u2013 \u20ac46,270 million
\n
Millions of euro
\n
2023 2022 Change
\n
Electricity 24,098 47, 15 5 (23,057) -48.9%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 2,884 6,161 (3,277) -53.2%
\n
Gas 16,583 47,930 (31,347) -65.4%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 8,063 33,092 (25,029) -75.6%
\n
Fair value gain/(loss) on contracts for purchase of electricity and gas with
\n
physical settlement closed during the period
\n
1,940 (2,140) 4,080 -
\n
Nuclear fuel 99 111 (12) -10.8%
\n
Other fuels 3,550 3,840 (290) -7.6%
\n
Total 46,270 96,896 (50,626) -52.2%
\n
\u201cElectricity\u201d purchases decreased due to a decrease in
\n
volumes purchased and a decline in average prices com-
\n
pared with the previous year, mainly attributable to Italy
\n
(\u20ac17,942 million) and Spain (\u20ac4,833 million).
\n
The decrease in costs for \u201cgas\u201d purchases mainly reflects
\n
the decrease in average prices for gas purchases, which
\n
also had a significant impact on the measurement of con-
\n
tracts with physical settlement, as well as the decrease in
\n
volumes handled, mainly in Italy and Spain.
\n
The item also includes charges of \u20ac515 million recognized
\n
related to the settlement of an arbitration dispute with a
\n
Qatari gas supplier in Spain.
\n
\n
Results of the fair value measurement of purchases of gas
\n
under contracts with physical settlement closed increased
\n
by \u20ac4,080 million compared with the previous year, of
\n
which \u20ac3,311 million attributable to gas and \u20ac769 million
\n
to electricity.
\n
The decrease in \u201cother fuels\u201d is mainly attributable to the
\n
decrease in volumes purchased.
\n
12.b Services and other materials \u2013 \u20ac18,304 million
\n
Millions of euro
\n
2023 2022 Change
\n
Wheeling 7,781 8,247 (466) -5.7%
\n
Maintenance and repairs 1,134 1,067 67 6.3%
\n
Telephone and postal costs 168 181 (13) -7. 2 %
\n
Communication services 120 117 3 2.6%
\n
IT services 840 872 (32) -3.7%
\n
Leases and rentals 534 503 31 6.2%
\n
Other services 4,980 5,707 (727) -12.7%
\n
Environmental certificates not used for compliance 1,002 963 39 4.0%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 725 868 (143) -16.5%
\n
Fair value gain/(loss) on contracts for purchase of environmental certificates
\n
with physical settlement closed during the period
\n
1 135 (134) -99.3%
\n
Change in inventories of environmental certificates (593) (97) (496) -
\n
Other materials 2,337 2,533 (196) -7.7%
\n
Total 18,304 20,228 (1,924) -9.5%
\n
Costs for services and other materials amounted to
\n
\u20ac18,304 million in 2023, a decrease of \u20ac1,924 million com-
\n
pared with 2022. This change essentially reflected:
\n
\u2022
\n
a decrease of \u20ac466 million in costs for \u201cwheeling\u201d,
\n
mainly due to lower volumes in Italy and lower prices
\n
in Spain;
\n
\u2022
\n
a decrease of \u20ac727 million in \u201cother services\u201d essentially
\n
reflecting the decrease in costs for services connected
\n
\n\n
\n\n
\n\n
\n
with the electricity and gas business (\u20ac371 million) and
\n
those related to concessions in Brazil (\u20ac353 million);
\n
\u2022
\n
a decrease in costs of environmental certificates, in-
\n
cluding the change in inventories, essentially related to
\n
lower purchases of CO
\n
2
\n
allowances;
\n
\u2022
\n
a decrease in \u201cother materials\u201d mainly attributable to
\n
procurement costs due to changes in the consolida-
\n
tion scope.
\n\n
12.c Personnel expenses \u2013 \u20ac5,030 million
\n
Millions of euro
\n
2023 2022 Change
\n
Wages and salaries 3,498 3,442 56 1.6%
\n
Social security contributions 903 924 (21) -2.3%
\n
Italian post-employment benefits 114 107 7 6.5%
\n
Post-employment and other long-term benefits 67 73 (6) -8.2%
\n
Early retirement incentives 42 (20) 62 -
\n
Early retirement incentives connected with restructuring agreements 214 (151) 365 -
\n
Other costs 192 195 (3) -1.5%
\n
Total 5,030 4,570 460 10.1%
\n
Personnel expenses in 2023 amounted to \u20ac5,030 million,
\n
an increase of \u20ac460 million.
\n
The Group\u2019s workforce decreased by 4,069 employees,
\n
mainly reflecting the negative balance between new hires
\n
and terminations (201 employees) adding to negative
\n
changes in the consolidation scope (-3,868 employees),
\n
essentially attributable to:
\n
\u2022
\n
the sale of Enel Generaci\u00f3n Costanera SA in Argentina;
\n
\u2022
\n
the sale of Central Dock Sud SA in Argentina;
\n
\u2022
\n
the sale of Usme ZE SAS and Fontib\u00f3n ZE SAS in Co-
\n
lombia;
\n
\u2022
\n
the sale of Avikiran Solar India Private Limited in India;
\n
\u2022
\n
the sale of Enel Green Power Australia in Australia;
\n
\u2022
\n
the sale of all Romanian companies;
\n
\u2022
\n
the sale of Enel Green Power Hellas and all companies
\n
in Greece.
\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, Spain, Chile and Colombia.
\n
The \u20ac6 million decrease in \u201cpost-employment and other
\n
long-term benefits\u201d is mainly attributable to Latin America
\n
and Spain.
\n
The increase in \u201cearly retirement incentives\u201d and \u201cearly re-
\n
tirement incentives connected with restructuring agree-
\n
ments\u201d is mainly attributable to an increase in costs in
\n
Spain, following the \u20ac177 million adjustment of the pro-
\n
vision for the Acuerdo Voluntario de Salida (AVS) plan, and
\n
in Italy of the provision for restructuring and digitalization
\n
in respect of the framework agreement in application of
\n
Article 4, paragraphs 1-7-ter, of Law 92/2012 signed in
\n
2021, which required a negative adjustment in 2022 and
\n
a positive adjustment in 2023, according to the develop-
\n
ments of the period and changes underlying the actuarial
\n
assumptions.
\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, 2023.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
\n
2023 2022 at Dec. 31, 2023
\n
Senior managers 1 ,374 1,389 1,310
\n
Middle managers 12,589 12,528 12,389
\n
Office staff 33,906 35,676 31,308
\n
Blue collar 16,527 16,883 16,048
\n
Total 64,396 66,476 61,055
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013 \u20ac1,334
\n
million
\n
Millions of euro
\n
2023 2022 Change
\n
Impairment losses on trade receivables 1,384 1,375 9 0.7%
\n
Impairment losses on other financial assets 162 169 (7) -4.1%
\n
Total impairment losses on trade receivables and other financial assets 1,546 1,544 2 0.1%
\n
Impairment gains on trade receivables (210) (265) 55 20.8%
\n
Impairment gains on other financial assets (2) (1) (1) -
\n
Total impairment gains on trade receivables and other financial assets (212) (266) 54 20.3%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,334 1,278 56 4.4%
\n
The item, equal to \u20ac1,334 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
are essentially in line with the previous year.
\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac8,089 million
\n
Millions of euro
\n
2023 2022 Change
\n
Property, plant and equipment 4,674 4,472 202 4.5%
\n
Investment property 2 2 - -
\n
Intangible assets 1,677 1,612 65 4.0%
\n
Other impairment losses 1,792 1,414 378 26.7%
\n
Other reversals of impairment losses (56) (53) (3) -5.7%
\n
Total 8,089 7,4 47 642 8.6%
\n
The change in \u201cdepreciation, amortization and other im-
\n
pairment losses\u201d essentially reflected:
\n
\u2022
\n
higher depreciation and amortization due to new capi-
\n
tal expenditure, mainly in the sector of renewable ener-
\n
gy and distribution;
\n
\u2022
\n
the impairment losses on a number of renewables gen-
\n
eration companies (\u20ac1,268 million) in North America,
\n
mainly attributable to the deterioration in the outlook
\n
for certain markets, which was consolidated over the
\n
course of 2023, accompanied by a general deteriora-
\n
tion in macroeconomic conditions as well as redefined
\n
strategic and restructuring plans in the area;
\n
\u2022
\n
impairment losses recognized in 2023 on the assets of
\n
Enel X and Enel X Way (totaling \u20ac126 million) in North
\n
America;
\n
\u2022
\n
the impairment loss of \u20ac171 million on the Windpeshi
\n
wind project in Colombia as it was classified as held for
\n
sale;
\n
\u2022
\n
the value adjustments in 2022 of the net assets of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac827 million), CGT
\n
Fortaleza (\u20ac73 million) in Brazil, and net assets of Enel
\n
Generaci\u00f3n Costanera SA (\u20ac174 million) and Central
\n
Dock Sud SA (\u20ac116 million) in Argentina.
\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
12.f Other operating costs \u2013 \u20ac6,125 million
\n
Millions of euro
\n
2023 2022 Change
\n
System charges \u2013 Environmental certificates
\n
(1)
\n
2,603 2,510 93 3.7%
\n
Other costs connected with electrical and gas system 568 172 396 -
\n
Other taxes and duties 1,529 1,107 422 38.1%
\n
Capital losses and other costs on the disposal of equity investments 404 363 41 11.3%
\n
Extraordinary solidarity levies 208 - 208 -
\n
Other 813 533 280 52.5%
\n
Total 6,125 4,685 1,440 30.7%
\n
(1) For more on \u201cSystem charges \u2013 Environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Other operating costs increased by \u20ac1,440 million com-
\n
pared with the previous year due to the following.
\n
\u201cOther costs connected with electrical and gas system\u201d
\n
increased by \u20ac396 million, mainly due to:
\n
\u2022
\n
the increased impact of the Bono Social in Spain (\u20ac246
\n
million), mainly attributable to the recognition in 2022
\n
of an indemnity of \u20ac152 million following Supreme
\n
Court ruling no. 202/2022;
\n
\u2022
\n
an increase in indemnities and penalties connected
\n
with service quality in Italy provided for under the Regu-
\n
latory Authority for Energy, Networks and Environment
\n
(ARERA) Resolution no. 566/2019/R/eel charged to dis-
\n
tributors (\u20ac118 million).
\n
\u201cOther taxes and duties\u201d increased by \u20ac422 million, main-
\n
ly due to the clawback mechanism in Italy (\u20ac357 million)
\n
introduced with Decree Law 25 of March 28, 2022 and in
\n
Spain (\u20ac118 million) as a result of Royal Decree 17/2021.
\n
The change was partly offset by a decrease in charges for
\n
the occupation of public land in Spain (\u20ac76 million) as a
\n
result of a reduction in fees.
\n
\u201cCapital losses and other costs on the disposal of equity
\n
investments\u201d in 2023 mainly include the capital losses on
\n
the disposal of Enel Generaci\u00f3n Costanera (\u20ac132 million)
\n
and Central Dock Sud (\u20ac194 million) in Argentina and the
\n
price adjustment in respect of the disposal of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac23 million). In 2022
\n
the item mainly referred to capital losses recognized for
\n
the disposal of Enel Goi\u00e1s (\u20ac208 million) and CGT Fortale-
\n
za (\u20ac135 million) in Brazil.
\n
\u201cExtraordinary solidarity levies\u201d regard the extraordinary
\n
solidarity levy recognized, in 2023, in Spain (\u20ac208 million)
\n
following the approval of Law 38 of December 27, 2022.
\n
The increase in \u201cother\u201d operating costs is mainly attrib-
\n
utable to an increase in provisions for risks and charges
\n
recognized by Enel Insurance in response to claims con-
\n
nected with adverse weather events.
\n
\n\n
\n\n
12.g Capitalized costs \u2013 \u20ac(3,385) million
\n
Millions of euro
\n
2023 2022 Change
\n
Personnel (1,120) (1,184) 64 5.4%
\n
Materials (1,338) (1,258) (80) -6.4%
\n
Other (927) (973) 46 4.7%
\n
Total (3,385) (3,415) 30 0.9%
\n
Capitalized costs are in line with the previous year.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag96": { "value": "\n
Costs
\n
12.a Electricity, gas and fuel \u2013 \u20ac46,270 million
\n
Millions of euro
\n
2023 2022 Change
\n
Electricity 24,098 47, 15 5 (23,057) -48.9%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 2,884 6,161 (3,277) -53.2%
\n
Gas 16,583 47,930 (31,347) -65.4%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 8,063 33,092 (25,029) -75.6%
\n
Fair value gain/(loss) on contracts for purchase of electricity and gas with
\n
physical settlement closed during the period
\n
1,940 (2,140) 4,080 -
\n
Nuclear fuel 99 111 (12) -10.8%
\n
Other fuels 3,550 3,840 (290) -7.6%
\n
Total 46,270 96,896 (50,626) -52.2%
\n
\u201cElectricity\u201d purchases decreased due to a decrease in
\n
volumes purchased and a decline in average prices com-
\n
pared with the previous year, mainly attributable to Italy
\n
(\u20ac17,942 million) and Spain (\u20ac4,833 million).
\n
The decrease in costs for \u201cgas\u201d purchases mainly reflects
\n
the decrease in average prices for gas purchases, which
\n
also had a significant impact on the measurement of con-
\n
tracts with physical settlement, as well as the decrease in
\n
volumes handled, mainly in Italy and Spain.
\n
The item also includes charges of \u20ac515 million recognized
\n
related to the settlement of an arbitration dispute with a
\n
Qatari gas supplier in Spain.
\n
\n
Results of the fair value measurement of purchases of gas
\n
under contracts with physical settlement closed increased
\n
by \u20ac4,080 million compared with the previous year, of
\n
which \u20ac3,311 million attributable to gas and \u20ac769 million
\n
to electricity.
\n
The decrease in \u201cother fuels\u201d is mainly attributable to the
\n
decrease in volumes purchased.
\n
12.b Services and other materials \u2013 \u20ac18,304 million
\n
Millions of euro
\n
2023 2022 Change
\n
Wheeling 7,781 8,247 (466) -5.7%
\n
Maintenance and repairs 1,134 1,067 67 6.3%
\n
Telephone and postal costs 168 181 (13) -7. 2 %
\n
Communication services 120 117 3 2.6%
\n
IT services 840 872 (32) -3.7%
\n
Leases and rentals 534 503 31 6.2%
\n
Other services 4,980 5,707 (727) -12.7%
\n
Environmental certificates not used for compliance 1,002 963 39 4.0%
\n
- of which purchases under contracts with physical settlement (IFRS 9) 725 868 (143) -16.5%
\n
Fair value gain/(loss) on contracts for purchase of environmental certificates
\n
with physical settlement closed during the period
\n
1 135 (134) -99.3%
\n
Change in inventories of environmental certificates (593) (97) (496) -
\n
Other materials 2,337 2,533 (196) -7.7%
\n
Total 18,304 20,228 (1,924) -9.5%
\n
Costs for services and other materials amounted to
\n
\u20ac18,304 million in 2023, a decrease of \u20ac1,924 million com-
\n
pared with 2022. This change essentially reflected:
\n
\u2022
\n
a decrease of \u20ac466 million in costs for \u201cwheeling\u201d,
\n
mainly due to lower volumes in Italy and lower prices
\n
in Spain;
\n
\u2022
\n
a decrease of \u20ac727 million in \u201cother services\u201d essentially
\n
reflecting the decrease in costs for services connected
\n
\n\n
\n
with the electricity and gas business (\u20ac371 million) and
\n
those related to concessions in Brazil (\u20ac353 million);
\n
\u2022
\n
a decrease in costs of environmental certificates, in-
\n
cluding the change in inventories, essentially related to
\n
lower purchases of CO
\n
2
\n
allowances;
\n
\u2022
\n
a decrease in \u201cother materials\u201d mainly attributable to
\n
procurement costs due to changes in the consolida-
\n
tion scope.
\n\n
12.c Personnel expenses \u2013 \u20ac5,030 million
\n
Millions of euro
\n
2023 2022 Change
\n
Wages and salaries 3,498 3,442 56 1.6%
\n
Social security contributions 903 924 (21) -2.3%
\n
Italian post-employment benefits 114 107 7 6.5%
\n
Post-employment and other long-term benefits 67 73 (6) -8.2%
\n
Early retirement incentives 42 (20) 62 -
\n
Early retirement incentives connected with restructuring agreements 214 (151) 365 -
\n
Other costs 192 195 (3) -1.5%
\n
Total 5,030 4,570 460 10.1%
\n
Personnel expenses in 2023 amounted to \u20ac5,030 million,
\n
an increase of \u20ac460 million.
\n
The Group\u2019s workforce decreased by 4,069 employees,
\n
mainly reflecting the negative balance between new hires
\n
and terminations (201 employees) adding to negative
\n
changes in the consolidation scope (-3,868 employees),
\n
essentially attributable to:
\n
\u2022
\n
the sale of Enel Generaci\u00f3n Costanera SA in Argentina;
\n
\u2022
\n
the sale of Central Dock Sud SA in Argentina;
\n
\u2022
\n
the sale of Usme ZE SAS and Fontib\u00f3n ZE SAS in Co-
\n
lombia;
\n
\u2022
\n
the sale of Avikiran Solar India Private Limited in India;
\n
\u2022
\n
the sale of Enel Green Power Australia in Australia;
\n
\u2022
\n
the sale of all Romanian companies;
\n
\u2022
\n
the sale of Enel Green Power Hellas and all companies
\n
in Greece.
\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, Spain, Chile and Colombia.
\n
The \u20ac6 million decrease in \u201cpost-employment and other
\n
long-term benefits\u201d is mainly attributable to Latin America
\n
and Spain.
\n
The increase in \u201cearly retirement incentives\u201d and \u201cearly re-
\n
tirement incentives connected with restructuring agree-
\n
ments\u201d is mainly attributable to an increase in costs in
\n
Spain, following the \u20ac177 million adjustment of the pro-
\n
vision for the Acuerdo Voluntario de Salida (AVS) plan, and
\n
in Italy of the provision for restructuring and digitalization
\n
in respect of the framework agreement in application of
\n
Article 4, paragraphs 1-7-ter, of Law 92/2012 signed in
\n
2021, which required a negative adjustment in 2022 and
\n
a positive adjustment in 2023, according to the develop-
\n
ments of the period and changes underlying the actuarial
\n
assumptions.
\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, 2023.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
\n
2023 2022 at Dec. 31, 2023
\n
Senior managers 1 ,374 1,389 1,310
\n
Middle managers 12,589 12,528 12,389
\n
Office staff 33,906 35,676 31,308
\n
Blue collar 16,527 16,883 16,048
\n
Total 64,396 66,476 61,055
\n
(1) For companies consolidated on a proportionate basis, the headcount corresponds to Enel\u2019s percentage share of the total.
\n
\n\n
\n\n
\n\n
\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013 \u20ac1,334
\n
million
\n
Millions of euro
\n
2023 2022 Change
\n
Impairment losses on trade receivables 1,384 1,375 9 0.7%
\n
Impairment losses on other financial assets 162 169 (7) -4.1%
\n
Total impairment losses on trade receivables and other financial assets 1,546 1,544 2 0.1%
\n
Impairment gains on trade receivables (210) (265) 55 20.8%
\n
Impairment gains on other financial assets (2) (1) (1) -
\n
Total impairment gains on trade receivables and other financial assets (212) (266) 54 20.3%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,334 1,278 56 4.4%
\n
The item, equal to \u20ac1,334 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
are essentially in line with the previous year.
\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac8,089 million
\n
Millions of euro
\n
2023 2022 Change
\n
Property, plant and equipment 4,674 4,472 202 4.5%
\n
Investment property 2 2 - -
\n
Intangible assets 1,677 1,612 65 4.0%
\n
Other impairment losses 1,792 1,414 378 26.7%
\n
Other reversals of impairment losses (56) (53) (3) -5.7%
\n
Total 8,089 7,4 47 642 8.6%
\n
The change in \u201cdepreciation, amortization and other im-
\n
pairment losses\u201d essentially reflected:
\n
\u2022
\n
higher depreciation and amortization due to new capi-
\n
tal expenditure, mainly in the sector of renewable ener-
\n
gy and distribution;
\n
\u2022
\n
the impairment losses on a number of renewables gen-
\n
eration companies (\u20ac1,268 million) in North America,
\n
mainly attributable to the deterioration in the outlook
\n
for certain markets, which was consolidated over the
\n
course of 2023, accompanied by a general deteriora-
\n
tion in macroeconomic conditions as well as redefined
\n
strategic and restructuring plans in the area;
\n
\u2022
\n
impairment losses recognized in 2023 on the assets of
\n
Enel X and Enel X Way (totaling \u20ac126 million) in North
\n
America;
\n
\u2022
\n
the impairment loss of \u20ac171 million on the Windpeshi
\n
wind project in Colombia as it was classified as held for
\n
sale;
\n
\u2022
\n
the value adjustments in 2022 of the net assets of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac827 million), CGT
\n
Fortaleza (\u20ac73 million) in Brazil, and net assets of Enel
\n
Generaci\u00f3n Costanera SA (\u20ac174 million) and Central
\n
Dock Sud SA (\u20ac116 million) in Argentina.
\n
\n\n
\n\n
\n\n
\n\n
\n\n
12.f Other operating costs \u2013 \u20ac6,125 million
\n
Millions of euro
\n
2023 2022 Change
\n
System charges \u2013 Environmental certificates
\n
(1)
\n
2,603 2,510 93 3.7%
\n
Other costs connected with electrical and gas system 568 172 396 -
\n
Other taxes and duties 1,529 1,107 422 38.1%
\n
Capital losses and other costs on the disposal of equity investments 404 363 41 11.3%
\n
Extraordinary solidarity levies 208 - 208 -
\n
Other 813 533 280 52.5%
\n
Total 6,125 4,685 1,440 30.7%
\n
(1) For more on \u201cSystem charges \u2013 Environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Other operating costs increased by \u20ac1,440 million com-
\n
pared with the previous year due to the following.
\n
\u201cOther costs connected with electrical and gas system\u201d
\n
increased by \u20ac396 million, mainly due to:
\n
\u2022
\n
the increased impact of the Bono Social in Spain (\u20ac246
\n
million), mainly attributable to the recognition in 2022
\n
of an indemnity of \u20ac152 million following Supreme
\n
Court ruling no. 202/2022;
\n
\u2022
\n
an increase in indemnities and penalties connected
\n
with service quality in Italy provided for under the Regu-
\n
latory Authority for Energy, Networks and Environment
\n
(ARERA) Resolution no. 566/2019/R/eel charged to dis-
\n
tributors (\u20ac118 million).
\n
\u201cOther taxes and duties\u201d increased by \u20ac422 million, main-
\n
ly due to the clawback mechanism in Italy (\u20ac357 million)
\n
introduced with Decree Law 25 of March 28, 2022 and in
\n
Spain (\u20ac118 million) as a result of Royal Decree 17/2021.
\n
The change was partly offset by a decrease in charges for
\n
the occupation of public land in Spain (\u20ac76 million) as a
\n
result of a reduction in fees.
\n
\u201cCapital losses and other costs on the disposal of equity
\n
investments\u201d in 2023 mainly include the capital losses on
\n
the disposal of Enel Generaci\u00f3n Costanera (\u20ac132 million)
\n
and Central Dock Sud (\u20ac194 million) in Argentina and the
\n
price adjustment in respect of the disposal of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac23 million). In 2022
\n
the item mainly referred to capital losses recognized for
\n
the disposal of Enel Goi\u00e1s (\u20ac208 million) and CGT Fortale-
\n
za (\u20ac135 million) in Brazil.
\n
\u201cExtraordinary solidarity levies\u201d regard the extraordinary
\n
solidarity levy recognized, in 2023, in Spain (\u20ac208 million)
\n
following the approval of Law 38 of December 27, 2022.
\n
The increase in \u201cother\u201d operating costs is mainly attrib-
\n
utable to an increase in provisions for risks and charges
\n
recognized by Enel Insurance in response to claims con-
\n
nected with adverse weather events.
\n
\n\n
\n\n
12.g Capitalized costs \u2013 \u20ac(3,385) million
\n
Millions of euro
\n
2023 2022 Change
\n
Personnel (1,120) (1,184) 64 5.4%
\n
Materials (1,338) (1,258) (80) -6.4%
\n
Other (927) (973) 46 4.7%
\n
Total (3,385) (3,415) 30 0.9%
\n
Capitalized costs are in line with the previous year.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag97": { "value": "\n
12.c Personnel expenses \u2013 \u20ac5,030 million
\n
Millions of euro
\n
2023 2022 Change
\n
Wages and salaries 3,498 3,442 56 1.6%
\n
Social security contributions 903 924 (21) -2.3%
\n
Italian post-employment benefits 114 107 7 6.5%
\n
Post-employment and other long-term benefits 67 73 (6) -8.2%
\n
Early retirement incentives 42 (20) 62 -
\n
Early retirement incentives connected with restructuring agreements 214 (151) 365 -
\n
Other costs 192 195 (3) -1.5%
\n
Total 5,030 4,570 460 10.1%
\n
Personnel expenses in 2023 amounted to \u20ac5,030 million,
\n
an increase of \u20ac460 million.
\n
The Group\u2019s workforce decreased by 4,069 employees,
\n
mainly reflecting the negative balance between new hires
\n
and terminations (201 employees) adding to negative
\n
changes in the consolidation scope (-3,868 employees),
\n
essentially attributable to:
\n
\u2022
\n
the sale of Enel Generaci\u00f3n Costanera SA in Argentina;
\n
\u2022
\n
the sale of Central Dock Sud SA in Argentina;
\n
\u2022
\n
the sale of Usme ZE SAS and Fontib\u00f3n ZE SAS in Co-
\n
lombia;
\n
\u2022
\n
the sale of Avikiran Solar India Private Limited in India;
\n
\u2022
\n
the sale of Enel Green Power Australia in Australia;
\n
\u2022
\n
the sale of all Romanian companies;
\n
\u2022
\n
the sale of Enel Green Power Hellas and all companies
\n
in Greece.
\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, Spain, Chile and Colombia.
\n
The \u20ac6 million decrease in \u201cpost-employment and other
\n
long-term benefits\u201d is mainly attributable to Latin America
\n
and Spain.
\n
The increase in \u201cearly retirement incentives\u201d and \u201cearly re-
\n
tirement incentives connected with restructuring agree-
\n
ments\u201d is mainly attributable to an increase in costs in
\n
Spain, following the \u20ac177 million adjustment of the pro-
\n
vision for the Acuerdo Voluntario de Salida (AVS) plan, and
\n
in Italy of the provision for restructuring and digitalization
\n
in respect of the framework agreement in application of
\n
Article 4, paragraphs 1-7-ter, of Law 92/2012 signed in
\n
2021, which required a negative adjustment in 2022 and
\n
a positive adjustment in 2023, according to the develop-
\n
ments of the period and changes underlying the actuarial
\n
assumptions.
\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, 2023.
\n
No. Average
\n
(1)
\n
Headcount
\n
(1)
\n
\n
2023 2022 at Dec. 31, 2023
\n
Senior managers 1 ,374 1,389 1,310
\n
Middle managers 12,589 12,528 12,389
\n
Office staff 33,906 35,676 31,308
\n
Blue collar 16,527 16,883 16,048
\n
Total 64,396 66,476 61,055
\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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag98": { "value": "\n
\n
12.d Net impairment/(reversals) on trade receivables and other receivables \u2013 \u20ac1,334
\n
million
\n
Millions of euro
\n
2023 2022 Change
\n
Impairment losses on trade receivables 1,384 1,375 9 0.7%
\n
Impairment losses on other financial assets 162 169 (7) -4.1%
\n
Total impairment losses on trade receivables and other financial assets 1,546 1,544 2 0.1%
\n
Impairment gains on trade receivables (210) (265) 55 20.8%
\n
Impairment gains on other financial assets (2) (1) (1) -
\n
Total impairment gains on trade receivables and other financial assets (212) (266) 54 20.3%
\n
NET IMPAIRMENT/(REVERSALS) ON TRADE RECEIVABLES AND OTHER
\n
FINANCIAL ASSETS
\n
1,334 1,278 56 4.4%
\n
The item, equal to \u20ac1,334 million, includes impairment
\n
losses and reversals on trade receivables and other finan-
\n
cial assets. The net impairment losses on trade receivables
\n
are essentially in line with the previous year.
\n\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac8,089 million
\n
Millions of euro
\n
2023 2022 Change
\n
Property, plant and equipment 4,674 4,472 202 4.5%
\n
Investment property 2 2 - -
\n
Intangible assets 1,677 1,612 65 4.0%
\n
Other impairment losses 1,792 1,414 378 26.7%
\n
Other reversals of impairment losses (56) (53) (3) -5.7%
\n
Total 8,089 7,4 47 642 8.6%
\n
The change in \u201cdepreciation, amortization and other im-
\n
pairment losses\u201d essentially reflected:
\n
\u2022
\n
higher depreciation and amortization due to new capi-
\n
tal expenditure, mainly in the sector of renewable ener-
\n
gy and distribution;
\n
\u2022
\n
the impairment losses on a number of renewables gen-
\n
eration companies (\u20ac1,268 million) in North America,
\n
mainly attributable to the deterioration in the outlook
\n
for certain markets, which was consolidated over the
\n
course of 2023, accompanied by a general deteriora-
\n
tion in macroeconomic conditions as well as redefined
\n
strategic and restructuring plans in the area;
\n
\u2022
\n
impairment losses recognized in 2023 on the assets of
\n
Enel X and Enel X Way (totaling \u20ac126 million) in North
\n
America;
\n
\u2022
\n
the impairment loss of \u20ac171 million on the Windpeshi
\n
wind project in Colombia as it was classified as held for
\n
sale;
\n
\u2022
\n
the value adjustments in 2022 of the net assets of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac827 million), CGT
\n
Fortaleza (\u20ac73 million) in Brazil, and net assets of Enel
\n
Generaci\u00f3n Costanera SA (\u20ac174 million) and Central
\n
Dock Sud SA (\u20ac116 million) in Argentina.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag99": { "value": "\n
12.e Depreciation, amortization and other impairment losses \u2013 \u20ac8,089 million
\n
Millions of euro
\n
2023 2022 Change
\n
Property, plant and equipment 4,674 4,472 202 4.5%
\n
Investment property 2 2 - -
\n
Intangible assets 1,677 1,612 65 4.0%
\n
Other impairment losses 1,792 1,414 378 26.7%
\n
Other reversals of impairment losses (56) (53) (3) -5.7%
\n
Total 8,089 7,4 47 642 8.6%
\n
The change in \u201cdepreciation, amortization and other im-
\n
pairment losses\u201d essentially reflected:
\n
\u2022
\n
higher depreciation and amortization due to new capi-
\n
tal expenditure, mainly in the sector of renewable ener-
\n
gy and distribution;
\n
\u2022
\n
the impairment losses on a number of renewables gen-
\n
eration companies (\u20ac1,268 million) in North America,
\n
mainly attributable to the deterioration in the outlook
\n
for certain markets, which was consolidated over the
\n
course of 2023, accompanied by a general deteriora-
\n
tion in macroeconomic conditions as well as redefined
\n
strategic and restructuring plans in the area;
\n
\u2022
\n
impairment losses recognized in 2023 on the assets of
\n
Enel X and Enel X Way (totaling \u20ac126 million) in North
\n
America;
\n
\u2022
\n
the impairment loss of \u20ac171 million on the Windpeshi
\n
wind project in Colombia as it was classified as held for
\n
sale;
\n
\u2022
\n
the value adjustments in 2022 of the net assets of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac827 million), CGT
\n
Fortaleza (\u20ac73 million) in Brazil, and net assets of Enel
\n
Generaci\u00f3n Costanera SA (\u20ac174 million) and Central
\n
Dock Sud SA (\u20ac116 million) in Argentina.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag100": { "value": "\n
\n\n
12.f Other operating costs \u2013 \u20ac6,125 million
\n
Millions of euro
\n
2023 2022 Change
\n
System charges \u2013 Environmental certificates
\n
(1)
\n
2,603 2,510 93 3.7%
\n
Other costs connected with electrical and gas system 568 172 396 -
\n
Other taxes and duties 1,529 1,107 422 38.1%
\n
Capital losses and other costs on the disposal of equity investments 404 363 41 11.3%
\n
Extraordinary solidarity levies 208 - 208 -
\n
Other 813 533 280 52.5%
\n
Total 6,125 4,685 1,440 30.7%
\n
(1) For more on \u201cSystem charges \u2013 Environmental certificates\u201d, please see note 58 \u201cEnvironmental programs\u201d.
\n
Other operating costs increased by \u20ac1,440 million com-
\n
pared with the previous year due to the following.
\n
\u201cOther costs connected with electrical and gas system\u201d
\n
increased by \u20ac396 million, mainly due to:
\n
\u2022
\n
the increased impact of the Bono Social in Spain (\u20ac246
\n
million), mainly attributable to the recognition in 2022
\n
of an indemnity of \u20ac152 million following Supreme
\n
Court ruling no. 202/2022;
\n
\u2022
\n
an increase in indemnities and penalties connected
\n
with service quality in Italy provided for under the Regu-
\n
latory Authority for Energy, Networks and Environment
\n
(ARERA) Resolution no. 566/2019/R/eel charged to dis-
\n
tributors (\u20ac118 million).
\n
\u201cOther taxes and duties\u201d increased by \u20ac422 million, main-
\n
ly due to the clawback mechanism in Italy (\u20ac357 million)
\n
introduced with Decree Law 25 of March 28, 2022 and in
\n
Spain (\u20ac118 million) as a result of Royal Decree 17/2021.
\n
The change was partly offset by a decrease in charges for
\n
the occupation of public land in Spain (\u20ac76 million) as a
\n
result of a reduction in fees.
\n
\u201cCapital losses and other costs on the disposal of equity
\n
investments\u201d in 2023 mainly include the capital losses on
\n
the disposal of Enel Generaci\u00f3n Costanera (\u20ac132 million)
\n
and Central Dock Sud (\u20ac194 million) in Argentina and the
\n
price adjustment in respect of the disposal of Celg Dis-
\n
tribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac23 million). In 2022
\n
the item mainly referred to capital losses recognized for
\n
the disposal of Enel Goi\u00e1s (\u20ac208 million) and CGT Fortale-
\n
za (\u20ac135 million) in Brazil.
\n
\u201cExtraordinary solidarity levies\u201d regard the extraordinary
\n
solidarity levy recognized, in 2023, in Spain (\u20ac208 million)
\n
following the approval of Law 38 of December 27, 2022.
\n
The increase in \u201cother\u201d operating costs is mainly attrib-
\n
utable to an increase in provisions for risks and charges
\n
recognized by Enel Insurance in response to claims con-
\n
nected with adverse weather events.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1083": { "value": "\n
13. Net results from commodity contracts \u2013 \u20ac(2,966) million
\n
Millions of euro
\n
2023 2022 Change
\n
Commodity derivatives
\n
- income from settled derivatives 7,315 23,124 (15,809) -68.4%
\n
- expense from settled derivatives 9,865 18,929 (9,064) -47.9%
\n
Net income/(expense) from settled commodity derivatives (2,550) 4,195 (6,745) -
\n
- income from outstanding derivatives (3,283) (2,479) (804) -32.4%
\n
- expense from outstanding derivatives (3,404) 223 (3,627) -
\n
Net income/(expense) from outstanding commodity derivatives 121 (2,702) 2,823 -
\n
Outstanding contracts for energy commodities with physical settlement
\n
- results from outstanding contracts to sell energy commodities with
\n
physical settlement
\n
389 5,182 (4,793) -92.5%
\n
- results from outstanding contracts to purchase energy commodities with
\n
physical settlement
\n
(926) (4,310) 3,384 78.5%
\n
Net results from outstanding contracts for energy commodities with
\n
physical settlement
\n
(537) 872 (1,409) -
\n
NET RESULTS FROM COMMODITY CONTRACTS (2,966) 2,365 (5,331) -
\n
Net results from commodity contracts showed net expense
\n
of \u20ac2,966 million in 2023 (net income of \u20ac2,365 million in
\n
2022), and break down as follows:
\n
\u2022
\n
net expense from commodity derivatives totaling
\n
\u20ac2,429 million (net income of \u20ac1,493 million in 2022), in-
\n
cluding derivatives designated as cash flow hedges and
\n
derivatives measured at fair value through profit or loss.
\n
More specifically, net expense from derivatives settled
\n
in the period amounted to \u20ac2,550 million (net income
\n
of \u20ac4,195 million in 2022) and net income from the fair
\n
value measurement of outstanding derivatives came to
\n
\u20ac121 million (net expense of \u20ac2,702 million in 2022);
\n
\u2022
\n
net expense 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 \u20ac537 million (net income of \u20ac872 million
\n
in 2022).
\n
For more information on derivatives, please see note 51
\n
\u201cDerivatives and hedge accounting\u201d.
\n

\n\n", "dimensions": { "concept": "enel:DisclosureOfNetResultsFromCommodityContracts", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1084": { "value": "\n

\n\n

\n\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(609) million
\n
Millions of euro
\n
2023 2022 Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 756 1,442 (686) -47.6%
\n
- income from derivatives at fair value through profit or loss 802 1,676 (874) -52.1%
\n
Total income 1,558 3,118 (1,560) -50.0%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,254) (1,744) 490 28.1%
\n
- expense from derivatives at fair value through profit or loss (913) (1,670) 757 45.3%
\n
Total expense (2,167) (3,414) 1,247 36.5%
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (609) (296) (313) -
\n
In 2023 net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac609 million (net expense of
\n
\u20ac296 million in 2022) and breaks down as follows:
\n
\u2022
\n
net expense from derivatives designated as hedging
\n
derivatives in the amount of \u20ac498 million (net expense
\n
of \u20ac302 million in 2022) mainly in regard of cash flow
\n
hedges;
\n
\u2022
\n
net expense from derivatives at fair value through profit
\n
or loss in the amount of \u20ac111 million (net income of \u20ac6
\n
million in 2022).
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n
The net balances recognized in 2023 and 2022 on both
\n
hedging derivatives and those at fair value through profit
\n
or loss mainly referred to the hedging of exchange rate
\n
risk. For more information on derivatives, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n

\n
15. Net other financial income/(expense) \u2013 \u20ac(2,766) million
\n\n

\n\n
Other financial income
\n
Millions of euro
\n
2023 2022 Change
\n
Interest income from financial assets (current and non-current):
\n
- interest income at effective rate on non-current financial assets 289 158 131 82.9%
\n
- interest income at effective rate on current financial investments 335 201 134 66.7%
\n
Total interest income at the effective interest rate 624 359 265 73.8%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
- - - -
\n
Exchange gains 1,807 2,289 (482) -21.1%
\n
Income on equity investments 3 1 2 -
\n
Income from hyperinflation 1,575 1,739 (164) -9.4%
\n
Other income 482 781 (299) -38.3%
\n
TOTAL OTHER FINANCIAL INCOME 4,491 5,169 (678) -13.1%
\n
Other financial income amounted to \u20ac4,491 million, a de-
\n
crease of \u20ac678 million on 2022. The change mainly reflects
\n
the following factors:
\n
\u2022
\n
a decrease in income from exchange gains (\u20ac482 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac370
\n
million) and Enel Global Trading (\u20ac82 million);
\n
\u2022
\n
a decrease in income from hyperinflation (\u20ac164 mil-
\n
lion), recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value
\n
hedge relationships (\u20ac159 million), and the change in
\n
the consolidation scope relating to the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac45 million);
\n
\u2022
\n
an increase in interest income at the effective rate
\n
(\u20ac265 million).
\n

\n\n\n

\n\n\n\n

\n\n
Other financial expense
\n
Millions of euro
\n
2023 2022 Change
\n
Interest expense on financial debt (current and non-current):
\n
- interest on bank borrowings 987 509 478 93.9%
\n
- interest expense on bonds 2,079 1,884 195 10.4%
\n
- interest expense on other borrowings 451 235 216 91.9%
\n
Total interest expense 3,517 2,628 889 33.8%
\n
Financial expense on debt management transactions 7 - 7 -
\n
Exchange losses 1,058 2,179 (1,121) -51.4%
\n
Adjustment to post-employment and other employee benefits 165 145 20 13.8%
\n
Adjustment to other provisions 255 201 54 26.9%
\n
Expense from equity investments - - - -
\n
Expense from hyperinflation 1,291 1,449 (158) -10.9%
\n
Other expenses 964 727 237 32.6%
\n
TOTAL OTHER FINANCIAL EXPENSE 7, 2 57 7, 329 (72) -1.0%
\n

\n\n\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n

\n\n
Other financial expense amounted to \u20ac7,257 million, an
\n
overall decrease of \u20ac72 million compared with 2022 es-
\n
sentially reflecting the following factors:
\n
\u2022
\n
a decrease in expense from hyperinflation of \u20ac158 mil-
\n
lion, recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in expense on exchange losses of \u20ac1,121
\n
million, mainly relating to Enel Finance International
\n
(\u20ac733 million) and Enel Global Trading (\u20ac217 million);
\n
\u2022
\n
an increase in interest expense of \u20ac889 million, mainly
\n
attributable to the increase in interest rates;
\n
\u2022
\n
an increase in other expenses mainly attributable to
\n
impairment losses on liabilities covered by fair value
\n
hedges (\u20ac126 million) and financial expense on the as-
\n
signment of receivables (\u20ac102 million).
\n

\n\n\n

\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1085": { "value": "\n

\n\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(609) million
\n
Millions of euro
\n
2023 2022 Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 756 1,442 (686) -47.6%
\n
- income from derivatives at fair value through profit or loss 802 1,676 (874) -52.1%
\n
Total income 1,558 3,118 (1,560) -50.0%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,254) (1,744) 490 28.1%
\n
- expense from derivatives at fair value through profit or loss (913) (1,670) 757 45.3%
\n
Total expense (2,167) (3,414) 1,247 36.5%
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (609) (296) (313) -
\n
In 2023 net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac609 million (net expense of
\n
\u20ac296 million in 2022) and breaks down as follows:
\n
\u2022
\n
net expense from derivatives designated as hedging
\n
derivatives in the amount of \u20ac498 million (net expense
\n
of \u20ac302 million in 2022) mainly in regard of cash flow
\n
hedges;
\n
\u2022
\n
net expense from derivatives at fair value through profit
\n
or loss in the amount of \u20ac111 million (net income of \u20ac6
\n
million in 2022).
\n

\n\n\n

\n\n\n

\n\n
The net balances recognized in 2023 and 2022 on both
\n
hedging derivatives and those at fair value through profit
\n
or loss mainly referred to the hedging of exchange rate
\n
risk. For more information on derivatives, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n

\n\n\n
Other financial expense
\n
Millions of euro
\n
2023 2022 Change
\n
Interest expense on financial debt (current and non-current):
\n
- interest on bank borrowings 987 509 478 93.9%
\n
- interest expense on bonds 2,079 1,884 195 10.4%
\n
- interest expense on other borrowings 451 235 216 91.9%
\n
Total interest expense 3,517 2,628 889 33.8%
\n
Financial expense on debt management transactions 7 - 7 -
\n
Exchange losses 1,058 2,179 (1,121) -51.4%
\n
Adjustment to post-employment and other employee benefits 165 145 20 13.8%
\n
Adjustment to other provisions 255 201 54 26.9%
\n
Expense from equity investments - - - -
\n
Expense from hyperinflation 1,291 1,449 (158) -10.9%
\n
Other expenses 964 727 237 32.6%
\n
TOTAL OTHER FINANCIAL EXPENSE 7, 2 57 7, 329 (72) -1.0%
\n

\n\n\n
Other financial expense amounted to \u20ac7,257 million, an
\n
overall decrease of \u20ac72 million compared with 2022 es-
\n
sentially reflecting the following factors:
\n
\u2022
\n
a decrease in expense from hyperinflation of \u20ac158 mil-
\n
lion, recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in expense on exchange losses of \u20ac1,121
\n
million, mainly relating to Enel Finance International
\n
(\u20ac733 million) and Enel Global Trading (\u20ac217 million);
\n
\u2022
\n
an increase in interest expense of \u20ac889 million, mainly
\n
attributable to the increase in interest rates;
\n
\u2022
\n
an increase in other expenses mainly attributable to
\n
impairment losses on liabilities covered by fair value
\n
hedges (\u20ac126 million) and financial expense on the as-
\n
signment of receivables (\u20ac102 million).
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1086": { "value": "\n
14. Net financial income/(expense) from derivatives \u2013 \u20ac(609) million
\n
Millions of euro
\n
2023 2022 Change
\n
Income:
\n
- income from derivatives designated as hedging derivatives 756 1,442 (686) -47.6%
\n
- income from derivatives at fair value through profit or loss 802 1,676 (874) -52.1%
\n
Total income 1,558 3,118 (1,560) -50.0%
\n
Expense:
\n
- expense from derivatives designated as hedging derivatives (1,254) (1,744) 490 28.1%
\n
- expense from derivatives at fair value through profit or loss (913) (1,670) 757 45.3%
\n
Total expense (2,167) (3,414) 1,247 36.5%
\n
NET FINANCIAL INCOME/(EXPENSE) FROM DERIVATIVES (609) (296) (313) -
\n
In 2023 net expense from derivatives on interest and ex-
\n
change rates amounted to \u20ac609 million (net expense of
\n
\u20ac296 million in 2022) and breaks down as follows:
\n
\u2022
\n
net expense from derivatives designated as hedging
\n
derivatives in the amount of \u20ac498 million (net expense
\n
of \u20ac302 million in 2022) mainly in regard of cash flow
\n
hedges;
\n
\u2022
\n
net expense from derivatives at fair value through profit
\n
or loss in the amount of \u20ac111 million (net income of \u20ac6
\n
million in 2022).
\n

\n\n\n
The net balances recognized in 2023 and 2022 on both
\n
hedging derivatives and those at fair value through profit
\n
or loss mainly referred to the hedging of exchange rate
\n
risk. For more information on derivatives, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\n\n
Other financial income
\n
Millions of euro
\n
2023 2022 Change
\n
Interest income from financial assets (current and non-current):
\n
- interest income at effective rate on non-current financial assets 289 158 131 82.9%
\n
- interest income at effective rate on current financial investments 335 201 134 66.7%
\n
Total interest income at the effective interest rate 624 359 265 73.8%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
- - - -
\n
Exchange gains 1,807 2,289 (482) -21.1%
\n
Income on equity investments 3 1 2 -
\n
Income from hyperinflation 1,575 1,739 (164) -9.4%
\n
Other income 482 781 (299) -38.3%
\n
TOTAL OTHER FINANCIAL INCOME 4,491 5,169 (678) -13.1%
\n
Other financial income amounted to \u20ac4,491 million, a de-
\n
crease of \u20ac678 million on 2022. The change mainly reflects
\n
the following factors:
\n
\u2022
\n
a decrease in income from exchange gains (\u20ac482 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac370
\n
million) and Enel Global Trading (\u20ac82 million);
\n
\u2022
\n
a decrease in income from hyperinflation (\u20ac164 mil-
\n
lion), recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value
\n
hedge relationships (\u20ac159 million), and the change in
\n
the consolidation scope relating to the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac45 million);
\n
\u2022
\n
an increase in interest income at the effective rate
\n
(\u20ac265 million).
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1087": { "value": "\n

\n

\n
15. Net other financial income/(expense) \u2013 \u20ac(2,766) million
\n\n

\n\n
Other financial income
\n
Millions of euro
\n
2023 2022 Change
\n
Interest income from financial assets (current and non-current):
\n
- interest income at effective rate on non-current financial assets 289 158 131 82.9%
\n
- interest income at effective rate on current financial investments 335 201 134 66.7%
\n
Total interest income at the effective interest rate 624 359 265 73.8%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
- - - -
\n
Exchange gains 1,807 2,289 (482) -21.1%
\n
Income on equity investments 3 1 2 -
\n
Income from hyperinflation 1,575 1,739 (164) -9.4%
\n
Other income 482 781 (299) -38.3%
\n
TOTAL OTHER FINANCIAL INCOME 4,491 5,169 (678) -13.1%
\n
Other financial income amounted to \u20ac4,491 million, a de-
\n
crease of \u20ac678 million on 2022. The change mainly reflects
\n
the following factors:
\n
\u2022
\n
a decrease in income from exchange gains (\u20ac482 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac370
\n
million) and Enel Global Trading (\u20ac82 million);
\n
\u2022
\n
a decrease in income from hyperinflation (\u20ac164 mil-
\n
lion), recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value
\n
hedge relationships (\u20ac159 million), and the change in
\n
the consolidation scope relating to the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac45 million);
\n
\u2022
\n
an increase in interest income at the effective rate
\n
(\u20ac265 million).
\n

\n\n\n

\n\n\n\n

\n\n
Other financial expense
\n
Millions of euro
\n
2023 2022 Change
\n
Interest expense on financial debt (current and non-current):
\n
- interest on bank borrowings 987 509 478 93.9%
\n
- interest expense on bonds 2,079 1,884 195 10.4%
\n
- interest expense on other borrowings 451 235 216 91.9%
\n
Total interest expense 3,517 2,628 889 33.8%
\n
Financial expense on debt management transactions 7 - 7 -
\n
Exchange losses 1,058 2,179 (1,121) -51.4%
\n
Adjustment to post-employment and other employee benefits 165 145 20 13.8%
\n
Adjustment to other provisions 255 201 54 26.9%
\n
Expense from equity investments - - - -
\n
Expense from hyperinflation 1,291 1,449 (158) -10.9%
\n
Other expenses 964 727 237 32.6%
\n
TOTAL OTHER FINANCIAL EXPENSE 7, 2 57 7, 329 (72) -1.0%
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n
Other financial expense amounted to \u20ac7,257 million, an
\n
overall decrease of \u20ac72 million compared with 2022 es-
\n
sentially reflecting the following factors:
\n
\u2022
\n
a decrease in expense from hyperinflation of \u20ac158 mil-
\n
lion, recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in expense on exchange losses of \u20ac1,121
\n
million, mainly relating to Enel Finance International
\n
(\u20ac733 million) and Enel Global Trading (\u20ac217 million);
\n
\u2022
\n
an increase in interest expense of \u20ac889 million, mainly
\n
attributable to the increase in interest rates;
\n
\u2022
\n
an increase in other expenses mainly attributable to
\n
impairment losses on liabilities covered by fair value
\n
hedges (\u20ac126 million) and financial expense on the as-
\n
signment of receivables (\u20ac102 million).
\n

\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1088": { "value": "\n

\n\n
Other financial income
\n
Millions of euro
\n
2023 2022 Change
\n
Interest income from financial assets (current and non-current):
\n
- interest income at effective rate on non-current financial assets 289 158 131 82.9%
\n
- interest income at effective rate on current financial investments 335 201 134 66.7%
\n
Total interest income at the effective interest rate 624 359 265 73.8%
\n
Financial income on non-current financial assets designated at fair value
\n
through profit or loss
\n
- - - -
\n
Exchange gains 1,807 2,289 (482) -21.1%
\n
Income on equity investments 3 1 2 -
\n
Income from hyperinflation 1,575 1,739 (164) -9.4%
\n
Other income 482 781 (299) -38.3%
\n
TOTAL OTHER FINANCIAL INCOME 4,491 5,169 (678) -13.1%
\n
Other financial income amounted to \u20ac4,491 million, a de-
\n
crease of \u20ac678 million on 2022. The change mainly reflects
\n
the following factors:
\n
\u2022
\n
a decrease in income from exchange gains (\u20ac482 mil-
\n
lion), mainly relating to Enel Finance International (\u20ac370
\n
million) and Enel Global Trading (\u20ac82 million);
\n
\u2022
\n
a decrease in income from hyperinflation (\u20ac164 mil-
\n
lion), recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in other income mainly deriving from the
\n
value adjustment of hedged liabilities in fair value
\n
hedge relationships (\u20ac159 million), and the change in
\n
the consolidation scope relating to the disposal of Celg
\n
Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s) (\u20ac45 million);
\n
\u2022
\n
an increase in interest income at the effective rate
\n
(\u20ac265 million).
\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1089": { "value": "\n

\n\n
Other financial expense
\n
Millions of euro
\n
2023 2022 Change
\n
Interest expense on financial debt (current and non-current):
\n
- interest on bank borrowings 987 509 478 93.9%
\n
- interest expense on bonds 2,079 1,884 195 10.4%
\n
- interest expense on other borrowings 451 235 216 91.9%
\n
Total interest expense 3,517 2,628 889 33.8%
\n
Financial expense on debt management transactions 7 - 7 -
\n
Exchange losses 1,058 2,179 (1,121) -51.4%
\n
Adjustment to post-employment and other employee benefits 165 145 20 13.8%
\n
Adjustment to other provisions 255 201 54 26.9%
\n
Expense from equity investments - - - -
\n
Expense from hyperinflation 1,291 1,449 (158) -10.9%
\n
Other expenses 964 727 237 32.6%
\n
TOTAL OTHER FINANCIAL EXPENSE 7, 2 57 7, 329 (72) -1.0%
\n

\n\n\n

\n\n\n

\n\n
Other financial expense amounted to \u20ac7,257 million, an
\n
overall decrease of \u20ac72 million compared with 2022 es-
\n
sentially reflecting the following factors:
\n
\u2022
\n
a decrease in expense from hyperinflation of \u20ac158 mil-
\n
lion, recognized by the Argentine companies as a re-
\n
sult of the application of IAS 29 on financial reporting
\n
in hyperinflationary economies; for more information,
\n
please see note 5 of these consolidated financial state-
\n
ments at December 31, 2023;
\n
\u2022
\n
a decrease in expense on exchange losses of \u20ac1,121
\n
million, mainly relating to Enel Finance International
\n
(\u20ac733 million) and Enel Global Trading (\u20ac217 million);
\n
\u2022
\n
an increase in interest expense of \u20ac889 million, mainly
\n
attributable to the increase in interest rates;
\n
\u2022
\n
an increase in other expenses mainly attributable to
\n
impairment losses on liabilities covered by fair value
\n
hedges (\u20ac126 million) and financial expense on the as-
\n
signment of receivables (\u20ac102 million).
\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1090": { "value": "\n

\n\n

\n\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac(41) million
\n
Millions of euro
\n
2023 2022 Change
\n
Share of profit of associates
\n
(1)
\n
68 81 (13) -16.0%
\n
Share of loss of associates (109) (141) 32 22.7%
\n
Total
\n
(1)
\n
(41) (60) 19 31.7%
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The share of the net loss of equity-accounted investments
\n
in 2023 came to \u20ac41 million, an increase of \u20ac19 million on
\n
2022.
\n
The change was essentially due to an increase in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac65 million) and Gridspertise (\u20ac9 million), part-
\n
ly offset by the decrease in the share of profit/(loss) of
\n
Mooney (\u20ac18 million), PowerCrop (\u20ac22 million), Enel Green
\n
Power Australia (\u20ac7 million) and Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas (\u20ac7 million).
\n

\n\n\n

\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "enel:DisclosureOfIncomeExpenseOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1091": { "value": "\n

\n\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac(41) million
\n
Millions of euro
\n
2023 2022 Change
\n
Share of profit of associates
\n
(1)
\n
68 81 (13) -16.0%
\n
Share of loss of associates (109) (141) 32 22.7%
\n
Total
\n
(1)
\n
(41) (60) 19 31.7%
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The share of the net loss of equity-accounted investments
\n
in 2023 came to \u20ac41 million, an increase of \u20ac19 million on
\n
2022.
\n
The change was essentially due to an increase in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac65 million) and Gridspertise (\u20ac9 million), part-
\n
ly offset by the decrease in the share of profit/(loss) of
\n
Mooney (\u20ac18 million), PowerCrop (\u20ac22 million), Enel Green
\n
Power Australia (\u20ac7 million) and Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas (\u20ac7 million).
\n

\n\n\n

\n\n\n

\n\n\n
26. Equity-accounted investments \u2013 \u20ac1,650 million
\n
The following table shows changes in the main invest-
\n
ments in joint ventures and associated companies ac-
\n
counted for using the equity method.
\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Joint ventures
\n
Gridspertise Srl 299 50.0% 9 - - - - - (2) 306 50.0%
\n
Mooney Group
\n
SpA
\n
219 50.0% (35) - - - - - 1 185 50.0%
\n
Slovak Power
\n
Holding
\n
90 50.0% - - - - - - 99 189 50.0%
\n
Enel Green
\n
Power Australia
\n
- (7) 142 - - - - 13 148 50.0%
\n
Enel Green
\n
Power Hellas
\n
- (1) 246 - - - - - 245 50.0%
\n
Matimba project
\n
companies
\n
108 50.0% (1) (15) - - - - (17) 75 50.0%
\n
Kino project
\n
companies
\n
16 20.0% (13) - - - - - (2) 1 20.0%
\n
Ewiva Srl 20 50.0% (3) - - - - - 22 39 50.0%
\n
Drift Sand Wind
\n
Project
\n
45 50.0% 1 - - - - - (1) 45 50.0%
\n
Front Mar\u00edtim del
\n
Bes\u00f2s
\n
31 61.4% (2) - - - - - 1 30 61.4%
\n
Elecgas SA 30 50.0% 6 - (13) - - - (2) 21 50.0%
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica
\n
5 43.8% - - - - - - - 5 43.8%
\n
Suministradora
\n
El\u00e9ctrica de
\n
C\u00e1diz
\n
9 33.5% 3 - (3) - - - (1) 8 33.5%
\n
Energie
\n
Electrique de
\n
Tahaddart
\n
11 32.0% 3 - (2) - - - (4) 8 32.0%
\n
Rusenergosbyt 91 49.5% 58 - - (115) - - (34) -
\n
PowerCrop 14 50.0% (6) - - - - - - 8 50.0%
\n
Total joint
\n
ventures
\n
988 12 373 (18) (115) - - 73 1,313
\n
\n\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Associates
\n
CESI 58 42.7% (2) - - - - - - 56 42.7%
\n
GNL Chile SA 14 33.3% 7 - - - - - (1) 20 33.3%
\n
Energ\u00edas
\n
Especiales del
\n
Bierzo
\n
12 50.0% 1 - (2) - - - (1) 10 50.0%
\n
Gorona del
\n
Viento El Hierro
\n
SA
\n
13 23.2% (6) - - - - - - 7 23.2%
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas
\n
7 37.5 % 1 - (1) - - - - 7 37.5 %
\n
Sociedad E\u00f3lica
\n
El Puntal
\n
4 50.0% 1 - (2) - - - 2 5 50.0%
\n
Renovables
\n
Brovales 400 kV
\n
- - - - - - - 5 5 64.2%
\n
Cogenio Iberia 5 20.0% - - - - - - 1 6 20.0%
\n
Cogenio Srl 9 20.0% - - - - - - (1) 8 20.0%
\n
Avikiran Solar
\n
India
\n
- (1) 29 - - - - (1) 27 51.0%
\n
Avikiran Surya
\n
India
\n
27 51.1% (1) - - - - - (2) 24 51.0%
\n
EGPNA
\n
Renewable
\n
Energy Partners
\n
77 10.0% 2 - - - - - (15) 64 10.0%
\n
Rocky Caney
\n
Holding
\n
22 10.0% 2 - - - - - (4) 20 10.0%
\n
Other minor 45 (57) 8 (2) - (1) - 85 78
\n
Total associates 293 (53) 37 (7) - (1) - 68 337
\n
TOTAL 1,281 (41) 410 (25) (115) (1) - 141 1,650
\n
The increase in equity accounted investments in 2023
\n
mainly reflected:
\n
\u2022
\n
changes in the consolidation scope, mainly regarding:
\n
\u2013
\n
the recognition of the interest in the joint ventures
\n
of Enel Green Power Australia (\u20ac142 million), follow-
\n
ing the sale, to INPEX Corporation, of a 50% stake in
\n
those companies, previously wholly owned and clas-
\n
sified as held for sale;
\n
\u2013
\n
the recognition of the interest in the joint venture
\n
Enel Green Power Hellas (\u20ac246 million), following
\n
the sale, to Macquarie Asset Management, of a 50%
\n
stake in the company, previously controlled by the
\n
Enel Group;
\n
\u2013
\n
the recognition of the interest in the associate Avi-
\n
kiran Solar India Private Limited (\u20ac 29 million) follow-
\n
ing the sale to Norfund of 49% of the company, with
\n
loss of control;
\n
\u2013
\n
the recognition of the negative price adjustment of
\n
the investment in the joint venture holding the com-
\n
panies of the Matimba project (\u20ac15 million);
\n
\u2022
\n
the recognition of the Group\u2019s share in changes in the
\n
OCI reserves (\u20ac98 million) mainly in respect of Slovak
\n
Power Holding and attributable to developments in the
\n
fair value of cash flow hedge derivatives of the com-
\n
pany.
\n
These positive effects were mainly offset by the reclassifi-
\n
cation under discontinued operations of the entire invest-
\n
ment in Rusenergosbyt (\u20ac115 million), which was then sold
\n
in 2023, as well as dividends distributed in the year in the
\n
amount of \u20ac25 million, mainly by Spanish companies, and
\n
adverse exchange rate developments.
\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
\n\n
Millions of euro Non-current assets Current assets Total assets Non-current liabilities Current liabilities Total liabilities Equity
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2023 2022 2023 2022 2023 2022
\n
Joint ventures
\n
Gridspertise Srl 418 334 23 12 17 8
\n
Mooney Group SpA 435 224 (70) (33) (70) (33)
\n
Slovak Power Holding 5,129 5,184 856 (320) 598 (223)
\n
Enel Green Power
\n
Australia
\n
37 - (28) - (28) -
\n
Enel Green Power Hellas 127 - 25 - 17 -
\n
Matimba project
\n
companies
\n
148 114 (8) (39) (2) (24)
\n
Ewiva Srl - - (6) (4) (6) (4)
\n
Associates
\n
CESI 164 155 (5) (4) (5) (1)
\n
Avikiran Solar India 15 - (6) - (6) -
\n
Avikiran Surya India 18 9 (3) 1 (3) 1
\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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1092": { "value": "\n

\n\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac(41) million
\n
Millions of euro
\n
2023 2022 Change
\n
Share of profit of associates
\n
(1)
\n
68 81 (13) -16.0%
\n
Share of loss of associates (109) (141) 32 22.7%
\n
Total
\n
(1)
\n
(41) (60) 19 31.7%
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The share of the net loss of equity-accounted investments
\n
in 2023 came to \u20ac41 million, an increase of \u20ac19 million on
\n
2022.
\n
The change was essentially due to an increase in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac65 million) and Gridspertise (\u20ac9 million), part-
\n
ly offset by the decrease in the share of profit/(loss) of
\n
Mooney (\u20ac18 million), PowerCrop (\u20ac22 million), Enel Green
\n
Power Australia (\u20ac7 million) and Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas (\u20ac7 million).
\n

\n\n\n

\n\n\n
\n\n
26. Equity-accounted investments \u2013 \u20ac1,650 million
\n
The following table shows changes in the main invest-
\n
ments in joint ventures and associated companies ac-
\n
counted for using the equity method.
\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Joint ventures
\n
Gridspertise Srl 299 50.0% 9 - - - - - (2) 306 50.0%
\n
Mooney Group
\n
SpA
\n
219 50.0% (35) - - - - - 1 185 50.0%
\n
Slovak Power
\n
Holding
\n
90 50.0% - - - - - - 99 189 50.0%
\n
Enel Green
\n
Power Australia
\n
- (7) 142 - - - - 13 148 50.0%
\n
Enel Green
\n
Power Hellas
\n
- (1) 246 - - - - - 245 50.0%
\n
Matimba project
\n
companies
\n
108 50.0% (1) (15) - - - - (17) 75 50.0%
\n
Kino project
\n
companies
\n
16 20.0% (13) - - - - - (2) 1 20.0%
\n
Ewiva Srl 20 50.0% (3) - - - - - 22 39 50.0%
\n
Drift Sand Wind
\n
Project
\n
45 50.0% 1 - - - - - (1) 45 50.0%
\n
Front Mar\u00edtim del
\n
Bes\u00f2s
\n
31 61.4% (2) - - - - - 1 30 61.4%
\n
Elecgas SA 30 50.0% 6 - (13) - - - (2) 21 50.0%
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica
\n
5 43.8% - - - - - - - 5 43.8%
\n
Suministradora
\n
El\u00e9ctrica de
\n
C\u00e1diz
\n
9 33.5% 3 - (3) - - - (1) 8 33.5%
\n
Energie
\n
Electrique de
\n
Tahaddart
\n
11 32.0% 3 - (2) - - - (4) 8 32.0%
\n
Rusenergosbyt 91 49.5% 58 - - (115) - - (34) -
\n
PowerCrop 14 50.0% (6) - - - - - - 8 50.0%
\n
Total joint
\n
ventures
\n
988 12 373 (18) (115) - - 73 1,313
\n
\n\n
\n\n
\n\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Associates
\n
CESI 58 42.7% (2) - - - - - - 56 42.7%
\n
GNL Chile SA 14 33.3% 7 - - - - - (1) 20 33.3%
\n
Energ\u00edas
\n
Especiales del
\n
Bierzo
\n
12 50.0% 1 - (2) - - - (1) 10 50.0%
\n
Gorona del
\n
Viento El Hierro
\n
SA
\n
13 23.2% (6) - - - - - - 7 23.2%
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas
\n
7 37.5 % 1 - (1) - - - - 7 37.5 %
\n
Sociedad E\u00f3lica
\n
El Puntal
\n
4 50.0% 1 - (2) - - - 2 5 50.0%
\n
Renovables
\n
Brovales 400 kV
\n
- - - - - - - 5 5 64.2%
\n
Cogenio Iberia 5 20.0% - - - - - - 1 6 20.0%
\n
Cogenio Srl 9 20.0% - - - - - - (1) 8 20.0%
\n
Avikiran Solar
\n
India
\n
- (1) 29 - - - - (1) 27 51.0%
\n
Avikiran Surya
\n
India
\n
27 51.1% (1) - - - - - (2) 24 51.0%
\n
EGPNA
\n
Renewable
\n
Energy Partners
\n
77 10.0% 2 - - - - - (15) 64 10.0%
\n
Rocky Caney
\n
Holding
\n
22 10.0% 2 - - - - - (4) 20 10.0%
\n
Other minor 45 (57) 8 (2) - (1) - 85 78
\n
Total associates 293 (53) 37 (7) - (1) - 68 337
\n
TOTAL 1,281 (41) 410 (25) (115) (1) - 141 1,650
\n
The increase in equity accounted investments in 2023
\n
mainly reflected:
\n
\u2022
\n
changes in the consolidation scope, mainly regarding:
\n
\u2013
\n
the recognition of the interest in the joint ventures
\n
of Enel Green Power Australia (\u20ac142 million), follow-
\n
ing the sale, to INPEX Corporation, of a 50% stake in
\n
those companies, previously wholly owned and clas-
\n
sified as held for sale;
\n
\u2013
\n
the recognition of the interest in the joint venture
\n
Enel Green Power Hellas (\u20ac246 million), following
\n
the sale, to Macquarie Asset Management, of a 50%
\n
stake in the company, previously controlled by the
\n
Enel Group;
\n
\u2013
\n
the recognition of the interest in the associate Avi-
\n
kiran Solar India Private Limited (\u20ac 29 million) follow-
\n
ing the sale to Norfund of 49% of the company, with
\n
loss of control;
\n
\u2013
\n
the recognition of the negative price adjustment of
\n
the investment in the joint venture holding the com-
\n
panies of the Matimba project (\u20ac15 million);
\n
\u2022
\n
the recognition of the Group\u2019s share in changes in the
\n
OCI reserves (\u20ac98 million) mainly in respect of Slovak
\n
Power Holding and attributable to developments in the
\n
fair value of cash flow hedge derivatives of the com-
\n
pany.
\n
These positive effects were mainly offset by the reclassifi-
\n
cation under discontinued operations of the entire invest-
\n
ment in Rusenergosbyt (\u20ac115 million), which was then sold
\n
in 2023, as well as dividends distributed in the year in the
\n
amount of \u20ac25 million, mainly by Spanish companies, and
\n
adverse exchange rate developments.
\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
\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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2023 2022 2023 2022 2023 2022
\n
Joint ventures
\n
Gridspertise Srl 418 334 23 12 17 8
\n
Mooney Group SpA 435 224 (70) (33) (70) (33)
\n
Slovak Power Holding 5,129 5,184 856 (320) 598 (223)
\n
Enel Green Power
\n
Australia
\n
37 - (28) - (28) -
\n
Enel Green Power Hellas 127 - 25 - 17 -
\n
Matimba project
\n
companies
\n
148 114 (8) (39) (2) (24)
\n
Ewiva Srl - - (6) (4) (6) (4)
\n
Associates
\n
CESI 164 155 (5) (4) (5) (1)
\n
Avikiran Solar India 15 - (6) - (6) -
\n
Avikiran Surya India 18 9 (3) 1 (3) 1
\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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1093": { "value": "\n
16. Share of profit/(loss) of equity-accounted investments \u2013 \u20ac(41) million
\n
Millions of euro
\n
2023 2022 Change
\n
Share of profit of associates
\n
(1)
\n
68 81 (13) -16.0%
\n
Share of loss of associates (109) (141) 32 22.7%
\n
Total
\n
(1)
\n
(41) (60) 19 31.7%
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n
The share of the net loss of equity-accounted investments
\n
in 2023 came to \u20ac41 million, an increase of \u20ac19 million on
\n
2022.
\n
The change was essentially due to an increase in the share
\n
of profit/(loss) pertaining to the Group of Slovak Power
\n
Holding (\u20ac65 million) and Gridspertise (\u20ac9 million), part-
\n
ly offset by the decrease in the share of profit/(loss) of
\n
Mooney (\u20ac18 million), PowerCrop (\u20ac22 million), Enel Green
\n
Power Australia (\u20ac7 million) and Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas (\u20ac7 million).
\n

\n\n\n
\n\n
\n\n
26. Equity-accounted investments \u2013 \u20ac1,650 million
\n
The following table shows changes in the main invest-
\n
ments in joint ventures and associated companies ac-
\n
counted for using the equity method.
\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Joint ventures
\n
Gridspertise Srl 299 50.0% 9 - - - - - (2) 306 50.0%
\n
Mooney Group
\n
SpA
\n
219 50.0% (35) - - - - - 1 185 50.0%
\n
Slovak Power
\n
Holding
\n
90 50.0% - - - - - - 99 189 50.0%
\n
Enel Green
\n
Power Australia
\n
- (7) 142 - - - - 13 148 50.0%
\n
Enel Green
\n
Power Hellas
\n
- (1) 246 - - - - - 245 50.0%
\n
Matimba project
\n
companies
\n
108 50.0% (1) (15) - - - - (17) 75 50.0%
\n
Kino project
\n
companies
\n
16 20.0% (13) - - - - - (2) 1 20.0%
\n
Ewiva Srl 20 50.0% (3) - - - - - 22 39 50.0%
\n
Drift Sand Wind
\n
Project
\n
45 50.0% 1 - - - - - (1) 45 50.0%
\n
Front Mar\u00edtim del
\n
Bes\u00f2s
\n
31 61.4% (2) - - - - - 1 30 61.4%
\n
Elecgas SA 30 50.0% 6 - (13) - - - (2) 21 50.0%
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica
\n
5 43.8% - - - - - - - 5 43.8%
\n
Suministradora
\n
El\u00e9ctrica de
\n
C\u00e1diz
\n
9 33.5% 3 - (3) - - - (1) 8 33.5%
\n
Energie
\n
Electrique de
\n
Tahaddart
\n
11 32.0% 3 - (2) - - - (4) 8 32.0%
\n
Rusenergosbyt 91 49.5% 58 - - (115) - - (34) -
\n
PowerCrop 14 50.0% (6) - - - - - - 8 50.0%
\n
Total joint
\n
ventures
\n
988 12 373 (18) (115) - - 73 1,313
\n
\n\n
\n\n
\n\n
\n\n
\n\n
Millions of euro % held
\n
Impact
\n
on profit
\n
or loss
\n
Change in the
\n
consolidation
\n
scope Dividends
\n
Reclassification
\n
to discontinued
\n
operations
\n
Reclassifications
\n
from/to assets
\n
held for sale Impairment
\n
Other
\n
changes % held
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Associates
\n
CESI 58 42.7% (2) - - - - - - 56 42.7%
\n
GNL Chile SA 14 33.3% 7 - - - - - (1) 20 33.3%
\n
Energ\u00edas
\n
Especiales del
\n
Bierzo
\n
12 50.0% 1 - (2) - - - (1) 10 50.0%
\n
Gorona del
\n
Viento El Hierro
\n
SA
\n
13 23.2% (6) - - - - - - 7 23.2%
\n
Compa\u00f1\u00eda E\u00f3lica
\n
Tierras Altas
\n
7 37.5 % 1 - (1) - - - - 7 37.5 %
\n
Sociedad E\u00f3lica
\n
El Puntal
\n
4 50.0% 1 - (2) - - - 2 5 50.0%
\n
Renovables
\n
Brovales 400 kV
\n
- - - - - - - 5 5 64.2%
\n
Cogenio Iberia 5 20.0% - - - - - - 1 6 20.0%
\n
Cogenio Srl 9 20.0% - - - - - - (1) 8 20.0%
\n
Avikiran Solar
\n
India
\n
- (1) 29 - - - - (1) 27 51.0%
\n
Avikiran Surya
\n
India
\n
27 51.1% (1) - - - - - (2) 24 51.0%
\n
EGPNA
\n
Renewable
\n
Energy Partners
\n
77 10.0% 2 - - - - - (15) 64 10.0%
\n
Rocky Caney
\n
Holding
\n
22 10.0% 2 - - - - - (4) 20 10.0%
\n
Other minor 45 (57) 8 (2) - (1) - 85 78
\n
Total associates 293 (53) 37 (7) - (1) - 68 337
\n
TOTAL 1,281 (41) 410 (25) (115) (1) - 141 1,650
\n
The increase in equity accounted investments in 2023
\n
mainly reflected:
\n
\u2022
\n
changes in the consolidation scope, mainly regarding:
\n
\u2013
\n
the recognition of the interest in the joint ventures
\n
of Enel Green Power Australia (\u20ac142 million), follow-
\n
ing the sale, to INPEX Corporation, of a 50% stake in
\n
those companies, previously wholly owned and clas-
\n
sified as held for sale;
\n
\u2013
\n
the recognition of the interest in the joint venture
\n
Enel Green Power Hellas (\u20ac246 million), following
\n
the sale, to Macquarie Asset Management, of a 50%
\n
stake in the company, previously controlled by the
\n
Enel Group;
\n
\u2013
\n
the recognition of the interest in the associate Avi-
\n
kiran Solar India Private Limited (\u20ac 29 million) follow-
\n
ing the sale to Norfund of 49% of the company, with
\n
loss of control;
\n
\u2013
\n
the recognition of the negative price adjustment of
\n
the investment in the joint venture holding the com-
\n
panies of the Matimba project (\u20ac15 million);
\n
\u2022
\n
the recognition of the Group\u2019s share in changes in the
\n
OCI reserves (\u20ac98 million) mainly in respect of Slovak
\n
Power Holding and attributable to developments in the
\n
fair value of cash flow hedge derivatives of the com-
\n
pany.
\n
These positive effects were mainly offset by the reclassifi-
\n
cation under discontinued operations of the entire invest-
\n
ment in Rusenergosbyt (\u20ac115 million), which was then sold
\n
in 2023, as well as dividends distributed in the year in the
\n
amount of \u20ac25 million, mainly by Spanish companies, and
\n
adverse exchange rate developments.
\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
\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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
Millions of euro Total revenue Pre-tax profit/(loss)
\n
Profit/(Loss) from continuing
\n
operations
\n
2023 2022 2023 2022 2023 2022
\n
Joint ventures
\n
Gridspertise Srl 418 334 23 12 17 8
\n
Mooney Group SpA 435 224 (70) (33) (70) (33)
\n
Slovak Power Holding 5,129 5,184 856 (320) 598 (223)
\n
Enel Green Power
\n
Australia
\n
37 - (28) - (28) -
\n
Enel Green Power Hellas 127 - 25 - 17 -
\n
Matimba project
\n
companies
\n
148 114 (8) (39) (2) (24)
\n
Ewiva Srl - - (6) (4) (6) (4)
\n
Associates
\n
CESI 164 155 (5) (4) (5) (1)
\n
Avikiran Solar India 15 - (6) - (6) -
\n
Avikiran Surya India 18 9 (3) 1 (3) 1
\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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Joint ventures
\n
Gridspertise Srl 170 94 132 192 302 286
\n
49 9 158 198 207 207 95 79
\n
Mooney Group SpA 894 880 487 449 1,381 1,329 1,134 1,086 649 575 1,783 1,661 (402) (332)
\n
Slovak Power Holding 12,468 12,376 1,470 1,444 13,938 13,820 7,843 4,950 1,393 6,620 9,236 11,570 4,702 2,250
\n
Enel Green Power
\n
Australia
\n
428 - 73 - 501 - 315 - 21 - 336 - 165 -
\n
Enel Green Power Hellas 687 - 109 - 796 - 672 - 166 - 838 - (42) -
\n
Matimba project
\n
companies
\n
1,583 1,759 320 348 1,903 2,107 1,599 1,763 113 93 1,712 1,856 191 251
\n
Ewiva Srl 40 40 39 - 79 40 - - - - - - 79 40
\n
Associates
\n
CESI 179 191 13 25 192 216
\n
20 24 73 90 93 114 99 102
\n
Avikiran Solar India 148 - 6 - 154 - 87 - 14 - 101 - 53 -
\n
Avikiran Surya India 200 207 63 30 263 237 112 117 48 9 160 126 103 111
\n
\n\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInAssociatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1094": { "value": "\n
17. Income taxes \u2013 \u20ac2,778 million
\n
Millions of euro
\n
2023 2022 Change
\n
Current taxes 2,877 3,025 (148) -4.9%
\n
Adjustments for income taxes relating to prior years (75) (233) 158 67. 8 %
\n
Total current taxes 2,802 2,792 10 0.4%
\n
Deferred tax expense
\n
(1)
\n
(197) 318 (515) -
\n
Deferred tax income
\n
(1)
\n
173 413 (240) -58.1%
\n
TOTAL 2,778 3,523 (745) -21.1%
\n
(1) Figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Income taxes for 2023 came to \u20ac2,778 million and de-
\n
creased by \u20ac745 million compared with 2022.
\n
The tax rate for 2023 came to 37%, compared with 41% in
\n
2022.
\n
The decrease mainly reflects the following factors:
\n
\u2022
\n
the impact of higher impairment and losses resulting
\n
from mergers and acquisitions in 2022 that were not tax
\n
deductible, essentially regarding Celg Distribui\u00e7\u00e3o SA -
\n
Celg-D (Enel Goi\u00e1s) and CGT Fortaleza in Brazil;
\n
\u2022
\n
higher taxes recognized in 2022 in Italy in respect of
\n
the extraordinary energy cost tax, established by Law
\n
51/2022 (about \u20ac121 million), and the solidarity tax from
\n
Law 197/2022 (about \u20ac599 million);
\n
\u2022
\n
the tax effect of hyperinflation in Argentina mainly attrib-
\n
utable, in 2023, to the recognition for tax purposes of
\n
the increase in the value of assets adjusted for hyper-
\n
inflation;
\n
\u2022
\n
an increase in tax credit to eliminate dual taxation of div-
\n
idends at Enel Iberia in 2023.
\n
These factors were partially offset by:
\n
\u2022
\n
the non-deductibility of the extraordinary solidarity levy
\n
in Spain;
\n

\n\n\n
\u2022
\n
the reversal of the portion of deferred tax assets no lon-
\n
ger considered recoverable in the United States, Mex-
\n
ico and Peru;
\n
\u2022
\n
the tax effect (\u20ac190 million) of the sale of interests in
\n
Ufinet, Gridspertise and the finance companies of the
\n
Enel X segment to Mooney in 2022.
\n
For more information on changes in deferred tax assets
\n
and liabilities, please 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
2023 2022
\n
Pre-tax profit
\n
(1)
\n
7,416 8,677
\n
Theoretical taxes 1,780 24% 2,082 24%
\n
Delta of tax effect on impairment adjustments and M&A transactions 195 420
\n
Preferential tax treatment of Ufinet, Gridspertise and Mooney capital gain - (190)
\n
Preferential tax treatment of disposals in Australia and Greece (63) -
\n
Deferred tax assets recognized on the carve-out of Enel X Way - (60)
\n
Patent Box in Italy - (65)
\n
Sundry tax effects of hyperinflation accounting in Argentina (58) 30
\n
Tax effect of non-deductible provisions for risks in Spain - 30
\n
Write-off of deferred tax assets for Enel Green Power Per\u00fa and Enel
\n
Generaci\u00f3n Per\u00fa merger
\n
25 -
\n
Write-off of deferred tax assets for the United States and Mexico 155 -
\n
IRAP 352 260
\n
Extraordinary energy cost tax - 121
\n
Solidarity tax - 599
\n
Non-deductibility of extraordinary solidarity levy in Spain 52 -
\n
Other differences, effect of different tax rates abroad compared with the
\n
theoretical rate in Italy, and other minor items
\n
340 296
\n
Total 2,778 3,523
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1095": { "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\n
The number of treasury shares, with a par value of \u20ac1
\n
each, held at December 31, 2023 was equal to 9,262,330
\n
(7,153,795 at December 31, 2022).
\n

\n\n\n
Millions of euro
\n
2023 2022
\n
Profit for the year attributable to owners of the Parent (basic) 3,438 1,682
\n
of which from:
\n
- continuing operations
\n
(1)
\n
3,813 3,573
\n
- discontinued operations
\n
(1)
\n
(375) (1,891)
\n
Effect of preference rights on dividends (e.g., preference shares) - -
\n
Dividends on equity instruments (e.g., hybrid bonds) (182) (123)
\n
Other - -
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 3,256 1,559
\n
of which from:
\n
- continuing operations
\n
(1)
\n
3,631 3,450
\n
- discontinued operations
\n
(1)
\n
(375) (1,891)
\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 (7,696,284) (6,287,027)
\n
Effect of share options exercised 422,896 145,119
\n
Other - -
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,159,406,558 10,160,538,038
\n
Profit for the year attributable to ordinary owners of the Parent (basic) 3,256 1,559
\n
Effect of dilution:
\n
- interest on convertible bonds - -
\n
- other - -
\n
Profit for the year attributable to ordinary owners of the Parent (diluted) 3,256 1,559
\n
of which:
\n
- continuing operations 3,631 3,450
\n
- discontinued operations (375) (1,891)
\n
Number of shares (units)
\n
Weighted average number of ordinary shares outstanding (total) for basic
\n
earnings per share
\n
10,159,406,558 10,160,538,038
\n
Effect of conversion of convertible notes - -
\n
Other - -
\n
Weighted average number of ordinary shares outstanding (total) for
\n
diluted earnings per share
\n
10,159,406,558 10,160,538,038
\n
\n
Basic earnings per share
\n
Basic earnings per share 0.32 0.15
\n
Basic earnings per share from continuing operations 0.36 0.34
\n
Basic earnings per share from discontinued operations (0.04) (0.19)
\n
Diluted earnings per share
\n
Diluted earnings per share 0.32 0.15
\n
Diluted earnings per share from continuing operations 0.36 0.34
\n
Diluted earnings per share from discontinued operations (0.04) (0.19)
\n
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1096": { "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\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEarningsPerShareExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag102": { "value": "\n
19. Property, plant and equipment \u2013 \u20ac89,801 million
\n
The breakdown of and changes in property, plant and
\n
equipment for 2023 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 Total
\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
Capital expenditure 4 47 2,182 27 86 1 4 8,213 10,564
\n
Assets entering service 31 1,189 6,085 6 56 4 29 (7,365) 35
\n
Exchange differences 11 (22) (933) (1) (26) (23) - (464) (1,458)
\n
Change in the
\n
consolidation scope
\n
2 8 33 - - (6) - 3 40
\n
Disposals (2) (2) (106) (1) (31) (63) (1) 20 (186)
\n
Depreciation - (219) (3,857) (23) (81) (337) (34) - (4,551)
\n
Impairment losses (1) (230) (1,149) - - - - (186) (1,566)
\n
Impairment gains - 1 30 - - - - 8 39
\n
Leases - - - - - 684 - - 684
\n
Other changes (1) (92) 879 (1) 6 3 (1) 460 1,253
\n
Reclassifications from/to
\n
assets held for sale
\n
(43) (270) (2,590) (1) (5) (161) - (504) (3,574)
\n
Total changes 1 410 574 6 5 102 (3) 185 1,280
\n
Cost net of accumulated
\n
impairment losses
\n
630 12,084 167, 123 592 1,456 4,318 572 14,149 200,924
\n
Accumulated depreciation - 5,787 101,864 423 1,159 1,454 436 - 111,123
\n
Balance at Dec. 31, 2023 630 6,297 65,259 169 297 2,864 136 14,149 89,801
\n
Plant and machinery included assets to be relinquished
\n
free of charge with a carrying amount of \u20ac9,538 million
\n
(\u20ac8,409 million at December 31, 2022), largely regarding
\n
power plants in Iberia and Latin America amounting to
\n
\u20ac4,068 million (\u20ac3,456 million at December 31, 2022) and
\n
the electricity distribution grid in Latin America totaling
\n
\u20ac4,470 million (\u20ac4,228 million at December 31, 2022).
\n
For more information on \u201cleased assets\u201d, please see note
\n
21 below.
\n
Capital expenditure came to \u20ac11,919 million, of which
\n
10,564 million in \u201cproperty, plant and equipment\u201d, and
\n
\u20ac1,355 million in \u201cintangible assets\u201d (for more details see
\n
note 23). The types of capital expenditure made during
\n
2023 are summarized below by class of asset.
\n
Millions of euro
\n
2023 2022 Change
\n
Power plants:
\n
- thermal 550 659 (109) -16.5%
\n
- hydroelectric 458 435 23 5.3%
\n
- geothermal 136 121 15 12.4%
\n
- nuclear 163 134 29 21.6%
\n
- alternative energy sources 3,444 5,147 (1,703) -33.1%
\n
Total power plants 4,751 6,496 (1,745) -26.9%
\n
Electricity distribution grids
\n
(1)
\n
4,485 4,373 112 2.6%
\n
Enel X (e-City, e-Industries, e-Home) 449 373 76 20.4%
\n
Enel X Way (e-Mobility) 106 113 (7) -6.2%
\n
Retail customers 617 721 (104) -14.4%
\n
Other 1,511 1,097 414 37.7%
\n
TOTAL 11,919 13,173 (1,254) -9.5%
\n
(1) The figure for 2023 does not include \u20ac795 million in respect of infrastructure investments within the scope of IFRIC 12 (\u20ac1,174 million in 2022).
\n
\n\n
The Enel Group, in line with the Paris Agreement on CO
\n
2
\n
\n
emissions reductions and guided by energy efficiency
\n
and energy transition objectives, has invested above all in
\n
generation plants that exploit alternative energy sourc-
\n
es. Capital expenditure on thermal generation plants de-
\n
creased mainly in Latin America and Italy.
\n
Capital expenditure on the distribution grid were substan-
\n
tial; in particular, higher investments in Italy, mainly for cor-
\n
rective maintenance and grid reliability, were partly offset
\n
by lower investments in Brazil, Romania, Peru, Argentina
\n
and Chile.
\n
The decrease in capital expenditure in the Retail business
\n
in Italy, Spain and Romania is essentially attributable to
\n
a decrease in digitalization activities of operational pro-
\n
cesses in customer management.
\n
The growth of capital expenditure of Enel X mainly regards
\n
the e-City and the Distributed Energy businesses in Italy
\n
and the e-City business in Brazil.
\n
Impairment losses in 2023 amounted to \u20ac1,566 million, of
\n
which \u20ac1,234 million are attributable to the value adjust-
\n
ment of photovoltaic and wind plants in the United States,
\n
operating in a progressively deteriorating macroeconom-
\n
ic context and in local markets characterized by the per-
\n
sistence of disadvantageous conditions for the dispatch-
\n
ing of power, as well as the initiation and implementation
\n
by management of specific restructuring plans in the
\n
country, which have had a significant impact on the recov-
\n
erable values of those assets. The above circumstances
\n
constituted evidence of low margins, which, following IAS
\n
36 impairment testing, indicate that their carrying amount
\n
cannot be completely recovered.
\n
Impairment losses in 2023 also include value adjustments
\n
of thermal generation assets in the non-peninsular terri-
\n
tories in Spain (\u20ac91 million), in line with the decarboniza-
\n
tion process pursued by the Group, and the value adjust-
\n
ment of Windpeshi wind project in Colombia (\u20ac171 million)
\n
as a result of the implementation of a disposal program for
\n
the related assets, which prompted their classification as
\n
assets held for sale.
\n
Impairment gains of \u20ac39 million mainly regards generation
\n
assets in Colombia of Sociedad Portuaria Central Cartage-
\n
na SA, which had been written down in 2022 to reflect their
\n
realizable value.
\n
\u201cReclassifications from/to assets held for sale\u201d refer main-
\n
ly to electricity distribution and supply assets held by Enel
\n
Distribuci\u00f3n Per\u00fa SAA in Peru, generation assets held by
\n
Enel Generaci\u00f3n Per\u00fa, Compa\u00f1\u00eda Energ\u00e9tica Veracruz,
\n
and Enel Generaci\u00f3n Piura, a portfolio of renewables as-
\n
sets consisting of about 150 MW of geothermal and solar
\n
plants in North America, whose sale was finalized in Janu-
\n
ary 2024, photovoltaic plants of Arcadia Generaci\u00f3n Solar
\n
SA in Chile, sold during 2023, and the Windpeshi wind fa-
\n
cility under development.
\n
\u201cOther changes\u201d include the adjustment of plant decom-
\n
missioning and site restoration costs, which decreased by
\n
\u20ac38 million, mainly in Spain, new leases of \u20ac684 million,
\n
impairment losses on the property, plant and equipment
\n
of the Argentine companies operating in a hyperinflation-
\n
ary economy in the amount of \u20ac872 million and the effect
\n
of capitalizing interest on loans specifically dedicated to
\n
capital expenditure on property, plant and equipment of
\n
\u20ac303 million (\u20ac251 million in 2022), breaking down as fol-
\n
lows.
\n
Millions of euro
\n
2023 Rate % 2022 Rate % Change
\n
EGP North America 70 0.2% 83 0.5% (13) -15.7%
\n
EGP M\u00e9xico 16 9.8% 14 7. 0 % 2 14.3%
\n
EGP South Africa - - - 6.3% - -
\n
Enel Am\u00e9ricas Group 55 6.4% 41 3.2% 14 34.1%
\n
Enel Chile Group 90 6.0% 91 6.1% (1) -1.1%
\n
Endesa Group 12 3.2% 5 1.4% 7 -
\n
Enel Italia Group 58 2.1% 8 3.2% 50 -
\n
Nuove Energie 2 3.3% 2 1.6% - -
\n
Total 303 251 52 20.7%
\n
At December 31, 2023, contractual commitments to pur-
\n
chase property, plant and equipment came to \u20ac4,690 mil-
\n
lion.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag103": { "value": "\n
20. Infrastructure within the scope of \u201cIFRIC 12 \u2013 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
\n
and Costa Rica and public lighting in Brazil.
\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
intangible
\n
contract
\n
assets at Dec.
\n
31, 2023
\n
Amount
\n
recognized
\n
among
\n
financial
\n
contract
\n
assets at Dec.
\n
31, 2023
\n
Amount
\n
recognized
\n
among
\n
financial
\n
assets at
\n
Dec. 31,
\n
2023
\n
Amount
\n
recognized
\n
among
\n
intangible
\n
assets at
\n
Dec. 31,
\n
2023
\n
Enel
\n
Distribui\u00e7\u00e3o
\n
Rio de Janeiro
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1996-2026 3 years Yes 134 - 1,353 439
\n
Enel
\n
Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 5 years Yes 134 - 1,138 466
\n
Enel Green
\n
Power Mour\u00e3o
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 23 years No - - 6 -
\n
Enel Green
\n
Power
\n
Paranapanema
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2016-2046 23 years No - - 27 -
\n
Enel Green
\n
Power Volta
\n
Grande
\n
Brazilian
\n
government
\n
Electricity
\n
generation
\n
Brazil 2017-2047 24 years No - - 291 -
\n
Enel
\n
Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
Brazilian
\n
government
\n
Electricity
\n
distribution
\n
Brazil 1998-2028 5 years Yes 157 - 1,549 722
\n
Luz de Angra
\n
Energia
\n
Brazilian
\n
government
\n
Public
\n
lighting
\n
Brazil 2021-2036 13 years Yes
\n
(1)
\n
- 3 - -
\n
Luz de
\n
Jaboat\u00e3o
\n
Energia
\n
Brazilian
\n
government
\n
Public
\n
lighting
\n
Brazil 2023-2045 21 years Yes
\n
(1)
\n
- 5 - -
\n
Luz de Caruaru
\n
Energia
\n
Brazilian
\n
government
\n
Public
\n
lighting
\n
Brazil 2023-2043 19 years Yes
\n
(1)
\n
- 4 - -
\n
Luz de
\n
Cataguases
\n
Brazilian
\n
government
\n
Public
\n
lighting
\n
Brazil 2023-2048 24 years Yes
\n
(1)
\n
- 1 - -
\n
PH Chucas
\n
Costa Rican
\n
Electricity
\n
Institute
\n
Hydroelectric
\n
plant
\n
Costa
\n
Rica
\n
2012-2031 8 years No - - 40 38
\n
Total 425 13 4,404 1,665
\n
(1) Limited to 35 years.
\n
The assets classified under financial assets are measured
\n
at fair value at the end of the concessions. For more in-
\n
formation, please see note 52 \u201cAssets and liabilities mea-
\n
sured at fair 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, 2023.
\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2023
\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 - 5,677 5,678 5,673
\n
Enel Colombia
\n
(formerly Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,266 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 - 1,254 1,331 1,667
\n
Assets with an indefinite useful life amounted to \u20ac8,197
\n
million (\u20ac8,056 million at December 31, 2022) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,677 million), Colombia (\u20ac1,266 million) and
\n
Chile (\u20ac1,254 million), for which there was no statutory or
\n
currently predictable expiration date. On the basis of the
\n
forecasts developed, cash flows for each CGU, with which
\n
the various concessions are associated, were sufficient to
\n
recover the carrying amount. The change during the year
\n
was essentially attributable to changes in exchange rates
\n
in Latin America. The assets in respect of concession ar-
\n
rangements that do not fall within the scope of IFRIC 12
\n
of Enel Distribuci\u00f3n Per\u00fa were reclassified as held for sale
\n
in the amount of \u20ac581 million (\u20ac584 million at December
\n
31, 2022).
\n

\n\n\n\n\n\n\n\n
For more information on service concession arrange-
\n
ments, please see note 20.
\n

\n\n\n\n\n\n\n\n
28. Current/Non-current contract assets/(liabilities)
\n
Millions of euro Non-current Current
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Contract assets 444 508 212 106
\n
Contract liabilities 5,743 5,747 2,126 1,775
\n
\n\n
Non-current assets deriving from contracts with custom-
\n
ers (contract assets) refer mainly to assets with long-term
\n
utility under construction in respect of public-to-private
\n
service concession arrangements recognized in accor-
\n
dance with IFRIC 12 (\u20ac425 million). These cases arise when
\n
the concession holder has not yet obtained full right to
\n
recognize the asset from the grantor, in that there remains
\n
a contractual obligation to ensure that the asset is com-
\n
pleted and can be remunerated through rates. The figure
\n
at December 31, 2023 includes investments for the year in
\n
the amount of \u20ac795 million.
\n
\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Equity investments in other companies measured at fair value 346 366 (20) -5.5%
\n
Other non-current financial assets included in net financial debt
\n
(see note 29.1)
\n
3,837 4,213 (376) -8.9%
\n
Service concession arrangements 4,391 3,732 659 17.7%
\n
Financial assets in respect of joint development agreements (JDA) 133 - 133 -
\n
Non-current financial prepayments 43 48 (5) -10.4%
\n
Total 8,750 8,359 391 4.7%
\n

\n\n\n\n\n

\n\n\n\n\n
\u201cOther non-current financial assets\u201d increased by \u20ac391
\n
million reflecting:
\n
\u2022
\n
the increase in financial assets in respect of service
\n
concession arrangements, mainly in Brazil;
\n
\u2022
\n
the recognition of financial assets in respect of joint
\n
development agreements (JDA) in relation to amounts
\n
paid by a number of the Group\u2019s Italian renewables
\n
companies to developers for the development of re-
\n
newable generation projects; in 2022 those assets
\n
were recognized under other non-current assets in the
\n
amount of \u20ac100 million.
\n

\n\n\n\n\n

\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Cash and cash equivalents - - 35 6,772 10,169
\n
Trade receivables 34 1,726 1,388 34 16,047 15, 217
\n
Current portion of long-term loan assets - - 30.1 1,007 2,838
\n
Cash collateral - - 30.1 2,899 8,319
\n
Other financial assets 29.1 3,332 3,767 30.1 30 2,090
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 310 295 29 14 12
\n
Other financial assets at amortized cost 341 282 1,726 1,531
\n
Total 5,709 5,732 28,495 40,176
\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\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, 2023 at Dec. 31, 2023
\n
Equity investments in other
\n
companies at FVOCI
\n
29 338 15 28 295 - - - -
\n
Securities at FVOCI 29.1, 30.1 505 505 - - 81 81 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
39 - - 39 - - - -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 8 - - 8 - - - -
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 4,080 - 4,080 - - - - -
\n
Financial assets from JDA at FVTPL 123 41 - 82 - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
169 - - 169 190 131 - 59
\n
Other cash investments at FVTPL - - - - 29 29 - -
\n
Fair value hedge derivatives:
\n
- on interest rates 51 101 - 101 - - - - -
\n
- on exchange rates 51 12 - 12 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 174 - 174 - 1 - 1 -
\n
- on exchange rates 51 1,007 - 1,007 - 145 - 145 -
\n
- on commodities 51 883 173 375 335 1,818 1,311 413 94
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 24 - 24 -
\n
- on commodities 51 205 27 178 - 4,419 3,038 1,381 -
\n
Non-monetary grants in respect
\n
of environmental certificates
\n
- - - - 18 1 11 6
\n
Inventories measured at fair value 51 48 48 - - 3 - 3 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n\n\n\n\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, and are
\n
accounted for in accordance with IFRIC 12.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfServiceConcessionArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag104": { "value": "\n
21. Leases
\n
The table below shows changes in right-of-use assets in 2023.
\n
Millions of euro Leased land Leased buildings Leased plants Other leased assets Total
\n
Total at Dec. 31, 2022 1,312 513 424 513 2,762
\n
Increases 318 270 (3) 99 684
\n
Exchange differences (26) 2 - 1 (23)
\n
Depreciation (47) (118) (29) (143) (337)
\n
Other changes (69) (35) (114) (4) (222)
\n
Total at Dec. 31, 2023 1,488 632 278 466 2,864
\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, 2022 2,672
\n
Increases 677
\n
Payments (406)
\n
Other changes (38)
\n
Total at Dec. 31, 2023 2,905
\n
of which medium to long term 2,638
\n
of which short term 267
\n
Note that in 2023 no changes or renegotiations were
\n
made to leases.
\n
Millions of euro
\n
2023
\n
Depreciation of right-of-use assets 346
\n
Interest expense on lease liabilities 128
\n
Expense relating to short-term leases (included in costs for services and other materials) 46
\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) 29
\n
Total 549
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag105": { "value": "\n
22. Investment property \u2013 \u20ac97 million
\n
Millions of euro
\n
Cost net of accumulated impairment losses 116
\n
Accumulated depreciation 22
\n
Balance at Dec. 31, 2022 94
\n
Exchange differences -
\n
Depreciation (2)
\n
Impairment losses (1)
\n
Other changes 6
\n
Total changes 3
\n
Cost net of accumulated impairment losses 114
\n
Accumulated depreciation 17
\n
Balance at Dec. 31, 2023 97
\n
Investment property at December 31, 2023 amounted to
\n
\u20ac97 million, an increase of \u20ac3 million on 2022.
\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 2023 was mainly due to impairment losses
\n
recognized on a number of assets in Spain, a number of
\n
disposals in Italy and depreciation charges for the period.
\n
For more information on the valuation of investment prop-
\n
erty, please see notes 52 \u201cAssets and liabilities measured
\n
at fair value\u201d, and 52.2 \u201cAssets not measured at fair value in
\n
the statement of financial position\u201d.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentPropertyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1112": { "value": "\n

\n\n

\n
23. Intangible assets \u2013 \u20ac17,055 million
\n
A breakdown of and changes in intangible assets for 2023
\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 advances
\n
Contract
\n
costs Total
\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
\n
amortization
\n
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
Capital expenditure 3 30 45 - 122 - 640 515 1,355
\n
Assets entering service 2 300 8 - 209 - (564) 10 (35)
\n
Exchange differences 1 (4) 220 72 (4) - (49) (4) 232
\n
Change in the
\n
consolidation scope
\n
- - 1 - - - (1) - -
\n
Disposals - (2) - (18) - - 3 - (17)
\n
Amortization (5) (313) (199) (402) (342) - - (425) (1,686)
\n
Impairment losses (3) - 1 - (1) - (57) - (60)
\n
Impairment gains - - - - 2 - - - 2
\n
Other changes (47) 50 (10) 513 - - (46) 3 463
\n
Reclassifications from/to
\n
assets held for sale
\n
(4) (49) (590) - (44) - (32) - (719)
\n
Total changes (53) 12 (524) 165 (58) - (106) 99 (465)
\n
Cost net of accumulated
\n
impairment losses
\n
55 3,988 12,401 5,822 5,513 - 1,641 3,352 32,772
\n
Accumulated
\n
amortization
\n
29 3,313 2,130 4,157 4,139 - - 1,949 15,717
\n
Balance at Dec. 31, 2023 26 675 10,271 1,665 1,374 - 1,641 1,403 17,055
\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, 2023.
\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2023
\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 - 5,677 5,678 5,673
\n
Enel Colombia
\n
(formerly Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,266 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 - 1,254 1,331 1,667
\n
Assets with an indefinite useful life amounted to \u20ac8,197
\n
million (\u20ac8,056 million at December 31, 2022) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,677 million), Colombia (\u20ac1,266 million) and
\n
Chile (\u20ac1,254 million), for which there was no statutory or
\n
currently predictable expiration date. On the basis of the
\n
forecasts developed, cash flows for each CGU, with which
\n
the various concessions are associated, were sufficient to
\n
recover the carrying amount. The change during the year
\n
was essentially attributable to changes in exchange rates
\n
in Latin America. The assets in respect of concession ar-
\n
rangements that do not fall within the scope of IFRIC 12
\n
of Enel Distribuci\u00f3n Per\u00fa were reclassified as held for sale
\n
in the amount of \u20ac581 million (\u20ac584 million at December
\n
31, 2022).
\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

\n\n

\n\n
For more information on service concession arrange-
\n
ments, please see note 20.
\n

\n\n\n\n\n\n\n\n
Impairment losses amounted to \u20ac60 million in 2023, and
\n
mainly regarded renewable projects no longer considered
\n
strategic in Spain, the United States and Italy.
\n
\u201cReclassifications from/to assets held for sale\u201d refer main-
\n
ly to assets held by Enel Distribuci\u00f3n Per\u00fa SAA, Enel Gen-
\n
eraci\u00f3n Per\u00fa, Compa\u00f1\u00eda Energ\u00e9tica Veracruz and other
\n
renewable assets in North America (the latter sold at the
\n
beginning of 2024).
\n
\u201cOther changes\u201d mainly include the reclassification under
\n
financial assets of investments falling within the scope of
\n
IFRIC 12 in Brazil and the value adjustment of intangible
\n
assets of Argentine companies as a result of the applica-
\n
tion of the accounting standard for financial reporting in
\n
hyperinflationary economies.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n
24. Goodwill \u2013 \u20ac13,042 million
\n
Millions of euro at Dec. 31, 2022
\n
Change in the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Impairment
\n
losses
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes at Dec. 31, 2023
\n
Net carrying
\n
amount
\n
Net carrying
\n
amount
\n
Iberian Peninsula 8,785 - - - - - 8,785
\n
Chile 1,148 - (1) - (46) - 1,101
\n
Argentina 21 - (1) - - - 20
\n
Peru 571 - (1) - (570) - -
\n
Colombia 518 - 8 - - - 526
\n
Brazil 1,313 - 44 - - - 1,357
\n
Central America 26 - - - - - 26
\n
Enel Green Power North
\n
America
\n
70 - (2) - - - 68
\n
Enel X North America 142 - (4) (57) - - 81
\n
Enel X Way North America 70 - (1) (69) - -
\n
Enel X Asia Pacific 84 - - - - - 84
\n
Enel X Rest of Europe
\n
(1)
\n
43 - - - - - 43
\n
Market Italy
\n
(2)
\n
581 - - - - - 581
\n
Enel Green Power Italy 21 - - - - - 21
\n
Enel Produzione Italy 349 - - - - - 349
\n
Total 13,742 - 42 (126) (616) - 13,042
\n
(1) Includes Viva Labs.
\n
(2) Includes Enel Energia.
\n
The following table presents the allocation of goodwill
\n
in the matrix of business lines and geographical areas.
\n
Note that the changes in the presentation of operating
\n
segments, described in note 10 above, did not produce
\n
changes in the allocation of goodwill for the purposes of
\n
impairment testing.
\n

\n\n\n\n\n\n\n\n
Goodwill matrix at Dec. 31, 2023
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets
\n
Holding and
\n
Services Total
\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 - 1 19 - - 20
\n
Brazil - 502 855 - - 1,357
\n
Chile - 949 152 - - 1,101
\n
Colombia - 303 223 - - 526
\n
Peru - - - - - -
\n
Central America - 26 - - - 26
\n
Enel Green Power North America - 68 - - - 68
\n
Enel X North America - - - 81 - 81
\n
Enel X Way North America - - - - - -
\n
Enel X Asia Pacific - - - 84 - 84
\n
Enel X Rest of Europe
\n
(2)
\n
- - - 43 - 43
\n
Total - 3,409 7,037 2,596 - 13,042
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\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
\n
(1)
\n
Holding and
\n
Services
\n
(1)
\n
Total
\n
Enel Green Power Italy - 21 - - - 21
\n
Market Italy
\n
(2)
\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 North America - 70 - - - 70
\n
Enel X North America - - - 142 - 142
\n
Enel X Way North America - - - 70 - 70
\n
Enel X Asia Pacific - - - 84 - 84
\n
Enel X Rest of Europe
\n
(3)
\n
- - - 43 - 43
\n
Total 44 3,634 7, 337 2,727 - 13,742
\n
(1) The figures for 2022 for the End-user Market Business Line have been adjusted to take account of the values for Enel X and Enel X Way. The latter had
\n
previously been reported under Holding, Services and Other.
\n
(2) Includes Enel Energia.
\n
(3) Includes Viva Labs.
\n

\n\n\n\n\n\n\n\n
The decrease of \u20ac700 million in goodwill was mainly at-
\n
tributable to Peru for the reclassification as assets held for
\n
sale of generation and distribution assets (\u20ac570 million),
\n
and Chile for the reclassification to assets held for sale of
\n
Arcadia Generaci\u00f3n Solar (\u20ac46 million).
\n
New impairment losses were also recognized in 2023 in
\n
respect of the CGUs in North America of Enel X and Enel
\n
X Way (\u20ac57 and \u20ac69 million, respectively) following impair-
\n
ment testing conducted in response to changes in macro-
\n
economic conditions.
\n
The decrease is partly offset by exchange gains recog-
\n
nized in Brazil.
\n
The recoverable amount of the goodwill recognized was
\n
estimated by calculating the value in use of the CGUs us-
\n
ing discounted cash flow models, which involve estimating
\n
expected future cash flows and applying an appropriate
\n
discount rate, selected on the basis of market inputs such
\n
as risk-free rates, betas and market-risk premiums.
\n
Cash flows were determined on the basis of the best in-
\n
formation available at the time of the estimate, taking ac-
\n
count of the specific risks of each CGU, and drawn:
\n
\u2022
\n
for the explicit period, from the Business Plan approved
\n
by the Board of Directors of the Parent on November
\n
22, 2023, containing forecasts for volumes, revenue,
\n
operating costs, capital expenditure, industrial and
\n
commercial organization and developments in the main
\n
macroeconomic variables (inflation, nominal interest
\n
rates and exchange rates) and commodity prices. The
\n
explicit period of cash flows considered in impairment
\n
testing was three years;
\n
\u2022
\n
for subsequent years, from assumptions concerning
\n
long-term developments in the main variables that de-
\n
termine cash flows, the average residual useful life of
\n
assets or the duration of the concessions.
\n
More specifically, the terminal value is calculated based on
\n
the specific characteristics of the businesses related to
\n
the various CGUs subject to impairment testing:
\n
\u2022
\n
perpetuity, for the businesses of large-hydro (LH) pow-
\n
er generation and of distribution, in which the licenses
\n
and public concessions are of a long-term nature and
\n
renewal can be forecast with reasonable certainty; as
\n
well as for the Enel X and Enel X Way businesses, as they
\n
feature the development of specific know-how that is
\n
sustainable over the long term;
\n
\u2022
\n
annuity, for CGUs that are predominantly characterized
\n
by retail business, for which the residual life is, there-
\n
fore, essentially correlated with the average duration
\n
of the customer relationships; as well as for businesses
\n
of conventional thermal power generation (Genera-
\n
tion and Trading). This method is also used for the re-
\n
newable energy (Enel Green Power) businesses to take
\n
account of: (i) the value resulting from the remaining
\n
useful lives of the plants; and (ii) the residual value, in
\n
the event of plant decommissioning, associated with
\n
licensing rights, the competitiveness of the production
\n
facilities (in terms of natural resources), and network in-
\n
terconnectivity.
\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).
\n
Regarding the assumptions for commodity price develop-
\n
ments, the scenarios adopted are consistent with current
\n
emissions reductions targets.
\n
Note also that the Group has used sensitivity analysis to
\n
take account of the impacts of climate change in the long
\n
term. More specifically:
\n
\u2022
\n
we consider a perpetual long-term growth rate for
\n
cash flows after the explicit period that is in line with the
\n
change in electricity demand over the 2026-2050 pe-
\n
riod, based on the specific features of the businesses
\n
concerned, adopting certain assumptions concerning
\n
the increase in temperature due to climate change and
\n
trends connected with the energy transition;
\n
\u2022
\n
we consider changes in the hydroelectric, wind and
\n
photovoltaic generation levels of our Portfolio assets,
\n
associated with each projection of underlying climate
\n
and weather variables (for example, temperature, irra-
\n
diance, wind speed and precipitation);
\n
\u2022
\n
we assume that the Group will incur the costs provi-
\n
sioned for decommissioning fossil fuel generation
\n
plants in line with the goal of zero direct (Scope 1) and
\n
indirect emissions from retail activities (Scope 3).
\n
In order to verify the robustness of the value in use of
\n
the CGUs, sensitivity analyses were conducted for the
\n
main value drivers, in particular WACC and the long-term
\n
growth rate.
\n
Even in these circumstances, results were consistent with
\n
the evidence described previously, finding that for all the
\n
CGUs analyzed, with the exception of those written down
\n
(Enel X North America and Enel X Way North America), the
\n
value in use exceeded the carrying amount, ensuring the
\n
full recoverability of the carrying amounts of those assets
\n
in the consolidated financial statements of the Enel Group
\n
at December 31, 2023.
\n

\n\n\n\n\n\n\n\n
OUR ZERO-EMISSIONS
\n
AMBITION
\n
Enel is committ ed to achieving zero emissions by 2040
\n
and to developing a business model that is in line
\n
with the objectives of the Paris Agreement (COP 21)
\n
to limit the average increase in global temperatures
\n
to 1.5 \u00baC. For this reason, the Group has developed a
\n
decarbonatization roadmap that covers both direct
\n
and indirect emissions throughout the value chain. The
\n
roadmap includes four targets cert ifi ed by the Science
\n
Based Targets initiative (SBTi) in December 2022 to be
\n
in line with the Net Zero Standard.
\n
GHG TARGET
\n
Intensity of Scope 1 GHG emissions related to power generation
\n
Primary business
\n
activity
\n
Electricity generation
\n
Type of activity in
\n
value chain
\n
Direct
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
95% of Scope 1 GHG emissions
\n
(2)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
125 gCO
\n
2eq
\n
/kWh 72 gCO
\n
2eq
\n
/kWh
\n
0 gCO
\n
2eq
\n
/kWh
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-66% -80% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-22% -55% -100%
\n
Climate scenario
\n
1.5 \u00b0C
\n
(3)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Gradual phase out of coal-fi red capacity
\n
in 2024-2026, with planned closure of
\n
the Federico II and Torrevaldaliga Nord
\n
plants in Italy (with a total capacity of
\n
about 3.6 GW).
\n
\u2022 Invest \u20ac12.1 billion to accelerate the
\n
development of renewable energy by
\n
installing 13.4 GW of new renewables
\n
capacity (about 11.3 GW of which at
\n
the consolidated level) in 2024-2026,
\n
reaching 73 GW of renewables capacity
\n
(including BESS) by 2026.
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, with the
\n
proport ion of renewables plants in the
\n
Enel asset port folio reaching 78% in
\n
2026, with zero-emissions generation
\n
amounting to 86% of the total, including
\n
consolidated and managed generation.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, with Group
\n
investments raising the proport ion of
\n
renewables plants in the asset port folio
\n
to about 85% in 2030, with zero-
\n
emissions generation amounting to 90%
\n
of the total, including consolidated and
\n
managed generation.
\n
\u2022 Exit from coal-fi red generation, which is
\n
expected to take place by 2027 globally.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
\u2022 Exit from the thermal electricity
\n
generation business, achieving a 100%
\n
renewable energy mix.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 160 gCO
\n
2eq
\n
/kWh
\n
\u2022 About \u20ac5.9 billion invested in renewables in 2023.
\n
\u2022 New consolidated renewables capacity installed equal to 4 GW in 2023, bringing total consolidated capacity to 55.5 GW in
\n
2023.
\n
\u2022 Increase in consolidated renewables generation equal to 13% on 2022, representing 61% of total consolidated generation in
\n
2023.
\n
\u2022 Reduction of thermal capacity by about 5.1 GW on 2022, including the closure of two coal-fi red plants (for a total of about 2
\n
GW) and the sale of gas plants in Argentina (for a total of about 3 GW) and Colombia (for a total of about 0.2 GW).
\n
\u2022 Reduction of thermal generation by 38% on 2022 (specifi cally, with a 45% reduction in coal-fi red generation), representing 27%
\n
of total generation in 2023.
\n

\n\n\n\n\n\n\n\n
GHG TARGET
\n
Intensity of Scope 1 and Scope 3 GHG emissions related to Integrated Power
\n
Primary business
\n
activity
\n
Sale of electricity
\n
Type of activity in
\n
value chain
\n
\u2022 Direct (electricity generation)
\n
\u2022 Upstream in value chain (purchase of electricity from other generators for sale to end users)
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Electricity generators (peers)
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 95% of Scope 1 GHG emissions
\n
\u2022 42% of Scope 3 GHG emissions (corresponding to 78% of Scope 3 GHG emissions \u2013 category 3)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
135 gCO
\n
2eq
\n
/kWh 73 gCO
\n
2eq
\n
/kWh
\n
0 gCO
\n
2eq
\n
/kWh
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-59% -78% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-20% -57% -100%
\n
Climate scenario
\n
1.5 \u00b0C
\n
(3)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Increase the percentage of renewable
\n
energy sold to customers, while
\n
increasing the Group\u2019s renewables
\n
production and optimizing customer
\n
port folio, continuing supply and
\n
demand balancing strategy.
\n
\u2022 In Europe, increase the share of
\n
fi xed-price energy sales to end users
\n
covered by zero-emissions sources
\n
from about 65% in 2023 to more than
\n
80% in 2026.
\n
\u2022 In Latin America, maintain 100%
\n
zero-emissions sales to end users
\n
(including through PPAs).
\n
\u2022 In Nort h America, maintain 100% zero-
\n
emissions sales to end users.
\n
\u2022 Continue the process of
\n
decarbonizing electricity generation,
\n
increasing zero-emissions generation
\n
from 75% in 2023 (including managed
\n
capacity) to 86% of total in 2026,
\n
including consolidated and managed
\n
capacity.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 Continue the strategy of balancing
\n
supply and demand and increase the
\n
share of electricity sold at a fi xed price
\n
covered by carbon-free generation.
\n
\u2022 Continue the process of
\n
decarbonizing electricity generation,
\n
increasing zero-emissions generation
\n
to about 90% of the total in 2030.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 By 2040, achieve 100% of electricity
\n
sales covered by renewables.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 168 gCO
\n
2eq
\n
/kWh
\n
\u2022 13% increase in Group consolidated renewables generation in 2023 on 2022.
\n
\u2022 7% reduction in 2023 compared with 2022 in the gap between sale of electricity to end users and own generation in the
\n
countries in which the Group has an integrated position.
\n
\n\n
GHG TARGET
\n
Scope 3 GHG emissions related to the sale of natural gas on end-user market
\n
Primary business
\n
activity
\n
Sale of gas to end users
\n
Type of activity in
\n
value chain
\n
\u2022 Downstream in value chain
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Gas customers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 30% of Scope 3 GHG emissions (corresponding to 100% of Scope 3 GHG emissions \u2013 category 11)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
20.0 MtCO
\n
2eq
\n
11.4 MtCO
\n
2eq
\n
0 MtCO
\n
2eq
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-21% -55% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-
\n
(4)
\n
-32% -100%
\n
Climate scenario
\n
n.a.
\n
(5)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Encourage customers (especially
\n
residential customers) to switch
\n
from gas to electricity by promoting
\n
effi cient electricity technologies
\n
(e.g., heat pumps for home heating
\n
or induction cooktops in kitchens),
\n
increasing annual unit electricity
\n
consumption of free-market B2C
\n
power customers (in Italy and Iberia)
\n
from 2.65 MWh in 2023 to about 2.9
\n
MWh in 2026, thereby increasing the
\n
electrifi cation rate of customers.
\n
\u2022 Allocate 32% of investment in grids
\n
in 2024-2026 to connections, part ly
\n
with a view to enabling the expansion
\n
of distributed generation, thereby
\n
promoting the electrifi cation of
\n
end users\u2019 energy consumption.
\n
The number of connections to
\n
distributed generation is forecast
\n
to double in the period, reaching 4
\n
million in 2026.
\n
\u2022 Reduce the volumes of gas sold to
\n
customers to around 8.4 billion cubic
\n
meters in 2026.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 Encourage customers (especially
\n
residential customers) to switch
\n
from gas to electricity by promoting
\n
effi cient electricity technologies
\n
(e.g., heat pumps for home heating
\n
or induction cooktops in kitchens),
\n
increasing annual unit electricity
\n
consumption of free-market B2C
\n
power customers (in Italy and Iberia)
\n
to about 3.5 MWh in 2030, thereby
\n
increasing the electrifi cation rate of
\n
customers.
\n
\u2022 Continue to invest in distribution
\n
grids, support ing the growth of
\n
distributed generation, thereby
\n
promoting the electrifi cation of end
\n
users\u2019 energy consumption, reaching
\n
6 million connections to distributed
\n
generation in 2030.
\n
\u2022 Optimize the customer gas port folio
\n
(industrial customers in part icular),
\n
continuing to reduce the volume of
\n
gas sold to about 5.3 billion cubic
\n
meters in 2030.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 By 2040, achieve 100% of energy sales
\n
covered by renewables.
\n
\u2022 Exit retail gas sales business by 2040.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 16.8 MtCO
\n
2eq
\n
\u2022 6.2 million gas customers in 2023, down 6% on 2022.
\n
\u2022 Gas sales in 2023 equal to 8.3 billion cubic meters, down 19% on 2022.
\n
\u2022 3.6 million new connections in 2023.
\n

\n\n\n
GHG TARGET
\n
Additional emissions Scopes 1-2-3
\n
Primary business
\n
activity
\n
\u2022 Electricity distribution (Scopes 1 and 2)
\n
\u2022 Management of vehicle fl eet, buildings and other assets (Scopes 1 and 2)
\n
\u2022 Management of supply chain (Scope 3)
\n
\u2022 Purchase of fuels (Scope 3)
\n
Type of activity in
\n
value chain
\n
\u2022 Direct (electricity distribution and management of vehicle fl eet, buildings and other Group assets)
\n
\u2022 Upstream in value chain (supply chain for products and services and fuel business)
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Electricity generators (peers)
\n
\u2022 Suppliers of goods and services
\n
\u2022 Oil&gas suppliers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 0.5% of Scope 1 GHG emissions
\n
\u2022 100% of Scope 2 GHG emissions
\n
\u2022 Target 2030
\n
(6)
\n
: 15% of Scope 3 GHG emissions (corresponding to 17% of Scope 3 emissions - category 1 and 22%
\n
of Scope 3 emissions - category 3)
\n
\u2022 Target 2040
\n
(6)
\n
: 18% of Scope 3 GHG emissions (corresponding to 35% of Scope 3 emissions - category 1 and 22%
\n
of Scope 3 emissions - category 3)
\n
Time frame
\n
Medium term (2030) Long term (2040)
\n
GHG target
\n
10.4 MtCO
\n
2eq
\n
<2.5 MtCO
\n
2eq
\n
Net zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-55% -90%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-12% -83%
\n
Climate scenario
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Invest a total of \u20ac18.6 billion in grids over the 2024-2026
\n
period, of which 50% to improve grid resilience, quality
\n
and digitalization, thereby helping to reduce grid losses
\n
and related greenhouse gas emissions. Replace existing
\n
distribution grid infrastructure components with SF
\n
6
\n
-free
\n
solutions.
\n
\u2022 Implement a circular procurement approach; increase the
\n
number of contracts that include the measurement of the
\n
carbon footprint of the products and services purchased
\n
by Enel, encouraging its reduction in a collaborative
\n
decarbonization process with our suppliers. Strengthen
\n
dialogue with raw material producers and other utilities
\n
to defi ne shared and eff ective long-term decarbonization
\n
strategies.
\n
\u2022 Phase out coal-fi red generation by 2027, mitigating all GHG
\n
emissions related to coal supply.
\n
\u2022 No use of carbon-removal technologies to achieve the
\n
target.
\n
\u2022 Promote grid digitalization and replace existing distribution
\n
grid infrastructure components with SF
\n
6
\n
-free solutions.
\n
\u2022 Implement a circular procurement approach; increase the
\n
number of contracts that include the measurement of the
\n
carbon footprint of the products and services purchased
\n
by Enel, encouraging its reduction in a collaborative
\n
decarbonization process with our suppliers. Strengthen
\n
dialogue with raw material producers and other utilities
\n
to defi ne shared and eff ective long-term decarbonization
\n
strategies.
\n
\u2022 Eliminate emissions connected with gas extraction activities,
\n
as the Group has fully exited gas-fi red generation and sale of
\n
gas to end users.
\n
\u2022 Neutralize the residual amount through carbon-removal
\n
actions (purchase of cert ifi cates linked to nature-based or
\n
technology-based projects in voluntary carbon markets,
\n
in accordance with international standards) if complete
\n
mitigation of emissions is not feasible due to exogenous
\n
factors (technological, market or regulatory).
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 11.9 MtCO
\n
2eq
\n
(for 2017-2030 target scope) and 13.5 MtCO
\n
2eq
\n
(for 2017-2040 target scope)
\n
(6)
\n
\u2022 \u20ac5.4 billion invested in the grid in 2023.
\n
\u2022 43% reduction in coal burned in thermal generation plants.
\n
\u2022 41% reduction in volume of gas burned in thermal generation plants compared with 2022 (due also to the sale of gas plants
\n
in Russia and Argentina), and 19% reduction in volume of gas sold to end users compared with 2022.
\n
\u2022 8% reduction in electricity consumption in Group generation plants and buildings.
\n
\u2022 24% reduction in emissions intensity (tCO
\n
2eq
\n
/\u20acmn) in supply chain in 2023 compared with 2022, reaching 684 tCO
\n
2eq
\n
/\u20acmn.
\n

\n\n\n\n\n
TOTAL COVERAGE OF SCOPES 1-2-3
\n
EMISSIONS IN 2023
\n
\u2022
\n
95.5% of Scope 1 GHG emissions (2026, 2030 and 2040 targets)
\n
\u2022
\n
100% of Scope 2 GHG emissions (2030 and 2040 targets)
\n
\u2022
\n
87% (2017-2030 target) and 90% (2017-2040 target) of Scope 3 GHG emissions
\n
(6)
\n
(1) Percentages based on total GHG emissions in 2023.
\n
(2) Excludes marginal Scope 1 GHG emissions not directly related to the combustion of fossil fuels in electricity generation at thermal plants. These emissions
\n
also include the use of ancillary services in distribution operations. In part icular, in 2023 there was an extraordinarily high use of these services in Brazil
\n
to deal with the meteorological emergency that occurred in S\u00e3o Paulo in November 2023, which caused the interruption of grid operations. In any event,
\n
95.8% of Scope 1 and Scope 2 GHG emissions are covered by all of the above targets, greater than the 95% threshold required under the Science Based
\n
Targets initiative and the GHG Protocol.
\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 offi cially validated because the SBTi does not cert ify targets over a time frame of less than fi ve years from the presentation date.
\n
(4) In 2023, gas sales decreased considerably compared with previous years. Furt hermore, a methodological change in the use of conversion factors has been
\n
implemented. These two factors produced a value below the target expected for 2026.
\n
(5) The target could not be offi cially validated because the SBTi does not cert ify targets over a time frame of less than fi ve years from the presentation date. In
\n
addition, the SBTi has not defi ned a sectoral decarbonization approach for these types of emissions, so the ambition level cannot be verifi ed.
\n
(6) Two diff erent 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

\n\n\n\n\n\n\n\n
The table below reports the composition of the main
\n
goodwill values for the companies to which the CGU be-
\n
longs, along with the discount rates applied and the time
\n
horizon over which the expected cash flows have been
\n
discounted.
\n
Millions of euro
\n
Amount of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WACC
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period of
\n
cash flows
\n
Terminal
\n
value
\n
(3)
\n
Amount of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WACC
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period of
\n
cash flows
\n
Terminal
\n
value
\n
(3)
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Iberian Peninsula 8,785 2.19% 8.23% 3 years
\n
Perpetuity/22
\n
years EGP/12
\n
years G&T/15
\n
years MKT
\n
8,785 2.47% 6.10% 3 years
\n
Perpetuity/25
\n
years EGP/13
\n
years G&T
\n
Chile 1,101 2.07% 9.57% 3 years
\n
Perpetuity/28
\n
years EGP/5
\n
years G&T
\n
1,148 2.00% 8.45% 3 years
\n
Perpetuity/26
\n
years EGP/5
\n
years G&T
\n
Argentina 20 17.57 % 41.90% 3 years Perpetuity 21 45.70% 71.78% 3 years Perpetuity
\n
Peru n.a. n.a. n.a. n.a. n.a. 571 2.25% 8.75% 3 years
\n
Perpetuity/25
\n
years EGP/8
\n
years G&T
\n
Colombia 526 3.50% 14.25% 3 years
\n
Perpetuity/25
\n
years EGP/14
\n
years G&T
\n
518 3.20% 11.79% 3 years
\n
Perpetuity/26
\n
years EGP/15
\n
years G&T
\n
Brazil 1,357 3.86% 12.31% 3 years
\n
Perpetuity/24
\n
years EGP
\n
1,313 3.58% 11.22% 3 years
\n
Perpetuity/25
\n
years EGP
\n
Central America 26 2.10% 10.92% 3 years 17 years 26 2.02% 9.66% 3 years 18 years
\n
Enel Green Power
\n
North America
\n
68 2.10% 8.27% 3 years 24 years 70 2.02% 6.48% 3 years 25 years
\n
Enel X North America 81 2.10% 11.75% 3 years Perpetuity 142 2.02% 9.71% 3 years Perpetuity
\n
Enel X Way North
\n
America
\n
n.a. n.a. n.a. n.a. n.a. 70 2.02% 11.53% 3 years Perpetuity
\n
Enel X Asia Pacific 84 2.10% 13.27% 3 years Perpetuity 84 2.02% 10.39% 3 years Perpetuity
\n
Enel X Rest of Europe 43 2.10% 11.45% 3 years Perpetuity 43 1.62% 8.82% 3 years Perpetuity
\n
Enel Green Power Italy 21 2.10% 8.66% 3 years
\n
Perpetuity/26
\n
years
\n
21 1.62% 6.39% 3 years
\n
Perpetuity/24
\n
years
\n
Market Italy 581 1.93% 11.31% 3 years 15 years 581 2.38% 10.69% 3 years 15 years
\n
Enel Produzione Italy 349 2.06% 9.07% 3 years
\n
Perpetuity/14
\n
years
\n
349 1.64% 7.70 % 3 years
\n
Perpetuity/15
\n
years
\n
Romania n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
CGUs with no
\n
recognized goodwill
\n
but that underwent
\n
impairment testing
\n
given the presence
\n
of the indicators
\n
provided for in IAS 36
\n
Iberia - NPT (Non-
\n
Peninsular Territories)
\n
n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
Australia n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
Mexico n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\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, MKT = End-user Markets).
\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1113": { "value": "\n

\n
23. Intangible assets \u2013 \u20ac17,055 million
\n
A breakdown of and changes in intangible assets for 2023
\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 advances
\n
Contract
\n
costs Total
\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
\n
amortization
\n
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
Capital expenditure 3 30 45 - 122 - 640 515 1,355
\n
Assets entering service 2 300 8 - 209 - (564) 10 (35)
\n
Exchange differences 1 (4) 220 72 (4) - (49) (4) 232
\n
Change in the
\n
consolidation scope
\n
- - 1 - - - (1) - -
\n
Disposals - (2) - (18) - - 3 - (17)
\n
Amortization (5) (313) (199) (402) (342) - - (425) (1,686)
\n
Impairment losses (3) - 1 - (1) - (57) - (60)
\n
Impairment gains - - - - 2 - - - 2
\n
Other changes (47) 50 (10) 513 - - (46) 3 463
\n
Reclassifications from/to
\n
assets held for sale
\n
(4) (49) (590) - (44) - (32) - (719)
\n
Total changes (53) 12 (524) 165 (58) - (106) 99 (465)
\n
Cost net of accumulated
\n
impairment losses
\n
55 3,988 12,401 5,822 5,513 - 1,641 3,352 32,772
\n
Accumulated
\n
amortization
\n
29 3,313 2,130 4,157 4,139 - - 1,949 15,717
\n
Balance at Dec. 31, 2023 26 675 10,271 1,665 1,374 - 1,641 1,403 17,055
\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, 2023.
\n
Millions of euro
\n
Grantor Activity Country
\n
Concession
\n
period
\n
Concession
\n
period remaining
\n
Renewal
\n
option
\n
at Dec. 31,
\n
2023
\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 - 5,677 5,678 5,673
\n
Enel Colombia
\n
(formerly Codensa)
\n
Republic of
\n
Colombia
\n
Electricity
\n
distribution
\n
Colombia Indefinite Indefinite - 1,266 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 - 1,254 1,331 1,667
\n
Assets with an indefinite useful life amounted to \u20ac8,197
\n
million (\u20ac8,056 million at December 31, 2022) essentially
\n
accounted for by concessions for distribution activities
\n
in Spain (\u20ac5,677 million), Colombia (\u20ac1,266 million) and
\n
Chile (\u20ac1,254 million), for which there was no statutory or
\n
currently predictable expiration date. On the basis of the
\n
forecasts developed, cash flows for each CGU, with which
\n
the various concessions are associated, were sufficient to
\n
recover the carrying amount. The change during the year
\n
was essentially attributable to changes in exchange rates
\n
in Latin America. The assets in respect of concession ar-
\n
rangements that do not fall within the scope of IFRIC 12
\n
of Enel Distribuci\u00f3n Per\u00fa were reclassified as held for sale
\n
in the amount of \u20ac581 million (\u20ac584 million at December
\n
31, 2022).
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\n
For more information on service concession arrange-
\n
ments, please see note 20.
\n

\n\n\n\n\n\n\n\n
Impairment losses amounted to \u20ac60 million in 2023, and
\n
mainly regarded renewable projects no longer considered
\n
strategic in Spain, the United States and Italy.
\n
\u201cReclassifications from/to assets held for sale\u201d refer main-
\n
ly to assets held by Enel Distribuci\u00f3n Per\u00fa SAA, Enel Gen-
\n
eraci\u00f3n Per\u00fa, Compa\u00f1\u00eda Energ\u00e9tica Veracruz and other
\n
renewable assets in North America (the latter sold at the
\n
beginning of 2024).
\n
\u201cOther changes\u201d mainly include the reclassification under
\n
financial assets of investments falling within the scope of
\n
IFRIC 12 in Brazil and the value adjustment of intangible
\n
assets of Argentine companies as a result of the applica-
\n
tion of the accounting standard for financial reporting in
\n
hyperinflationary economies.
\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1114": { "value": "\n

\n\n
24. Goodwill \u2013 \u20ac13,042 million
\n
Millions of euro at Dec. 31, 2022
\n
Change in the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Impairment
\n
losses
\n
Reclassifications
\n
from/to assets
\n
held for sale
\n
Other
\n
changes at Dec. 31, 2023
\n
Net carrying
\n
amount
\n
Net carrying
\n
amount
\n
Iberian Peninsula 8,785 - - - - - 8,785
\n
Chile 1,148 - (1) - (46) - 1,101
\n
Argentina 21 - (1) - - - 20
\n
Peru 571 - (1) - (570) - -
\n
Colombia 518 - 8 - - - 526
\n
Brazil 1,313 - 44 - - - 1,357
\n
Central America 26 - - - - - 26
\n
Enel Green Power North
\n
America
\n
70 - (2) - - - 68
\n
Enel X North America 142 - (4) (57) - - 81
\n
Enel X Way North America 70 - (1) (69) - -
\n
Enel X Asia Pacific 84 - - - - - 84
\n
Enel X Rest of Europe
\n
(1)
\n
43 - - - - - 43
\n
Market Italy
\n
(2)
\n
581 - - - - - 581
\n
Enel Green Power Italy 21 - - - - - 21
\n
Enel Produzione Italy 349 - - - - - 349
\n
Total 13,742 - 42 (126) (616) - 13,042
\n
(1) Includes Viva Labs.
\n
(2) Includes Enel Energia.
\n
The following table presents the allocation of goodwill
\n
in the matrix of business lines and geographical areas.
\n
Note that the changes in the presentation of operating
\n
segments, described in note 10 above, did not produce
\n
changes in the allocation of goodwill for the purposes of
\n
impairment testing.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\n
Goodwill matrix at Dec. 31, 2023
\n
Millions of euro
\n
Thermal
\n
Generation and
\n
Trading
\n
Enel Green
\n
Power Enel Grids
\n
End-user
\n
Markets
\n
Holding and
\n
Services Total
\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 - 1 19 - - 20
\n
Brazil - 502 855 - - 1,357
\n
Chile - 949 152 - - 1,101
\n
Colombia - 303 223 - - 526
\n
Peru - - - - - -
\n
Central America - 26 - - - 26
\n
Enel Green Power North America - 68 - - - 68
\n
Enel X North America - - - 81 - 81
\n
Enel X Way North America - - - - - -
\n
Enel X Asia Pacific - - - 84 - 84
\n
Enel X Rest of Europe
\n
(2)
\n
- - - 43 - 43
\n
Total - 3,409 7,037 2,596 - 13,042
\n
(1) Includes Enel Energia.
\n
(2) Includes Viva Labs.
\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
\n
(1)
\n
Holding and
\n
Services
\n
(1)
\n
Total
\n
Enel Green Power Italy - 21 - - - 21
\n
Market Italy
\n
(2)
\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 North America - 70 - - - 70
\n
Enel X North America - - - 142 - 142
\n
Enel X Way North America - - - 70 - 70
\n
Enel X Asia Pacific - - - 84 - 84
\n
Enel X Rest of Europe
\n
(3)
\n
- - - 43 - 43
\n
Total 44 3,634 7, 337 2,727 - 13,742
\n
(1) The figures for 2022 for the End-user Market Business Line have been adjusted to take account of the values for Enel X and Enel X Way. The latter had
\n
previously been reported under Holding, Services and Other.
\n
(2) Includes Enel Energia.
\n
(3) Includes Viva Labs.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\n
The decrease of \u20ac700 million in goodwill was mainly at-
\n
tributable to Peru for the reclassification as assets held for
\n
sale of generation and distribution assets (\u20ac570 million),
\n
and Chile for the reclassification to assets held for sale of
\n
Arcadia Generaci\u00f3n Solar (\u20ac46 million).
\n
New impairment losses were also recognized in 2023 in
\n
respect of the CGUs in North America of Enel X and Enel
\n
X Way (\u20ac57 and \u20ac69 million, respectively) following impair-
\n
ment testing conducted in response to changes in macro-
\n
economic conditions.
\n
The decrease is partly offset by exchange gains recog-
\n
nized in Brazil.
\n
The recoverable amount of the goodwill recognized was
\n
estimated by calculating the value in use of the CGUs us-
\n
ing discounted cash flow models, which involve estimating
\n
expected future cash flows and applying an appropriate
\n
discount rate, selected on the basis of market inputs such
\n
as risk-free rates, betas and market-risk premiums.
\n
Cash flows were determined on the basis of the best in-
\n
formation available at the time of the estimate, taking ac-
\n
count of the specific risks of each CGU, and drawn:
\n
\u2022
\n
for the explicit period, from the Business Plan approved
\n
by the Board of Directors of the Parent on November
\n
22, 2023, containing forecasts for volumes, revenue,
\n
operating costs, capital expenditure, industrial and
\n
commercial organization and developments in the main
\n
macroeconomic variables (inflation, nominal interest
\n
rates and exchange rates) and commodity prices. The
\n
explicit period of cash flows considered in impairment
\n
testing was three years;
\n
\u2022
\n
for subsequent years, from assumptions concerning
\n
long-term developments in the main variables that de-
\n
termine cash flows, the average residual useful life of
\n
assets or the duration of the concessions.
\n
More specifically, the terminal value is calculated based on
\n
the specific characteristics of the businesses related to
\n
the various CGUs subject to impairment testing:
\n
\u2022
\n
perpetuity, for the businesses of large-hydro (LH) pow-
\n
er generation and of distribution, in which the licenses
\n
and public concessions are of a long-term nature and
\n
renewal can be forecast with reasonable certainty; as
\n
well as for the Enel X and Enel X Way businesses, as they
\n
feature the development of specific know-how that is
\n
sustainable over the long term;
\n
\u2022
\n
annuity, for CGUs that are predominantly characterized
\n
by retail business, for which the residual life is, there-
\n
fore, essentially correlated with the average duration
\n
of the customer relationships; as well as for businesses
\n
of conventional thermal power generation (Genera-
\n
tion and Trading). This method is also used for the re-
\n
newable energy (Enel Green Power) businesses to take
\n
account of: (i) the value resulting from the remaining
\n
useful lives of the plants; and (ii) the residual value, in
\n
the event of plant decommissioning, associated with
\n
licensing rights, the competitiveness of the production
\n
facilities (in terms of natural resources), and network in-
\n
terconnectivity.
\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).
\n
Regarding the assumptions for commodity price develop-
\n
ments, the scenarios adopted are consistent with current
\n
emissions reductions targets.
\n
Note also that the Group has used sensitivity analysis to
\n
take account of the impacts of climate change in the long
\n
term. More specifically:
\n
\u2022
\n
we consider a perpetual long-term growth rate for
\n
cash flows after the explicit period that is in line with the
\n
change in electricity demand over the 2026-2050 pe-
\n
riod, based on the specific features of the businesses
\n
concerned, adopting certain assumptions concerning
\n
the increase in temperature due to climate change and
\n
trends connected with the energy transition;
\n
\u2022
\n
we consider changes in the hydroelectric, wind and
\n
photovoltaic generation levels of our Portfolio assets,
\n
associated with each projection of underlying climate
\n
and weather variables (for example, temperature, irra-
\n
diance, wind speed and precipitation);
\n
\u2022
\n
we assume that the Group will incur the costs provi-
\n
sioned for decommissioning fossil fuel generation
\n
plants in line with the goal of zero direct (Scope 1) and
\n
indirect emissions from retail activities (Scope 3).
\n
In order to verify the robustness of the value in use of
\n
the CGUs, sensitivity analyses were conducted for the
\n
main value drivers, in particular WACC and the long-term
\n
growth rate.
\n
Even in these circumstances, results were consistent with
\n
the evidence described previously, finding that for all the
\n
CGUs analyzed, with the exception of those written down
\n
(Enel X North America and Enel X Way North America), the
\n
value in use exceeded the carrying amount, ensuring the
\n
full recoverability of the carrying amounts of those assets
\n
in the consolidated financial statements of the Enel Group
\n
at December 31, 2023.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\n
OUR ZERO-EMISSIONS
\n
AMBITION
\n
Enel is committ ed to achieving zero emissions by 2040
\n
and to developing a business model that is in line
\n
with the objectives of the Paris Agreement (COP 21)
\n
to limit the average increase in global temperatures
\n
to 1.5 \u00baC. For this reason, the Group has developed a
\n
decarbonatization roadmap that covers both direct
\n
and indirect emissions throughout the value chain. The
\n
roadmap includes four targets cert ifi ed by the Science
\n
Based Targets initiative (SBTi) in December 2022 to be
\n
in line with the Net Zero Standard.
\n
GHG TARGET
\n
Intensity of Scope 1 GHG emissions related to power generation
\n
Primary business
\n
activity
\n
Electricity generation
\n
Type of activity in
\n
value chain
\n
Direct
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
95% of Scope 1 GHG emissions
\n
(2)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
125 gCO
\n
2eq
\n
/kWh 72 gCO
\n
2eq
\n
/kWh
\n
0 gCO
\n
2eq
\n
/kWh
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-66% -80% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-22% -55% -100%
\n
Climate scenario
\n
1.5 \u00b0C
\n
(3)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Gradual phase out of coal-fi red capacity
\n
in 2024-2026, with planned closure of
\n
the Federico II and Torrevaldaliga Nord
\n
plants in Italy (with a total capacity of
\n
about 3.6 GW).
\n
\u2022 Invest \u20ac12.1 billion to accelerate the
\n
development of renewable energy by
\n
installing 13.4 GW of new renewables
\n
capacity (about 11.3 GW of which at
\n
the consolidated level) in 2024-2026,
\n
reaching 73 GW of renewables capacity
\n
(including BESS) by 2026.
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, with the
\n
proport ion of renewables plants in the
\n
Enel asset port folio reaching 78% in
\n
2026, with zero-emissions generation
\n
amounting to 86% of the total, including
\n
consolidated and managed generation.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
\u2022 Continue the process of decarbonizing
\n
electricity generation, with Group
\n
investments raising the proport ion of
\n
renewables plants in the asset port folio
\n
to about 85% in 2030, with zero-
\n
emissions generation amounting to 90%
\n
of the total, including consolidated and
\n
managed generation.
\n
\u2022 Exit from coal-fi red generation, which is
\n
expected to take place by 2027 globally.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
\u2022 Exit from the thermal electricity
\n
generation business, achieving a 100%
\n
renewable energy mix.
\n
\u2022 No use of carbon-removal technologies
\n
to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 160 gCO
\n
2eq
\n
/kWh
\n
\u2022 About \u20ac5.9 billion invested in renewables in 2023.
\n
\u2022 New consolidated renewables capacity installed equal to 4 GW in 2023, bringing total consolidated capacity to 55.5 GW in
\n
2023.
\n
\u2022 Increase in consolidated renewables generation equal to 13% on 2022, representing 61% of total consolidated generation in
\n
2023.
\n
\u2022 Reduction of thermal capacity by about 5.1 GW on 2022, including the closure of two coal-fi red plants (for a total of about 2
\n
GW) and the sale of gas plants in Argentina (for a total of about 3 GW) and Colombia (for a total of about 0.2 GW).
\n
\u2022 Reduction of thermal generation by 38% on 2022 (specifi cally, with a 45% reduction in coal-fi red generation), representing 27%
\n
of total generation in 2023.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n
\n\n
GHG TARGET
\n
Intensity of Scope 1 and Scope 3 GHG emissions related to Integrated Power
\n
Primary business
\n
activity
\n
Sale of electricity
\n
Type of activity in
\n
value chain
\n
\u2022 Direct (electricity generation)
\n
\u2022 Upstream in value chain (purchase of electricity from other generators for sale to end users)
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Electricity generators (peers)
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 95% of Scope 1 GHG emissions
\n
\u2022 42% of Scope 3 GHG emissions (corresponding to 78% of Scope 3 GHG emissions \u2013 category 3)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
135 gCO
\n
2eq
\n
/kWh 73 gCO
\n
2eq
\n
/kWh
\n
0 gCO
\n
2eq
\n
/kWh
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-59% -78% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-20% -57% -100%
\n
Climate scenario
\n
1.5 \u00b0C
\n
(3)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Increase the percentage of renewable
\n
energy sold to customers, while
\n
increasing the Group\u2019s renewables
\n
production and optimizing customer
\n
port folio, continuing supply and
\n
demand balancing strategy.
\n
\u2022 In Europe, increase the share of
\n
fi xed-price energy sales to end users
\n
covered by zero-emissions sources
\n
from about 65% in 2023 to more than
\n
80% in 2026.
\n
\u2022 In Latin America, maintain 100%
\n
zero-emissions sales to end users
\n
(including through PPAs).
\n
\u2022 In Nort h America, maintain 100% zero-
\n
emissions sales to end users.
\n
\u2022 Continue the process of
\n
decarbonizing electricity generation,
\n
increasing zero-emissions generation
\n
from 75% in 2023 (including managed
\n
capacity) to 86% of total in 2026,
\n
including consolidated and managed
\n
capacity.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 Continue the strategy of balancing
\n
supply and demand and increase the
\n
share of electricity sold at a fi xed price
\n
covered by carbon-free generation.
\n
\u2022 Continue the process of
\n
decarbonizing electricity generation,
\n
increasing zero-emissions generation
\n
to about 90% of the total in 2030.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 By 2040, achieve 100% of electricity
\n
sales covered by renewables.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 168 gCO
\n
2eq
\n
/kWh
\n
\u2022 13% increase in Group consolidated renewables generation in 2023 on 2022.
\n
\u2022 7% reduction in 2023 compared with 2022 in the gap between sale of electricity to end users and own generation in the
\n
countries in which the Group has an integrated position.
\n
\n\n
\n\n

\n\n
GHG TARGET
\n
Scope 3 GHG emissions related to the sale of natural gas on end-user market
\n
Primary business
\n
activity
\n
Sale of gas to end users
\n
Type of activity in
\n
value chain
\n
\u2022 Downstream in value chain
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Gas customers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 30% of Scope 3 GHG emissions (corresponding to 100% of Scope 3 GHG emissions \u2013 category 11)
\n
Time frame
\n
Short term (2026) Medium term (2030) Long term (2040)
\n
GHG target
\n
20.0 MtCO
\n
2eq
\n
11.4 MtCO
\n
2eq
\n
0 MtCO
\n
2eq
\n
Zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-21% -55% -100%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-
\n
(4)
\n
-32% -100%
\n
Climate scenario
\n
n.a.
\n
(5)
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Encourage customers (especially
\n
residential customers) to switch
\n
from gas to electricity by promoting
\n
effi cient electricity technologies
\n
(e.g., heat pumps for home heating
\n
or induction cooktops in kitchens),
\n
increasing annual unit electricity
\n
consumption of free-market B2C
\n
power customers (in Italy and Iberia)
\n
from 2.65 MWh in 2023 to about 2.9
\n
MWh in 2026, thereby increasing the
\n
electrifi cation rate of customers.
\n
\u2022 Allocate 32% of investment in grids
\n
in 2024-2026 to connections, part ly
\n
with a view to enabling the expansion
\n
of distributed generation, thereby
\n
promoting the electrifi cation of
\n
end users\u2019 energy consumption.
\n
The number of connections to
\n
distributed generation is forecast
\n
to double in the period, reaching 4
\n
million in 2026.
\n
\u2022 Reduce the volumes of gas sold to
\n
customers to around 8.4 billion cubic
\n
meters in 2026.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 Encourage customers (especially
\n
residential customers) to switch
\n
from gas to electricity by promoting
\n
effi cient electricity technologies
\n
(e.g., heat pumps for home heating
\n
or induction cooktops in kitchens),
\n
increasing annual unit electricity
\n
consumption of free-market B2C
\n
power customers (in Italy and Iberia)
\n
to about 3.5 MWh in 2030, thereby
\n
increasing the electrifi cation rate of
\n
customers.
\n
\u2022 Continue to invest in distribution
\n
grids, support ing the growth of
\n
distributed generation, thereby
\n
promoting the electrifi cation of end
\n
users\u2019 energy consumption, reaching
\n
6 million connections to distributed
\n
generation in 2030.
\n
\u2022 Optimize the customer gas port folio
\n
(industrial customers in part icular),
\n
continuing to reduce the volume of
\n
gas sold to about 5.3 billion cubic
\n
meters in 2030.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
\u2022 By 2040, achieve 100% of energy sales
\n
covered by renewables.
\n
\u2022 Exit retail gas sales business by 2040.
\n
\u2022 No use of carbon-removal
\n
technologies to achieve the target.
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 16.8 MtCO
\n
2eq
\n
\u2022 6.2 million gas customers in 2023, down 6% on 2022.
\n
\u2022 Gas sales in 2023 equal to 8.3 billion cubic meters, down 19% on 2022.
\n
\u2022 3.6 million new connections in 2023.
\n

\n\n\n

\n\n\n

\n\n
GHG TARGET
\n
Additional emissions Scopes 1-2-3
\n
Primary business
\n
activity
\n
\u2022 Electricity distribution (Scopes 1 and 2)
\n
\u2022 Management of vehicle fl eet, buildings and other assets (Scopes 1 and 2)
\n
\u2022 Management of supply chain (Scope 3)
\n
\u2022 Purchase of fuels (Scope 3)
\n
Type of activity in
\n
value chain
\n
\u2022 Direct (electricity distribution and management of vehicle fl eet, buildings and other Group assets)
\n
\u2022 Upstream in value chain (supply chain for products and services and fuel business)
\n
Stakeholders
\n
impacted or
\n
involved
\n
\u2022 Customers and power consumers
\n
\u2022 Electricity generators (peers)
\n
\u2022 Suppliers of goods and services
\n
\u2022 Oil&gas suppliers
\n
\u2022 Society and environment
\n
Sources
\n
of covered GHG
\n
(GHG Protocol)
\n
(1)
\n
\u2022 0.5% of Scope 1 GHG emissions
\n
\u2022 100% of Scope 2 GHG emissions
\n
\u2022 Target 2030
\n
(6)
\n
: 15% of Scope 3 GHG emissions (corresponding to 17% of Scope 3 emissions - category 1 and 22%
\n
of Scope 3 emissions - category 3)
\n
\u2022 Target 2040
\n
(6)
\n
: 18% of Scope 3 GHG emissions (corresponding to 35% of Scope 3 emissions - category 1 and 22%
\n
of Scope 3 emissions - category 3)
\n
Time frame
\n
Medium term (2030) Long term (2040)
\n
GHG target
\n
10.4 MtCO
\n
2eq
\n
<2.5 MtCO
\n
2eq
\n
Net zero emissions
\n
% reduction on 2017
\n
(SBTi baseline)
\n
-55% -90%
\n
% reduction on
\n
2023 (report ing
\n
year)
\n
-12% -83%
\n
Climate scenario
\n
1.5 \u00b0C (SBTi cert ifi ed) 1.5 \u00b0C (SBTi cert ifi ed)
\n
Primary drivers and
\n
actions
\n
\u2022 Invest a total of \u20ac18.6 billion in grids over the 2024-2026
\n
period, of which 50% to improve grid resilience, quality
\n
and digitalization, thereby helping to reduce grid losses
\n
and related greenhouse gas emissions. Replace existing
\n
distribution grid infrastructure components with SF
\n
6
\n
-free
\n
solutions.
\n
\u2022 Implement a circular procurement approach; increase the
\n
number of contracts that include the measurement of the
\n
carbon footprint of the products and services purchased
\n
by Enel, encouraging its reduction in a collaborative
\n
decarbonization process with our suppliers. Strengthen
\n
dialogue with raw material producers and other utilities
\n
to defi ne shared and eff ective long-term decarbonization
\n
strategies.
\n
\u2022 Phase out coal-fi red generation by 2027, mitigating all GHG
\n
emissions related to coal supply.
\n
\u2022 No use of carbon-removal technologies to achieve the
\n
target.
\n
\u2022 Promote grid digitalization and replace existing distribution
\n
grid infrastructure components with SF
\n
6
\n
-free solutions.
\n
\u2022 Implement a circular procurement approach; increase the
\n
number of contracts that include the measurement of the
\n
carbon footprint of the products and services purchased
\n
by Enel, encouraging its reduction in a collaborative
\n
decarbonization process with our suppliers. Strengthen
\n
dialogue with raw material producers and other utilities
\n
to defi ne shared and eff ective long-term decarbonization
\n
strategies.
\n
\u2022 Eliminate emissions connected with gas extraction activities,
\n
as the Group has fully exited gas-fi red generation and sale of
\n
gas to end users.
\n
\u2022 Neutralize the residual amount through carbon-removal
\n
actions (purchase of cert ifi cates linked to nature-based or
\n
technology-based projects in voluntary carbon markets,
\n
in accordance with international standards) if complete
\n
mitigation of emissions is not feasible due to exogenous
\n
factors (technological, market or regulatory).
\n
Results and
\n
main actions in
\n
2023
\n
KPI achievement in 2023: 11.9 MtCO
\n
2eq
\n
(for 2017-2030 target scope) and 13.5 MtCO
\n
2eq
\n
(for 2017-2040 target scope)
\n
(6)
\n
\u2022 \u20ac5.4 billion invested in the grid in 2023.
\n
\u2022 43% reduction in coal burned in thermal generation plants.
\n
\u2022 41% reduction in volume of gas burned in thermal generation plants compared with 2022 (due also to the sale of gas plants
\n
in Russia and Argentina), and 19% reduction in volume of gas sold to end users compared with 2022.
\n
\u2022 8% reduction in electricity consumption in Group generation plants and buildings.
\n
\u2022 24% reduction in emissions intensity (tCO
\n
2eq
\n
/\u20acmn) in supply chain in 2023 compared with 2022, reaching 684 tCO
\n
2eq
\n
/\u20acmn.
\n

\n\n\n\n\n

\n\n\n\n\n

\n\n
TOTAL COVERAGE OF SCOPES 1-2-3
\n
EMISSIONS IN 2023
\n
\u2022
\n
95.5% of Scope 1 GHG emissions (2026, 2030 and 2040 targets)
\n
\u2022
\n
100% of Scope 2 GHG emissions (2030 and 2040 targets)
\n
\u2022
\n
87% (2017-2030 target) and 90% (2017-2040 target) of Scope 3 GHG emissions
\n
(6)
\n
(1) Percentages based on total GHG emissions in 2023.
\n
(2) Excludes marginal Scope 1 GHG emissions not directly related to the combustion of fossil fuels in electricity generation at thermal plants. These emissions
\n
also include the use of ancillary services in distribution operations. In part icular, in 2023 there was an extraordinarily high use of these services in Brazil
\n
to deal with the meteorological emergency that occurred in S\u00e3o Paulo in November 2023, which caused the interruption of grid operations. In any event,
\n
95.8% of Scope 1 and Scope 2 GHG emissions are covered by all of the above targets, greater than the 95% threshold required under the Science Based
\n
Targets initiative and the GHG Protocol.
\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 offi cially validated because the SBTi does not cert ify targets over a time frame of less than fi ve years from the presentation date.
\n
(4) In 2023, gas sales decreased considerably compared with previous years. Furt hermore, a methodological change in the use of conversion factors has been
\n
implemented. These two factors produced a value below the target expected for 2026.
\n
(5) The target could not be offi cially validated because the SBTi does not cert ify targets over a time frame of less than fi ve years from the presentation date. In
\n
addition, the SBTi has not defi ned a sectoral decarbonization approach for these types of emissions, so the ambition level cannot be verifi ed.
\n
(6) Two diff erent 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

\n\n\n\n\n\n\n\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 to which the CGU be-
\n
longs, along with the discount rates applied and the time
\n
horizon over which the expected cash flows have been
\n
discounted.
\n
Millions of euro
\n
Amount of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WACC
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period of
\n
cash flows
\n
Terminal
\n
value
\n
(3)
\n
Amount of
\n
goodwill
\n
Growth
\n
rate
\n
(1)
\n
Pre-tax
\n
WACC
\n
discount
\n
rate
\n
(2)
\n
Explicit
\n
period of
\n
cash flows
\n
Terminal
\n
value
\n
(3)
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Iberian Peninsula 8,785 2.19% 8.23% 3 years
\n
Perpetuity/22
\n
years EGP/12
\n
years G&T/15
\n
years MKT
\n
8,785 2.47% 6.10% 3 years
\n
Perpetuity/25
\n
years EGP/13
\n
years G&T
\n
Chile 1,101 2.07% 9.57% 3 years
\n
Perpetuity/28
\n
years EGP/5
\n
years G&T
\n
1,148 2.00% 8.45% 3 years
\n
Perpetuity/26
\n
years EGP/5
\n
years G&T
\n
Argentina 20 17.57 % 41.90% 3 years Perpetuity 21 45.70% 71.78% 3 years Perpetuity
\n
Peru n.a. n.a. n.a. n.a. n.a. 571 2.25% 8.75% 3 years
\n
Perpetuity/25
\n
years EGP/8
\n
years G&T
\n
Colombia 526 3.50% 14.25% 3 years
\n
Perpetuity/25
\n
years EGP/14
\n
years G&T
\n
518 3.20% 11.79% 3 years
\n
Perpetuity/26
\n
years EGP/15
\n
years G&T
\n
Brazil 1,357 3.86% 12.31% 3 years
\n
Perpetuity/24
\n
years EGP
\n
1,313 3.58% 11.22% 3 years
\n
Perpetuity/25
\n
years EGP
\n
Central America 26 2.10% 10.92% 3 years 17 years 26 2.02% 9.66% 3 years 18 years
\n
Enel Green Power
\n
North America
\n
68 2.10% 8.27% 3 years 24 years 70 2.02% 6.48% 3 years 25 years
\n
Enel X North America 81 2.10% 11.75% 3 years Perpetuity 142 2.02% 9.71% 3 years Perpetuity
\n
Enel X Way North
\n
America
\n
n.a. n.a. n.a. n.a. n.a. 70 2.02% 11.53% 3 years Perpetuity
\n
Enel X Asia Pacific 84 2.10% 13.27% 3 years Perpetuity 84 2.02% 10.39% 3 years Perpetuity
\n
Enel X Rest of Europe 43 2.10% 11.45% 3 years Perpetuity 43 1.62% 8.82% 3 years Perpetuity
\n
Enel Green Power Italy 21 2.10% 8.66% 3 years
\n
Perpetuity/26
\n
years
\n
21 1.62% 6.39% 3 years
\n
Perpetuity/24
\n
years
\n
Market Italy 581 1.93% 11.31% 3 years 15 years 581 2.38% 10.69% 3 years 15 years
\n
Enel Produzione Italy 349 2.06% 9.07% 3 years
\n
Perpetuity/14
\n
years
\n
349 1.64% 7.70 % 3 years
\n
Perpetuity/15
\n
years
\n
Romania n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
CGUs with no
\n
recognized goodwill
\n
but that underwent
\n
impairment testing
\n
given the presence
\n
of the indicators
\n
provided for in IAS 36
\n
Iberia - NPT (Non-
\n
Peninsular Territories)
\n
n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
Australia n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\n
Mexico n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.
\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, MKT = End-user Markets).
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag101": { "value": "\n
25. Deferred tax assets and liabilities \u2013 \u20ac9,218 million and \u20ac8,217 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
\n
held for sale
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Deferred tax assets:
\n
- differences in the
\n
carrying amount of
\n
intangible assets,
\n
property, plant and
\n
equipment
\n
2,313 (79) - - - 65 (30) 2,269
\n
- accruals to provisions
\n
for risks and charges
\n
and impairment
\n
losses with deferred
\n
deductibility
\n
1,956 (68) - - 6 33 (2) 1,925
\n
- tax loss carried forward 786 (39) - - (12) 11 - 746
\n
- measurement of
\n
financial instruments
\n
2,914 1 (1,521) - (2) (70) - 1,322
\n
- employee benefits 798 (25) 66 - 22 3 (1) 863
\n
- other items
\n
(1)
\n
2,408 32 11 1 (148) (98) (113) 2,093
\n
Total 11,175 (178) (1,444) 1 (134) (56) (146) 9,218
\n
Deferred tax liabilities:
\n
- differences on non-
\n
current and financial
\n
assets
\n
5,719 17 - 1 (490) 306 (515) 5,038
\n
- measurement of
\n
financial instruments
\n
1,506 (3) (473) - (3) (69) (1) 957
\n
- other items
\n
(1)
\n
2,569 (200) (5) - (27) (68) (47) 2,222
\n
Total 9,794 (186) (478) 1 (520) 169 (563) 8,217
\n
Non-offsettable
\n
deferred tax assets
\n
5,221
\n
Non-offsettable
\n
deferred tax liabilities
\n
3,347
\n
Excess net deferred
\n
tax liabilities after any
\n
offsetting
\n
873
\n
(1) The figures at December 31, 2022 for deferred tax assets and liabilities have been adjusted in the amount of \u20ac250 million and \u20ac252 million respectively to
\n
take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods beginning on or after January 1, 2023. For more
\n
information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Deferred tax assets recognized at December 31, 2023, as
\n
the recovery of such assets is considered reasonably cer-
\n
tain, totaled \u20ac9,218 million (\u20ac11,175 million at December
\n
31, 2022).
\n
Deferred tax assets decreased by \u20ac1,957 million during
\n
the year, essentially due to:
\n
\u2022
\n
a decrease in deferred tax assets connected with de-
\n
velopments in the fair value of cash flow hedge deriv-
\n
atives;
\n
\u2022
\n
the impact of exchange rate differences in Latin Amer-
\n
ica, in particular in Argentina;
\n
\u2022
\n
the reversal of the portion of deferred tax assets no
\n
longer considered recoverable in the United States and
\n
Mexico;
\n
\u2022
\n
the reclassification to assets held for sale of generation
\n
and distribution assets in Peru.
\n
Note that deferred tax assets have not been assessed on
\n
tax losses carried forward for the year (\u20ac1,480 million) in
\n
\n\n
the amount of \u20ac453 million, as their recoverability is not
\n
considered probable based on current estimates of future
\n
taxable income.
\n
Deferred tax liabilities amounted to \u20ac8,217 million at De-
\n
cember 31, 2023 (\u20ac9,794 million at December 31, 2022).
\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 decreased by a total of \u20ac1,577 mil-
\n
lion, due in particular to:
\n
\u2022
\n
the decrease in deferred tax liabilities connected with
\n
developments in the fair value of cash flow hedge de-
\n
rivatives;
\n
\u2022
\n
the impact of exchange rate differences in Latin Amer-
\n
ica, in particular in Argentina;
\n
\u2022
\n
the reversal of deferred tax liabilities connected with
\n
impairment losses on renewable generation plants in
\n
the United States;
\n
\u2022
\n
the reclassification of deferred tax liabilities relating to
\n
companies held for sale in Peru.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1097": { "value": "\n
27. Derivatives
\n
Millions of euro Non-current Current
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivative financial assets 2,383 3,970 6,407 14,830
\n
Derivative financial liabilities 3,373 5,895 6,461 16,141
\n
For more information on derivatives qualifying has hedg-
\n
ing instruments and measured at FVTPL, please see note
\n
51 \u201cDerivatives and hedge accounting\u201d.
\n

\n\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
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
DERIVATIVE ASSETS
\n
Fair value hedge derivatives:
\n
- on interest rates 556 154 101 22 - - - -
\n
- on exchange rates 90 99 12 15 - - - -
\n
Total 646 253 113 37 - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 4,090 4,949 174 336 54 9 1 -
\n
- on exchange rates 11,060 16,955 1,007 1,854 4,393 4,053 145 389
\n
- on commodities 4,094 4,321 883 1,270 5,560 7,416 1,818 2,366
\n
Total 19,244 26,225 2,064 3,460 10,007 11,478 1,964 2,755
\n
Trading derivatives:
\n
- on interest rates - - - - - - - -
\n
- on exchange rates 84 19 1 1 1,734 3,640 24 74
\n
- on commodities 858 1 ,774 205 472 17,51 1 49,253 4,419 12,001
\n
Total 942 1,793 206 473 19,245 52,893 4,443 12,075
\n
TOTAL DERIVATIVE ASSETS 20,832 28,271 2,383 3,970 29,252 64,371 6,407 14,830
\n
\n\n
\n
Millions of euro Non-current Current
\n
Notional Fair value Notional Fair value
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
DERIVATIVE LIABILITIES
\n
Fair value hedge derivatives:
\n
- on interest rates 675 1,603 27 92 554 - 17 -
\n
- on exchange rates 929 813 78 99 - 185 - -
\n
Total 1,604 2,416 105 191 554 185 17 -
\n
Cash flow hedge derivatives:
\n
- on interest rates 1,897 890 91 59 100 150 - 1
\n
- on exchange rates 11,173 11,956 1,830 1,640 4,785 3,798 332 176
\n
- on commodities 3,075 6,403 1,143 3,417 4,696 9,556 1,627 4,322
\n
Total 16,145 19,249 3,064 5,116 9,581 13,504 1,959 4,499
\n
Trading derivatives:
\n
- on interest rates - - - - 100 100 29 23
\n
- on exchange rates 67 52 1 1 1,807 2,096 28 34
\n
- on commodities 921 1,281 203 587 16,693 45,899 4,428 11,585
\n
Total 988 1,333 204 588 18,600 48,095 4,485 11,642
\n
TOTAL DERIVATIVE LIABILITIES 18,737 22,998 3,373 5,895 28,735 61,784 6,461 16,141
\n\n
51.1 Derivatives designated as hedging
\n
instruments
\n
Derivatives are initially recognized at fair value, on the
\n
trade date of the contract, and are subsequently re-mea-
\n
sured at their fair value. The method of recognizing the
\n
resulting gain or loss depends on whether the derivative is
\n
designated as a hedging instrument, and if so, the nature
\n
of the 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) when all
\n
the criteria provided 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
\n
fair value hedges;
\n
\u2022
\n
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
\n
existence of an economic relationship between hedg-
\n
ing instrument and hedged item;
\n
\u2022
\n
the effect of credit risk does not dominate the value
\n
changes resulting from the economic relationship;
\n
\u2022
\n
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
\n
a qualitative assessment or a quantitative computation,
\n
depending on the following circumstances:
\n
\u2022
\n
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
\n
on the other hand, if the underlying 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 that of the hedged item, different
\n
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
\n\n
\n\n
\n\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
\n
the hedge relationships (including commodity price risk
\n
hedging) 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
\n
if the critical terms of the hedged item and hedging
\n
instrument match and there are no other sources of
\n
ineffectiveness including the credit risk adjustment on
\n
the hedging derivative, the hedge relationship will be
\n
considered fully effective on the basis of a qualitative
\n
assessment;
\n
\u2022
\n
if the critical terms of the hedged item and hedging in-
\n
strument do not match or there is at least one source
\n
of ineffectiveness, the hedge ineffectiveness will be
\n
quantified applying the dollar offset cumulative meth-
\n
od with hypothetical derivative. This method compares
\n
changes in the fair value of the hedging instrument and
\n
the hypothetical derivative between the reporting date
\n
and the inception date.
\n
The main causes of hedge ineffectiveness can be the fol-
\n
lowing:
\n
\u2022
\n
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
\n
timing differences (i.e. the hedged item and hedging in-
\n
strument occur or are settled at different dates);
\n
\u2022
\n
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
\n
other risks (i.e. changes in the fair value or cash flows of
\n
a derivative hedging instrument or hedged item relate
\n
to risks other than the specific risk being hedged);
\n
\u2022
\n
credit risk (i.e. the counterparty credit risk differently
\n
impacts the changes in the fair value of the hedging
\n
instruments and hedged items).
\n
Fair value hedges
\n
Fair value hedges are mainly used to protect the Group
\n
against exposures to changes in the fair value of 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 val-
\n
ue of the hedged item that are attributable to the hedged
\n
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 meth-
\n
od is used is amortized to profit or loss over the period to
\n
maturity.
\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 af-
\n
fect 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
\n\n
\n\n
\n\n
\n
hedge accounting approach based on specific liquidity
\n
requirements (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 ex-
\n
piry but also during the hedge relationship, if and only if the
\n
new derivative meets both of the following requirements:
\n
\u2022
\n
it represents a best proxy of the old derivative in terms
\n
of ranking;
\n
\u2022
\n
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
\n
the effective fair value of the new derivative will be rec-
\n
ognized in equity (the hedging reserve), while changes in
\n
the fair value of the old derivative are recognized through
\n
profit 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.
\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, the 1-month, 3-month and 6-month
\n
USD LIBOR benchmarks have become unrepresentative
\n
after June 30, 2023 and the alternative reference rate is
\n
the Secured Overnight Financing Rate (SOFR).
\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
\u2022
\n
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
\n
rate (Phase 1); and
\n
\u2022
\n
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 previously been implemented in contracts in-
\n
dexed to GBP LIBOR in 2021 and others have been imple-
\n
mented in 2023, considering that, as already mentioned,
\n
USD LIBOR benchmarks have become unrepresentative as
\n
from June 30, 2023.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and is almost entirely hedged using finan-
\n
cial 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 2023, the Group obtained new dollar loans indexed
\n
to SOFR and focused on the implementation of how to
\n
change all exposures from USD LIBOR to USD SOFR.
\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
\n
rates within the 2006 ISDA definitions to include replace-
\n
ment clauses that would apply upon the permanent discon-
\n
tinuation of specific key benchmarks. These changes took
\n
effect 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
As regards Euribor, the Group is assessing whether to: (i)
\n
adopt that protocol in the light of its exposure and devel-
\n
opments in the IBOR reform or (ii) adjust in advance any
\n
contracts impacted bilaterally by the reform.
\n
\n
\n\n
\n\n
\n\n
\n\n
\n\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, SOFR and SONIA.
\n
The Group has assessed the impact of uncertainty en-
\n
gendered by the IBOR reform on hedge relationships at
\n
December 31, 2023 with reference to both hedging in-
\n
struments and hedged items. Both the hedged items and
\n
the hedging instruments have changed their parameter-
\n
ization from interbank market-based benchmarks (IBORs)
\n
to alternative risk-free rates (RFRs) as a result of the con-
\n
tractual amendments that have taken effect.
\n
In particular, in order to manage the uncertainty associ-
\n
ated with both hedging instruments and hedged items
\n
indexed to USD LIBOR, until June 30, 2023 the Group has
\n
continued to apply the temporary exceptions provided for
\n
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
\n
determining if a forecast transaction is highly probable;
\n
\u2022
\n
establishing whether the future hedged cash flows will
\n
arise in a discontinued cash flow hedge relationship;
\n
\u2022
\n
assessing the economic relationship between the
\n
hedged item and the hedging instrument.
\n
The hedge relationships impacted may have become in-
\n
effective due to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In order to
\n
avoid that risk, the Group has sought to implement the
\n
replacements at the same time.
\n
In addition, the Group changed the reference to USD LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically
\n
equivalent, SOFR benchmark in 2023. Consequently, the
\n
Group no longer applies the amendments to IFRS 9 issued
\n
in September 2019 (Phase 1) to these hedge relationships
\n
and, consequently, is applying the amendments to IFRS
\n
9 issued in August 2020 (Phase 2), modifying the formal
\n
designation of the hedge relationship as required by the
\n
IBOR reform and without considering this event as a ter-
\n
mination of the hedge relationship.
\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
\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
2023 and December 31, 2022, broken down by maturity.
\n
Maturity
\n
Millions of euro 2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Interest rate swaps
\n
Total notional amount 708 564 879 1,975 19 3,781 7, 9 2 6
\n
Notional amount related to IRSs in euro 608 564 636 1,532 19 3,141 6,500
\n
Average IRS rate in euro 4.56 1.92 2.12 3.38 0.86 2.37
\n
Notional amount related to IRSs in US dollars 46 - - 444 - 210 700
\n
Average IRS rate in US dollars 0.70 3.28 5.05
\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, 2023 and
\n
December 31, 2022, 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
\n
Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Fair value hedges
\n
Interest rate swaps
\n
Floating-rate
\n
borrowings/bonds
\n
98 - 544 20 (2) 518
\n
Interest rate swaps
\n
Fixed-rate borrowings/
\n
bonds
\n
3 (44) 1,241 2 (90) 1,239
\n
Cash flow hedges
\n
Interest rate swaps Floating-rate bonds 12 (49) 1,040 29 (44) 1,190
\n
Interest rate swaps
\n
Floating-rate loan
\n
assets
\n
- (7) 145 - (9) 162
\n
Interest rate swaps
\n
Floating-rate
\n
borrowings
\n
163 (35) 4,956 307 (7) 4,646
\n
Total 276 (135) 7, 926 358 (152) 7,755
\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, 2023 and December 31, 2022, broken down
\n
by type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Fair value hedges
\n
Interest rate swaps 556 154 101 22 1,229 1,603 (44) (92)
\n
Total 556 154 101 22 1,229 1,603 (44) (92)
\n
Cash flow hedges
\n
Interest rate swaps 4,144 4,958 175 336 1,997 1,040 (91) (60)
\n
Total 4,144 4,958 175 336 1,997 1,040 (91) (60)
\n
TOTAL INTEREST RATE DERIVATIVES 4,700 5,112 276 358 3,226 2,643 (135) (152)
\n
The notional amount of derivatives classified as hedging
\n
instruments at December 31, 2023 came to \u20ac7,926 million,
\n
with a corresponding positive fair value of \u20ac141 million.
\n
Compared with December 31, 2022, the notional amount
\n
increased by \u20ac171 million, mainly reflecting:
\n
\u2022
\n
the expiry of interest rate swaps amounting to \u20ac159
\n
million;
\n
\u2022
\n
early closure of interest rate swaps for an amount of
\n
\u20ac150 million, following early redemption of the under-
\n
lying;
\n
\u2022
\n
new interest rate swaps amounting to \u20ac800 million;
\n
\u2022
\n
the reduction in the notional amount of amortizing in-
\n
terest rate swaps in the amount of \u20ac320 million.
\n
The deterioration in the fair value of \u20ac65 million mainly re-
\n
flects developments in the 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
\n
interest rate risk both in 2023 and the previous year.
\n
Millions of euro 2023 2022
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments 125 (84)
\n
Hedged item (132) 75
\n
Ineffective portion (7) (9)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Interest rate swaps 1,785 57 57 1,757 (70) (70)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
\n
of fair value
\n
of hedged
\n
item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings 1,186 (43) 44 1,138 (89) (79)
\n
Fixed-rate bonds 14 2 (2) 14 2 (2)
\n
Floating-rate bonds 671 41 (107) 576 (16) (18)
\n
Total 1,871 - (65) 1,728 (103) (99)
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in
\n
coming years from cash flow hedge derivatives on interest
\n
rate risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on interest rates
\n
Positive fair value 175 86 29 19 14 12 28
\n
Negative fair value (91) (8) (21) (20) (17) (13) (22)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Interest rate swaps 6,141 84 84 5,998 276 276
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
37 - (37) - - 15 - (15) - -
\n
Floating-rate loan
\n
assets
\n
7 - (7) - - 9 - (9) - -
\n
Floating-rate
\n
borrowings
\n
(149) (20) 149 - (1) (327) (28) 326 - 2
\n
Total (105) (20) 105 - (1) (303) (28) 302 - 2
\n
Currency risk
\n
The following table reports the maturity profile of the
\n
notional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2023 and De-
\n
cember 31, 2022.
\n
Millions of euro Maturity
\n
2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 4,562 2,577 1,222 2,337 2,037 13,386 26,121
\n
Notional amount for CCIRSs EUR/USD 2,213 2,036 1,132 1,560 2,037 9,102 18,080
\n
Average exchange rate EUR/USD 1.13 1.07 1.07 1.10 1.18 1.15
\n
Notional amount for CCIRSs EUR/GBP 981 - - 577 - 3,856 5,414
\n
Average exchange rate EUR/GBP 0.88 0.90 0.82
\n
Notional amount for CCIRSs EUR/CHF 242 - - 140 - - 382
\n
Average exchange rate EUR/CHF 1.07 1.21
\n
Notional amount for CCIRSs USD/BRL 279 231 91 - - 387 988
\n
Average exchange rate USD/BRL 5.50 5.22 5.30 4.13
\n
Notional amount for CCIRSs EUR/BRL 445 231 - 60 - - 736
\n
Average exchange rate EUR/BRL 6.25 6.05 3.92
\n
Currency forwards
\n
Total notional amount of forwards 4,616 1,186 507 - - - 6,309
\n
Notional amount - currency forwards EUR/USD 3,144 1,042 507 - - - 4,693
\n
Average currency forward rate - EUR/USD 1.10 1.11 1.13
\n
Notional amount - currency forwards USD/CLP 938 141 - - - - 1,079
\n
Average currency forward rate - USD/CLP 873.05 885.2239
\n
Notional amount - currency forwards EUR/CNH 175 - - - - - 175
\n
Average currency forward rate - EUR/CNH 7.8 1
\n
Notional amount - currency forwards USD/BRL 130 - - - - - 130
\n
Average currency forward rate - USD/BRL 4.95
\n
Notional amount - currency forwards USD/COP 122 2 - - - - 124
\n
Average currency forward rate - USD/COP 4,498.97 4,597.37
\n
\n\n
\n\n
\n\n
\n\n
\n\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRSs 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 CCIRSs EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount CCIRSs EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRSs 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 CCIRSs 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 - - - 7,6 83
\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
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, 2023 and
\n
December 31, 2022 broken down by type of hedged item.
\n
Millions or 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, 2023 at Dec. 31, 2022
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
12 (78) 1,019 15 (99) 1,097
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings in
\n
foreign currencies
\n
- - - - - -
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings/
\n
financial assets in foreign
\n
currencies
\n
67 (36) 754 95 (76) 1,061
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
5 (220) 2,104 4 (233) 2,445
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate bonds in foreign
\n
currencies
\n
56 - 250 60 - 414
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
965 (1,724) 21,763 1,864 (1,293) 23,381
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Future cash flows denominated
\n
in foreign currencies
\n
- (43) 231 - (50) 335
\n
Currency forwards
\n
Future cash flows denominated
\n
in foreign currencies
\n
2 (1) 117 9 (6) 326
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign
\n
currencies
\n
54 (126) 5,666 192 (135) 7,508
\n
Currency forwards
\n
Purchases of investment goods
\n
and other in foreign currencies
\n
3 (12) 526 19 (23) 1,292
\n
Total 1,164 (2,240) 32,430 2,258 (1,915) 37,859
\n
Cash flow hedges and fair value hedges include:
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac24,886 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro with a negative
\n
fair value of \u20ac1,040 million;
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac1,235 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 \u20ac44 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac5,783
\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 negative fair value of \u20ac71 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac526 mil-
\n
lion and a negative fair value of \u20ac9 million, in respect
\n
of OTC transactions to mitigate the currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of
\n
investment goods in the renewables (including Battery
\n
Energy Storage Systems - BESS) 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 val-
\n
ue of foreign exchange derivatives at December 31, 2023
\n
and December 31, 2022, broken down by type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Fair value hedges
\n
CCIRSs 90 99 12 15 929 998 (78) (99)
\n
Total 90 99 12 15 929 998 (78) (99)
\n
Cash flow hedges
\n
Currency forwards 1,979 4,313 59 220 4,330 4,813 (140) (164)
\n
CCIRSs 13,474 16,695 1,093 2,023 11,628 10,941 (2,022) (1,652)
\n
Total 15,453 21,008 1,152 2,243 15,958 15,754 (2,162) (1,816)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
15,543 21,107 1,164 2,258 16,887 16,752 (2,240) (1,915)
\n
\n\n
\n\n
\n\n
\n\n
\n\n
The notional amount of CCIRSs at December 31, 2023
\n
amounted to \u20ac26,121 million, a decrease of \u20ac2,612 million
\n
from \u20ac28,733 million at December 31, 2022. In particular:
\n
\u2022
\n
CCIRSs with a total amount of \u20ac737 million expired;
\n
\u2022
\n
a partial unwinding operation of CCIRSs was carried out
\n
following the early repurchase of part of the hybrid bond
\n
denominated in US dollars. That transaction, together
\n
with the natural expiry of the residual portion of that li-
\n
ability and the associated CCIRSs, caused a decrease in
\n
the notional amount compared with December 31, 2022
\n
of \u20ac1,171 million;
\n
\u2022
\n
new derivatives amounted to \u20ac109 million. The notional
\n
amount decreased by \u20ac813 million, reflecting develop-
\n
ments in the exchange rate of the euro against the main
\n
other currencies and the effect of amortization.
\n
The notional amount of currency forwards at December 31,
\n
2023 amounted to \u20ac6,309 million (\u20ac9,126 million at Decem-
\n
ber 31, 2022), a decrease of \u20ac2,817 million. The exposure to
\n
currency risk, especially that associated with the US dollar,
\n
is mainly due to purchases of natural gas, purchases of fuel
\n
and cash flows in respect of investments.
\n
After the turbulence experienced in raw material prices
\n
during 2022, which led to a considerable increase in the
\n
notional amounts hedged, the notional value of currency
\n
hedges on energy commodities returned to normal oper-
\n
ating levels in 2023. The deterioration of net fair value of
\n
\u20ac137 million reflected normal developments in exchange
\n
rates.
\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 2023 and the pre-
\n
vious year.
\n
Millions of euro 2023 2022
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments 20 (119)
\n
Hedged item (12) 129
\n
Ineffective portion 8 10
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 1,019 (66) (68) 1,097 (84) (87)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 bonds in foreign currencies 500 (77) 48 458 (106) 90
\n
Fixed-rate borrowings in foreign
\n
currencies
\n
434 (7) 24 520 (8) (2)
\n
Total 934 (84) 72 978 (114) 88
\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 coming
\n
years from cash flow hedge derivatives on currency risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 1,152 358 216 258 211 273 885
\n
Negative fair value (2,162) (960) (594) (13) (34) (18) (644)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 25,102 (930) (919) 27,636 371 433
\n
Currency forwards 6,309 (80) (73) 9,126 56 56
\n
Total 31,411 (1,010) (992) 36,762 427 489
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
\n
effects
\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
Other
\n
effects
\n
(1)
\n
Floating-rate
\n
borrowings in
\n
foreign currencies
\n
(31) 31 - - - (30) 30 - (11) -
\n
Fixed-rate
\n
borrowings in
\n
foreign currencies
\n
219 (219) 4 - - 225 (225) (4) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(56) 56 - - - (60) 60 - - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
861 (861) (15) - 118 (628) 509 (56) - 118
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
CCIRSs)
\n
43 (43) - - - 50 (50) - - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(1) 1 - - - (3) 3 - - -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
72 (72) (1) - - (60) 59 (1) (1) -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
3 (3) (6) - - 7 (7) 1 2 -
\n
Total 1,110 (1,110) (18) - 118 (499) 379 (60) (10) 118
\n
(1) Impact connected with the change in spot exchange rates between the date the CCIRSs to hedge bonds in foreign currencies were obtained and the
\n
actual disbursement of the loan for the CCIRSs obtained in 2022.
\n
\n\n
\n\n
\n\n
\n\n
Commodity price risk
\n
Millions of euro Maturity
\n
2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Commodity swaps
\n
Notional amount on power 128 106 100 284 91 286 995
\n
Average commodity swap price on power (\u20ac/MWh) 87.0 44.0 37.0 59.6 32.0 34.0
\n
Notional amount on coal/shipping - - - - - - -
\n
Average commodity swap price on coal/shipping ($/ton) - - - - - -
\n
Notional amount on gas 1,551 1,747 296 - - 125 3,719
\n
Average commodity swap price on gas (\u20ac/MWh) 41.8 40.4 27.0 - - 7.0
\n
Notional amount on oil 1,016 106 10 - - - 1,132
\n
Average commodity swap price on oil ($/barrel) 86.0 78.0 69.0 - - -
\n
Commodity forwards/futures
\n
Notional amount on power 2,506 388 297 258 151 606 4,206
\n
Average commodity forward/future price on power (\u20ac/MWh) 114.9 18.0 18.0 16.0 18.0 16.0
\n
Notional amount on coal/shipping 38 - - - - - 38
\n
Average commodity forward/future price on coal/shipping ($/ton) 175.0 - - - - -
\n
Notional amount on gas 4,432 377 626 - - - 5,435
\n
Average commodity forward/future price on gas (\u20ac/MWh) 71.4 48.9 32.0 - - -
\n
Notional amount on CO
\n
2
\n
662 336 21 - - - 1,019
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/ton) 91.9 93.0 84.0 - - -
\n
Notional amount on oil 354 - - - - - 354
\n
Average commodity forward/future price on oil ($/barrel) 74.6 - - - - -
\n
Commodity options
\n
Notional amount on power 24 39 44 39 39 342 527
\n
Average commodity option price on power (\u20ac/MWh) 27.5 30.0 30.5 34.0 34.0 34.0
\n
Notional amount on gas - - - - - - -
\n
Average commodity option price on gas (\u20ac/MWh) - - - - - -
\n
Notional amount on oil - - - - - - -
\n
Average commodity option price on oil ($/barrel) - - - - - -
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Commodity swaps
\n
Notional amount on power 653 164 143 139 132 333 1,564
\n
Average commodity swap price on power (\u20ac/MWh) 162.5 77.9 48.9 47. 2 45.8 29.0
\n
Notional amount on coal/shipping 1,037 - - - - - 1,037
\n
Average commodity swap price on coal/shipping ($/ton) 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 ($/barrel) 105.0 93.0 82.0 - - -
\n
Commodity forwards/futures
\n
Notional amount on power 2,906 509 388 294 249 720 5,066
\n
Average commodity forward/future price on power (\u20ac/MWh) 148.1 35.2 17.4 17. 8 15.8 15.6
\n
Notional amount on coal/shipping - - - - - - -
\n
Average commodity forward/future price on coal/shipping ($/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
1,635 226 50 - - - 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 ($/barrel) 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 oil 70 - - - - - 70
\n
Average commodity option price on oil (\u20ac/barrel) 133 - - - - - -
\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, 2023 and De-
\n
cember 31, 2022, 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
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Derivatives
\n
Cash flow hedges
\n
Derivatives on power:
\n
- swaps 684 1,213 357 982 311 352 (233) (498)
\n
- forwards/futures 1,636 1,535 162 89 2,570 3,510 (763) (898)
\n
- options 527 218 93 36 - - (62) (12)
\n
Total derivatives on power 2,847 2,966 612 1,107 2,881 3,862 (1,058) (1,408)
\n
Derivatives on coal/shipping:
\n
- swaps - 9 - 2 - 1,028 - (373)
\n
- forwards/futures - - - - 38 - (17) -
\n
- options - - - - - - - -
\n
Total derivatives on coal/shipping - 9 - 2 38 1,028 (17) (373)
\n
Derivatives on gas and oil:
\n
- swaps 2,785 2,302 623 666 2,066 2,729 (468) (765)
\n
- forwards/futures 3,382 4,734 1,375 1,714 2,407 8,085 (1,198) (5,182)
\n
- options - 22 - 4 - 48 - (4)
\n
Total derivatives on gas and oil 6,167 7,058 1,998 2,384 4,473 10,862 (1,666) (5,951)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps - - - - - - - -
\n
- forwards/futures 640 1,704 91 143 379 207 (29) (7)
\n
- options - - - - - - - -
\n
Total derivatives on CO
\n
2
\n
640 1,704 91 143 379 207 (29) (7)
\n
TOTAL COMMODITY DERIVATIVES 9,654 11,737 2,701 3,636 7,77 1 15,959 (2,770) (7,739)
\n
The table reports the notional amount and fair value of
\n
derivatives hedging commodity price risk at December
\n
31, 2023 and December 31, 2022, broken down by type
\n
of 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 \u20ac1,998 million, derivatives on CO
\n
2
\n
\n
in the amount of \u20ac 91 million and derivatives on power for
\n
\u20ac612 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 \u20ac1,666 million, derivatives on power in the
\n
amount of \u20ac1,058 million and, to a lesser extent, deriva-
\n
tives on coal and CO
\n
2
\n
in the amount of respectively \u20ac17
\n
million and \u20ac29 million.
\n
\n\n
\n\n
\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in
\n
coming years from cash flow hedge derivatives on com-
\n
modity price risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on commodities
\n
Positive fair value 2,701 1,861 428 153 85 55 246
\n
Negative fair value (2,770) (1,727) (430) (217) (216) (72) (235)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Power swaps 995 124 126 1,564 485 469
\n
Coal/shipping swaps - - - 1,037 (371) (371)
\n
Gas and oil swaps 4,850 155 155 5,031 (99) (98)
\n
Power forwards/futures 4,206 (602) (638) 5,045 (809) (938)
\n
Coal/shipping forwards/futures 38 (17) (17) - - -
\n
Gas and oil forwards/futures 5,789 178 92 12,820 (3,469) (3,673)
\n
CO
\n
2
\n
forwards/futures 1,019 62 62 1,911 136 138
\n
Power options 528 31 31 218 24 24
\n
Gas and oil options - - - 70 - -
\n
Total 17,425 (69) (189) 27,696 (4,103) (4,449)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 491 (491) 12 (59) 602 (602) 15 (32)
\n
Future transactions in coal/shipping 17 (17) - - 371 (371) - -
\n
Future transactions in gas and oil (422) 422 - (118) 3,360 (3,360) - (232)
\n
Future transactions in CO
\n
2
\n
(62) 62 - - (133) 133 - -
\n
Total 24 (24) 12 (177) 4,200 (4,200) 15 (264)
\n
With regard to cash flow hedge derivatives on commodity
\n
prices, 2023 was marked by a progressive reduction in the
\n
extreme price volatility seen in past years.
\n
The greatest impact in terms of changes in the cash flow
\n
hedge reserve is mainly attributable to future transac-
\n
tions in gas and power, which experience a reduction in
\n
the magnitude of the amount to defer to future years be-
\n
cause those commodities were the most affected by the
\n
high price volatility.
\n
Moreover, the change is also attributable to the usual re-
\n
\n\n
\n\n
\n\n
lease of the impact on profit or loss of amounts accrued in
\n
2023, which were the most affected by major price swings
\n
of the past years.
\n
The ineffectiveness recognized in 2023 on future trans-
\n
actions in gas is mainly related to proxy hedging opera-
\n
tions in Spain, while ineffectiveness on future transactions
\n
in power is mainly related to proxy hedging operations in
\n
North America.
\n
51.2 Derivatives at fair value through profit or
\n
loss
\n
The following table shows the notional amount and the fair
\n
value of derivatives at FVTPL as at December 31, 2023 and
\n
December 31, 2022.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Derivatives at FVTPL
\n
on interest rates:
\n
- interest rate swaps - - - - 100 100 (29) (23)
\n
- interest rate options - - - - - - - -
\n
on exchange rates:
\n
- currency forwards 1,818 3,659 25 75 1 ,874 2,102 (29) (34)
\n
- CCIRSs - - - - - 46 - (1)
\n
on commodities
\n
Derivatives on power:
\n
- swaps 243 595 24 106 68 245 (16) (180)
\n
- forwards/futures 5,294 6,903 905 872 5,039 5,620 (906) (908)
\n
- options 46 7 4 15 80 140 (171) (172)
\n
Total derivatives on power 5,583 7,505 933 993 5,187 6,005 (1,093) (1,260)
\n
Derivatives on coal:
\n
- swaps - - - - - - - -
\n
- forwards/futures 156 115 23 21 112 1,291 (43) (9)
\n
- options - - - - - - - -
\n
Total derivatives on coal 156 115 23 21 112 1,291 (43) (9)
\n
Derivatives on gas and oil:
\n
- swaps 969 1,964 295 806 529 834 (167) (550)
\n
- forwards/futures 10,687 40,669 2,970 10,456 10,856 38,651 (2,963) (10,280)
\n
- options 448 34 344 8 278 33 (232) (22)
\n
Total derivatives on gas and oil 12,104 42,667 3,609 11,270 11,663 39,518 (3,362) (10,852)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps - - - - - - - -
\n
- forwards/futures 498 725 41 115 426 361 (42) (35)
\n
- options 12 2 14 2 11 - (14) -
\n
Total derivatives on CO
\n
2
\n
510 727 55 117 437 361 (56) (35)
\n
Derivatives on other:
\n
- swaps - - - - 39 - (6) -
\n
- forwards/futures 16 13 4 72 171 5 (71) (16)
\n
- options - - - - 5 - - -
\n
Total derivatives on other 16 13 4 72 215 5 (77) (16)
\n
TOTAL 20,187 54,686 4,649 12,548 19,588 49,428 (4,689) (12,230)
\n
\n\n
\n\n
\n\n
At December 31, 2023 the notional amount of trading de-
\n
rivatives on interest rates came to \u20ac100 million. The nega-
\n
tive fair value of \u20ac29 million deteriorated by \u20ac6 million on
\n
the previous year mainly due to developments in the yield
\n
curve.
\n
At December 31, 2023 the notional amount of derivatives
\n
on exchange rates was \u20ac3,692 million. After the strains ex-
\n
perienced in raw material prices during 2022, which led to
\n
a considerable increase in the notional amounts hedged,
\n
the notional value of currency hedges on energy com-
\n
modities returned to normal operating levels in 2023. This
\n
produced an overall decrease in the value of the hedges of
\n
\u20ac2,069 million. The deterioration of net fair value of \u20ac45
\n
million reflected normal developments in exchange rates.
\n
At December 31, 2023, the notional amount of deriva-
\n
tives on commodities came to \u20ac35,983 million. In absolute
\n
terms, the notional amounts decreased compared with
\n
2022 in line with the gradual decline observed in the pric-
\n
es of energy commodities. The fair value of trading deriv-
\n
atives on commodities classified as assets mainly reflects
\n
the market valuation of hedges of gas and oil amount-
\n
ing to \u20ac3,609 million, derivatives on power amounting to
\n
\u20ac933 million, derivatives on CO
\n
2
\n
amounting to \u20ac55 million
\n
and, to a lesser extent, derivatives on coal and other com-
\n
modities totaling \u20ac23 million and \u20ac4 million, respectively.
\n
The fair value of trading derivatives on commodities
\n
classified as liabilities mainly regards hedges of gas and
\n
oil amounting to \u20ac3,362 million, derivatives on power
\n
amounting to \u20ac1,093 million, and derivatives on CO
\n
2
\n
, coal
\n
and other commodities in the amount of \u20ac56 million, \u20ac43
\n
million and \u20ac77 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
In addition to weather derivative hedges, the \u201cother\u201d cat-
\n
egory includes hedges carried out on guarantees of or-
\n
igin and green certificates, i.e. incentive mechanisms for
\n
the production of electricity from renewable sources. In
\n
addition to the commodity price risk, the Group compa-
\n
nies have to manage the risk of fluctuations in the price of
\n
these certificates which were recently affected by greater
\n
market volatility compared with the past, due to the in-
\n
creasing market attention to environmental sustainability
\n
issues.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1108": { "value": "\n
\n
\n

\n\n
28. Current/Non-current contract assets/(liabilities)
\n
Millions of euro Non-current Current
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Contract assets 444 508 212 106
\n
Contract liabilities 5,743 5,747 2,126 1,775
\n
\n\n\n
Non-current assets deriving from contracts with custom-
\n
ers (contract assets) refer mainly to assets with long-term
\n
utility under construction in respect of public-to-private
\n
service concession arrangements recognized in accor-
\n
dance with IFRIC 12 (\u20ac425 million). These cases arise when
\n
the concession holder has not yet obtained full right to
\n
recognize the asset from the grantor, in that there remains
\n
a contractual obligation to ensure that the asset is com-
\n
pleted and can be remunerated through rates. The figure
\n
at December 31, 2023 includes investments for the year in
\n
the amount of \u20ac795 million.
\n
\n\n
Current contract assets mainly concern construction con-
\n
tracts in progress (\u20ac167 million) to be invoiced, payments
\n
on which are subject to the fulfillment of a performance
\n
obligation.
\n
The value at December 31, 2023 of non-current contract
\n
liabilities is mainly attributable to distribution operations
\n
in Italy (\u20ac3,014 million) and Spain (\u20ac2,729 million) as a re-
\n
sult of the accounting treatment of revenue from con-
\n
nections of new customers, which are deferred over the
\n
average duration of the associated contracts.
\n
Current contract liabilities include the contractual liabili-
\n
ties related to revenue from connections to the electricity
\n
grid expiring within 12 months in the amount of \u20ac1,628
\n
million mainly recognized in Italy and Spain, as well as lia-
\n
bilities for construction contracts in progress (\u20ac453 mil-
\n
lion).
\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, 2023 at Dec. 31, 2022
\n
Within 1 year 2,126 1,775
\n
Within 2 years 568 516
\n
Within 3 years 567 517
\n
Within 4 years 565 516
\n
Within 5 years 564 515
\n
More than 5 years 3,479 3,683
\n
Total 7,8 69 7,522
\n

\n\n\n\n", "dimensions": { "concept": "enel:DisclosureOfContractAssetsLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1107": { "value": "\n
29. Other non-current financial assets \u2013 \u20ac8,750 million
\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Equity investments in other companies measured at fair value 346 366 (20) -5.5%
\n
Other non-current financial assets included in net financial debt
\n
(see note 29.1)
\n
3,837 4,213 (376) -8.9%
\n
Service concession arrangements 4,391 3,732 659 17.7%
\n
Financial assets in respect of joint development agreements (JDA) 133 - 133 -
\n
Non-current financial prepayments 43 48 (5) -10.4%
\n
Total 8,750 8,359 391 4.7%
\n

\n\n\n\n\n

\n\n\n\n\n

\n\n
\u201cOther non-current financial assets\u201d increased by \u20ac391
\n
million reflecting:
\n
\u2022
\n
the increase in financial assets in respect of service
\n
concession arrangements, mainly in Brazil;
\n
\u2022
\n
the recognition of financial assets in respect of joint
\n
development agreements (JDA) in relation to amounts
\n
paid by a number of the Group\u2019s Italian renewables
\n
companies to developers for the development of re-
\n
newable generation projects; in 2022 those assets
\n
were recognized under other non-current assets in the
\n
amount of \u20ac100 million.
\n

\n\n\n\n\n
These positive effects were partly offset mainly by the de-
\n
crease in other non-current financial assets included in
\n
net financial debt, as specified in note 29.1, and the de-
\n
crease in equity investments in other companies following
\n
the disposal of the investment in Athonet Srl and the re-
\n
duction in the value of the investments in Termoel\u00e9ctrica
\n
Jos\u00e9 de San Mart\u00edn SA and Termoel\u00e9ctrica Manuel Belgra-
\n
no SA.
\n\n
The following is a breakdown of equity investments in oth-
\n
er companies measured at fair value.
\n

\n\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 % held at Dec. 31, 2022 % held Change
\n
Empresa Propietaria de la Red SA 8 11.1% 7 11.1% 1
\n
European Energy Exchange AG 22 2.4% 22 2.4% -
\n
Athonet Srl - - 7 16.0% (7)
\n
Korea Line Corporation 1 0.3% 1 0.3% -
\n
Hubject GmbH 11 12.5% 11 12.5% -
\n
Termoel\u00e9ctrica Jos\u00e9 de San Mart\u00edn SA 3 5.6% 11 24.7% (8)
\n
Termoel\u00e9ctrica Manuel Belgrano SA 2 6.2% 9 8.6% (7)
\n
Zacapa Topco S\u00e0rl 287 19.5% 288 19.5% (1)
\n
Other 12 10 2
\n
Total 346 366 (20)
\n

\n\n\n\n\n
29.1 Other non-current financial assets included in net financial debt \u2013 \u20ac3,837 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Securities 505 447 58 13.0%
\n
Other financial assets 3,332 3,766 (434) -11.5%
\n
Total 3,837 4,213 (376) -8.9%
\n
\u201cSecurities\u201d at FVOCI are represented by financial instru-
\n
ments in which the Dutch insurance companies invest a
\n
portion of their liquidity.
\n
The decrease in \u201cother financial assets\u201d is mainly attribut-
\n
able to a decrease in financial assets for security deposits
\n
(\u20ac634 million), mainly in the Endesa Group, partly offset
\n
in particular by the increase in financial assets relating to
\n
the deficit of the Spanish electricity system (\u20ac85 million)
\n
and medium- and long-term financial assets (\u20ac79 million),
\n
mainly in Enel Finance International and Enel Am\u00e9ricas.
\n

\n\n\n
30. Other current financial assets \u2013 \u20ac4,329 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Current financial assets included in net financial debt (see note 30.1) 4, 148 13,501 (9,353) -69.3%
\n
Other 181 252 (71) -28.2%
\n
Total 4,329 13,753 (9,424) -68.5%
\n
\u201cOther current financial assets\u201d decreased by \u20ac9,424 mil-
\n
lion, mainly reflecting the decrease in current financial as-
\n
sets included in net financial debt, as detailed in note 30.1,
\n
and the decrease in accrued financial income.
\n
30.1 Other current financial assets included in net financial debt \u2013 \u20ac4,148 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Current portion of long-term financial assets 1,007 2,838 (1,831) -64.5%
\n
Securities at FVOCI 81 78 3 3.8%
\n
Cash collateral and other financial assets in respect of derivatives
\n
transactions
\n
2,899 8,319 (5,420) -65.2%
\n
Other 161 2,266 (2,105) -92.9%
\n
Total 4,148 13,501 (9,353) -69.3%
\n
The change in the item is mainly attributable to:
\n
\u2022
\n
\u20ac5,420 million in respect of a decrease in cash collat-
\n
eral paid to counterparties for derivatives transactions;
\n
\u2022
\n
a decrease in \u201cother\u201d, mainly reflecting the decrease in
\n
financial assets of:
\n
\u2013
\n
Enel Brasil (\u20ac1,212 million), mainly in respect of the
\n
recognition in 2022 of the receivables connected to
\n
the sale of Celg Distribui\u00e7\u00e3o SA - Celg-D (Enel Goi\u00e1s);
\n
\u2013
\n
Enel X Italia (\u20ac581 million), mainly reflecting the col-
\n
lection of financial assets in respect of the assign-
\n
ment of tax credits for building renovations under
\n
the \u201ceco-sisma bonus\u201d program in 2022;
\n
\u2022
\n
the decrease in the current portion of long-term finan-
\n
cial assets (\u20ac1,831 million), mainly due to a decrease in
\n
financial assets relating to the deficit of the Spanish
\n
electricity system.
\n

\n\n\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Financial assets measured at amortized cost 48.1.1 5,709 5,732 28,495 40,176
\n
Financial assets at FVOCI 48.1.2 882 901 81 279
\n
Financial assets at FVTPL
\n
Derivative financial assets at FVTPL 48.1.3 206 473 4,443 12,075
\n
Other financial assets at FVTPL 48.1.3 4,341 3,442 219 1,048
\n
Total financial assets at FVTPL 4,547 3,915 4,662 13,123
\n
Derivative financial assets designated as hedging instruments
\n
Fair value hedge derivatives 48.1.4 113 37 - -
\n
Cash flow hedge derivatives 48.1.4 2,064 3,460 1,964 2,755
\n
Total derivative financial assets designated as hedging instruments 2,177 3,497 1,964 2,755
\n
TOTAL 13,315 14,045 35,202 56,333
\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, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\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\n\n\n\n

\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Cash and cash equivalents - - 35 6,772 10,169
\n
Trade receivables 34 1,726 1,388 34 16,047 15, 217
\n
Current portion of long-term loan assets - - 30.1 1,007 2,838
\n
Cash collateral - - 30.1 2,899 8,319
\n
Other financial assets 29.1 3,332 3,767 30.1 30 2,090
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 310 295 29 14 12
\n
Other financial assets at amortized cost 341 282 1,726 1,531
\n
Total 5,709 5,732 28,495 40,176
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n
Impairment of financial assets measured at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac34,202 million at December 31, 2023 (\u20ac45,788 million at
\n
December 31, 2022) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,098 million at De-
\n
cember 31, 2023 (\u20ac4,087 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
\n
cash and cash equivalents;
\n
\u2022
\n
trade receivables and contract assets;
\n
\u2022
\n
loan assets;
\n
\u2022
\n
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
\n
the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receiv-
\n
ables. This approach, based on an assessment of any
\n
significant increase in credit risk since initial recogni-
\n
tion, is performed comparing the PD at origination with
\n
PD at the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss
\n
allowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e. staging):
\n
\u2013
\n
12-month ECL, for financial assets for which there
\n
has not been a significant increase in credit risk
\n
since initial recognition;
\n
\u2013
\n
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
\n
the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a signifi-
\n
cant financing component, based on lifetime ECL with-
\n
out 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
\n
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
\n
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
\n
right to cash flows is legally or contractually extinguished,
\n
transferred or expired).
\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, 2023 at Dec. 31, 2022
\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 6,772 - 6,772 10,169 - 10,169
\n
Trade receivables 21,548 3,775 17,7 73 20,388 3,783 16,605
\n
Loan assets 7,579 311 7, 2 6 8 17, 2 6 2 248 17,014
\n
Other financial assets at amortized cost 2,403 12 2,391 2,176 56 2,120
\n
Total 38,302 4,098 34,204 49,995 4,087 45,908
\n

\n\n\n

\n\n\n

\n\n
To measure expected losses, the Group assesses trade
\n
receivables and contract assets with the simplified ap-
\n
proach, both on an individual basis (e.g., government enti-
\n
ties, authorities, financial counterparties, wholesale sellers,
\n
traders and large companies, etc.) and a collective basis
\n
(e.g., retail 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
\n
risk characteristics and information on past due positions,
\n
considering a specific definition of default.
\n
Based on each business and local regulatory framework,
\n
as well as differences between customer portfolios, in-
\n
cluding their default and recovery rates (comprising ex-
\n
pectations for recovery beyond 90 days):
\n
\u2022
\n
the Group mainly defines a defaulted position as one
\n
that is 180 days past due. Accordingly, beyond this time
\n
limit, trade receivables are presumed to be credit im-
\n
paired); and
\n
\u2022
\n
specific clusters are defined on the basis of specific
\n
markets, business and risk characteristics.
\n
Contract assets substantially have the same risk charac-
\n
teristics as trade receivables for the same types of con-
\n
tracts.
\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
\n
PD, assumed equal to the average default rate, is calcu-
\n
lated by cluster and considering historical data from at
\n
least 24 months;
\n
\u2022
\n
LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022
\n
EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices
\n
issued but not past due and invoices to be issued.
\n
The following table reports changes in the allowance for
\n
expected credit losses on loan assets in accordance with
\n
the general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\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
Opening balance at Jan. 1, 2023 29 219
\n
Accruals - 36
\n
Uses - 11
\n
Reversals to profit or loss (32) (6)
\n
Other changes 45 9
\n
Closing balance at Dec. 31, 2023 42 269
\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, 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
Opening balance at Jan. 1, 2023 3,783
\n
Accruals 1,384
\n
Uses (1,136)
\n
Reversals to profit or loss (210)
\n
Other changes (46)
\n
Closing balance at Dec. 31, 2023 3,775
\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 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, 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
Opening balance at Jan. 1, 2023 56
\n
Accruals 149
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (192)
\n
Closing balance at Dec. 31, 2023 12
\n

\n\n\n\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\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

\n\n\n\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Investments in other companies at FVOCI 29 338 360 - -
\n
Securities 29.1 505 447 30.1 81 78
\n
Receivables and other financial assets at FVOCI 39 94 - 201
\n
Total 882 901 81 279
\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, 2023 360 -
\n
Purchases - -
\n
Sales (7) -
\n
Changes in fair value through OCI (15) -
\n
Other changes - -
\n
Closing balance at Dec. 31, 2023 338 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2023 447 78
\n
Purchases 160 -
\n
Sales (14) (15)
\n
Changes in fair value through OCI 17 -
\n
Reclassifications (105) 105
\n
Other changes - (87)
\n
Closing balance at Dec. 31, 2023 505 81
\n

\n\n\n

\n\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n\n

\n\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", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1106": { "value": "\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Equity investments in other companies measured at fair value 346 366 (20) -5.5%
\n
Other non-current financial assets included in net financial debt
\n
(see note 29.1)
\n
3,837 4,213 (376) -8.9%
\n
Service concession arrangements 4,391 3,732 659 17.7%
\n
Financial assets in respect of joint development agreements (JDA) 133 - 133 -
\n
Non-current financial prepayments 43 48 (5) -10.4%
\n
Total 8,750 8,359 391 4.7%
\n

\n\n\n\n\n
The following is a breakdown of equity investments in oth-
\n
er companies measured at fair value.
\n

\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 % held at Dec. 31, 2022 % held Change
\n
Empresa Propietaria de la Red SA 8 11.1% 7 11.1% 1
\n
European Energy Exchange AG 22 2.4% 22 2.4% -
\n
Athonet Srl - - 7 16.0% (7)
\n
Korea Line Corporation 1 0.3% 1 0.3% -
\n
Hubject GmbH 11 12.5% 11 12.5% -
\n
Termoel\u00e9ctrica Jos\u00e9 de San Mart\u00edn SA 3 5.6% 11 24.7% (8)
\n
Termoel\u00e9ctrica Manuel Belgrano SA 2 6.2% 9 8.6% (7)
\n
Zacapa Topco S\u00e0rl 287 19.5% 288 19.5% (1)
\n
Other 12 10 2
\n
Total 346 366 (20)
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsOtherThanInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1103": { "value": "\n

\n\n

\n\n
31. Other non-current assets \u2013 \u20ac2,249 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 331 282 49 17.4%
\n
Net assets of personnel programs 42 8 34 -
\n
Tax assets > 12 months 1,487 1 ,674 (187) -11.2%
\n
Operating security deposits >12 months 306 301 5 1.7%
\n
Other 83 221 (138) -62.4%
\n
Total 2,249 2,486 (237) -9.5%
\n
Amounts due from institutional market operators in-
\n
creased by \u20ac49 million on 2022, mainly in Spain in respect
\n
of distribution activities.
\n
Tax assets decreased by \u20ac187 million, mainly in Brazil in
\n
connection with the PIS/COFINS tax dispute (\u20ac338 mil-
\n
lion), partly offset by an increase in tax assets in Italy and
\n
Chile.
\n

\n\n\n\n\n

\n\n\n\n\n

\n\n\n\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 1,161 1,033 128 12.4%
\n
Advances to suppliers 311 332 (21) -6.3%
\n
Amounts due from employees 28 30 (2) -6.7%
\n
Non-monetary grants to be received for environmental certificates 24 16 8 50.0%
\n
Amounts due from others 1,068 1,040 28 2.7%
\n
Sundry tax assets 1,311 1,598 (287) -18.0%
\n
Current accrued income and prepayments 196 265 (69) -26.0%
\n
Total 4,099 4,314 (215) -5.0%
\n

\n\n\n\n\n
Amounts due from institutional market operators mainly
\n
include amounts due in respect of the Italian system in
\n
the amount of \u20ac700 million (\u20ac617 million at December 31,
\n
2022) and the Spanish system in the amount of \u20ac422 mil-
\n
lion (\u20ac388 million at December 31, 2022).
\n
The increase was essentially attributable to the increase
\n
in amounts receivable in Italy in respect of the Energy and
\n
Environmental Services Fund, mainly held by e-distribuzi-
\n
one (\u20ac390 million) and Servizio Elettrico Nazionale (\u20ac252
\n
million), primarily connected with equalization mecha-
\n
nisms.
\n
The decrease of \u20ac287 million in sundry tax assets is mainly
\n
attributable to a decrease in credits for indirect taxes and
\n
duties recognized by the Parent Company Enel SpA (\u20ac274
\n
million) in Italy (\u20ac18 million) and Latin America (\u20ac108 mil-
\n
lion), partially offset by an increase in such items in Spain
\n
(\u20ac146 million) and North America (\u20ac58 million).
\n

\n\n\n\n\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1104": { "value": "\n

\n\n
31. Other non-current assets \u2013 \u20ac2,249 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 331 282 49 17.4%
\n
Net assets of personnel programs 42 8 34 -
\n
Tax assets > 12 months 1,487 1 ,674 (187) -11.2%
\n
Operating security deposits >12 months 306 301 5 1.7%
\n
Other 83 221 (138) -62.4%
\n
Total 2,249 2,486 (237) -9.5%
\n
Amounts due from institutional market operators in-
\n
creased by \u20ac49 million on 2022, mainly in Spain in respect
\n
of distribution activities.
\n
Tax assets decreased by \u20ac187 million, mainly in Brazil in
\n
connection with the PIS/COFINS tax dispute (\u20ac338 mil-
\n
lion), partly offset by an increase in tax assets in Italy and
\n
Chile.
\n

\n\n\n\n\n

\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 1,161 1,033 128 12.4%
\n
Advances to suppliers 311 332 (21) -6.3%
\n
Amounts due from employees 28 30 (2) -6.7%
\n
Non-monetary grants to be received for environmental certificates 24 16 8 50.0%
\n
Amounts due from others 1,068 1,040 28 2.7%
\n
Sundry tax assets 1,311 1,598 (287) -18.0%
\n
Current accrued income and prepayments 196 265 (69) -26.0%
\n
Total 4,099 4,314 (215) -5.0%
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1105": { "value": "\n
31. Other non-current assets \u2013 \u20ac2,249 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 331 282 49 17.4%
\n
Net assets of personnel programs 42 8 34 -
\n
Tax assets > 12 months 1,487 1 ,674 (187) -11.2%
\n
Operating security deposits >12 months 306 301 5 1.7%
\n
Other 83 221 (138) -62.4%
\n
Total 2,249 2,486 (237) -9.5%
\n
Amounts due from institutional market operators in-
\n
creased by \u20ac49 million on 2022, mainly in Spain in respect
\n
of distribution activities.
\n
Tax assets decreased by \u20ac187 million, mainly in Brazil in
\n
connection with the PIS/COFINS tax dispute (\u20ac338 mil-
\n
lion), partly offset by an increase in tax assets in Italy and
\n
Chile.
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1101": { "value": "\n

\n
32. Other current assets \u2013 \u20ac4,099 million
\n\n

\n\n

\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 1,161 1,033 128 12.4%
\n
Advances to suppliers 311 332 (21) -6.3%
\n
Amounts due from employees 28 30 (2) -6.7%
\n
Non-monetary grants to be received for environmental certificates 24 16 8 50.0%
\n
Amounts due from others 1,068 1,040 28 2.7%
\n
Sundry tax assets 1,311 1,598 (287) -18.0%
\n
Current accrued income and prepayments 196 265 (69) -26.0%
\n
Total 4,099 4,314 (215) -5.0%
\n

\n\n\n\n\n
Amounts due from institutional market operators mainly
\n
include amounts due in respect of the Italian system in
\n
the amount of \u20ac700 million (\u20ac617 million at December 31,
\n
2022) and the Spanish system in the amount of \u20ac422 mil-
\n
lion (\u20ac388 million at December 31, 2022).
\n
The increase was essentially attributable to the increase
\n
in amounts receivable in Italy in respect of the Energy and
\n
Environmental Services Fund, mainly held by e-distribuzi-
\n
one (\u20ac390 million) and Servizio Elettrico Nazionale (\u20ac252
\n
million), primarily connected with equalization mecha-
\n
nisms.
\n
The decrease of \u20ac287 million in sundry tax assets is mainly
\n
attributable to a decrease in credits for indirect taxes and
\n
duties recognized by the Parent Company Enel SpA (\u20ac274
\n
million) in Italy (\u20ac18 million) and Latin America (\u20ac108 mil-
\n
lion), partially offset by an increase in such items in Spain
\n
(\u20ac146 million) and North America (\u20ac58 million).
\n

\n\n\n\n\n

\n\n\n\n\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1102": { "value": "\n

\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due from institutional market operators 1,161 1,033 128 12.4%
\n
Advances to suppliers 311 332 (21) -6.3%
\n
Amounts due from employees 28 30 (2) -6.7%
\n
Non-monetary grants to be received for environmental certificates 24 16 8 50.0%
\n
Amounts due from others 1,068 1,040 28 2.7%
\n
Sundry tax assets 1,311 1,598 (287) -18.0%
\n
Current accrued income and prepayments 196 265 (69) -26.0%
\n
Total 4,099 4,314 (215) -5.0%
\n

\n\n\n\n\n
Amounts due from institutional market operators mainly
\n
include amounts due in respect of the Italian system in
\n
the amount of \u20ac700 million (\u20ac617 million at December 31,
\n
2022) and the Spanish system in the amount of \u20ac422 mil-
\n
lion (\u20ac388 million at December 31, 2022).
\n
The increase was essentially attributable to the increase
\n
in amounts receivable in Italy in respect of the Energy and
\n
Environmental Services Fund, mainly held by e-distribuzi-
\n
one (\u20ac390 million) and Servizio Elettrico Nazionale (\u20ac252
\n
million), primarily connected with equalization mecha-
\n
nisms.
\n
The decrease of \u20ac287 million in sundry tax assets is mainly
\n
attributable to a decrease in credits for indirect taxes and
\n
duties recognized by the Parent Company Enel SpA (\u20ac274
\n
million) in Italy (\u20ac18 million) and Latin America (\u20ac108 mil-
\n
lion), partially offset by an increase in such items in Spain
\n
(\u20ac146 million) and North America (\u20ac58 million).
\n

\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1100": { "value": "\n
33. Inventories \u2013 \u20ac4,290 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Raw and ancillary materials, and consumables:
\n
- fuels 1,598 2,396 (798) -33.3%
\n
- materials, equipment and other inventories 2,000 2,137 (137) -6.4%
\n
Total 3,598 4,533 (935) -20.6%
\n
Environmental certificates:
\n
- CO
\n
2
\n
emissions allowances 514 152 362 -
\n
- guarantees of origin 39 18 21 -
\n
- energy efficiency certificates - 6 (6) -
\n
- other environmental certificates 6 - 6
\n
Total 559 176 383 -
\n
Buildings held for sale 45 47 (2) -4.3%
\n
Payments on account 88 97 (9) -9.3%
\n
TOTAL 4,290 4,853 (563) -11.6%
\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 decrease in inventories in 2023 (\u20ac563 million) is
\n
mainly attributable to a decrease in inventories of fuel and
\n
materials, devices and other inventories recorded in Italy
\n
(\u20ac537 million, of which \u20ac166 million in respect of write-
\n
downs of coal and other materials), Spain (\u20ac363 million)
\n
and Latin America (\u20ac35 million), notably gas inventories
\n
to meet the needs of the Group, partially offset by the in-
\n
crease in CO
\n
2
\n
emissions allowances in Italy.
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1099": { "value": "\n
34. Trade receivables \u2013 \u20ac17,773 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Customers:
\n
- electricity sales and transport 11,133 10,216 917 9.0%
\n
- distribution and sale of gas 2,811 3,026 (215) -7. 1 %
\n
- other assets 3,646 3,118 528 16.9%
\n
Total trade receivables due from customers 17,590 16,360 1,230 7.5%
\n
Trade receivables due from associates and joint ventures 183 245 (62) -25.3%
\n
TOTAL 17,773 16,605 1,168 7.0 %
\n
Trade receivables due from customers are recognized net
\n
of loss allowances, which totaled \u20ac3,775 million at the end
\n
of the year, compared with a balance of \u20ac3,783 million at
\n
the end of the previous year.
\n
Specifically, the increase in 2023, totaling \u20ac1,168 million,
\n
is attributable to an increase in receivables for electricity
\n
sale and transport recognized in the year.
\n
The change was mainly recognized in Italy (\u20ac1,810 million),
\n
partially offset by the decrease recognized in Spain (\u20ac230
\n
million) and Latin America (\u20ac231 million).
\n
For more information on trade receivables, please see
\n
note 48 \u201cFinancial instruments by category\u201d.
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1098": { "value": "\n
35. Cash and cash equivalents \u2013 \u20ac6,801 million
\n
Cash and cash equivalents, detailed in the following ta-
\n
ble, decreased by \u20ac4,240 million, mainly in Italy and North
\n
America, partially offset by an increase in Spain.
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Bank and postal deposits 4,664 8,968 (4,304) -48.0%
\n
Cash and cash equivalents on hand 23 35 (12) -34.3%
\n
Other investments of liquidity 2,114 2,038 76 3.7%
\n
Total 6,801 11,041 (4,240) -38.4%
\n

\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag236": { "value": "\n

\n\n
36. Assets and liabilities included in disposal groups classified as held for sale \u2013 \u20ac5,919
\n
million and \u20ac2,316 million
\n
Changes in assets held for sale in 2023 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 the
\n
consolidation
\n
scope Impairment
\n
Exchange
\n
differences Investments
\n
Other
\n
changes
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Property, plant and equipment 3,304 3,574 (3,440) (263) (59) 820 (228) 3,708
\n
Intangible assets 334 719 (328) 16 (14) 29 (41) 715
\n
Goodwill - 616 (46) (1) 3 - - 572
\n
Deferred tax assets
\n
(1)
\n
217 146 (88) - (56) - (23) 196
\n
Equity-accounted investments 27 116 (142) - - - - 1
\n
Other non-current assets
\n
(2)
\n
50 37 (222) - - - 170 35
\n
Non-current financial assets
\n
and securities
\n
(2)
\n
75 - (29) - (45) - (1) -
\n
Non-current financial assets 138 - (85) - (3) - (50) -
\n
Current financial assets and
\n
securities
\n
43 1 (20) - (32) - 9 1
\n
Other current financial assets 9 2 (11) - - - - -
\n
Cash and cash equivalents 425 259 (320) - (40) - (63) 261
\n
Inventories, trade receivables
\n
and other current assets
\n
1,533 351 (1,479) - 29 - (4) 430
\n
Total
\n
(1)
\n
6,155 5,821 (6,210) (248) (217) 849 (231) 5,919
\n
(1) The figures at December 31, 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting
\n
periods beginning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
(2) At December 31, 2022, \u201cOther non-current assets\u201d included the \u201cNon-current financial assets and securities\u201d reported separately in the table above.
\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 the
\n
consolidation
\n
scope
\n
Exchange
\n
differences
\n
Other
\n
changes
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
Long-term borrowings 775 663 (908) (49) 249 730
\n
Provisions for risks and charges, non-current portion 33 33 (34) - 4 36
\n
Deferred tax liabilities
\n
(1)
\n
246 563 (192) (70) (42) 505
\n
Post-employment and other employee benefits 23 4 (22) (3) 3 5
\n
Non-current financial liabilities 69 - (80) (2) 23 10
\n
Non-current contract liabilities 442 - (453) - 11 -
\n
Other non-current liabilities 179 19 (149) (8) 13 54
\n
Short-term borrowings 642 217 (189) (10) (384) 276
\n
Long-term borrowings, current portion 18 100 (9) (5) 41 145
\n
Provisions for risks and charges, current portion 33 10 (64) (2) 32 9
\n
Other current financial liabilities 12 8 (17) - 6 9
\n
Trade payables and other current liabilities 894 385 (705) 11 (48) 537
\n
Total
\n
(1)
\n
3,366 2,002 (2,822) (138) (92) 2,316
\n
(1) The figures at December 31, 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting
\n
periods beginning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n

\n\n\n\n\n\n

\n\n
The item essentially includes assets measured at the lower of
\n
cost, understood as their net carrying amount, and the esti-
\n
mated realizable value, which, due to management decisions,
\n
meet the requirements of \u201cIFRS 5 - Non-current Assets Held
\n
for Sale and Discontinued Operations\u201d for their classification
\n
in this item.
\n
The balances of assets held for sale and associated liabilities
\n
at December 31, 2023 came to, respectively, \u20ac5,919 million
\n
and \u20ac2,316 million and mainly refer to:
\n
\u2022
\n
3SUN in Italy: on the basis of the negotiations finalized to
\n
the disposal of a 50% stake in the social capital of 3SUN
\n
Srl, its net assets have been reclassified as \u201cNon-current
\n
assets held for sale and discontinued operations\u201d, in line
\n
with IFRS 5;
\n
\u2022
\n
North America: assets relating to a renewable portfolio in
\n
the United States including about 150 MW of operational
\n
geothermal and solar plants;
\n
\u2022
\n
Peru: the electricity distribution and supply assets held by
\n
Enel Distribuci\u00f3n Per\u00fa SAA, the advanced energy services
\n
assets of Enel X Per\u00fa SAC and the generation assets held
\n
by Enel Generaci\u00f3n Per\u00fa, Compa\u00f1\u00eda Energ\u00e9tica Veracruz
\n
and Enel Generaci\u00f3n Piura as, on the basis of the negoti-
\n
ations in place, the requirements set by IFRS 5 have been
\n
met;
\n
\u2022
\n
Colombia: the Windpeshi wind farm under construction,
\n
which based on negotiations under way satisfies the re-
\n
quirements of IFRS 5.
\n
Assets previously classified as held for sale disposed of in
\n
2023 include:
\n
\u2022
\n
in the 1st Half of 2023, Enel Generaci\u00f3n Costanera, Inver-
\n
sora Dock Sud and Central Dock Sud generation compa-
\n
nies were sold in Argentina; Enel Green Power India relin-
\n
quished control of the net assets held through Avikiran
\n
Solar India Private Limited while maintaining a residual in-
\n
terest in the company of 51% of the paid-up share capital;
\n
\u2022
\n
in the 3rd Quarter of 2023, the subsidiary Enel Green
\n
Power SpA sold 50% of the two companies holding all of
\n
the Group renewable assets in Australia, specifically Enel
\n
Green Power Australia (Pty) Ltd and Enel Green Power Aus-
\n
tralia Trust, to INPEX Corporation;
\n
\u2022
\n
during the 4th Quarter of 2023, the Enel Group completed
\n
through the subsidiary Endesa Generaci\u00f3n SAU the sale of
\n
the entire stake held in Tecnatom SA.
\n
For more information on the financial effects of the above
\n
transactions, please see note 9 \u201cMain acquisitions and dis-
\n
posals during the year\u201d.
\n
Several assets previously classified as discontinued opera-
\n
tions were disposed of in 2023. In particular, in the 4th Quarter
\n
the Group completed the sale of all the stakes held in Roma-
\n
nia. Finally, the sale of a 50% stake in Enel Green Power Hellas
\n
was finalized.
\n
For more information on the financial effects of the above
\n
transactions, please see note 7 \u201cDiscontinued operations\u201d
\n
and note 9 \u201cMain acquisitions and disposals during the year\u201d.
\n

\n\n\n\n\n\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag222": { "value": "\n
37. Equity \u2013 \u20ac45,109 million
\n
37.1 Equity attributable to owners of the Parent \u2013 \u20ac31,755 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Share capital 10,167 10,167 -
\n
Treasury share reserve (59) (47) (12)
\n
Other reserves 6,551 2,740 3,811
\n
Share premium reserve 7,49 6 7,496 -
\n
Reserve for equity instruments - perpetual hybrid bonds 6,553 5,567 986
\n
Legal reserve 2,034 2,034 -
\n
Other reserves 2,341 2,332 9
\n
Translation reserve (5,289) (5,912) 623
\n
Hedging reserve (1,393) (3,553) 2,160
\n
Hedging costs reserve (38) (81) 43
\n
Reserve from measurement of financial instruments at FVOCI 10 (22) 32
\n
Reserve from equity-accounted investments (375) (476) 101
\n
Actuarial reserve (1,185) (1,063) (122)
\n
Reserve from disposal of equity interests without loss of control (2,390) (2,390) -
\n
Reserve from acquisitions of non-controlling interests (1,213) (1,192) (21)
\n
Retained earnings
\n
(1)
\n
15,096 15,795 (699)
\n
Equity attributable to owners of the Parent
\n
(1)
\n
31,755 28,655 3,100
\n
(1) The figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods begin-
\n
ning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n

\n

\n

\n\n
Share capital \u2013 \u20ac10,167 million
\n
At December 31, 2023 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, 2022.
\n
At December 31, 2023, based on the shareholders regis-
\n
ter and the notices submitted to CONSOB and received
\n
by the Parent pursuant to Article 120 of Legislative Decree
\n
58 of February 24, 1998, as well as other available infor-
\n
mation, shareholders with interests of greater than 3% in
\n
the Parent\u2019s share capital were the Ministry for the Economy
\n
and Finance (with a 23.585% stake) and BlackRock Inc. (with
\n
a 5.023% stake held for asset management purposes).
\n

\n\n\n\n\n\n\n
Treasury share reserve \u2013 \u20ac(59) million
\n
At December 31, 2023, treasury shares are represented by
\n
9,262,330 ordinary shares of Enel SpA with a par value of
\n
\u20ac1.00 each (7,153,795 at December 31, 2022), purchased
\n
through an authorized intermediary for a total of \u20ac59 mil-
\n
lion.
\n

\n\n\n\n\n\n\n
Other reserves \u2013 \u20ac6,551 million
\n
Share premium reserve \u2013 \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
\u2013 \u20ac6,553 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
The change of \u20ac986 million in the reserve reflects the is-
\n
sue of new bonds in the amount of \u20ac1,738 million, net of
\n
transaction costs, partly offset by the repurchase and sub-
\n
sequent cancellation of previous bonds in the amount of
\n
\u20ac752 million, including transaction costs.
\n
In 2023, coupons of \u20ac182 million were paid to holders of
\n
perpetual hybrid bonds.
\n
Legal reserve \u2013 \u20ac2,034 million
\n
The legal reserve is formed as allocation of part of the net
\n
income that, pursuant to Article 2430 of the Italian Civil
\n
Code, cannot be distributed as dividends.
\n
Other reserves \u2013 \u20ac2,341 million
\n
These include \u20ac2,215 million related to the remaining por-
\n
tion of the value adjustments carried out when Enel was
\n
transformed from a public entity to a joint-stock company.
\n
Pursuant to Article 47 of the Uniform Income Tax Code,
\n
this amount does not constitute taxable income when dis-
\n
tributed.
\n
Translation reserve \u2013 \u20ac(5,289) million
\n
The increase of \u20ac623 million in the period was mainly due
\n
to the change in the consolidation scope connected with
\n
stakes held in Romania, Inversora Dock Sud and Central
\n
Dock Sud and Enel Generaci\u00f3n Costanera, as well as the
\n
net depreciation of the functional currencies used by for-
\n
eign subsidiaries, mainly in Chile and the United States,
\n
against the euro (presentation currency of the Parent).
\n
Hedging reserve \u2013 \u20ac(1,393) million
\n
This includes the net expense recognized in equity from
\n
the measurement of hedging derivatives. The change in
\n
the period is mainly attributable to developments in com-
\n
modity prices.
\n
Hedging costs reserve \u2013 \u20ac(38) 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 2023 is mainly attributable to devel-
\n
opments in commodity prices.
\n
Reserve from measurement of financial instruments at
\n
FVOCI \u2013 \u20ac10 million
\n
This includes net unrealized fair value losses on financial
\n
assets.
\n
Reserve from equity-accounted investments \u2013 \u20ac(375)
\n
million
\n
The reserve reports the share of comprehensive income
\n
to be recognized directly in equity of equity-accounted
\n
investees. The change in 2023 is mainly attributable to the
\n
change in the hedging reserve of Slovak Power Holding.
\n
Actuarial reserve \u2013 \u20ac(1,185) 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 \u2013 \u20ac(2,390) million
\n
This item mainly reports:
\n
\u2022
\n
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
\n
the sale of non-controlling interests recognized as a
\n
result of the Enersis (now Enel Am\u00e9ricas and Enel Chile)
\n
capital increase;
\n

\n

\n\n\n\n\n\n

\n\n\n\n\n\n

\n\n
\u2022
\n
the capital loss, net of expenses associated with the
\n
disposal and the related taxation, from the public offer-
\n
ing of 21.92% of Endesa;
\n
\u2022
\n
the disposal to third parties of the non-controlling in-
\n
terest in Enel Green Power North America Renewable
\n
Energy Partners;
\n
\u2022
\n
the effects of the merger into Enel Am\u00e9ricas of Endesa
\n
Am\u00e9ricas and Chilectra Am\u00e9ricas;
\n
\u2022
\n
the effects of the disposal of a 49% stake held by Enel
\n
Green Power Canada in Pincher Creek LP and Riverview
\n
LP.
\n
Reserve from acquisitions of non-controlling interests \u2013
\n
\u20ac(1,213) 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 (-\u20ac21 million) mainly reflects the
\n
effects of the merger of Enel Green Power Per\u00fa, Energ\u00e9ti-
\n
ca Monz\u00f3n and Empresa de Generaci\u00f3n El\u00e9ctrica Los Pi-
\n
nos (merged entities) into Enel Generaci\u00f3n Per\u00fa (acquiring
\n
entity), changing the interest held by the Group in those
\n
companies.
\n

\n

\n\n\n\n\n\n
Retained earnings \u2013 \u20ac15,096 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
Millions of euro
\n
at Dec. 31, 2022 Changes at Dec. 31, 2023
\n
Total
\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 Total
\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
(10,900) (5,424) (5,476) (504) - - (504) (415) (89) (11,404) (5,839) (5,565)
\n
Hedging reserve (4,656) (3,573) (1,083) 1,146 2,512 (947) 2,711 2,111 600 (1,945) (1,462) (483)
\n
Hedging costs
\n
reserve
\n
(111) (91) (20) 75 (16) (10) 49 43 6 (62) (48) (14)
\n
Reserve from
\n
measurement
\n
of financial
\n
instruments at
\n
FVOCI
\n
(33) (32) (1) 12 - (1) 11 15 (4) (22) (17) (5)
\n
Share of OCI
\n
of equity-
\n
accounted
\n
associates
\n
(586) (601) 15 92 - 6 98 97 1 (488) (504) 16
\n
Reserve from
\n
measurement
\n
of equity
\n
investments
\n
in other
\n
companies
\n
(19) (19) - 3 - - 3 3 - (16) (16) -
\n
Actuarial reserve (1,474) (1,016) (458) (217) - 66 (151) (120) (31) (1,625) (1,136) (489)
\n
Total gains/
\n
(losses)
\n
recognized in
\n
equity
\n
(17,779) (10,756) (7,023) 607 2,496 (886) 2,217 1,734 483 (15,562) (9,022) (6,540)
\n

\n\n\n\n\n\n

\n\n

\n

\n
37.2 Dividends
\n
Amount distributed
\n
(millions of euro) Dividend per share (euro)
\n
Dividends distributed in 2022
\n
Dividends for 2021 3,861 0.38
\n
Interim dividends for 2022
\n
(1)
\n
- -
\n
Special dividends - -
\n
Total dividends distributed in 2022 3,861 0.38
\n
Dividends distributed in 2023
\n
Dividends for 2022 4,064 0.40
\n
Interim dividends for 2023
\n
(2)
\n
- -
\n
Special dividends - -
\n
Total dividends distributed in 2023 4,064 0.40
\n
(1) 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
\n
million).
\n
(2) Approved by the Board of Directors on November 7, 2023 and paid as from January 24, 2024 (interim dividend of \u20ac0.215 per share for a total of \u20ac2,186
\n
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 2023, is equal to \u20ac0.43 per share, for a
\n
total of \u20ac4,372 million (of which \u20ac0.215 per share for a to-
\n
tal of \u20ac2,186 million already paid as an interim dividend). It
\n
will be proposed to the Shareholders\u2019 Meeting of May 23,
\n
2024 at single call.
\n
These consolidated financial statements do not take ac-
\n
count of the effects of the distribution to shareholders
\n
of the dividend for 2023, except for the liability in respect
\n
of shareholders for the interim dividend for 2023, which
\n
was approved by the Board of Directors on November 7,
\n
2023 for a potential maximum of \u20ac2,186 million, and paid
\n
as from January 24, 2024 net of the portion pertaining to
\n
the 10,085,106 treasury shares held as at the record date
\n
of January 23, 2024.
\n
In 2023 the Group also paid \u20ac182 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
\n
adequate capitalization that enables it to achieve a sat-
\n
isfactory return for shareholders and ensure access to
\n
external sources of financing, in part by maintaining an
\n
adequate 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 2023.
\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, 2023 and 2022 is summarized in the follow-
\n
ing table.
\n

\n\n\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Non-current financial debt 61,093 68,191 (7,098)
\n
Net current financial position 2,907 (3,315) 6,222
\n
Non-current financial assets and long-term securities (3,837) (4,213) 376
\n
Net financial debt
\n
(1)
\n
60,163 60,663 (500)
\n
Equity attributable to owners of the Parent 31,755 28,655 3,100
\n
Non-controlling interests 13,354 13,425 (71)
\n
Equity
\n
(2)
\n
45,109 42,080 3,029
\n
Debt/equity ratio 1.33 1.44 (0.11)
\n
(1) In order to facilitate analysis of developments in Group net financial debt, thereby ensuring greater comparability over time, management has decided
\n
to exclude the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on loans. Accordingly, in order to
\n
improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2022.
\n
(2) The figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods begin-
\n
ning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n

\n\n\n\n\n\n

\n\n\n\n\n\n

\n

\n

\n\n\n
The decrease in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in equity as a result of profit for the year, the increase in
\n
reserves from the measurement of cash flow hedge deriv-
\n
atives and the change in the scope of the reserve for the
\n
translation of financial statements in foreign currency, only
\n
partly offset by dividend distributions. The reduction in net
\n
financial debt further contributed to the decline.
\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\n\n\n\n

\n\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,354 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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Italy - 1 - -
\n
Iberia 5,470 5,321 192 713
\n
Latin America 7,665 7,42 2 666 857
\n
Europe - 328 3 (342)
\n
North America 151 218 (39) 10
\n
Africa, Asia and Oceania 68 135 7 -
\n
Total 13,354 13,425 829 1,238
\n
The change in non-controlling interests mainly reflects the
\n
effect of the dividends distributed and the disposal of eq-
\n
uity stakes in Romania. These effects were offset by the
\n
results for the period, the impact of hyperinflation and the
\n
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
The figures at December 31, 2022 have been adjusted to
\n
take account of the effects of the Amendment to IAS 12,
\n
which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please
\n
see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Millions of euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 27,578 29,635 8,459 5,430 36,037 35,065
\n
Enel Chile 10,810 11,094 1,722 1,541 12,532 12,635
\n
Endesa 43,701 45,125 4,033 11,166 47,73 4 56,291
\n
Millions of euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable
\n
to owners of the
\n
Parent
\n
Non-controlling
\n
interests
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 10,466 11,569 7,314 6,208 17,78 0 17,777 18,257 17, 28 8 12,936 12,136 5,321 5,152
\n
Enel Chile 3,706 4,222 2,730 2,460 6,436 6,682 6,096 5,953 3,753 3,683 2,343 2,270
\n
Endesa 16,018 18,523 10,045 17,372 26,063 35,895 21,671 20,396 16,202 15,081 5,469 5,315
\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

\n\n\n
Millions of euro Total revenue Pre-tax profit
\n
Profit from
\n
continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable
\n
to non-controlling
\n
interests
\n
2023 2022 2023 2022 2023 2022 2023 2022 2023 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 13,400 14,696 1,639 1,015 877 221 504 (90) 373 311
\n
Enel Chile 4,678 6,450 996 1,971 748 1,458 456 913 292 545
\n
Endesa 25,423 32,714 839 3,055 595 2,244 402 1,534 193 710
\n

\n\n\n\n\n\n

\n\n\n

\n\n\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag225": { "value": "\n
Share capital \u2013 \u20ac10,167 million
\n
At December 31, 2023 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, 2022.
\n
At December 31, 2023, based on the shareholders regis-
\n
ter and the notices submitted to CONSOB and received
\n
by the Parent pursuant to Article 120 of Legislative Decree
\n
58 of February 24, 1998, as well as other available infor-
\n
mation, shareholders with interests of greater than 3% in
\n
the Parent\u2019s share capital were the Ministry for the Economy
\n
and Finance (with a 23.585% stake) and BlackRock Inc. (with
\n
a 5.023% stake held for asset management purposes).
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag226": { "value": "\n
Treasury share reserve \u2013 \u20ac(59) million
\n
At December 31, 2023, treasury shares are represented by
\n
9,262,330 ordinary shares of Enel SpA with a par value of
\n
\u20ac1.00 each (7,153,795 at December 31, 2022), purchased
\n
through an authorized intermediary for a total of \u20ac59 mil-
\n
lion.
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag227": { "value": "\n
Other reserves \u2013 \u20ac6,551 million
\n
Share premium reserve \u2013 \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
\u2013 \u20ac6,553 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
The change of \u20ac986 million in the reserve reflects the is-
\n
sue of new bonds in the amount of \u20ac1,738 million, net of
\n
transaction costs, partly offset by the repurchase and sub-
\n
sequent cancellation of previous bonds in the amount of
\n
\u20ac752 million, including transaction costs.
\n
In 2023, coupons of \u20ac182 million were paid to holders of
\n
perpetual hybrid bonds.
\n
Legal reserve \u2013 \u20ac2,034 million
\n
The legal reserve is formed as allocation of part of the net
\n
income that, pursuant to Article 2430 of the Italian Civil
\n
Code, cannot be distributed as dividends.
\n
Other reserves \u2013 \u20ac2,341 million
\n
These include \u20ac2,215 million related to the remaining por-
\n
tion of the value adjustments carried out when Enel was
\n
transformed from a public entity to a joint-stock company.
\n
Pursuant to Article 47 of the Uniform Income Tax Code,
\n
this amount does not constitute taxable income when dis-
\n
tributed.
\n
Translation reserve \u2013 \u20ac(5,289) million
\n
The increase of \u20ac623 million in the period was mainly due
\n
to the change in the consolidation scope connected with
\n
stakes held in Romania, Inversora Dock Sud and Central
\n
Dock Sud and Enel Generaci\u00f3n Costanera, as well as the
\n
net depreciation of the functional currencies used by for-
\n
eign subsidiaries, mainly in Chile and the United States,
\n
against the euro (presentation currency of the Parent).
\n
Hedging reserve \u2013 \u20ac(1,393) million
\n
This includes the net expense recognized in equity from
\n
the measurement of hedging derivatives. The change in
\n
the period is mainly attributable to developments in com-
\n
modity prices.
\n
Hedging costs reserve \u2013 \u20ac(38) 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 2023 is mainly attributable to devel-
\n
opments in commodity prices.
\n
Reserve from measurement of financial instruments at
\n
FVOCI \u2013 \u20ac10 million
\n
This includes net unrealized fair value losses on financial
\n
assets.
\n
Reserve from equity-accounted investments \u2013 \u20ac(375)
\n
million
\n
The reserve reports the share of comprehensive income
\n
to be recognized directly in equity of equity-accounted
\n
investees. The change in 2023 is mainly attributable to the
\n
change in the hedging reserve of Slovak Power Holding.
\n
Actuarial reserve \u2013 \u20ac(1,185) 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 \u2013 \u20ac(2,390) million
\n
This item mainly reports:
\n
\u2022
\n
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
\n
the sale of non-controlling interests recognized as a
\n
result of the Enersis (now Enel Am\u00e9ricas and Enel Chile)
\n
capital increase;
\n

\n

\n\n\n\n\n\n
\u2022
\n
the capital loss, net of expenses associated with the
\n
disposal and the related taxation, from the public offer-
\n
ing of 21.92% of Endesa;
\n
\u2022
\n
the disposal to third parties of the non-controlling in-
\n
terest in Enel Green Power North America Renewable
\n
Energy Partners;
\n
\u2022
\n
the effects of the merger into Enel Am\u00e9ricas of Endesa
\n
Am\u00e9ricas and Chilectra Am\u00e9ricas;
\n
\u2022
\n
the effects of the disposal of a 49% stake held by Enel
\n
Green Power Canada in Pincher Creek LP and Riverview
\n
LP.
\n
Reserve from acquisitions of non-controlling interests \u2013
\n
\u20ac(1,213) 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 (-\u20ac21 million) mainly reflects the
\n
effects of the merger of Enel Green Power Per\u00fa, Energ\u00e9ti-
\n
ca Monz\u00f3n and Empresa de Generaci\u00f3n El\u00e9ctrica Los Pi-
\n
nos (merged entities) into Enel Generaci\u00f3n Per\u00fa (acquiring
\n
entity), changing the interest held by the Group in those
\n
companies.
\n

\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag228": { "value": "\n

\n

\n
37.2 Dividends
\n
Amount distributed
\n
(millions of euro) Dividend per share (euro)
\n
Dividends distributed in 2022
\n
Dividends for 2021 3,861 0.38
\n
Interim dividends for 2022
\n
(1)
\n
- -
\n
Special dividends - -
\n
Total dividends distributed in 2022 3,861 0.38
\n
Dividends distributed in 2023
\n
Dividends for 2022 4,064 0.40
\n
Interim dividends for 2023
\n
(2)
\n
- -
\n
Special dividends - -
\n
Total dividends distributed in 2023 4,064 0.40
\n
(1) 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
\n
million).
\n
(2) Approved by the Board of Directors on November 7, 2023 and paid as from January 24, 2024 (interim dividend of \u20ac0.215 per share for a total of \u20ac2,186
\n
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 2023, is equal to \u20ac0.43 per share, for a
\n
total of \u20ac4,372 million (of which \u20ac0.215 per share for a to-
\n
tal of \u20ac2,186 million already paid as an interim dividend). It
\n
will be proposed to the Shareholders\u2019 Meeting of May 23,
\n
2024 at single call.
\n
These consolidated financial statements do not take ac-
\n
count of the effects of the distribution to shareholders
\n
of the dividend for 2023, except for the liability in respect
\n
of shareholders for the interim dividend for 2023, which
\n
was approved by the Board of Directors on November 7,
\n
2023 for a potential maximum of \u20ac2,186 million, and paid
\n
as from January 24, 2024 net of the portion pertaining to
\n
the 10,085,106 treasury shares held as at the record date
\n
of January 23, 2024.
\n
In 2023 the Group also paid \u20ac182 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
\n
adequate capitalization that enables it to achieve a sat-
\n
isfactory return for shareholders and ensure access to
\n
external sources of financing, in part by maintaining an
\n
adequate 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 2023.
\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, 2023 and 2022 is summarized in the follow-
\n
ing table.
\n

\n\n\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Non-current financial debt 61,093 68,191 (7,098)
\n
Net current financial position 2,907 (3,315) 6,222
\n
Non-current financial assets and long-term securities (3,837) (4,213) 376
\n
Net financial debt
\n
(1)
\n
60,163 60,663 (500)
\n
Equity attributable to owners of the Parent 31,755 28,655 3,100
\n
Non-controlling interests 13,354 13,425 (71)
\n
Equity
\n
(2)
\n
45,109 42,080 3,029
\n
Debt/equity ratio 1.33 1.44 (0.11)
\n
(1) In order to facilitate analysis of developments in Group net financial debt, thereby ensuring greater comparability over time, management has decided
\n
to exclude the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on loans. Accordingly, in order to
\n
improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2022.
\n
(2) The figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods begin-
\n
ning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n

\n\n\n\n\n\n\n
The decrease in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in equity as a result of profit for the year, the increase in
\n
reserves from the measurement of cash flow hedge deriv-
\n
atives and the change in the scope of the reserve for the
\n
translation of financial statements in foreign currency, only
\n
partly offset by dividend distributions. The reduction in net
\n
financial debt further contributed to the decline.
\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\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag229": { "value": "0.4", "decimals": 2, "dimensions": { "concept": "ifrs-full:DividendsRecognisedAsDistributionsToOwnersPerShare", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:EUR/xbrli:shares" } }, "Tag230": { "value": "0.43", "decimals": 2, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwnersPerShare", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:EUR/xbrli:shares" } }, "Tag231": { "value": "4372", "decimals": 0, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:EUR" } }, "Tag232": { "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
\n
adequate capitalization that enables it to achieve a sat-
\n
isfactory return for shareholders and ensure access to
\n
external sources of financing, in part by maintaining an
\n
adequate 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 2023.
\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, 2023 and 2022 is summarized in the follow-
\n
ing table.
\n

\n\n\n\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Non-current financial debt 61,093 68,191 (7,098)
\n
Net current financial position 2,907 (3,315) 6,222
\n
Non-current financial assets and long-term securities (3,837) (4,213) 376
\n
Net financial debt
\n
(1)
\n
60,163 60,663 (500)
\n
Equity attributable to owners of the Parent 31,755 28,655 3,100
\n
Non-controlling interests 13,354 13,425 (71)
\n
Equity
\n
(2)
\n
45,109 42,080 3,029
\n
Debt/equity ratio 1.33 1.44 (0.11)
\n
(1) In order to facilitate analysis of developments in Group net financial debt, thereby ensuring greater comparability over time, management has decided
\n
to exclude the fair value of the cash flow hedge and fair value hedge derivatives used to hedge the exchange rate risk on loans. Accordingly, in order to
\n
improve the comparability of the figures, it was necessary to recalculate net financial debt at December 31, 2022.
\n
(2) The figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods begin-
\n
ning on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d.
\n

\n\n\n\n\n\n
The decrease in the debt/equity ratio, which measures fi-
\n
nancial leverage, is essentially attributable to the increase
\n
in equity as a result of profit for the year, the increase in
\n
reserves from the measurement of cash flow hedge deriv-
\n
atives and the change in the scope of the reserve for the
\n
translation of financial statements in foreign currency, only
\n
partly offset by dividend distributions. The reduction in net
\n
financial debt further contributed to the decline.
\n
See note 47 for a breakdown of the individual items in the
\n
table.
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag233": { "value": "\n

\n\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,354 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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Italy - 1 - -
\n
Iberia 5,470 5,321 192 713
\n
Latin America 7,665 7,42 2 666 857
\n
Europe - 328 3 (342)
\n
North America 151 218 (39) 10
\n
Africa, Asia and Oceania 68 135 7 -
\n
Total 13,354 13,425 829 1,238
\n
The change in non-controlling interests mainly reflects the
\n
effect of the dividends distributed and the disposal of eq-
\n
uity stakes in Romania. These effects were offset by the
\n
results for the period, the impact of hyperinflation and the
\n
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
The figures at December 31, 2022 have been adjusted to
\n
take account of the effects of the Amendment to IAS 12,
\n
which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please
\n
see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Millions of euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 27,578 29,635 8,459 5,430 36,037 35,065
\n
Enel Chile 10,810 11,094 1,722 1,541 12,532 12,635
\n
Endesa 43,701 45,125 4,033 11,166 47,73 4 56,291
\n
Millions of euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable
\n
to owners of the
\n
Parent
\n
Non-controlling
\n
interests
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 10,466 11,569 7,314 6,208 17,78 0 17,777 18,257 17, 28 8 12,936 12,136 5,321 5,152
\n
Enel Chile 3,706 4,222 2,730 2,460 6,436 6,682 6,096 5,953 3,753 3,683 2,343 2,270
\n
Endesa 16,018 18,523 10,045 17,372 26,063 35,895 21,671 20,396 16,202 15,081 5,469 5,315
\n

\n\n\n

\n\n\n\n\n\n

\n\n\n\n\n\n

\n\n\n
Millions of euro Total revenue Pre-tax profit
\n
Profit from
\n
continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable
\n
to non-controlling
\n
interests
\n
2023 2022 2023 2022 2023 2022 2023 2022 2023 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 13,400 14,696 1,639 1,015 877 221 504 (90) 373 311
\n
Enel Chile 4,678 6,450 996 1,971 748 1,458 456 913 292 545
\n
Endesa 25,423 32,714 839 3,055 595 2,244 402 1,534 193 710
\n

\n\n\n\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag234": { "value": "\n

\n\n
37.3 Non-controlling interests \u2013 \u20ac13,354 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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Italy - 1 - -
\n
Iberia 5,470 5,321 192 713
\n
Latin America 7,665 7,42 2 666 857
\n
Europe - 328 3 (342)
\n
North America 151 218 (39) 10
\n
Africa, Asia and Oceania 68 135 7 -
\n
Total 13,354 13,425 829 1,238
\n
The change in non-controlling interests mainly reflects the
\n
effect of the dividends distributed and the disposal of eq-
\n
uity stakes in Romania. These effects were offset by the
\n
results for the period, the impact of hyperinflation and the
\n
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
The figures at December 31, 2022 have been adjusted to
\n
take account of the effects of the Amendment to IAS 12,
\n
which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please
\n
see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Millions of euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 27,578 29,635 8,459 5,430 36,037 35,065
\n
Enel Chile 10,810 11,094 1,722 1,541 12,532 12,635
\n
Endesa 43,701 45,125 4,033 11,166 47,73 4 56,291
\n
Millions of euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable
\n
to owners of the
\n
Parent
\n
Non-controlling
\n
interests
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 10,466 11,569 7,314 6,208 17,78 0 17,777 18,257 17, 28 8 12,936 12,136 5,321 5,152
\n
Enel Chile 3,706 4,222 2,730 2,460 6,436 6,682 6,096 5,953 3,753 3,683 2,343 2,270
\n
Endesa 16,018 18,523 10,045 17,372 26,063 35,895 21,671 20,396 16,202 15,081 5,469 5,315
\n

\n\n\n

\n\n\n\n\n\n\n
Millions of euro Total revenue Pre-tax profit
\n
Profit from
\n
continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable
\n
to non-controlling
\n
interests
\n
2023 2022 2023 2022 2023 2022 2023 2022 2023 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 13,400 14,696 1,639 1,015 877 221 504 (90) 373 311
\n
Enel Chile 4,678 6,450 996 1,971 748 1,458 456 913 292 545
\n
Endesa 25,423 32,714 839 3,055 595 2,244 402 1,534 193 710
\n

\n\n\n\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag235": { "value": "\n
37.3 Non-controlling interests \u2013 \u20ac13,354 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, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Italy - 1 - -
\n
Iberia 5,470 5,321 192 713
\n
Latin America 7,665 7,42 2 666 857
\n
Europe - 328 3 (342)
\n
North America 151 218 (39) 10
\n
Africa, Asia and Oceania 68 135 7 -
\n
Total 13,354 13,425 829 1,238
\n
The change in non-controlling interests mainly reflects the
\n
effect of the dividends distributed and the disposal of eq-
\n
uity stakes in Romania. These effects were offset by the
\n
results for the period, the impact of hyperinflation and the
\n
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
The figures at December 31, 2022 have been adjusted to
\n
take account of the effects of the Amendment to IAS 12,
\n
which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please
\n
see note 8 \u201cRestatement of comparative disclosures\u201d.
\n
Millions of euro Non-current assets Current assets Total assets
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 27,578 29,635 8,459 5,430 36,037 35,065
\n
Enel Chile 10,810 11,094 1,722 1,541 12,532 12,635
\n
Endesa 43,701 45,125 4,033 11,166 47,73 4 56,291
\n
Millions of euro
\n
Non-current
\n
liabilities Current liabilities Total liabilities Equity
\n
Equity attributable
\n
to owners of the
\n
Parent
\n
Non-controlling
\n
interests
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
at Dec.
\n
31, 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 10,466 11,569 7,314 6,208 17,78 0 17,777 18,257 17, 28 8 12,936 12,136 5,321 5,152
\n
Enel Chile 3,706 4,222 2,730 2,460 6,436 6,682 6,096 5,953 3,753 3,683 2,343 2,270
\n
Endesa 16,018 18,523 10,045 17,372 26,063 35,895 21,671 20,396 16,202 15,081 5,469 5,315
\n

\n\n\n
Millions of euro Total revenue Pre-tax profit
\n
Profit from
\n
continuing
\n
operations
\n
Profit attributable to
\n
owners of the Parent
\n
Profit attributable
\n
to non-controlling
\n
interests
\n
2023 2022 2023 2022 2023 2022 2023 2022 2023 2022
\n
Subsidiaries
\n
Enel Am\u00e9ricas 13,400 14,696 1,639 1,015 877 221 504 (90) 373 311
\n
Enel Chile 4,678 6,450 996 1,971 748 1,458 456 913 292 545
\n
Endesa 25,423 32,714 839 3,055 595 2,244 402 1,534 193 710
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag223": { "value": "\n
38. Borrowings
\n
Millions of euro Non-current Current
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Long-term borrowings 61,085 68,191 9,086 2,835
\n
Short-term borrowings - - 4,769 18,392
\n
Total 61,085 68,191 13,855 21,227
\n
For more information on the nature of borrowings, please
\n
see note 48.2 \u201cFinancial liabilities by category\u201d.
\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 \u20ac70,171 million
\n
The following table reports the nominal value, carrying
\n
amount and fair value of long-term borrowing, including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
Millions of euro
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Changes
\n
in
\n
carrying
\n
amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Bonds:
\n
- listed, fixed rate 29,539 29,163 4,686 24,477 27,885 30,355 29,892 978 28,914 27,468 (729)
\n
- listed, floating rate 2,643 2,622 623 1,999 2,641 2,569 2,547 537 2,010 2,473 75
\n
- unlisted, fixed rate 18,336 18,129 1,357 16,772 17, 8 4 2 18,959 18,727 - 18,727 17, 249 (598)
\n
- unlisted, floating rate 428 428 97 331 456 525 525 97 428 600 (97)
\n
Total bonds 50,946 50,342 6,763 43,579 48,824 52,408 51,691 1,612 50,079 47,79 0 (1,349)
\n
Bank borrowings:
\n
- fixed rate 3,874 3,822 853 2,969 3,746 3,367 3,273 211 3,062 3,021 549
\n
- floating rate 12,664 12,629 1,139 11,490 12,892 12,884 12,848 677 12,171 12,570 (219)
\n
- use of revolving credit
\n
lines
\n
41 41 - 41 41 30 30 2 28 26 11
\n
Total bank borrowings 16,579 16,492 1,992 14,500 16,679 16,281 16,151 890 15,261 15,617 341
\n
Leases:
\n
- fixed rate 2,852 2,852 256 2,596 2,852 2,630 2,630 251 2,379 2,630 222
\n
- floating rate 53 53 12 41 53 42 42 10 32 42 11
\n
Total leases 2,905 2,905 268 2,637 2,905 2,672 2,672 261 2,411 2,672 233
\n
Other non-bank
\n
borrowings
\n
(1)
\n
:
\n
- fixed rate 426 426 63 363 426 504 504 70 434 504 (78)
\n
- floating rate 6 6 - 6 6 8 8 2 6 12 (2)
\n
Total other non-bank
\n
borrowings
\n
432 432 63 369 432 512 512 72 440 516 (80)
\n
Total fixed-rate
\n
borrowings
\n
55,027 54,392 7, 215 47, 17 7 52,751 55,815 55,026 1,510 53,516 50,872 (634)
\n
Total floating-rate
\n
borrowings
\n
15,835 15,779 1,871 13,908 16,089 16,058 16,000 1,325 14,675 15,723 (221)
\n
TOTAL 70,862 70,171 9,086 61,085 68,840 71,873 71,026 2,835 68,191 66,595 (855)
\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
The table below reports long-term financial debt by cur-
\n
rency and interest rate.
\n
Long-term borrowing (including the portion falling due within 12 months) by currency and interest rate
\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 rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest rate
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Euro 35,865 36,166 34,993 35,383 2.5% 2.8% 1.9% 2.1%
\n
US dollar 24,601 24,847 26,930 27,209 4.9% 5.2% 4.8% 5.1%
\n
Pound sterling 4,612 4,720 4,470 4,610 4.6% 4.8% 4.6% 4.8%
\n
Colombian peso 1,884 1,888 1,310 1,310 13.5% 13.5% 10.3% 10.3%
\n
Brazilian real 2,229 2,255 1,899 1,926 10.5% 10.6% 10.0% 10.2%
\n
Swiss franc 382 382 359 360 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 510 514 526 531 5.1% 5.2% 5.1% 5.2%
\n
Peruvian sol - - 429 429 5.3% 5.3%
\n
Other currencies 88 90 110 115
\n
Total non-euro currencies 34,306 34,696 36,033 36,490
\n
TOTAL 70,171 70,862 71,026 71,873
\n
Long-term financial debt denominated in currencies other
\n
than the euro decreased by \u20ac1,727 million, largely attribut-
\n
able to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term borrowing (including the portion falling due within 12 months)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope New borrowings
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31, 2022 at Dec. 31, 2023
\n
Bonds 52,408 (2,798) (293) 1,900 (271) 50,946
\n
Borrowings 19,465 (3,208) (482) 4,193 (52) 19,916
\n
- of which leases 2,672 (406) (36) 677 (2) 2,905
\n
Total financial debt 71,873 (6,006) (775) 6,093 (323) 70,862
\n
The nominal value of long-term debt amounted to \u20ac70,862
\n
million at December 31, 2023, a decrease of \u20ac1,011 million
\n
compared with December 31, 2022. The decrease reflect-
\n
ed repayments in the amount of \u20ac6,006 million, changes
\n
in consolidation scope for \u20ac775 million and positive ex-
\n
change differences of \u20ac323 million, only partially offset by
\n
new borrowings of \u20ac6,093 million.
\n
Repayments in 2023 involved bonds in the amount of
\n
\u20ac2,798 million and loans in the amount of \u20ac3,208 million.
\n
Specifically, repayments of bonds in 2023 included:
\n
\u2022
\n
$1,250 million (\u20ac1,132 million at December 31, 2023), in
\n
respect of the hybrid bond issued by Enel SpA involved
\n
in a partial tender offer in the first months of 2023 and
\n
entirely repaid in September 2023;
\n
\u2022
\n
\u20ac100 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in February 2023;
\n
\u2022
\n
290,130 million Colombian pesos (equivalent to \u20ac68
\n
million at December 31, 2023) in respect of a float-
\n
ing-rate bond issued by Enel Colombia, maturing in
\n
February 2023;
\n
\u2022
\n
280,000 million Colombian pesos (equivalent to \u20ac65
\n
million at December 31, 2023) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2023;
\n
\u2022
\n
\u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in March 2023;
\n
\u2022
\n
\u20ac585 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in April 2023;
\n
\u2022
\n
R$305 million (equivalent to \u20ac57 million at December
\n
31, 2023), in respect of a floating-rate bond issued by
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, maturing in April 2023;
\n

\n\n\n

\n\n\n

\n\n
\u2022
\n
\u20ac300 million in respect of a fixed-rate bond issued by
\n
Enel Finance International maturing in September 2023;
\n
\u2022
\n
R$698 million (equivalent to \u20ac130 million at December
\n
31, 2023), in respect of a floating-rate amortizing bond
\n
issued by Enel Distribui\u00e7\u00e3o S\u00e3o Paulo maturing in Sep-
\n
tember 2023.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022
\n
\u20ac200 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022
\n
\u20ac367 in respect of sustainable loans of Group\u2019s Italian
\n
companies;
\n
\u2022
\n
\u20ac1,493 million in respect of Endesa loans, of which \u20ac452
\n
million in sustainable loans;
\n
\u2022
\n
the equivalent of \u20ac322 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2023 involved \u20ac1,900 million in bonds
\n
and \u20ac4,193 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2023 and translated into euros
\n
at the exchange rate prevailing at December 29, 2023.
\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.00% Fixed rate 20.02.2031
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.50% Fixed rate 20.02.2043
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.01.2023 177 BRL CDI + 1.48% Floating rate 11.01.2026
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.05.2023 93 BRL CDI + 1.65% Floating rate 15.05.2024
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
26.06.2023 121 BRL CDI + 1.65% Floating rate 28.06.2024
\n
Total bonds 1,891
\n
Bank borrowings
\n
Enel SpA 24.07.2023 200 EUR Euribor 3M + 0.35% Floating rate 03.05.2024
\n
e-distribuzione 20.10.2023 500 EUR Euribor 6M + 0.55% Floating rate 20.10.2038
\n
Enel X Way Italia 07.08.2023 70 EUR Euribor 6M + 0.56% Floating rate 09.08.2038
\n
Enel Italia 15.06.2023 60 EUR Euribor 6M + 0.56% Floating rate 15.06.2038
\n
Enel Finance
\n
America
\n
04.04.2023 335 USD SOFR 6M CPM + 1.22% Floating rate 15.05.2034
\n
Endesa 30.04.2023 50 EUR 0.26% Fixed rate 31.07.2028
\n
Endesa 03.05.2023 425 EUR 4.18% Fixed rate 03.05.2028
\n
Endesa 04.05.2023 75 EUR 3.98% Fixed rate 04.05.2028
\n
Endesa 05.05.2023 125 EUR 4.63% Fixed rate 05.05.2028
\n
Endesa 03.07.2023 300 EUR Euribor 6M + 0.80% Floating rate 28.06.2035
\n
Endesa 21.12.2023 400 EUR Euribor 6M + 0.72% Floating rate 21.12.2028
\n
Enel Chile 13.04.2023 68 USD SOFR 1M + 1.33% Floating rate 26.06.2024
\n
Enel Chile 21.07.2023 72 USD 5.46% Fixed rate 21.07.2038
\n
Enel Chile 20.12.2023 74 USD 5.62% Fixed rate 21.12.2038
\n
Enel Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
20.04.2023 50 USD 4.38% Fixed rate 20.04.2038
\n
Enel Colombia 12.04.2023 160 COP IBR O/N 3M + 3.7% Floating rate 12.04.2028
\n
Enel Colombia 30.11.2023 283 COP IBR O/N 3M + 3.1% Floating rate 15.10.2031
\n
Enel Colombia 21.12.2023 70 COP IBR 3M + 3.85% Floating rate 21.12.2027
\n
Total bank
\n
borrowings
\n
3,317
\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, 2023 at Dec. 31, 2022
\n
Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Euro 35,865 36,166 51.0% 21,862 58,028 81.9% 34,993 35,383 49.2% 23,473 58,856 81.9%
\n
US dollar 24,601 24,847 35.1% (17,850) 6,997 9.9% 26,930 27,209 37.9% (19,759) 7,4 5 0 10.4%
\n
Pound sterling 4,612 4,720 6.7% (4,720) - - 4,470 4,610 6.4% (4,610) - -
\n
Colombian peso 1,884 1,888 2.7% - 1,888 2.7% 1,310 1,310 1.8% - 1,310 1.8%
\n
Brazilian real 2,229 2,255 3.2% 1,047 3,302 4.7% 1,899 1,926 2.7% 1,205 3,131 4.4%
\n
Swiss franc 382 382 0.5% (382) - - 359 360 0.5% (360) - -
\n
Chilean peso/UF 510 514 0.7% - 514 0.7% 526 531 0.7% - 531 0.7%
\n
Peruvian sol - - - - - - 429 429 0.6% - 429 0.6%
\n
Other currencies 88 90 0.1% 43 133 0.2% 110 115 0.2% 51 166 0.2%
\n
Total non-euro
\n
currencies
\n
34,306 34,696 49.0% (21,862) 12,834 18.1% 36,033 36,490 50.8% (23,473) 13,017 18.1%
\n
TOTAL 70,171 70,862 100.0% - 70,862 100.0% 71,026 71,873 100.0% - 71,873 100.0%
\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 2023 2022
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Floating rate 20,604 27. 2 % 17, 241 22.8% 34,450 38.2% 31,353 34.7%
\n
Fixed rate 55,027 72.8% 58,389 77.2% 55,815 61.8% 58,912 65.3%
\n
Total 75,631 75,630 90,265 90,265
\n
At December 31,2023, 27.2% of the nominal value of long-
\n
and medium-term financial debt was floating rate (38.2%
\n
at December 31, 2022). Taking account of hedges of in-
\n
terest rates considered effective pursuant to the IFRS-EU,
\n
22.8% of the nominal value of long- and medium-term fi-
\n
nancial debt was exposed to interest rate risk at Decem-
\n
ber 31, 2023 (34.7% at December 31, 2022). These figures
\n
are in line with the limits established in the risk manage-
\n
ment policy.
\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 programs 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
\n
the Group\u2019s so-called eligible green projects) and those
\n
regarding bonds issued by Enel Finance International NV
\n
on the US market guaranteed by Enel SpA can be summa-
\n
rized as follows:
\n
\u2022
\n
negative pledge clauses under which the issuer and
\n
the guarantor may not establish or maintain mortgag-
\n
es, liens or other encumbrances on all or part of their
\n
assets or revenue to secure certain financial liabilities,
\n
unless the same encumbrances are extended equally
\n
or pro rata to the bonds in question;
\n
\u2022
\n
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
and are issued without preferential rights among them
\n
and have at least the same seniority as other present
\n
and future unsubordinated and unsecured bonds of
\n
the issuer and the guarantor;
\n

\n\n\n

\n\n\n\n

\n

\n
\u2022
\n
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
\n
(as part of the Euro Medium-Term Notes - EMTN bond
\n
issue program) and on the American market, both guar-
\n
anteed by Enel SpA, linked to the achievement of a num-
\n
ber of the Sustainable Development Goals (SDGs) of the
\n
United Nations that contain the same covenants as other
\n
bonds of 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
\n
subordination clauses, under which each hybrid bond
\n
is subordinate to all other bonds issued by the com-
\n
pany and has the same seniority with all other hybrid
\n
financial instruments issued, being senior only to equity
\n
instruments;
\n
\u2022
\n
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 of
\n
Enel SpA 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
(52)
\n
\u2022
\n
negative pledge clauses, under which the borrower
\n
and, in some cases, the guarantor are subject to lim-
\n
itations on the establishment of mortgages, liens or
\n
other encumbrances on all or part of their respective
\n
assets, with the exception of expressly permitted en-
\n
cumbrances;
\n
\u2022
\n
disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their
\n
assets or operations, with the exception of expressly
\n
permitted disposals;
\n
\u2022
\n
pari passu clauses, under which the payment under-
\n
takings of the borrower have the same seniority as its
\n
other unsecured and unsubordinated payment obliga-
\n
tions;
\n
\u2022
\n
change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required
\n
to renegotiate the terms and conditions of the financ-
\n
ing or make compulsory early repayment of the loans
\n
granted;
\n
\u2022
\n
rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022
\n
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 cases,
\n
the guarantor constitutes a default in respect of the li-
\n
abilities in question, which become immediately repay-
\n
able.
\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
(52) The sustainability-linked loan entered into on September 30, 2022, granted by EKF Denmark\u2019s Export Credit Agency and Citi to Enel Finance America LLC
\n
as borrower and Enel SpA (as guarantor), provide for a number of additional covenants, such as:
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending bank can request the cancellation of its financial commitment undertaken by it and the early
\n
payment of the sums disbursed if it has suffered ascertained harm to its own reputation or that of other persons as a result of substantial breach of certain
\n
regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure compliance with certain environmental and social regulations and standards.
\n

\n\n\n

\n\n\n

\n\n
48.3.2 Short-term borrowings \u2013 \u20ac4,769 million
\n
At December 31, 2023, short-term borrowings totaled
\n
\u20ac4,769 million, a decrease of \u20ac13,623 million compared
\n
with December 31, 2022, and break down as follows.
\n
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Short-term bank borrowings 393 1,320 (927)
\n
Commercial paper 2,499 13,838 (11,339)
\n
Cash collateral and other financing on derivatives 1,383 1,513 (130)
\n
Other short-term borrowings
\n
(1)
\n
494 1,721 (1,227)
\n
Short-term borrowings 4,769 18,392 (13,623)
\n
(1) Does not include current financial liabilities included in \u201cOther current financial liabilities\u201d in net short-term financial debt.
\n
Commercial paper liabilities totaling \u20ac2,499 million con-
\n
cerned issues by Enel Finance International and Enel Fi-
\n
nance America.
\n
The main commercial paper programs include:
\n
\u2022
\n
\u20ac8,000 million of Enel Finance International;
\n
\u2022
\n
\u20ac5,000 million of Endesa;
\n
\u2022
\n
$5,000 million (equivalent to \u20ac4,526 million at Decem-
\n
ber 31, 2023) of Enel Finance America.
\n
At December 31, 2023, the whole amount of commercial
\n
paper issues, equal to \u20ac2,499 million, was linked to sus-
\n
tainability objectives.
\n
Sustainability-linked finance at Enel
\n
The new sustainability-linked bond issues, together with all
\n
the sustainable financing arranged in the last year, made it
\n
possible to reach a 64% ratio of sustainable sources of fi-
\n
nancing to the Group\u2019s total gross debt at the end of 2023,
\n
with a goal of reaching around 70% in 2026.
\n
Shown below are the KPIs and targets included in the
\n
latest update of Enel\u2019s Sustainability-Linked Financing
\n
Framework, published in January 2024.
\n
KPI Actual value Sustainability Performance Targets (SPTs)
\n
2023 2023 2024 2025 2026 2030 2040
\n
Intensity of Scope 1 GHG emissions related to
\n
power generation (gCO
\n
2eq
\n
/kWh)
\n
160 148 140 130 125 72 0
\n
Intensity of Scope 1 and Scope 3 GHG
\n
emissions related to Integrated Power
\n
(gCO
\n
2eq
\n
/kWh)
\n
168 135 135 73 0
\n
Absolute Scope 3 GHG emissions related to
\n
retail gas (MtCO
\n
2eq
\n
)
\n
16.8 20.9 20.0 11.4 0
\n
Percentage of installed renewables capacity (%) 68.2 65 69 73 74 80 100
\n
Percentage of capital expenditure aligned with
\n
the EU taxonomy (%)
\n
84.8
\n
>80
\n
(2023-2025)
\n
(53)
\n
>80
\n
(2024-2026)
\n
(54)
\n
Developments in the indicators shown in the table are pe-
\n
riodically verified by an external auditor.
\n
The war in Ukraine and the resulting restrictions on gas
\n
imports from Russia into the EU, which caused a decrease
\n
in gas supplies accompanied by a surge in wholesale elec-
\n
tricity and gas prices, with serious effects for households
\n
and businesses, prompted EU governments to implement
\n
a series of policy responses to mitigate the impact of ris-
\n
ing costs and ensure the stability of the energy system.
\n
Despite these policy measures, the Group managed to re-
\n
duce direct and indirect greenhouse gas emissions along
\n
the entire value chain by 26.3% overall compared with
\n
the previous year. Furthermore, the Group also reduced
\n
the intensity of Scope 1 GHG emissions related to power
\n
generation by over 30.6%, going from 229 gCO
\n
2eq
\n
/kWh in
\n
2022 to 160 gCO
\n
2eq
\n
/kWh in 2023. This reduction reflected
\n
a 12.9% increase in consolidated renewables generation
\n
and a 37.5% reduction in consolidated thermal generation
\n
compared with 2022, a consequence of the Group\u2019s strat-
\n
egy to shift its generation mix towards renewables and to
\n
advance the decarbonization process.
\n
(53) SPT with cumulative observation period of 2023-2025.
\n
(54) SPT with cumulative observation period of 2024-2026.
\n

\n\n\n

\n\n\n

\n\n

\n
However, due to the unprecedented crisis faced by the Eu-
\n
ropean energy system in 2022 and 2023, the Group\u2019s emis-
\n
sions reduction in 2023 was not sufficient to achieve the
\n
Scope 1 GHG emissions intensity target related to electric-
\n
ity generation set for 2023 as announced on the occasion
\n
of the Capital Markets Day held in November 2020 for the
\n
launch of the 2021-2023 Strategic Plan. As a result of the
\n
energy crisis, the intensity value was slightly higher than the
\n
target of 148 gCO
\n
2eq
\n
/kWh. In the absence of these factors,
\n
Enel would have been able to reach an emissions intensity
\n
level well below the target of 148 gCO
\n
2eq
\n
/kWh.
\n
As a result, the Group\u2019s sustainability-linked instruments
\n
that set the Scope 1 emissions intensity target for elec-
\n
tricity generation at 148 gCO
\n
2eq
\n
/kWh for 2023 will be sub-
\n
ject to an increase in the relative step-up.
\n

\n

\n\n\n

\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag224": { "value": "\n
39. Employee benefits \u2013 \u20ac2,320 million
\n
The Group provides its employees with a variety of bene-
\n
fits, including deferred compensation benefits, addition-
\n
al months\u2019 pay for having reached age limits or eligibility
\n
for old-age pension, loyalty bonuses for achievement of
\n
seniority milestones, supplemental retirement and health-
\n
care plans, residential electricity discounts and similar
\n
benefits. More specifically:
\n
\u2022
\n
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
\n
the benefits due to personnel under law or contract
\n
at the time the employment relationship is terminated.
\n
For the foreign companies, the item refers to post-em-
\n
ployment benefits, of which the most material regard
\n
the pension benefit schemes of Endesa in Spain, which
\n
break down into three types that differ on the basis of
\n
employee seniority and company. In general, under the
\n
framework agreement of October 25, 2000, employees
\n
participate in a specific defined contribution pension
\n
plan and, in cases of disability or death of employees
\n
in service, a defined benefit plan which is covered by
\n
appropriate insurance policies. In addition, the group
\n
has two other limited-enrollment plans (i) for current
\n
and retired Endesa employees covered by the elec-
\n
tricity industry collective bargaining agreement prior
\n
to the changes introduced with the framework agree-
\n
ment noted earlier and (ii) for employees of the Catalan
\n
companies merged in the past (Fecsa/Enher/HidroEm-
\n
pord\u00e0). Both are defined benefit plans and benefits are
\n
fully insured, with the exception of the former plan for
\n
benefits in the event of the death of a retired employee.
\n
Finally, the Brazilian companies have also established
\n
defined benefit plans;
\n
\u2022
\n
the item \u201celectricity discount\u201d comprises benefits re-
\n
garding electricity supply associated in particular with
\n
foreign companies;
\n
\u2022
\n
the item \u201chealth insurance\u201d refers to benefits for cur-
\n
rent or retired employees covering medical expenses;
\n
\u2022
\n
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
\n
for achievement of seniority milestones (25th and 35th
\n
year of service). It also includes other incentive plans,
\n
which provide for the award to certain Company man-
\n
agers of a monetary bonus subject to specified condi-
\n
tions.
\n
The following table reports changes in the defined bene-
\n
fit obligation for post-employment and other long-term
\n
employee benefits at December 31, 2023, and December
\n
31, 2022, respectively, as well as a reconciliation of that
\n
obligation with the actuarial liability.
\n

\n\n\n\n\n\n
Millions of euro 2023 2022
\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
\n
obligation previous year
\n
Actuarial obligation at the
\n
start of the year
\n
3,765 224 162 118 4,269 4,240 410 206 190 5,046
\n
Current service cost 9 1 3 (1) 12 13 1 5 13 32
\n
Interest expense 336 8 9 4 357 320 7 8 5 340
\n
Actuarial (gains)/losses arising
\n
from changes in demographic
\n
assumptions
\n
- - - 2 2 - - - - -
\n
Actuarial (gains)/losses arising
\n
from changes in financial
\n
assumptions
\n
224 8 6 3 241 (533) (93) (38) (18) (682)
\n
Experience adjustments (43) (12) 6 1 (48) 119 (80) 8 1 48
\n
Past service cost - - - - - (3) - - - (3)
\n
(Gains)/Losses arising from
\n
settlements
\n
- - - - - (163) - - - (163)
\n
Exchange differences 145 1 4 (4) 146 335 - 6 (1) 340
\n
Employer contributions - - - - - - - - - -
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (393) (14) (14) (17) (438) (470) (15) (13) (44) (542)
\n
Other changes - - - - - - - - (6) (6)
\n
Reclassification to assets 41 - - - 41 8 - - - 8
\n
Liabilities included in disposal
\n
groups classified as held for
\n
sale
\n
1 - - (4) (3) (101) (6) (20) (22) (149)
\n
Actuarial obligation at year-
\n
end (A)
\n
4,085 216 176 102 4,579 3,765 224 162 118 4,269
\n
CHANGES IN PLAN ASSETS
\n
Fair value of plan assets at
\n
the start of the year
\n
2,124 - - - 2,124 2,348 - - - 2,348
\n
Interest income 200 - - - 200 193 - - - 193
\n
Expected return on plan
\n
assets excluding amounts
\n
included in interest income
\n
(52) - - - (52) (184) - - - (184)
\n
Exchange differences 89 - - - 89 213 - - - 213
\n
Employer contributions 331 14 14 11 370 286 15 13 22 336
\n
Employee contributions - - - - - - - - - -
\n
Benefits paid (393) (14) (14) (11) (432) (470) (15) (13) (22) (520)
\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
2,299 - - - 2,299 2,124 - - - 2,124
\n
EFFECT OF ASSET CEILING
\n
Asset ceiling at the start of
\n
the year
\n
57 - - - 57 26 - - - 26
\n
Interest income 6 - - - 6 2 - - - 2
\n
Changes in asset ceiling (26) - - - (26) 27 - - - 27
\n
Exchange differences 3 - - - 3 2 - - - 2
\n
Changes in the consolidation
\n
scope
\n
- - - - - - - - - -
\n
Asset ceiling at year-end (C) 40 - - - 40 57 - - - 57
\n
Net liability in statement of
\n
financial position (A-B+C)
\n
1,826 216 176
\n
102 2,320 1,698 224 162 118 2,202
\n

\n\n\n\n\n\n
The liability recognized came to \u20ac2,320 million, an in-
\n
crease of \u20ac118 million on 2022 mainly reflecting impair-
\n
ment losses recognized in reflection of a change in the
\n
financial assumptions following the general adverse devel-
\n
opments in rates (discount and inflation rates). In addition
\n
to normal annual changes, in 2023, the actuarial liabilities
\n
of Enel Generaci\u00f3n Per\u00fa SAA and Enel Distribuci\u00f3n Per\u00fa
\n
SAA in Peru were reclassified as held for sale. Furthermore,
\n
the actuarial measurement of a plan of Asociaci\u00f3n Nucle-
\n
ar Asc\u00f3-Vandell\u00f3s II AIE, in Spain, showed a surplus with
\n
respect to the obligation assumed by the company, and
\n
was thus reclassified in a specific asset item of the balance
\n
sheet.
\n
Millions of euro
\n
2023 2022
\n
(Gains)/Losses taken to profit or loss
\n
Service cost and past service cost 17 22
\n
Net interest expense 163 149
\n
(Gains)/Losses arising from settlements - -
\n
Actuarial (gains)/losses on other long-term benefits (5) 7
\n
Other changes 5 (20)
\n
Total 180 158
\n
Millions of euro
\n
2023 2022
\n
Change in (gains)/losses in OCI
\n
Expected return on plan assets excluding amounts included in interest
\n
income
\n
52 184
\n
Actuarial (gains)/losses on defined benefit plans 190 (614)
\n
Changes in asset ceiling excluding amounts included in interest income (26) 27
\n
Other changes 1 -
\n
Total 217 (403)
\n
The change in the cost recognized in profit or loss was
\n
equal to \u20ac22 million. The impact on the income statement
\n
is, therefore, greater but essentially in line with 2022.
\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 of
\n
plan assets, amounting to \u20ac2,299 million at December 31,
\n
2023. The item \u201cactuarial (gains)/losses on defined benefit
\n
plans\u201d shows an increase on 2022, following the decrease
\n
in interest rates, compared to the strong increase in 2022.
\n
Those assets, which are entirely in Spain and Brazil, break
\n
down as follows.
\n
% 2023 2022
\n
Investments quoted in active markets
\n
Equity instruments 4 10
\n
Fixed-income securities 73 66
\n
Investment property 3 3
\n
Other 20 21
\n
Unquoted investments
\n
Assets held by insurance undertakings - -
\n
Other - -
\n
Total 100 100
\n
The main actuarial assumptions used to calculate the li-
\n
abilities in respect of employee benefits and the plan as-
\n
sets, which are consistent with those used the previous
\n
year, are set out in the following table.
\n

\n\n\n\n\n\n
Italy Iberia
\n
Latin
\n
America
\n
Other
\n
countries Italy Iberia
\n
Latin
\n
America
\n
Other
\n
countries
\n
2023 2022
\n
Discount rate 3.30%-3.40% 3.14%-3.47% 5.31%-10.09% 7.20% 3.60%-3.70% 3.57%-3.77% 5.40%-10.40% 3.75%-7.65%
\n
Inflation rate 2.30% 2.57% 3.00%-7.58% 2.30% 2.78% 3.00%-8.00% 2.40%-3.50%
\n
Rate of wage increases 2.30%-4.30% 2.57% 4.55%-10.00% 10.00% 2.30%-4.30% 2.78% 3.80%-8.49% 3.00%-10.00%
\n
Rate of increase in
\n
healthcare costs
\n
3.30% 4.77% 7.63%-10.00% 3.30% 4.98% 7.12%-10.00% -
\n
Expected rate of return on
\n
plan assets
\n
- 3.22%-3.31% 9.99%-10.09% - 3.76%-3.77% 10.40% 7.40%
\n
The following table reports the outcome of a sensitivi-
\n
ty analysis that demonstrates the effects on the defined
\n
benefit obligation of changes reasonably possible at the
\n
end of the year in the actuarial assumptions used in esti-
\n
mating the obligation.
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits
\n
Pension
\n
benefits
\n
Electricity
\n
discount
\n
Health
\n
insurance
\n
Other
\n
benefits
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Decrease of 0.5% in
\n
discount rate
\n
147 8 5 (6) 185 2 6 (17)
\n
Increase of 0.5% in
\n
discount rate
\n
(188) (14) (9) (12) (118) (22) (9) (23)
\n
Increase of 0.5% in inflation
\n
rate
\n
(49) (4) (9) (12) 16 (11) (8) (21)
\n
Decrease of 0.5% in
\n
inflation rate
\n
(30) (4) 5 (6) 37 (10) 6 (16)
\n
Increase of 0.5% in
\n
remuneration
\n
(28) (4) (19) 18 29 (10) (2) (17)
\n
Increase of 0.5% in
\n
pensions currently being
\n
paid
\n
(28) (4) (19) 11 28 (10) (2) (20)
\n
Increase of 1% in
\n
healthcare costs
\n
- - (164) - - - (147) -
\n
Increase of 1 year in life
\n
expectancy of active and
\n
retired employees
\n
16 2 (15) 12 55 (9) 5 (17)
\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 \u20ac243 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, 2023 at Dec. 31, 2022
\n
Within 1 year 447 427
\n
In 1-2 years 407 397
\n
In 2-5 years 1,120 1,124
\n
More than 5 years 1,739 1,826
\n

\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag12": { "value": "\n
40. Provisions for risks and charges \u2013 \u20ac7,312 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Non-current Current Total Non-current Current Total
\n
Provision for litigation, risks and other
\n
charges:
\n
- nuclear decommissioning 571 - 571 581 - 581
\n
- site retirement, removal and restoration 2,517 160 2,677 2,686 247 2,933
\n
- litigation 663 39 702 652 51 703
\n
- environmental certificates - 250 250 - 292 292
\n
- taxes and duties 295 19 314 313 26 339
\n
- other 1,053 425 1,478 803 316 1,119
\n
Total 5,099 893 5,992 5,035 932 5,967
\n
Provision for early retirement incentives and
\n
other restructuring plans
\n
154 128 282 231 192 423
\n
Provision for restructuring programs
\n
connected with the energy transition
\n
765 273 1,038 789 201 990
\n
TOTAL 6,018 1,294 7,312 6,055 1,325 7,380
\n
Millions of euro Accrual Reversal Utilization Discounting
\n
Provisions
\n
for site
\n
retirement
\n
and
\n
restoration
\n
Change in the
\n
consolidation
\n
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.
\n
31, 2022
\n
at Dec.
\n
31, 2023
\n
Provision for
\n
litigation, risks and
\n
other charges:
\n
- nuclear
\n
decommissioning
\n
581 - - - 17 (27) - - - - 571
\n
- site retirement
\n
removal and
\n
restoration
\n
2,933 47 (47) (161) - (15) - (10) (37) (33) 2,677
\n
- litigation 703 188 (105) (118) 36 - - 6 - (8) 702
\n
- environmental
\n
certificates
\n
292 241 - (313) - - - - 30 - 250
\n
- taxes and duties 339 18 (19) (40) 6 - - 2 9 (1) 314
\n
- other 1,119 519 (24) (151) 1 5 - (8) 18 (1) 1 ,478
\n
Total 5,967 1,013 (195) (783) 60 (37) - (10) 20 (43) 5,992
\n
Provision for
\n
early retirement
\n
incentives and other
\n
restructuring plans
\n
423 28 (11) (174) 18 - - - (2) - 282
\n
Provision for
\n
restructuring
\n
programs connected
\n
with the energy
\n
transition
\n
990 209 (6) (184) 35 - - - (6) - 1,038
\n
TOTAL 7,380 1,250 (212) (1,141) 113 (37) - (10) 12 (43) 7,312
\n
Nuclear decommissioning provision
\n
At December 31, 2023 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, which regulates the retirement
\n
and closing of nuclear power plants. The time horizon en-
\n
visaged, three years, corresponds to the period from the
\n
termination of power generation to the transfer of plant
\n
management to Enresa (so-called post-operational costs)
\n
and takes account, among the various assumptions used
\n
to estimate the amount, of the quantity of unused nuclear
\n
fuel expected at the date of closure of each of the Spanish
\n
nuclear plants on the basis of the provisions of the con-
\n
cession agreement.
\n

\n\n\n

\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 2023
\n
was mainly linked to the uses and releases of provisions
\n
set aside in previous years to deal with the decarboniza-
\n
tion process, mainly in Italy, Spain and Chile.
\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 276 258
\n
In 1-5 years 1,147 1,045
\n
More than 5 years 2,636 1 ,374
\n
Total 4,059 2,677
\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 (\u20ac396 million), Spain (\u20ac158
\n
million) and Italy (\u20ac116 million).
\n
The amount is virtually unchanged compared with 2022, as
\n
the decrease associated with higher uses and releases in
\n
Brazil was offset by new accruals.
\n
Provision for environmental certificates
\n
The provision for environmental certificates covers costs
\n
in respect of shortfalls in the environmental certificates
\n
need for compliance with national or supranational en-
\n
vironmental protection requirements and mainly regards
\n
Iberia (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
\n
for current and potential disputes concerning local prop-
\n
erty tax (whether the Imposta Comunale sugli Immobili -
\n
ICI or the Imposta Municipale Unica - IMU) in Italy. In Italy,
\n
the 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 increase of \u20ac342 million in other provisions is mainly
\n
attributable to Enel Reinsurance for accruals of provisions
\n
for insurance claims (\u20ac217 million) and provisions for regu-
\n
latory measures, atmospheric events and faults.
\n

\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 \u20ac141 million for the year mainly
\n
reflects uses of provisions for incentives established in
\n
previous period in Spain and Italy to cover the early termi-
\n
nation of employment for certain 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
\n
in the roles and skills of employees, which the Group in-
\n
tends to implement with highly sustainable plans based
\n
on redeployment programs, with major upskilling and
\n
reskilling plans and voluntary individual early retirement
\n

\n\n\n
agreements. The energy transition is also based on the
\n
progressive and expansive development of digital tools, as
\n
digitization is essential to responding to multiple external
\n
forces and making informed and well-considered deci-
\n
sions at every level within the Group.
\n
A provision was therefore established in 2020 for restruc-
\n
turing programs, which at December 31, 2023 amounted
\n
to \u20ac1,038 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 tran-
\n
sition, for all direct and indirect activities related to the
\n
review of processes and operating models and the roles
\n
and skills of employees. New accruals in 2023 mainly re-
\n
gard Spain following the adjustment of \u20ac177 million to the
\n
provision for the Acuerdo Voluntario de Salida (AVS) plan.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag13": { "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 increase of \u20ac342 million in other provisions is mainly
\n
attributable to Enel Reinsurance for accruals of provisions
\n
for insurance claims (\u20ac217 million) and provisions for regu-
\n
latory measures, atmospheric events and faults.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag14": { "value": "\n
41. Other non-current financial liabilities \u2013 \u20ac8 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Other non-current financial liabilities 8 - 8 -
\n
Total 8 - 8 -
\n
The change in \u201cother non-current financial liabilities\u201d came
\n
to \u20ac8 million and regards the recognition of non-current
\n
financial liabilities in respect of the Spanish electrical sys-
\n
tem deficit, which were included in net financial debt.
\n
\n\n
45. Other current financial liabilities \u2013 \u20ac909 million
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Accrued financial expense and deferred financial income 734 710 24 3.4%
\n
Other current financial liabilities included in net financial debt 1 - 1 -
\n
Other liabilities 174 143 31 21.7%
\n
Total 909 853 56 6.6%
\n
The increase in other current financial liabilities is mainly
\n
attributable to the increase in accrued financial expense.
\n
The item also includes current financial liabilities in re-
\n
spect of the deficit of the Spanish electrical system in the
\n
amount of \u20ac1 million included in net financial debt.
\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Financial liabilities measured at amortized cost 48.2.1 61,734 68,432 39,784 45,697
\n
Financial liabilities at fair value through profit or loss
\n
Derivative financial liabilities at FVTPL 48.4 204 588 4,485 11,642
\n
Total financial liabilities at fair value through profit or loss 204 588 4,485 11,642
\n
Derivative financial liabilities designated as hedging instruments
\n
Fair value hedge derivatives 48.4 105 191 17 -
\n
Cash flow hedge derivatives 48.4 3,064 5,116 1,959 4,499
\n
Total derivative financial liabilities designated as hedging
\n
instruments
\n
3,169 5,307 1,976 4,499
\n
TOTAL 65,107 74,327 46,245 61,838
\n
For more information on fair value measurement, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\n

\n\n\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Long-term borrowings 48.3 61,085 68,191 48.3 9,086 2,835
\n
Short-term borrowings - - 48.3 4,769 18,392
\n
Trade payables 44 334 36 44 15,487 17,605
\n
Other financial liabilities 315 205 10,442 6,865
\n
Total 61,734 68,432 39,784 45,697
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag15": { "value": "\n
\n\n
\n\n
\n
42. Other non-current liabilities \u2013 \u20ac4,236 million
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Accrued operating expenses and deferred income 464 347 117 33.7%
\n
Liabilities with equalization funds/market and energy services operators 307 205 102 49.8%
\n
Liabilities for tax partnerships > 12 months 1,262 1,322 (60) -4.5%
\n
Sundry non-current payments on account 348 - 348 -
\n
Other items 1,855 2,372 (517) -21.8%
\n
Total 4,236 4,246 (10) -0.2%
\n
\n\n
The change in \u201cother items\u201d reflected the decrease in
\n
\u201cother liabilities\u201d mainly relating to the outcome of the PIS/
\n
COFINS dispute in Brazil (already discussed under \u201cOther
\n
non-current assets\u201d) in the amount of \u20ac401 million. The
\n
item \u201csundry non-current payments on account\u201d reports
\n
the collection by e-distribuzione of \u20ac348 million in respect
\n
of the 10% advance payment of the grant for 24 projects
\n
awarded NRRP subsidies.
\n
\n\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag16": { "value": "\n
\n\n
\n
42. Other non-current liabilities \u2013 \u20ac4,236 million
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Accrued operating expenses and deferred income 464 347 117 33.7%
\n
Liabilities with equalization funds/market and energy services operators 307 205 102 49.8%
\n
Liabilities for tax partnerships > 12 months 1,262 1,322 (60) -4.5%
\n
Sundry non-current payments on account 348 - 348 -
\n
Other items 1,855 2,372 (517) -21.8%
\n
Total 4,236 4,246 (10) -0.2%
\n
\n\n
The change in \u201cother items\u201d reflected the decrease in
\n
\u201cother liabilities\u201d mainly relating to the outcome of the PIS/
\n
COFINS dispute in Brazil (already discussed under \u201cOther
\n
non-current assets\u201d) in the amount of \u20ac401 million. The
\n
item \u201csundry non-current payments on account\u201d reports
\n
the collection by e-distribuzione of \u20ac348 million in respect
\n
of the 10% advance payment of the grant for 24 projects
\n
awarded NRRP subsidies.
\n
\n\n
\n\n
\n\n
\n
43. Other current liabilities \u2013 \u20ac14,760 million
\n\n
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
The change in \u201cother current liabilities\u201d mainly reflects:
\n
\u2022
\n
the decrease in \u201camounts due to customers\u201d, which
\n
mainly reports the change in security deposits from cus-
\n
tomers in Italy in line with the decrease in the number
\n
of customers served by market companies, offset by the
\n
increase in trade receivables following the restoration of
\n
distribution system costs. In Italy, the item also includes
\n
the decrease in various sundry amounts due to custom-
\n
ers, mainly for the amounts relating to VAT recovery on
\n
uncollected receivables, amounts available to customers
\n
and refunds to be made, on behalf of the distribution
\n
companies, to customers moved from the regulated
\n
market to the free market for exceeding rate limits in
\n
previous years. The decrease was offset by the increase,
\n
in the distribution segment, in amounts collected and in
\n
processing and in liabilities for indemnities;
\n
\u2022
\n
the increase in \u201camounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, and in particular
\n
e-distribuzione SpA, for the progressive restoration, in
\n
2023, of charges relating to the support of renewable
\n
energy and cogeneration, and of other charges (Asos
\n
and Arim components) determined in ARERA Resolu-
\n
tions nos. 735/2022, 134/2023, 297/2023 and 419/2023,
\n
and Spain, in particular Edistribuci\u00f3n Redes Digitales, for
\n
an increase in amounts due to the local regulator Comis-
\n
i\u00f3n Nacional de los Mercados y la Competencia (CNMC);
\n
\u2022
\n
the increase in liabilities for \u201cdividends\u201d to be distributed
\n
to shareholders, essentially those of the Parent Company
\n
Enel SpA and the Spanish subsidiary Endesa SA;
\n
\u2022
\n
the increase in liabilities in respect of derivatives to be
\n
settled on energy commodities in Italy;
\n
\u2022
\n
the decrease in \u201cother liabilities\u201d, mainly attributable to a
\n
decline in liabilities in Spain and Brazil.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag17": { "value": "\n
\n
42. Other non-current liabilities \u2013 \u20ac4,236 million
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Accrued operating expenses and deferred income 464 347 117 33.7%
\n
Liabilities with equalization funds/market and energy services operators 307 205 102 49.8%
\n
Liabilities for tax partnerships > 12 months 1,262 1,322 (60) -4.5%
\n
Sundry non-current payments on account 348 - 348 -
\n
Other items 1,855 2,372 (517) -21.8%
\n
Total 4,236 4,246 (10) -0.2%
\n
\n\n
The change in \u201cother items\u201d reflected the decrease in
\n
\u201cother liabilities\u201d mainly relating to the outcome of the PIS/
\n
COFINS dispute in Brazil (already discussed under \u201cOther
\n
non-current assets\u201d) in the amount of \u20ac401 million. The
\n
item \u201csundry non-current payments on account\u201d reports
\n
the collection by e-distribuzione of \u20ac348 million in respect
\n
of the 10% advance payment of the grant for 24 projects
\n
awarded NRRP subsidies.
\n
\n\n
\n
43. Other current liabilities \u2013 \u20ac14,760 million
\n\n
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n\n
\n\n
\n\n
\n\n
The change in \u201cother current liabilities\u201d mainly reflects:
\n
\u2022
\n
the decrease in \u201camounts due to customers\u201d, which
\n
mainly reports the change in security deposits from cus-
\n
tomers in Italy in line with the decrease in the number
\n
of customers served by market companies, offset by the
\n
increase in trade receivables following the restoration of
\n
distribution system costs. In Italy, the item also includes
\n
the decrease in various sundry amounts due to custom-
\n
ers, mainly for the amounts relating to VAT recovery on
\n
uncollected receivables, amounts available to customers
\n
and refunds to be made, on behalf of the distribution
\n
companies, to customers moved from the regulated
\n
market to the free market for exceeding rate limits in
\n
previous years. The decrease was offset by the increase,
\n
in the distribution segment, in amounts collected and in
\n
processing and in liabilities for indemnities;
\n
\u2022
\n
the increase in \u201camounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, and in particular
\n
e-distribuzione SpA, for the progressive restoration, in
\n
2023, of charges relating to the support of renewable
\n
energy and cogeneration, and of other charges (Asos
\n
and Arim components) determined in ARERA Resolu-
\n
tions nos. 735/2022, 134/2023, 297/2023 and 419/2023,
\n
and Spain, in particular Edistribuci\u00f3n Redes Digitales, for
\n
an increase in amounts due to the local regulator Comis-
\n
i\u00f3n Nacional de los Mercados y la Competencia (CNMC);
\n
\u2022
\n
the increase in liabilities for \u201cdividends\u201d to be distributed
\n
to shareholders, essentially those of the Parent Company
\n
Enel SpA and the Spanish subsidiary Endesa SA;
\n
\u2022
\n
the increase in liabilities in respect of derivatives to be
\n
settled on energy commodities in Italy;
\n
\u2022
\n
the decrease in \u201cother liabilities\u201d, mainly attributable to a
\n
decline in liabilities in Spain and Brazil.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag18": { "value": "\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Accrued operating expenses and deferred income 464 347 117 33.7%
\n
Liabilities with equalization funds/market and energy services operators 307 205 102 49.8%
\n
Liabilities for tax partnerships > 12 months 1,262 1,322 (60) -4.5%
\n
Sundry non-current payments on account 348 - 348 -
\n
Other items 1,855 2,372 (517) -21.8%
\n
Total 4,236 4,246 (10) -0.2%
\n
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag19": { "value": "\n
\n\n
\n\n
\n
43. Other current liabilities \u2013 \u20ac14,760 million
\n\n
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
\n\n
The change in \u201cother current liabilities\u201d mainly reflects:
\n
\u2022
\n
the decrease in \u201camounts due to customers\u201d, which
\n
mainly reports the change in security deposits from cus-
\n
tomers in Italy in line with the decrease in the number
\n
of customers served by market companies, offset by the
\n
increase in trade receivables following the restoration of
\n
distribution system costs. In Italy, the item also includes
\n
the decrease in various sundry amounts due to custom-
\n
ers, mainly for the amounts relating to VAT recovery on
\n
uncollected receivables, amounts available to customers
\n
and refunds to be made, on behalf of the distribution
\n
companies, to customers moved from the regulated
\n
market to the free market for exceeding rate limits in
\n
previous years. The decrease was offset by the increase,
\n
in the distribution segment, in amounts collected and in
\n
processing and in liabilities for indemnities;
\n
\u2022
\n
the increase in \u201camounts due to institutional market
\n
operators\u201d, mainly attributable to Italy, and in particular
\n
e-distribuzione SpA, for the progressive restoration, in
\n
2023, of charges relating to the support of renewable
\n
energy and cogeneration, and of other charges (Asos
\n
and Arim components) determined in ARERA Resolu-
\n
tions nos. 735/2022, 134/2023, 297/2023 and 419/2023,
\n
and Spain, in particular Edistribuci\u00f3n Redes Digitales, for
\n
an increase in amounts due to the local regulator Comis-
\n
i\u00f3n Nacional de los Mercados y la Competencia (CNMC);
\n
\u2022
\n
the increase in liabilities for \u201cdividends\u201d to be distributed
\n
to shareholders, essentially those of the Parent Company
\n
Enel SpA and the Spanish subsidiary Endesa SA;
\n
\u2022
\n
the increase in liabilities in respect of derivatives to be
\n
settled on energy commodities in Italy;
\n
\u2022
\n
the decrease in \u201cother liabilities\u201d, mainly attributable to a
\n
decline in liabilities in Spain and Brazil.
\n
\n\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag20": { "value": "\n
\n\n
\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Amounts due to customers 1,882 2,094 (212) -10.1%
\n
Amounts due to institutional market operators 5,479 2,115 3,364 -
\n
Amounts due to employees 503 519 (16) -3.1%
\n
Other tax liabilities 1,034 1,046 (12) -1.1%
\n
Amounts due to social security institutions 235 215 20 9.3%
\n
Current accrued expenses and deferred income 314 441 (127) -28.8%
\n
Liabilities for closed energy commodity derivatives 437 285 152 53.3%
\n
Dividends 2,470 2,228 242 10.9%
\n
Liabilities for tax partnerships < 12 months 271 241 30 12.4%
\n
Sundry current payments on account 144 201 (57) -28.4%
\n
Other liabilities 1,991 2,328 (337) -14.5%
\n
Total 14,760 11,713 3,047 26.0%
\n
\n\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDepositsFromCustomersExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag21": { "value": "\n
44. Trade payables \u2013 \u20ac15,821 million
\n
The item amounted to \u20ac15,821 million (\u20ac17,641 million at
\n
December 31, 2022) 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 \u20ac15,487 million (\u20ac17,605 million at
\n
December 31, 2022) while those falling due in more than
\n
12 months amounted to \u20ac334 million (\u20ac36 million at De-
\n
cember 31, 2022).
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag930": { "value": "\n
46. Cash flows
\n
Millions of euro
\n
2023 2022 Change
\n
Cash and cash equivalents at the beginning of the year
\n
(1)
\n
11,543 8,990 2,553
\n
Cash flows from operating activities
\n
(2)
\n
14,620 8,649 5,971
\n
of which discontinued operations 132 (391)
\n
Cash flows from/(used in) investing activities (10,610) (13,626) 3,016
\n
of which discontinued operations (442) (351)
\n
Cash flows from financing activities
\n
(2)
\n
(8,361) 7,3 9 4 (15,755)
\n
of which discontinued operations (16) 656
\n
Impact of exchange rate fluctuations on cash and cash equivalents (49) 136 (185)
\n
Cash and cash equivalents at the end of the year
\n
(3)
\n
7, 143 11,543 (4,400)
\n
(1) Of which cash and cash equivalents equal to \u20ac11,041 million at January 1, 2023 (\u20ac8,315 million at January 1, 2022), short-term securities equal to \u20ac78 million
\n
at January 1, 2023 (\u20ac88 million at January 1, 2022), cash and cash equivalents pertaining to \u201cAssets classified as held for sale\u201d in the amount of \u20ac98 million
\n
at January 1, 2023 (\u20ac44 million at January 1, 2022) and cash and cash equivalents pertaining to \u201cDiscontinued operations\u201d equal to \u20ac326 million at January
\n
1, 2023 (\u20ac543 million at January 1, 2022).
\n
(2) In order to improve presentation, for comparative purposes only, realized financial income and expense connected solely with borrowings have been re-
\n
classified from \u201cCollections/(Payments) associated with derivatives connected with borrowings\u201d in the section on cash flows from financing activities to the
\n
items \u201cInterest income and other financial income collected\u201d and \u201cInterest expense and other financial expense paid\u201d
\n
\n
included in cash flows from operating
\n
activities.
\n
(3) Of which cash and cash equivalents equal to \u20ac6,801 million at December 31, 2023 (\u20ac11,041 million at December 31, 2022), short-term securities equal to
\n
\u20ac81 million at December 31, 2023 (\u20ac78 million at December 31, 2022), cash and cash equivalents pertaining to \u201cAssets classified as held for sale\u201d in the
\n
amount of \u20ac261 million at December 31, 2023 (\u20ac98 million at December 31, 2022) and cash and cash equivalents pertaining to \u201cDiscontinued operations\u201d
\n
equal to \u20ac326 million at December 31, 2022.
\n
Cash flows from operating activities in 2023 was a posi-
\n
tive \u20ac14,620 million, an increase of \u20ac5,971 million on 2022,
\n
mainly attributable to lower cash requirements connected
\n
with changes in net working capital.
\n
Cash flows used in investing activities in 2023 came to
\n
\u20ac10,610 million, from \u20ac13,626 million in 2022.
\n
More specifically, investments in property, plant and
\n
equipment, intangibles, property investment and contract
\n
assets came to \u20ac13,563 million (including \u20ac849 million
\n
classified as available for sale), a decrease on 2022.
\n
Investments in companies or business units, net of cash
\n
and cash equivalents acquired, amount to \u20ac17 million (in
\n
2022 they came to \u20ac1,275 million and mainly referred to
\n
the acquisition by Enel Produzione SpA of 100% of ERG
\n
Hydro Srl (now Enel Hydro Appennino Centrale Srl), for
\n
a consideration of \u20ac1,196 million net of cash and cash
\n
equivalents acquired of \u20ac69 million.
\n
Disposals of businesses or business units, net of cash and
\n
cash equivalents sold, amount to \u20ac2,083 million and main-
\n
ly refer to:
\n
\u2022
\n
the sale by Enel Argentina of the entire stake held in
\n
Enel Generaci\u00f3n Costanera for \u20ac28 million, net of cash
\n
and cash equivalents sold of \u20ac14 million;
\n
\u2022
\n
the sale by Enel Green Power India Private Limited of
\n
the entire stake held in Khidrat Renewable Energy Pri-
\n
vate Limited for \u20ac4 million;
\n
\u2022
\n
the sale to YPF and Pan American Sur SA of the stakes
\n
held in Inversora Dock Sud SA and Central Dock Sud SA,
\n
for a total amount of about \u20ac29 million, net of cash and
\n
cash equivalents sold of \u20ac19 million;
\n
\u2022
\n
the sale of 80% of the stake held in the Colombian bus
\n
company Colombia ZE SAS for about \u20ac6 million;
\n
\u2022
\n
the sale of 50% of the two companies holding all the
\n
Group assets dedicated to renewables in Australia,
\n
more specifically Enel Green Power Australia (Pty) Ltd
\n
and Enel Green Power Australia Trust, to INPEX Corpo-
\n
ration, for a total amount of \u20ac121 million, net of cash
\n
and cash equivalents sold of \u20ac21 million;
\n
\u2022
\n
the sale of the stakes held in Romania for a total amount
\n
of \u20ac1,013 million, net of cash and cash equivalents sold
\n
of \u20ac228 million;
\n
\u2022
\n
the sale of the interest held in Transmisora de Energ\u00eda
\n
Renovable, in Guatemala, for a total of \u20ac22 million, net
\n
of cash and cash equivalents sold of \u20ac11 million;
\n
\u2022
\n
the sale to Sonnedix of the interest held by Enel Chile in
\n
Arcadia Generaci\u00f3n Solar SA, for a total of \u20ac533 million,
\n
net of cash and cash equivalents sold of \u20ac2 million;
\n
\u2022
\n
the sale of 50% of Enel Green Power Hellas, Enel Green
\n
Power wholly-owned subsidiary dedicated to renew-
\n
ables in Greece, to Macquarie Asset Management, for
\n
a total of \u20ac322 million, net of cash and cash equivalents
\n
sold of \u20ac29 million.
\n

\n\n\n
Cash flows from/(used in) other investing activities in 2023
\n
came to \u20ac474 million and mainly reflects:
\n
\u2022
\n
the sale of the entire stake held in Tecnatom SA for a
\n
total of \u20ac26 million. The transaction had no impact on
\n
profit or loss;
\n
\u2022
\n
the sale of the stake held in Rusenergosbyt LLC for \u20ac83
\n
million;
\n
\u2022
\n
minor disposals mainly in Italy, Iberia, North America and
\n
Latin America.
\n
Cash flows from financing activities came to a negative
\n
\u20ac8,361 million, compared with a positive \u20ac7,394 million in
\n
2022, mainly reflecting:
\n
\u2022
\n
the change in net financial debt (as the balance be-
\n
tween repayments, new borrowings and other changes)
\n
of \u20ac3,985 million;
\n
\u2022
\n
distribution of dividends in the amount of \u20ac5,135 mil-
\n
lion, plus \u20ac182 million paid to holders of perpetual hy-
\n
brid bonds;
\n
\u2022
\n
the issue of hybrid bonds in the amount of \u20ac986 million;
\n
\u2022
\n
capital increases in subsidiaries with no change in con-
\n
trol in the amount of \u20ac25 million, particularly in Australia.
\n
In 2023, cash flow used in investing activities of \u20ac10,610
\n
million and financing activities of \u20ac8,361 million fully ab-
\n
sorbed the cash flows from operating activities in the
\n
amount of \u20ac14,620 million. The difference is reflected in
\n
a decrease in cash and cash equivalents, which at De-
\n
cember 31, 2023 came to \u20ac7,143 million, from \u20ac11,543
\n
million at the end of 2022. The change was also affected
\n
by effects associated with negative developments in the
\n
exchange rates of local currencies against the euro, in the
\n
amount of \u20ac49 million.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag931": { "value": "\n
47. Net financial position and long-term financial assets and securities \u2013 \u20ac60,163 million
\n
The following table shows the net financial position and
\n
long-term financial assets and securities on the basis of the
\n
items on the statement of consolidated financial position.
\n
Millions of euro
\n
Notes at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Long-term borrowings 38 61,085 68,191 (7,106) -10.4%
\n
Other non-current financial borrowings
\n
(1)
\n
41 8 - 8 -
\n
Short-term borrowings 38 4,769 18,392 (13,623) -74. 1%
\n
Other current financial borrowings
\n
(2)
\n
1 - 1 -
\n
Current portion of long-term borrowings 38 9,086 2,835 6,251 -
\n
Other non-current financial assets included in net financial debt 29.1 (3,837) (4,213) 376 8.9%
\n
Other current financial assets included in net financial debt 30.1 (4,148) (13,501) 9,353 69.3%
\n
Cash and cash equivalents 35 (6,801) (11,041) 4,240 38.4%
\n
Total
\n
(3)
\n
60,163 60,663 (500) -0.8%
\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, 2022 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\n
The financial position is reported in compliance with
\n
Guideline 39, issued on March 4, 2021 by ESMA and ap-
\n
plicable as from May 5, 2021, and with warning notice
\n
no. 5/2021 issued by CONSOB on April 29, 2021, which
\n
replaced the references to the CESR Recommendations
\n
and the references in Communication no. DEM/6064293
\n
of July 28, 2006 regarding the net financial position.
\n
The net financial debt of the Enel Group at December 31,
\n
2023 and December 31, 2022 is reconciled with net finan-
\n
cial debt as provided for in the presentation methods of
\n
the Enel Group.
\n

\n\n\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Liquidity
\n
Cash and cash equivalents on hand 23 35 (12) -34.3%
\n
Bank and post office deposits 4,664 8,968 (4,304) -48.0%
\n
Liquid assets 4,687 9,003 (4,316) -47.9%
\n
Cash equivalents 2,114 2,038 76 3.7%
\n
Securities 81 78 3 3.8%
\n
Short-term loan assets 3,060 10,585 (7,525) -71.1%
\n
Current portion of long-term loan assets 1,007 2,838 (1,831) -64.5%
\n
Other current financial assets 4,148 13,501 (9,353) -69.3%
\n
Liquidity 10,949 24,542 (13,593) -55.4%
\n
Current financial debt
\n
Bank debt (393) (1,320) 927 70.2%
\n
Commercial paper (2,499) (13,838) 11,339 81.9%
\n
Other short-term borrowings
\n
(1)
\n
(1,878) (3,234) 1,356 41.9%
\n
Current financial debt (including debt instruments) (4,770) (18,392) 13,622 74.1%
\n
Current portion of long-term bank borrowings (1,992) (890) (1,102) -
\n
Bonds issued (current portion) (6,763) (1,612) (5,151) -
\n
Other borrowings (current portion) (331) (333) 2 0.6%
\n
Non-current financial debt (current portion) (9,086) (2,835) (6,251) -
\n
Current financial debt (13,856) (21,227) 7,371 34.7%
\n
Net current financial debt (2,907) 3,315 (6,222) -
\n
Non-current financial debt
\n
Bank borrowings (14,500) (15,261) 761 5.0%
\n
Other borrowings
\n
(2)
\n
(3,014) (2,851) (163) -5.7%
\n
Non-current financial debt (excluding current portion and debt
\n
instruments)
\n
(17,514) (18,112) 598 3.3%
\n
Bonds (43,579) (50,079) 6,500 13.0%
\n
Trade payables and other non-interest-bearing non-current liabilities with
\n
a significant financing component
\n
- - - -
\n
Non-current financial position (61,093) (68,191) 7,09 8 10.4%
\n
Financial assets in respect of \u201cAssets classified as held for sale\u201d 262 543 (281) -51.7%
\n
Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
(1,150) (1,435) 285 19.9%
\n
Net financial position as per CONSOB instructions (64,888) (65,768) 880 1.3%
\n
Long-term financial receivables and securities 3,837 4,213 (376) -8.9%
\n
( - ) Financial assets in respect of \u201cAssets classified as held for sale\u201c (262) (543) 281 51.7%
\n
( - ) Financial liabilities in respect of \u201cLiabilities included in disposal groups
\n
classified as held for sale\u201c
\n
1,150 1,435 (285) -19.9%
\n
NET FINANCIAL DEBT
\n
(3)
\n
(60,163) (60,663) 500 0.8%
\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, 2022 in accordance with the new
\n
representation of net financial debt by the Enel Group.
\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, 2023 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 \u20ac2,383 million (\u20ac3,970
\n
million at December 31, 2022), \u201cCurrent financial derivative
\n
assets\u201d in the amount of \u20ac6,407 million (\u20ac14,830 million
\n
at December 31, 2022), \u201cNon-current financial derivative
\n
liabilities\u201d in the amount of \u20ac3,373 million (\u20ac5,895 million
\n
at December 31, 2022), and \u201cCurrent financial derivative
\n
liabilities\u201d in the amount of \u20ac6,461
\n
million (\u20ac16,141 million
\n
at December 31, 2022).
\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

\n\n\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Investments in other companies at FVOCI 29 338 360 - -
\n
Securities 29.1 505 447 30.1 81 78
\n
Receivables and other financial assets at FVOCI 39 94 - 201
\n
Total 882 901 81 279
\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, 2023 360 -
\n
Purchases - -
\n
Sales (7) -
\n
Changes in fair value through OCI (15) -
\n
Other changes - -
\n
Closing balance at Dec. 31, 2023 338 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2023 447 78
\n
Purchases 160 -
\n
Sales (14) (15)
\n
Changes in fair value through OCI 17 -
\n
Reclassifications (105) 105
\n
Other changes - (87)
\n
Closing balance at Dec. 31, 2023 505 81
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfDebtSecuritiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag932": { "value": "\n

\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

\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Financial assets measured at amortized cost 48.1.1 5,709 5,732 28,495 40,176
\n
Financial assets at FVOCI 48.1.2 882 901 81 279
\n
Financial assets at FVTPL
\n
Derivative financial assets at FVTPL 48.1.3 206 473 4,443 12,075
\n
Other financial assets at FVTPL 48.1.3 4,341 3,442 219 1,048
\n
Total financial assets at FVTPL 4,547 3,915 4,662 13,123
\n
Derivative financial assets designated as hedging instruments
\n
Fair value hedge derivatives 48.1.4 113 37 - -
\n
Cash flow hedge derivatives 48.1.4 2,064 3,460 1,964 2,755
\n
Total derivative financial assets designated as hedging instruments 2,177 3,497 1,964 2,755
\n
TOTAL 13,315 14,045 35,202 56,333
\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, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\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\n\n\n\n

\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Cash and cash equivalents - - 35 6,772 10,169
\n
Trade receivables 34 1,726 1,388 34 16,047 15, 217
\n
Current portion of long-term loan assets - - 30.1 1,007 2,838
\n
Cash collateral - - 30.1 2,899 8,319
\n
Other financial assets 29.1 3,332 3,767 30.1 30 2,090
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 310 295 29 14 12
\n
Other financial assets at amortized cost 341 282 1,726 1,531
\n
Total 5,709 5,732 28,495 40,176
\n

\n\n\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n

\n
Impairment of financial assets measured at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac34,202 million at December 31, 2023 (\u20ac45,788 million at
\n
December 31, 2022) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,098 million at De-
\n
cember 31, 2023 (\u20ac4,087 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
\n
cash and cash equivalents;
\n
\u2022
\n
trade receivables and contract assets;
\n
\u2022
\n
loan assets;
\n
\u2022
\n
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
\n
the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receiv-
\n
ables. This approach, based on an assessment of any
\n
significant increase in credit risk since initial recogni-
\n
tion, is performed comparing the PD at origination with
\n
PD at the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss
\n
allowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e. staging):
\n
\u2013
\n
12-month ECL, for financial assets for which there
\n
has not been a significant increase in credit risk
\n
since initial recognition;
\n
\u2013
\n
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
\n
the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a signifi-
\n
cant financing component, based on lifetime ECL with-
\n
out 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
\n
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
\n
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
\n
right to cash flows is legally or contractually extinguished,
\n
transferred or expired).
\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, 2023 at Dec. 31, 2022
\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 6,772 - 6,772 10,169 - 10,169
\n
Trade receivables 21,548 3,775 17,7 73 20,388 3,783 16,605
\n
Loan assets 7,579 311 7, 2 6 8 17, 2 6 2 248 17,014
\n
Other financial assets at amortized cost 2,403 12 2,391 2,176 56 2,120
\n
Total 38,302 4,098 34,204 49,995 4,087 45,908
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n
To measure expected losses, the Group assesses trade
\n
receivables and contract assets with the simplified ap-
\n
proach, both on an individual basis (e.g., government enti-
\n
ties, authorities, financial counterparties, wholesale sellers,
\n
traders and large companies, etc.) and a collective basis
\n
(e.g., retail 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
\n
risk characteristics and information on past due positions,
\n
considering a specific definition of default.
\n
Based on each business and local regulatory framework,
\n
as well as differences between customer portfolios, in-
\n
cluding their default and recovery rates (comprising ex-
\n
pectations for recovery beyond 90 days):
\n
\u2022
\n
the Group mainly defines a defaulted position as one
\n
that is 180 days past due. Accordingly, beyond this time
\n
limit, trade receivables are presumed to be credit im-
\n
paired); and
\n
\u2022
\n
specific clusters are defined on the basis of specific
\n
markets, business and risk characteristics.
\n
Contract assets substantially have the same risk charac-
\n
teristics as trade receivables for the same types of con-
\n
tracts.
\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
\n
PD, assumed equal to the average default rate, is calcu-
\n
lated by cluster and considering historical data from at
\n
least 24 months;
\n
\u2022
\n
LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022
\n
EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices
\n
issued but not past due and invoices to be issued.
\n
The following table reports changes in the allowance for
\n
expected credit losses on loan assets in accordance with
\n
the general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\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
Opening balance at Jan. 1, 2023 29 219
\n
Accruals - 36
\n
Uses - 11
\n
Reversals to profit or loss (32) (6)
\n
Other changes 45 9
\n
Closing balance at Dec. 31, 2023 42 269
\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, 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
Opening balance at Jan. 1, 2023 3,783
\n
Accruals 1,384
\n
Uses (1,136)
\n
Reversals to profit or loss (210)
\n
Other changes (46)
\n
Closing balance at Dec. 31, 2023 3,775
\n

\n\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 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, 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
Opening balance at Jan. 1, 2023 56
\n
Accruals 149
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (192)
\n
Closing balance at Dec. 31, 2023 12
\n

\n\n\n\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\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

\n\n\n\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Investments in other companies at FVOCI 29 338 360 - -
\n
Securities 29.1 505 447 30.1 81 78
\n
Receivables and other financial assets at FVOCI 39 94 - 201
\n
Total 882 901 81 279
\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, 2023 360 -
\n
Purchases - -
\n
Sales (7) -
\n
Changes in fair value through OCI (15) -
\n
Other changes - -
\n
Closing balance at Dec. 31, 2023 338 -
\n
Securities and other receivables at FVOCI
\n
Millions of euro Non-current Current
\n
Opening balance at Jan. 1, 2023 447 78
\n
Purchases 160 -
\n
Sales (14) (15)
\n
Changes in fair value through OCI 17 -
\n
Reclassifications (105) 105
\n
Other changes - (87)
\n
Closing balance at Dec. 31, 2023 505 81
\n

\n\n\n

\n\n\n

\n\n\n

\n

\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n\n

\n\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
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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Financial liabilities measured at amortized cost 48.2.1 61,734 68,432 39,784 45,697
\n
Financial liabilities at fair value through profit or loss
\n
Derivative financial liabilities at FVTPL 48.4 204 588 4,485 11,642
\n
Total financial liabilities at fair value through profit or loss 204 588 4,485 11,642
\n
Derivative financial liabilities designated as hedging instruments
\n
Fair value hedge derivatives 48.4 105 191 17 -
\n
Cash flow hedge derivatives 48.4 3,064 5,116 1,959 4,499
\n
Total derivative financial liabilities designated as hedging
\n
instruments
\n
3,169 5,307 1,976 4,499
\n
TOTAL 65,107 74,327 46,245 61,838
\n
For more information on fair value measurement, please
\n
see note 52 \u201cAssets and liabilities measured at fair value\u201d.
\n

\n\n\n

\n\n\n

\n

\n

\n\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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Long-term borrowings 48.3 61,085 68,191 48.3 9,086 2,835
\n
Short-term borrowings - - 48.3 4,769 18,392
\n
Trade payables 44 334 36 44 15,487 17,605
\n
Other financial liabilities 315 205 10,442 6,865
\n
Total 61,734 68,432 39,784 45,697
\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 \u20ac70,171 million
\n
The following table reports the nominal value, carrying
\n
amount and fair value of long-term borrowing, including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
Millions of euro
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Changes
\n
in
\n
carrying
\n
amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Bonds:
\n
- listed, fixed rate 29,539 29,163 4,686 24,477 27,885 30,355 29,892 978 28,914 27,468 (729)
\n
- listed, floating rate 2,643 2,622 623 1,999 2,641 2,569 2,547 537 2,010 2,473 75
\n
- unlisted, fixed rate 18,336 18,129 1,357 16,772 17, 8 4 2 18,959 18,727 - 18,727 17, 249 (598)
\n
- unlisted, floating rate 428 428 97 331 456 525 525 97 428 600 (97)
\n
Total bonds 50,946 50,342 6,763 43,579 48,824 52,408 51,691 1,612 50,079 47,79 0 (1,349)
\n
Bank borrowings:
\n
- fixed rate 3,874 3,822 853 2,969 3,746 3,367 3,273 211 3,062 3,021 549
\n
- floating rate 12,664 12,629 1,139 11,490 12,892 12,884 12,848 677 12,171 12,570 (219)
\n
- use of revolving credit
\n
lines
\n
41 41 - 41 41 30 30 2 28 26 11
\n
Total bank borrowings 16,579 16,492 1,992 14,500 16,679 16,281 16,151 890 15,261 15,617 341
\n
Leases:
\n
- fixed rate 2,852 2,852 256 2,596 2,852 2,630 2,630 251 2,379 2,630 222
\n
- floating rate 53 53 12 41 53 42 42 10 32 42 11
\n
Total leases 2,905 2,905 268 2,637 2,905 2,672 2,672 261 2,411 2,672 233
\n
Other non-bank
\n
borrowings
\n
(1)
\n
:
\n
- fixed rate 426 426 63 363 426 504 504 70 434 504 (78)
\n
- floating rate 6 6 - 6 6 8 8 2 6 12 (2)
\n
Total other non-bank
\n
borrowings
\n
432 432 63 369 432 512 512 72 440 516 (80)
\n
Total fixed-rate
\n
borrowings
\n
55,027 54,392 7, 215 47, 17 7 52,751 55,815 55,026 1,510 53,516 50,872 (634)
\n
Total floating-rate
\n
borrowings
\n
15,835 15,779 1,871 13,908 16,089 16,058 16,000 1,325 14,675 15,723 (221)
\n
TOTAL 70,862 70,171 9,086 61,085 68,840 71,873 71,026 2,835 68,191 66,595 (855)
\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
The table below reports long-term financial debt by cur-
\n
rency and interest rate.
\n
Long-term borrowing (including the portion falling due within 12 months) by currency and interest rate
\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 rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest rate
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Euro 35,865 36,166 34,993 35,383 2.5% 2.8% 1.9% 2.1%
\n
US dollar 24,601 24,847 26,930 27,209 4.9% 5.2% 4.8% 5.1%
\n
Pound sterling 4,612 4,720 4,470 4,610 4.6% 4.8% 4.6% 4.8%
\n
Colombian peso 1,884 1,888 1,310 1,310 13.5% 13.5% 10.3% 10.3%
\n
Brazilian real 2,229 2,255 1,899 1,926 10.5% 10.6% 10.0% 10.2%
\n
Swiss franc 382 382 359 360 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 510 514 526 531 5.1% 5.2% 5.1% 5.2%
\n
Peruvian sol - - 429 429 5.3% 5.3%
\n
Other currencies 88 90 110 115
\n
Total non-euro currencies 34,306 34,696 36,033 36,490
\n
TOTAL 70,171 70,862 71,026 71,873
\n
Long-term financial debt denominated in currencies other
\n
than the euro decreased by \u20ac1,727 million, largely attribut-
\n
able to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term borrowing (including the portion falling due within 12 months)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope New borrowings
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31, 2022 at Dec. 31, 2023
\n
Bonds 52,408 (2,798) (293) 1,900 (271) 50,946
\n
Borrowings 19,465 (3,208) (482) 4,193 (52) 19,916
\n
- of which leases 2,672 (406) (36) 677 (2) 2,905
\n
Total financial debt 71,873 (6,006) (775) 6,093 (323) 70,862
\n
The nominal value of long-term debt amounted to \u20ac70,862
\n
million at December 31, 2023, a decrease of \u20ac1,011 million
\n
compared with December 31, 2022. The decrease reflect-
\n
ed repayments in the amount of \u20ac6,006 million, changes
\n
in consolidation scope for \u20ac775 million and positive ex-
\n
change differences of \u20ac323 million, only partially offset by
\n
new borrowings of \u20ac6,093 million.
\n
Repayments in 2023 involved bonds in the amount of
\n
\u20ac2,798 million and loans in the amount of \u20ac3,208 million.
\n
Specifically, repayments of bonds in 2023 included:
\n
\u2022
\n
$1,250 million (\u20ac1,132 million at December 31, 2023), in
\n
respect of the hybrid bond issued by Enel SpA involved
\n
in a partial tender offer in the first months of 2023 and
\n
entirely repaid in September 2023;
\n
\u2022
\n
\u20ac100 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in February 2023;
\n
\u2022
\n
290,130 million Colombian pesos (equivalent to \u20ac68
\n
million at December 31, 2023) in respect of a float-
\n
ing-rate bond issued by Enel Colombia, maturing in
\n
February 2023;
\n
\u2022
\n
280,000 million Colombian pesos (equivalent to \u20ac65
\n
million at December 31, 2023) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2023;
\n
\u2022
\n
\u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in March 2023;
\n
\u2022
\n
\u20ac585 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in April 2023;
\n
\u2022
\n
R$305 million (equivalent to \u20ac57 million at December
\n
31, 2023), in respect of a floating-rate bond issued by
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, maturing in April 2023;
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n
\u2022
\n
\u20ac300 million in respect of a fixed-rate bond issued by
\n
Enel Finance International maturing in September 2023;
\n
\u2022
\n
R$698 million (equivalent to \u20ac130 million at December
\n
31, 2023), in respect of a floating-rate amortizing bond
\n
issued by Enel Distribui\u00e7\u00e3o S\u00e3o Paulo maturing in Sep-
\n
tember 2023.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022
\n
\u20ac200 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022
\n
\u20ac367 in respect of sustainable loans of Group\u2019s Italian
\n
companies;
\n
\u2022
\n
\u20ac1,493 million in respect of Endesa loans, of which \u20ac452
\n
million in sustainable loans;
\n
\u2022
\n
the equivalent of \u20ac322 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2023 involved \u20ac1,900 million in bonds
\n
and \u20ac4,193 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2023 and translated into euros
\n
at the exchange rate prevailing at December 29, 2023.
\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.00% Fixed rate 20.02.2031
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.50% Fixed rate 20.02.2043
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.01.2023 177 BRL CDI + 1.48% Floating rate 11.01.2026
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.05.2023 93 BRL CDI + 1.65% Floating rate 15.05.2024
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
26.06.2023 121 BRL CDI + 1.65% Floating rate 28.06.2024
\n
Total bonds 1,891
\n
Bank borrowings
\n
Enel SpA 24.07.2023 200 EUR Euribor 3M + 0.35% Floating rate 03.05.2024
\n
e-distribuzione 20.10.2023 500 EUR Euribor 6M + 0.55% Floating rate 20.10.2038
\n
Enel X Way Italia 07.08.2023 70 EUR Euribor 6M + 0.56% Floating rate 09.08.2038
\n
Enel Italia 15.06.2023 60 EUR Euribor 6M + 0.56% Floating rate 15.06.2038
\n
Enel Finance
\n
America
\n
04.04.2023 335 USD SOFR 6M CPM + 1.22% Floating rate 15.05.2034
\n
Endesa 30.04.2023 50 EUR 0.26% Fixed rate 31.07.2028
\n
Endesa 03.05.2023 425 EUR 4.18% Fixed rate 03.05.2028
\n
Endesa 04.05.2023 75 EUR 3.98% Fixed rate 04.05.2028
\n
Endesa 05.05.2023 125 EUR 4.63% Fixed rate 05.05.2028
\n
Endesa 03.07.2023 300 EUR Euribor 6M + 0.80% Floating rate 28.06.2035
\n
Endesa 21.12.2023 400 EUR Euribor 6M + 0.72% Floating rate 21.12.2028
\n
Enel Chile 13.04.2023 68 USD SOFR 1M + 1.33% Floating rate 26.06.2024
\n
Enel Chile 21.07.2023 72 USD 5.46% Fixed rate 21.07.2038
\n
Enel Chile 20.12.2023 74 USD 5.62% Fixed rate 21.12.2038
\n
Enel Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
20.04.2023 50 USD 4.38% Fixed rate 20.04.2038
\n
Enel Colombia 12.04.2023 160 COP IBR O/N 3M + 3.7% Floating rate 12.04.2028
\n
Enel Colombia 30.11.2023 283 COP IBR O/N 3M + 3.1% Floating rate 15.10.2031
\n
Enel Colombia 21.12.2023 70 COP IBR 3M + 3.85% Floating rate 21.12.2027
\n
Total bank
\n
borrowings
\n
3,317
\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, 2023 at Dec. 31, 2022
\n
Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Euro 35,865 36,166 51.0% 21,862 58,028 81.9% 34,993 35,383 49.2% 23,473 58,856 81.9%
\n
US dollar 24,601 24,847 35.1% (17,850) 6,997 9.9% 26,930 27,209 37.9% (19,759) 7,4 5 0 10.4%
\n
Pound sterling 4,612 4,720 6.7% (4,720) - - 4,470 4,610 6.4% (4,610) - -
\n
Colombian peso 1,884 1,888 2.7% - 1,888 2.7% 1,310 1,310 1.8% - 1,310 1.8%
\n
Brazilian real 2,229 2,255 3.2% 1,047 3,302 4.7% 1,899 1,926 2.7% 1,205 3,131 4.4%
\n
Swiss franc 382 382 0.5% (382) - - 359 360 0.5% (360) - -
\n
Chilean peso/UF 510 514 0.7% - 514 0.7% 526 531 0.7% - 531 0.7%
\n
Peruvian sol - - - - - - 429 429 0.6% - 429 0.6%
\n
Other currencies 88 90 0.1% 43 133 0.2% 110 115 0.2% 51 166 0.2%
\n
Total non-euro
\n
currencies
\n
34,306 34,696 49.0% (21,862) 12,834 18.1% 36,033 36,490 50.8% (23,473) 13,017 18.1%
\n
TOTAL 70,171 70,862 100.0% - 70,862 100.0% 71,026 71,873 100.0% - 71,873 100.0%
\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 2023 2022
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Floating rate 20,604 27. 2 % 17, 241 22.8% 34,450 38.2% 31,353 34.7%
\n
Fixed rate 55,027 72.8% 58,389 77.2% 55,815 61.8% 58,912 65.3%
\n
Total 75,631 75,630 90,265 90,265
\n
At December 31,2023, 27.2% of the nominal value of long-
\n
and medium-term financial debt was floating rate (38.2%
\n
at December 31, 2022). Taking account of hedges of in-
\n
terest rates considered effective pursuant to the IFRS-EU,
\n
22.8% of the nominal value of long- and medium-term fi-
\n
nancial debt was exposed to interest rate risk at Decem-
\n
ber 31, 2023 (34.7% at December 31, 2022). These figures
\n
are in line with the limits established in the risk manage-
\n
ment policy.
\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 programs 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
\n
the Group\u2019s so-called eligible green projects) and those
\n
regarding bonds issued by Enel Finance International NV
\n
on the US market guaranteed by Enel SpA can be summa-
\n
rized as follows:
\n
\u2022
\n
negative pledge clauses under which the issuer and
\n
the guarantor may not establish or maintain mortgag-
\n
es, liens or other encumbrances on all or part of their
\n
assets or revenue to secure certain financial liabilities,
\n
unless the same encumbrances are extended equally
\n
or pro rata to the bonds in question;
\n
\u2022
\n
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
and are issued without preferential rights among them
\n
and have at least the same seniority as other present
\n
and future unsubordinated and unsecured bonds of
\n
the issuer and the guarantor;
\n

\n\n\n

\n\n\n

\n\n\n

\n\n\n

\n

\n
\u2022
\n
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
\n
(as part of the Euro Medium-Term Notes - EMTN bond
\n
issue program) and on the American market, both guar-
\n
anteed by Enel SpA, linked to the achievement of a num-
\n
ber of the Sustainable Development Goals (SDGs) of the
\n
United Nations that contain the same covenants as other
\n
bonds of 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
\n
subordination clauses, under which each hybrid bond
\n
is subordinate to all other bonds issued by the com-
\n
pany and has the same seniority with all other hybrid
\n
financial instruments issued, being senior only to equity
\n
instruments;
\n
\u2022
\n
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 of
\n
Enel SpA 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
(52)
\n
\u2022
\n
negative pledge clauses, under which the borrower
\n
and, in some cases, the guarantor are subject to lim-
\n
itations on the establishment of mortgages, liens or
\n
other encumbrances on all or part of their respective
\n
assets, with the exception of expressly permitted en-
\n
cumbrances;
\n
\u2022
\n
disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their
\n
assets or operations, with the exception of expressly
\n
permitted disposals;
\n
\u2022
\n
pari passu clauses, under which the payment under-
\n
takings of the borrower have the same seniority as its
\n
other unsecured and unsubordinated payment obliga-
\n
tions;
\n
\u2022
\n
change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required
\n
to renegotiate the terms and conditions of the financ-
\n
ing or make compulsory early repayment of the loans
\n
granted;
\n
\u2022
\n
rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022
\n
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 cases,
\n
the guarantor constitutes a default in respect of the li-
\n
abilities in question, which become immediately repay-
\n
able.
\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
(52) The sustainability-linked loan entered into on September 30, 2022, granted by EKF Denmark\u2019s Export Credit Agency and Citi to Enel Finance America LLC
\n
as borrower and Enel SpA (as guarantor), provide for a number of additional covenants, such as:
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending bank can request the cancellation of its financial commitment undertaken by it and the early
\n
payment of the sums disbursed if it has suffered ascertained harm to its own reputation or that of other persons as a result of substantial breach of certain
\n
regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure compliance with certain environmental and social regulations and standards.
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n
48.3.2 Short-term borrowings \u2013 \u20ac4,769 million
\n
At December 31, 2023, short-term borrowings totaled
\n
\u20ac4,769 million, a decrease of \u20ac13,623 million compared
\n
with December 31, 2022, and break down as follows.
\n
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Short-term bank borrowings 393 1,320 (927)
\n
Commercial paper 2,499 13,838 (11,339)
\n
Cash collateral and other financing on derivatives 1,383 1,513 (130)
\n
Other short-term borrowings
\n
(1)
\n
494 1,721 (1,227)
\n
Short-term borrowings 4,769 18,392 (13,623)
\n
(1) Does not include current financial liabilities included in \u201cOther current financial liabilities\u201d in net short-term financial debt.
\n
Commercial paper liabilities totaling \u20ac2,499 million con-
\n
cerned issues by Enel Finance International and Enel Fi-
\n
nance America.
\n
The main commercial paper programs include:
\n
\u2022
\n
\u20ac8,000 million of Enel Finance International;
\n
\u2022
\n
\u20ac5,000 million of Endesa;
\n
\u2022
\n
$5,000 million (equivalent to \u20ac4,526 million at Decem-
\n
ber 31, 2023) of Enel Finance America.
\n
At December 31, 2023, the whole amount of commercial
\n
paper issues, equal to \u20ac2,499 million, was linked to sus-
\n
tainability objectives.
\n
Sustainability-linked finance at Enel
\n
The new sustainability-linked bond issues, together with all
\n
the sustainable financing arranged in the last year, made it
\n
possible to reach a 64% ratio of sustainable sources of fi-
\n
nancing to the Group\u2019s total gross debt at the end of 2023,
\n
with a goal of reaching around 70% in 2026.
\n
Shown below are the KPIs and targets included in the
\n
latest update of Enel\u2019s Sustainability-Linked Financing
\n
Framework, published in January 2024.
\n
KPI Actual value Sustainability Performance Targets (SPTs)
\n
2023 2023 2024 2025 2026 2030 2040
\n
Intensity of Scope 1 GHG emissions related to
\n
power generation (gCO
\n
2eq
\n
/kWh)
\n
160 148 140 130 125 72 0
\n
Intensity of Scope 1 and Scope 3 GHG
\n
emissions related to Integrated Power
\n
(gCO
\n
2eq
\n
/kWh)
\n
168 135 135 73 0
\n
Absolute Scope 3 GHG emissions related to
\n
retail gas (MtCO
\n
2eq
\n
)
\n
16.8 20.9 20.0 11.4 0
\n
Percentage of installed renewables capacity (%) 68.2 65 69 73 74 80 100
\n
Percentage of capital expenditure aligned with
\n
the EU taxonomy (%)
\n
84.8
\n
>80
\n
(2023-2025)
\n
(53)
\n
>80
\n
(2024-2026)
\n
(54)
\n
Developments in the indicators shown in the table are pe-
\n
riodically verified by an external auditor.
\n
The war in Ukraine and the resulting restrictions on gas
\n
imports from Russia into the EU, which caused a decrease
\n
in gas supplies accompanied by a surge in wholesale elec-
\n
tricity and gas prices, with serious effects for households
\n
and businesses, prompted EU governments to implement
\n
a series of policy responses to mitigate the impact of ris-
\n
ing costs and ensure the stability of the energy system.
\n
Despite these policy measures, the Group managed to re-
\n
duce direct and indirect greenhouse gas emissions along
\n
the entire value chain by 26.3% overall compared with
\n
the previous year. Furthermore, the Group also reduced
\n
the intensity of Scope 1 GHG emissions related to power
\n
generation by over 30.6%, going from 229 gCO
\n
2eq
\n
/kWh in
\n
2022 to 160 gCO
\n
2eq
\n
/kWh in 2023. This reduction reflected
\n
a 12.9% increase in consolidated renewables generation
\n
and a 37.5% reduction in consolidated thermal generation
\n
compared with 2022, a consequence of the Group\u2019s strat-
\n
egy to shift its generation mix towards renewables and to
\n
advance the decarbonization process.
\n
(53) SPT with cumulative observation period of 2023-2025.
\n
(54) SPT with cumulative observation period of 2024-2026.
\n

\n\n\n

\n\n\n

\n\n\n

\n\n

\n\n

\n
However, due to the unprecedented crisis faced by the Eu-
\n
ropean energy system in 2022 and 2023, the Group\u2019s emis-
\n
sions reduction in 2023 was not sufficient to achieve the
\n
Scope 1 GHG emissions intensity target related to electric-
\n
ity generation set for 2023 as announced on the occasion
\n
of the Capital Markets Day held in November 2020 for the
\n
launch of the 2021-2023 Strategic Plan. As a result of the
\n
energy crisis, the intensity value was slightly higher than the
\n
target of 148 gCO
\n
2eq
\n
/kWh. In the absence of these factors,
\n
Enel would have been able to reach an emissions intensity
\n
level well below the target of 148 gCO
\n
2eq
\n
/kWh.
\n
As a result, the Group\u2019s sustainability-linked instruments
\n
that set the Scope 1 emissions intensity target for elec-
\n
tricity generation at 148 gCO
\n
2eq
\n
/kWh for 2023 will be sub-
\n
ject to an increase in the relative step-up.
\n

\n

\n\n\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
48.5 Net gain/(loss)
\n
The following table shows net gains and losses by catego-
\n
ry of financial instruments, excluding derivatives.
\n
Millions of euro 2023 2022
\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 measured at amortized cost (1,112) (1,320) (1,242) (1,305)
\n
Financial assets at FVOCI
\n
Equity investments at FVOCI - - - -
\n
Other financial assets at FVOCI 15 - (4) -
\n
Total financial assets at FVOCI 15 - (4) -
\n
Financial assets at FVTPL
\n
Financial assets at FVTPL 6 - 9 -
\n
Financial assets designated upon initial recognition (fair value option) - - - -
\n
Total financial assets at FVTPL 6 - 9 -
\n
Financial liabilities measured at amortized cost (2,759) - (2,357) -
\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
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", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag933": { "value": "\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\n\n\n

\n
Millions of euro Non-current Current
\n
Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Cash and cash equivalents - - 35 6,772 10,169
\n
Trade receivables 34 1,726 1,388 34 16,047 15, 217
\n
Current portion of long-term loan assets - - 30.1 1,007 2,838
\n
Cash collateral - - 30.1 2,899 8,319
\n
Other financial assets 29.1 3,332 3,767 30.1 30 2,090
\n
Financial assets from service concession arrangements at
\n
amortized cost
\n
29 310 295 29 14 12
\n
Other financial assets at amortized cost 341 282 1,726 1,531
\n
Total 5,709 5,732 28,495 40,176
\n

\n\n\n

\n\n\n

\n
Impairment of financial assets measured at amortized cost
\n
Financial assets measured at amortized cost amounted to
\n
\u20ac34,202 million at December 31, 2023 (\u20ac45,788 million at
\n
December 31, 2022) and are recognized net of allowances
\n
for expected credit losses totaling \u20ac4,098 million at De-
\n
cember 31, 2023 (\u20ac4,087 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
\n
cash and cash equivalents;
\n
\u2022
\n
trade receivables and contract assets;
\n
\u2022
\n
loan assets;
\n
\u2022
\n
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
\n
the general approach, for financial assets other than
\n
trade receivables, contract assets and lease receiv-
\n
ables. This approach, based on an assessment of any
\n
significant increase in credit risk since initial recogni-
\n
tion, is performed comparing the PD at origination with
\n
PD at the reporting date, at each reporting date.
\n
Then, based on the results of the assessment, a loss
\n
allowance is recognized based on 12-month ECL or life-
\n
time ECL (i.e. staging):
\n
\u2013
\n
12-month ECL, for financial assets for which there
\n
has not been a significant increase in credit risk
\n
since initial recognition;
\n
\u2013
\n
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
\n
the simplified approach, for trade receivables, contract
\n
assets and lease receivables with or without a signifi-
\n
cant financing component, based on lifetime ECL with-
\n
out 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
\n
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
\n
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
\n
right to cash flows is legally or contractually extinguished,
\n
transferred or expired).
\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, 2023 at Dec. 31, 2022
\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 6,772 - 6,772 10,169 - 10,169
\n
Trade receivables 21,548 3,775 17,7 73 20,388 3,783 16,605
\n
Loan assets 7,579 311 7, 2 6 8 17, 2 6 2 248 17,014
\n
Other financial assets at amortized cost 2,403 12 2,391 2,176 56 2,120
\n
Total 38,302 4,098 34,204 49,995 4,087 45,908
\n

\n\n\n
To measure expected losses, the Group assesses trade
\n
receivables and contract assets with the simplified ap-
\n
proach, both on an individual basis (e.g., government enti-
\n
ties, authorities, financial counterparties, wholesale sellers,
\n
traders and large companies, etc.) and a collective basis
\n
(e.g., retail 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
\n
risk characteristics and information on past due positions,
\n
considering a specific definition of default.
\n
Based on each business and local regulatory framework,
\n
as well as differences between customer portfolios, in-
\n
cluding their default and recovery rates (comprising ex-
\n
pectations for recovery beyond 90 days):
\n
\u2022
\n
the Group mainly defines a defaulted position as one
\n
that is 180 days past due. Accordingly, beyond this time
\n
limit, trade receivables are presumed to be credit im-
\n
paired); and
\n
\u2022
\n
specific clusters are defined on the basis of specific
\n
markets, business and risk characteristics.
\n
Contract assets substantially have the same risk charac-
\n
teristics as trade receivables for the same types of con-
\n
tracts.
\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
\n
PD, assumed equal to the average default rate, is calcu-
\n
lated by cluster and considering historical data from at
\n
least 24 months;
\n
\u2022
\n
LGD is a function of the recovery rates for each cluster,
\n
discounted using the effective interest rate; and
\n
\u2022
\n
EAD is estimated as equal to the carrying amount at the
\n
reporting date net of cash deposits, including invoices
\n
issued but not past due and invoices to be issued.
\n
The following table reports changes in the allowance for
\n
expected credit losses on loan assets in accordance with
\n
the general approach.
\n
Millions of euro ECL 12-month allowance ECL lifetime allowance
\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
Opening balance at Jan. 1, 2023 29 219
\n
Accruals - 36
\n
Uses - 11
\n
Reversals to profit or loss (32) (6)
\n
Other changes 45 9
\n
Closing balance at Dec. 31, 2023 42 269
\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, 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
Opening balance at Jan. 1, 2023 3,783
\n
Accruals 1,384
\n
Uses (1,136)
\n
Reversals to profit or loss (210)
\n
Other changes (46)
\n
Closing balance at Dec. 31, 2023 3,775
\n

\n\n\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, 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
Opening balance at Jan. 1, 2023 56
\n
Accruals 149
\n
Uses -
\n
Reversals to profit or loss (1)
\n
Other changes (192)
\n
Closing balance at Dec. 31, 2023 12
\n

\n\n\n
Note 49 \u201cRisk management\u201d provides additional informa-
\n
tion on the exposure to credit risk and expected losses.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAllowanceForCreditLossesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag934": { "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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n\n

\n\n\n

\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag935": { "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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n\n

\n\n\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsDesignatedAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag936": { "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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag937": { "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
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022 Notes
\n
at
\n
Dec. 31, 2023
\n
at
\n
Dec. 31, 2022
\n
Derivatives at FVTPL 51 206 473 51 4,443 12,075
\n
Investments in liquid assets - - 35 29 872
\n
Securities - - 30.1 - -
\n
Equity investments in other companies at FVTPL 29 8 6 - -
\n
Financial assets from service concession arrangements at FVTPL 29 4,080 3,436 - -
\n
Financial assets from joint development agreements (JDA) at FVTPL 123 - - -
\n
Other financial assets at FVTPL 130 -
\n
30,
\n
30.1
\n
190 176
\n
Total 4,547 3,915 4,662 13,123
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag938": { "value": "\n
48.3 Borrowings
\n
48.3.1 Long-term borrowings (including the portion
\n
falling due within 12 months) \u2013 \u20ac70,171 million
\n
The following table reports the nominal value, carrying
\n
amount and fair value of long-term borrowing, including
\n
the portion falling due within 12 months.
\n
Long-term borrowings by category and type of interest rate
\n
Millions of euro
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Nominal
\n
value
\n
\n
Carrying
\n
amount
\n
Current
\n
portion
\n
Portion
\n
due in
\n
more
\n
than 12
\n
months
\n
Fair
\n
value
\n
Changes
\n
in
\n
carrying
\n
amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Bonds:
\n
- listed, fixed rate 29,539 29,163 4,686 24,477 27,885 30,355 29,892 978 28,914 27,468 (729)
\n
- listed, floating rate 2,643 2,622 623 1,999 2,641 2,569 2,547 537 2,010 2,473 75
\n
- unlisted, fixed rate 18,336 18,129 1,357 16,772 17, 8 4 2 18,959 18,727 - 18,727 17, 249 (598)
\n
- unlisted, floating rate 428 428 97 331 456 525 525 97 428 600 (97)
\n
Total bonds 50,946 50,342 6,763 43,579 48,824 52,408 51,691 1,612 50,079 47,79 0 (1,349)
\n
Bank borrowings:
\n
- fixed rate 3,874 3,822 853 2,969 3,746 3,367 3,273 211 3,062 3,021 549
\n
- floating rate 12,664 12,629 1,139 11,490 12,892 12,884 12,848 677 12,171 12,570 (219)
\n
- use of revolving credit
\n
lines
\n
41 41 - 41 41 30 30 2 28 26 11
\n
Total bank borrowings 16,579 16,492 1,992 14,500 16,679 16,281 16,151 890 15,261 15,617 341
\n
Leases:
\n
- fixed rate 2,852 2,852 256 2,596 2,852 2,630 2,630 251 2,379 2,630 222
\n
- floating rate 53 53 12 41 53 42 42 10 32 42 11
\n
Total leases 2,905 2,905 268 2,637 2,905 2,672 2,672 261 2,411 2,672 233
\n
Other non-bank
\n
borrowings
\n
(1)
\n
:
\n
- fixed rate 426 426 63 363 426 504 504 70 434 504 (78)
\n
- floating rate 6 6 - 6 6 8 8 2 6 12 (2)
\n
Total other non-bank
\n
borrowings
\n
432 432 63 369 432 512 512 72 440 516 (80)
\n
Total fixed-rate
\n
borrowings
\n
55,027 54,392 7, 215 47, 17 7 52,751 55,815 55,026 1,510 53,516 50,872 (634)
\n
Total floating-rate
\n
borrowings
\n
15,835 15,779 1,871 13,908 16,089 16,058 16,000 1,325 14,675 15,723 (221)
\n
TOTAL 70,862 70,171 9,086 61,085 68,840 71,873 71,026 2,835 68,191 66,595 (855)
\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
The table below reports long-term financial debt by cur-
\n
rency and interest rate.
\n
Long-term borrowing (including the portion falling due within 12 months) by currency and interest rate
\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 rate
\n
Current
\n
average
\n
nominal
\n
interest rate
\n
Current
\n
effective
\n
interest rate
\n
at Dec. 31, 2023 at Dec. 31, 2022 at Dec. 31, 2023 at Dec. 31, 2022
\n
Euro 35,865 36,166 34,993 35,383 2.5% 2.8% 1.9% 2.1%
\n
US dollar 24,601 24,847 26,930 27,209 4.9% 5.2% 4.8% 5.1%
\n
Pound sterling 4,612 4,720 4,470 4,610 4.6% 4.8% 4.6% 4.8%
\n
Colombian peso 1,884 1,888 1,310 1,310 13.5% 13.5% 10.3% 10.3%
\n
Brazilian real 2,229 2,255 1,899 1,926 10.5% 10.6% 10.0% 10.2%
\n
Swiss franc 382 382 359 360 1.8% 1.8% 1.8% 1.8%
\n
Chilean peso/UF 510 514 526 531 5.1% 5.2% 5.1% 5.2%
\n
Peruvian sol - - 429 429 5.3% 5.3%
\n
Other currencies 88 90 110 115
\n
Total non-euro currencies 34,306 34,696 36,033 36,490
\n
TOTAL 70,171 70,862 71,026 71,873
\n
Long-term financial debt denominated in currencies other
\n
than the euro decreased by \u20ac1,727 million, largely attribut-
\n
able to the changes in debt denominated in US dollars.
\n
Change in the nominal value of long-term borrowing (including the portion falling due within 12 months)
\n
Millions of euro Nominal value Repayments
\n
Change in the
\n
consolidation
\n
scope New borrowings
\n
Exchange
\n
differences Nominal value
\n
at Dec. 31, 2022 at Dec. 31, 2023
\n
Bonds 52,408 (2,798) (293) 1,900 (271) 50,946
\n
Borrowings 19,465 (3,208) (482) 4,193 (52) 19,916
\n
- of which leases 2,672 (406) (36) 677 (2) 2,905
\n
Total financial debt 71,873 (6,006) (775) 6,093 (323) 70,862
\n
The nominal value of long-term debt amounted to \u20ac70,862
\n
million at December 31, 2023, a decrease of \u20ac1,011 million
\n
compared with December 31, 2022. The decrease reflect-
\n
ed repayments in the amount of \u20ac6,006 million, changes
\n
in consolidation scope for \u20ac775 million and positive ex-
\n
change differences of \u20ac323 million, only partially offset by
\n
new borrowings of \u20ac6,093 million.
\n
Repayments in 2023 involved bonds in the amount of
\n
\u20ac2,798 million and loans in the amount of \u20ac3,208 million.
\n
Specifically, repayments of bonds in 2023 included:
\n
\u2022
\n
$1,250 million (\u20ac1,132 million at December 31, 2023), in
\n
respect of the hybrid bond issued by Enel SpA involved
\n
in a partial tender offer in the first months of 2023 and
\n
entirely repaid in September 2023;
\n
\u2022
\n
\u20ac100 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in February 2023;
\n
\u2022
\n
290,130 million Colombian pesos (equivalent to \u20ac68
\n
million at December 31, 2023) in respect of a float-
\n
ing-rate bond issued by Enel Colombia, maturing in
\n
February 2023;
\n
\u2022
\n
280,000 million Colombian pesos (equivalent to \u20ac65
\n
million at December 31, 2023) in respect of a fixed-rate
\n
bond issued by Enel Colombia, maturing in March 2023;
\n
\u2022
\n
\u20ac50 million in respect of a floating-rate bond issued by
\n
Enel Finance International, maturing in March 2023;
\n
\u2022
\n
\u20ac585 million in respect of a fixed-rate bond issued by
\n
Enel Finance International, maturing in April 2023;
\n
\u2022
\n
R$305 million (equivalent to \u20ac57 million at December
\n
31, 2023), in respect of a floating-rate bond issued by
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo, maturing in April 2023;
\n

\n\n\n
\u2022
\n
\u20ac300 million in respect of a fixed-rate bond issued by
\n
Enel Finance International maturing in September 2023;
\n
\u2022
\n
R$698 million (equivalent to \u20ac130 million at December
\n
31, 2023), in respect of a floating-rate amortizing bond
\n
issued by Enel Distribui\u00e7\u00e3o S\u00e3o Paulo maturing in Sep-
\n
tember 2023.
\n
The main repayments of loans made during the year in-
\n
cluded:
\n
\u2022
\n
\u20ac200 million in respect of floating-rate revolving credit
\n
lines of Enel SpA;
\n
\u2022
\n
\u20ac367 in respect of sustainable loans of Group\u2019s Italian
\n
companies;
\n
\u2022
\n
\u20ac1,493 million in respect of Endesa loans, of which \u20ac452
\n
million in sustainable loans;
\n
\u2022
\n
the equivalent of \u20ac322 million relating to South Ameri-
\n
can companies.
\n
New borrowings in 2023 involved \u20ac1,900 million in bonds
\n
and \u20ac4,193 million in loans.
\n
The table below shows the main characteristics of financial
\n
transactions carried out in 2023 and translated into euros
\n
at the exchange rate prevailing at December 29, 2023.
\n
Issuer/Borrower
\n
Issue/Grant
\n
date
\n
Amount in
\n
millions of euro Currency Interest rate
\n
Interest rate
\n
type Maturity
\n
Bonds
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.00% Fixed rate 20.02.2031
\n
Enel Finance
\n
International
\n
20.02.2023 750 EUR 4.50% Fixed rate 20.02.2043
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.01.2023 177 BRL CDI + 1.48% Floating rate 11.01.2026
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
11.05.2023 93 BRL CDI + 1.65% Floating rate 15.05.2024
\n
Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1
\n
26.06.2023 121 BRL CDI + 1.65% Floating rate 28.06.2024
\n
Total bonds 1,891
\n
Bank borrowings
\n
Enel SpA 24.07.2023 200 EUR Euribor 3M + 0.35% Floating rate 03.05.2024
\n
e-distribuzione 20.10.2023 500 EUR Euribor 6M + 0.55% Floating rate 20.10.2038
\n
Enel X Way Italia 07.08.2023 70 EUR Euribor 6M + 0.56% Floating rate 09.08.2038
\n
Enel Italia 15.06.2023 60 EUR Euribor 6M + 0.56% Floating rate 15.06.2038
\n
Enel Finance
\n
America
\n
04.04.2023 335 USD SOFR 6M CPM + 1.22% Floating rate 15.05.2034
\n
Endesa 30.04.2023 50 EUR 0.26% Fixed rate 31.07.2028
\n
Endesa 03.05.2023 425 EUR 4.18% Fixed rate 03.05.2028
\n
Endesa 04.05.2023 75 EUR 3.98% Fixed rate 04.05.2028
\n
Endesa 05.05.2023 125 EUR 4.63% Fixed rate 05.05.2028
\n
Endesa 03.07.2023 300 EUR Euribor 6M + 0.80% Floating rate 28.06.2035
\n
Endesa 21.12.2023 400 EUR Euribor 6M + 0.72% Floating rate 21.12.2028
\n
Enel Chile 13.04.2023 68 USD SOFR 1M + 1.33% Floating rate 26.06.2024
\n
Enel Chile 21.07.2023 72 USD 5.46% Fixed rate 21.07.2038
\n
Enel Chile 20.12.2023 74 USD 5.62% Fixed rate 21.12.2038
\n
Enel Distribui\u00e7\u00e3o
\n
S\u00e3o Paulo
\n
20.04.2023 50 USD 4.38% Fixed rate 20.04.2038
\n
Enel Colombia 12.04.2023 160 COP IBR O/N 3M + 3.7% Floating rate 12.04.2028
\n
Enel Colombia 30.11.2023 283 COP IBR O/N 3M + 3.1% Floating rate 15.10.2031
\n
Enel Colombia 21.12.2023 70 COP IBR 3M + 3.85% Floating rate 21.12.2027
\n
Total bank
\n
borrowings
\n
3,317
\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, 2023 at Dec. 31, 2022
\n
Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging Initial debt structure
\n
Impact
\n
of hedge
\n
Debt structure after
\n
hedging
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Carrying
\n
amount
\n
Nominal
\n
value %
\n
Euro 35,865 36,166 51.0% 21,862 58,028 81.9% 34,993 35,383 49.2% 23,473 58,856 81.9%
\n
US dollar 24,601 24,847 35.1% (17,850) 6,997 9.9% 26,930 27,209 37.9% (19,759) 7,4 5 0 10.4%
\n
Pound sterling 4,612 4,720 6.7% (4,720) - - 4,470 4,610 6.4% (4,610) - -
\n
Colombian peso 1,884 1,888 2.7% - 1,888 2.7% 1,310 1,310 1.8% - 1,310 1.8%
\n
Brazilian real 2,229 2,255 3.2% 1,047 3,302 4.7% 1,899 1,926 2.7% 1,205 3,131 4.4%
\n
Swiss franc 382 382 0.5% (382) - - 359 360 0.5% (360) - -
\n
Chilean peso/UF 510 514 0.7% - 514 0.7% 526 531 0.7% - 531 0.7%
\n
Peruvian sol - - - - - - 429 429 0.6% - 429 0.6%
\n
Other currencies 88 90 0.1% 43 133 0.2% 110 115 0.2% 51 166 0.2%
\n
Total non-euro
\n
currencies
\n
34,306 34,696 49.0% (21,862) 12,834 18.1% 36,033 36,490 50.8% (23,473) 13,017 18.1%
\n
TOTAL 70,171 70,862 100.0% - 70,862 100.0% 71,026 71,873 100.0% - 71,873 100.0%
\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 2023 2022
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Nominal
\n
amount
\n
pre-hedge %
\n
Nominal
\n
amount
\n
post-hedge %
\n
Floating rate 20,604 27. 2 % 17, 241 22.8% 34,450 38.2% 31,353 34.7%
\n
Fixed rate 55,027 72.8% 58,389 77.2% 55,815 61.8% 58,912 65.3%
\n
Total 75,631 75,630 90,265 90,265
\n
At December 31,2023, 27.2% of the nominal value of long-
\n
and medium-term financial debt was floating rate (38.2%
\n
at December 31, 2022). Taking account of hedges of in-
\n
terest rates considered effective pursuant to the IFRS-EU,
\n
22.8% of the nominal value of long- and medium-term fi-
\n
nancial debt was exposed to interest rate risk at Decem-
\n
ber 31, 2023 (34.7% at December 31, 2022). These figures
\n
are in line with the limits established in the risk manage-
\n
ment policy.
\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 programs 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
\n
the Group\u2019s so-called eligible green projects) and those
\n
regarding bonds issued by Enel Finance International NV
\n
on the US market guaranteed by Enel SpA can be summa-
\n
rized as follows:
\n
\u2022
\n
negative pledge clauses under which the issuer and
\n
the guarantor may not establish or maintain mortgag-
\n
es, liens or other encumbrances on all or part of their
\n
assets or revenue to secure certain financial liabilities,
\n
unless the same encumbrances are extended equally
\n
or pro rata to the bonds in question;
\n
\u2022
\n
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
and are issued without preferential rights among them
\n
and have at least the same seniority as other present
\n
and future unsubordinated and unsecured bonds of
\n
the issuer and the guarantor;
\n

\n\n\n

\n

\n
\u2022
\n
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
\n
(as part of the Euro Medium-Term Notes - EMTN bond
\n
issue program) and on the American market, both guar-
\n
anteed by Enel SpA, linked to the achievement of a num-
\n
ber of the Sustainable Development Goals (SDGs) of the
\n
United Nations that contain the same covenants as other
\n
bonds of 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
\n
subordination clauses, under which each hybrid bond
\n
is subordinate to all other bonds issued by the com-
\n
pany and has the same seniority with all other hybrid
\n
financial instruments issued, being senior only to equity
\n
instruments;
\n
\u2022
\n
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 of
\n
Enel SpA 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
(52)
\n
\u2022
\n
negative pledge clauses, under which the borrower
\n
and, in some cases, the guarantor are subject to lim-
\n
itations on the establishment of mortgages, liens or
\n
other encumbrances on all or part of their respective
\n
assets, with the exception of expressly permitted en-
\n
cumbrances;
\n
\u2022
\n
disposals clauses, under which the borrower and, in
\n
some cases, the guarantor may not dispose of their
\n
assets or operations, with the exception of expressly
\n
permitted disposals;
\n
\u2022
\n
pari passu clauses, under which the payment under-
\n
takings of the borrower have the same seniority as its
\n
other unsecured and unsubordinated payment obliga-
\n
tions;
\n
\u2022
\n
change of control clauses, under which the borrower
\n
and, in some cases, the guarantor could be required
\n
to renegotiate the terms and conditions of the financ-
\n
ing or make compulsory early repayment of the loans
\n
granted;
\n
\u2022
\n
rating clauses, which provide for the borrower or the
\n
guarantor to maintain their rating above a certain spec-
\n
ified level;
\n
\u2022
\n
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 cases,
\n
the guarantor constitutes a default in respect of the li-
\n
abilities in question, which become immediately repay-
\n
able.
\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
(52) The sustainability-linked loan entered into on September 30, 2022, granted by EKF Denmark\u2019s Export Credit Agency and Citi to Enel Finance America LLC
\n
as borrower and Enel SpA (as guarantor), provide for a number of additional covenants, such as:
\n
\u2022 a \u201creputational damage\u201d clause, under which the lending bank can request the cancellation of its financial commitment undertaken by it and the early
\n
payment of the sums disbursed if it has suffered ascertained harm to its own reputation or that of other persons as a result of substantial breach of certain
\n
regulations;
\n
\u2022 the commitment, also of the guarantor, to ensure compliance with certain environmental and social regulations and standards.
\n

\n\n\n
48.3.2 Short-term borrowings \u2013 \u20ac4,769 million
\n
At December 31, 2023, short-term borrowings totaled
\n
\u20ac4,769 million, a decrease of \u20ac13,623 million compared
\n
with December 31, 2022, and break down as follows.
\n
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022 Change
\n
Short-term bank borrowings 393 1,320 (927)
\n
Commercial paper 2,499 13,838 (11,339)
\n
Cash collateral and other financing on derivatives 1,383 1,513 (130)
\n
Other short-term borrowings
\n
(1)
\n
494 1,721 (1,227)
\n
Short-term borrowings 4,769 18,392 (13,623)
\n
(1) Does not include current financial liabilities included in \u201cOther current financial liabilities\u201d in net short-term financial debt.
\n
Commercial paper liabilities totaling \u20ac2,499 million con-
\n
cerned issues by Enel Finance International and Enel Fi-
\n
nance America.
\n
The main commercial paper programs include:
\n
\u2022
\n
\u20ac8,000 million of Enel Finance International;
\n
\u2022
\n
\u20ac5,000 million of Endesa;
\n
\u2022
\n
$5,000 million (equivalent to \u20ac4,526 million at Decem-
\n
ber 31, 2023) of Enel Finance America.
\n
At December 31, 2023, the whole amount of commercial
\n
paper issues, equal to \u20ac2,499 million, was linked to sus-
\n
tainability objectives.
\n
Sustainability-linked finance at Enel
\n
The new sustainability-linked bond issues, together with all
\n
the sustainable financing arranged in the last year, made it
\n
possible to reach a 64% ratio of sustainable sources of fi-
\n
nancing to the Group\u2019s total gross debt at the end of 2023,
\n
with a goal of reaching around 70% in 2026.
\n
Shown below are the KPIs and targets included in the
\n
latest update of Enel\u2019s Sustainability-Linked Financing
\n
Framework, published in January 2024.
\n
KPI Actual value Sustainability Performance Targets (SPTs)
\n
2023 2023 2024 2025 2026 2030 2040
\n
Intensity of Scope 1 GHG emissions related to
\n
power generation (gCO
\n
2eq
\n
/kWh)
\n
160 148 140 130 125 72 0
\n
Intensity of Scope 1 and Scope 3 GHG
\n
emissions related to Integrated Power
\n
(gCO
\n
2eq
\n
/kWh)
\n
168 135 135 73 0
\n
Absolute Scope 3 GHG emissions related to
\n
retail gas (MtCO
\n
2eq
\n
)
\n
16.8 20.9 20.0 11.4 0
\n
Percentage of installed renewables capacity (%) 68.2 65 69 73 74 80 100
\n
Percentage of capital expenditure aligned with
\n
the EU taxonomy (%)
\n
84.8
\n
>80
\n
(2023-2025)
\n
(53)
\n
>80
\n
(2024-2026)
\n
(54)
\n
Developments in the indicators shown in the table are pe-
\n
riodically verified by an external auditor.
\n
The war in Ukraine and the resulting restrictions on gas
\n
imports from Russia into the EU, which caused a decrease
\n
in gas supplies accompanied by a surge in wholesale elec-
\n
tricity and gas prices, with serious effects for households
\n
and businesses, prompted EU governments to implement
\n
a series of policy responses to mitigate the impact of ris-
\n
ing costs and ensure the stability of the energy system.
\n
Despite these policy measures, the Group managed to re-
\n
duce direct and indirect greenhouse gas emissions along
\n
the entire value chain by 26.3% overall compared with
\n
the previous year. Furthermore, the Group also reduced
\n
the intensity of Scope 1 GHG emissions related to power
\n
generation by over 30.6%, going from 229 gCO
\n
2eq
\n
/kWh in
\n
2022 to 160 gCO
\n
2eq
\n
/kWh in 2023. This reduction reflected
\n
a 12.9% increase in consolidated renewables generation
\n
and a 37.5% reduction in consolidated thermal generation
\n
compared with 2022, a consequence of the Group\u2019s strat-
\n
egy to shift its generation mix towards renewables and to
\n
advance the decarbonization process.
\n
(53) SPT with cumulative observation period of 2023-2025.
\n
(54) SPT with cumulative observation period of 2024-2026.
\n

\n\n\n

\n
However, due to the unprecedented crisis faced by the Eu-
\n
ropean energy system in 2022 and 2023, the Group\u2019s emis-
\n
sions reduction in 2023 was not sufficient to achieve the
\n
Scope 1 GHG emissions intensity target related to electric-
\n
ity generation set for 2023 as announced on the occasion
\n
of the Capital Markets Day held in November 2020 for the
\n
launch of the 2021-2023 Strategic Plan. As a result of the
\n
energy crisis, the intensity value was slightly higher than the
\n
target of 148 gCO
\n
2eq
\n
/kWh. In the absence of these factors,
\n
Enel would have been able to reach an emissions intensity
\n
level well below the target of 148 gCO
\n
2eq
\n
/kWh.
\n
As a result, the Group\u2019s sustainability-linked instruments
\n
that set the Scope 1 emissions intensity target for elec-
\n
tricity generation at 148 gCO
\n
2eq
\n
/kWh for 2023 will be sub-
\n
ject to an increase in the relative step-up.
\n

\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSubordinatedLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1": { "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
\n
variety of financial risks, notably interest rate risk, com-
\n
modity risk, currency risk, credit and counterparty risk and
\n
liquidity risk.
\n
As noted in the section \u201cRisk management\u201d in the Report
\n
on Operations, the Group\u2019s governance arrangements for
\n
financial risks include risk committees and the establish-
\n
ment of dedicated policies, measurement metrics and
\n
operational limits. Enel\u2019s primary objective is to mitigate
\n
financial risks appropriately so that they do not give rise to
\n
unexpected changes 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
\n
portfolio of financial liabilities by contract type, maturity
\n
and interest rate, and modifying the risk profile of spe-
\n
cific exposures using OTC derivatives, mainly interest rate
\n
swaps and interest rate options. The term of such deriv-
\n
atives does not exceed the maturity of the underlying fi-
\n
nancial liability, so that any change in the fair value and/or
\n
expected cash flows of such contracts is offset by a corre-
\n
sponding change in the fair value and/or cash flows of the
\n
hedged position.
\n
Proxy hedging techniques can be used in a number of re-
\n
sidual circumstances, when the hedging instruments for
\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, 2023 and December 31,
\n
2022, broken down by type of contract.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Floating-to-fixed interest rate swaps 5,996 5,836
\n
Fixed-to-floating interest rate swaps 1,386 1,401
\n
Floating-to-floating interest rate swaps 644 618
\n
Total 8,026 7,855
\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 par-
\n
allel increases and decreases in the yield curve as at the
\n
reporting date.
\n
There were no changes introduced in the methods and
\n
assumptions used in the sensitivity analysis compared
\n
with 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
\n\n
\n
\n
\n
\n
Millions of euro 2023
\n
Pre-tax impact on profit
\n
or loss
\n
Pre-tax impact on
\n
equity
\n
Basis points Increase Decrease Increase Decrease
\n
Change in financial expense on gross long-term floating-rate debt after
\n
hedging
\n
25 31 (31) - -
\n
Change in the fair value of derivatives classified as non-hedging
\n
instruments
\n
25 32 (32) - -
\n
Change in the value of derivatives designated as hedging instruments
\n
Cash flow hedges 25 - - 26 (26)
\n
Fair value hedges 25 - - (6) 6
\n
At December 31, 2023, 22.3% (22.3% at December 31,
\n
2022) 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), 82.4% of the nominal value of
\n
gross long-term financial debt was hedged at December
\n
31, 2023 (82.0% at December 31, 2022).
\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
In order to minimize the exposure to currency risk, Enel
\n
implements diversified revenue and cost sources geo-
\n
graphically, and uses indexing mechanisms in commercial
\n
contracts. Enel also uses various types of derivatives, typi-
\n
cally on the OTC market.
\n
The derivatives in the Group\u2019s portfolio of financial in-
\n
struments include cross currency interest rate swaps,
\n
currency forwards and currency swaps. The term of such
\n
contracts does not exceed the maturity of the underlying
\n
instrument, so that any change in the fair value and/or ex-
\n
pected cash flows of such instruments offsets the corre-
\n
sponding change in the fair value and/or cash flows of the
\n
hedged 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
\n
in 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
\n
the actual exchange of the two principal amounts (deliv-
\n
erable forwards) or payment of the difference generated
\n
by differences between the strike exchange rate and the
\n
prevailing exchange rate at maturity (non-deliverable for-
\n
wards). In the latter case, the strike rate and/or the spot
\n
rate can be determined as averages of the rates observed
\n
in a given 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)
\n
that provide for the exchange of principal denominated in
\n
different currencies.
\n
The following table reports the notional amount of trans-
\n
actions outstanding at December 31, 2023 and December
\n
31, 2022, broken down by type of hedged item.
\n
\n
\n\n\n
Millions of euro Notional amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRSs) hedging debt denominated in
\n
currencies other than the euro
\n
25,890 28,444
\n
Currency forwards hedging currency risk on commodities 6,496 8,392
\n
Currency forwards/CCIRSs hedging future cash flows in currencies other
\n
than the euro
\n
3,134 5,333
\n
Other currency forwards 602 1,497
\n
Total 36,122 43,666
\n
\n\n
\n\n
\n
\n\n
More specifically, these include:
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac25,890 million to
\n
hedge the currency risk on debt denominated in cur-
\n
rencies other than the euro (\u20ac28,444 million at Decem-
\n
ber 31, 2022);
\n
\u2022
\n
currency forwards and cross currency swaps with a to-
\n
tal notional amount of \u20ac9,630 million used to hedge the
\n
currency risk associated with purchases of natural gas
\n
and fuel and expected cash flows in currencies other
\n
than the euro (\u20ac13,725 million at December 31, 2022).
\n
\u201cOther currency forwards\u201d include OTC derivatives trans-
\n
actions carried out to mitigate currency risk on expect-
\n
ed cash flows in currencies other than the presentation
\n
currency. This includes transactions connected with the
\n
purchase of investment goods in the renewables sector
\n
(including battery energy storage systems), as well as in-
\n
frastructure and grids sectors (as new generation digital
\n
meters) and operating costs for the supply of cloud ser-
\n
vices and on revenue from the sale of renewable energy.
\n
At December 31, 2023, 49% (51% at December 31, 2022)
\n
of Group long-term debt was denominated in currencies
\n
other than the euro.
\n
Taking account of hedges of currency risk, the percentage
\n
of debt not hedged against that risk amounted to 18% at
\n
December 31, 2023 (18% at December 31, 2022).
\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 poten-
\n
tial impact on profit or loss and equity of market scenarios
\n
that would cause a change in the fair value of derivatives
\n
or in the financial expense associated with unhedged
\n
gross medium/long-term debt.
\n
These scenarios are obtained by simulating the appreci-
\n
ation/depreciation of the euro against all of the curren-
\n
cies compared with the value observed as at the reporting
\n
date.
\n
There were no changes in the methods or assumptions
\n
used in the sensitivity analysis compared with the previous
\n
year.
\n
With all other variables held constant, the pre-tax profit
\n
would be affected by changes in exchange rates as follows.
\n
Millions of euro 2023
\n
Pre-tax impact on
\n
profit or loss
\n
Pre-tax impact
\n
on equity
\n
Exchange rate EUR appr. EUR depr. EUR appr. EUR depr.
\n
Change in the fair value of derivatives classified as non-
\n
hedging instruments
\n
10% 494 (603) - -
\n
Change in the fair value of derivatives designated as
\n
hedging instruments
\n
Cash flow hedges 10% - - (2,883) 3,522
\n
Fair value hedges 10% (44) 53 - -
\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 mar-
\n
gins, in accordance with the policies and operating lim-
\n
its determined by the Group\u2019s governance and leaving an
\n
appropriate margin of flexibility to seize any short-term
\n
opportunities that may present themselves, Enel devel-
\n
ops and plans strategies that impact the various phases
\n
of the industrial process linked to the production and sale
\n
of electricity and gas (such as forward procurement and
\n
long-term commercial agreements), as well as risk miti-
\n
gation plans and techniques using derivative contracts
\n
(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 (Power Purchase Agreements, or PPAs) and finan-
\n
cial contracts (e.g., contracts for differences, Virtual Power
\n
Purchase Agreements or VPPAs, etc.) in which differences
\n
are paid to the counterparty if the market electricity price
\n
exceeds the strike price and to Enel in the opposite case.
\n
\n\n
\n\n\n
The table below shows the main characteristics of PPA and
\n
VPPA contracts at December 31, 2023.
\n
at Dec. 31, 2023
\n
Country Type of contract Sell/Buy Price terms
\n
Volume of power
\n
contracted (GWh) Duration (years)
\n
Accounting
\n
treatment
\n
Italy PPA Buy fixed price 17.3 1 FVTPL
\n
Italy PPA Buy fixed price 35.8 1 FVTPL
\n
Italy PPA Buy floating price 1,501.5 1 FVTPL
\n
Italy PPA Buy floating price 28.7 2 FVTPL
\n
Italy PPA Buy fixed price 395.9 10
\n
Own use
\n
exemption
\n
Italy VPPA Sell fixed price 1,801.2 4 CFH
\n
Italy VPPA Sell fixed price 800.0 4 CFH
\n
Iberia VPPA Buy fixed price 30.0 9 FVTPL
\n
Iberia VPPA Buy fixed price 22,650.0 15 CFH
\n
Iberia VPPA Sell fixed price 14,010.0 18 CFH
\n
Germany VPPA Buy floating price 44.7 2 FVTPL
\n
United States VPPA Sell fixed price 49.9 8-20 CFH
\n
United States VPPA Sell fixed price 15.5 8-15 FVTPL
\n
United States VPPA Sell fixed price 2.3 12-20
\n
Own use
\n
exemption
\n
United States VPPA Sell floating price 3.4 12 CFH
\n
United States PPA Sell fixed price 6.0 12 CFH
\n
United States PPA Sell fixed price 6.0 12 FVTPL
\n
United States PPA Sell fixed price 194.4 10-30
\n
Own use
\n
exemption
\n
United States PPA Sell floating price 12.2 12-30
\n
Own use
\n
exemption
\n
South Africa PPA Sell floating price 1.2 20 FVTPL
\n
Brazil PPA Sell fixed price 115,542.6 1-20
\n
Own use
\n
exemption
\n
Brazil PPA Buy fixed price 37,474.9 1-16
\n
Own use
\n
exemption
\n
Chile PPA Sell fixed price 249,377.4 1-15
\n
Own use
\n
exemption
\n
Chile PPA Sell floating price 258.0 1-3
\n
Own use
\n
exemption
\n
Chile VPPA Sell fixed price 27,828.2 4 -10
\n
Own use
\n
exemption
\n
Chile VPPA Buy fixed price 50,101.9 5-15
\n
Own use
\n
exemption
\n
Chile PPA Buy fixed price 98,412.7 1-20
\n
Own use
\n
exemption
\n
Colombia VPPA Sell fixed price 91,509.4 1-16
\n
Own use
\n
exemption
\n
Colombia VPPA Sell floating price 4,546.3 1-10
\n
Own use
\n
exemption
\n
Colombia VPPA Buy fixed price 56,763.5 1-19
\n
Own use
\n
exemption
\n
Guatemala VPPA Sell fixed price 3,336.0 1-15
\n
Own use
\n
exemption
\n
Guatemala VPPA Sell floating price 20.0 1-2
\n
Own use
\n
exemption
\n
Panama VPPA Sell fixed price 23,858.0 3-15
\n
Own use
\n
exemption
\n
Panama VPPA Sell floating price 4,253.0 5-25
\n
Own use
\n
exemption
\n
Panama VPPA Buy fixed price 263.0 7-10
\n
Own use
\n
exemption
\n
Panama VPPA Buy floating price 1,455.0 1-2
\n
Own use
\n
exemption
\n
Peru PPA Buy fixed price 5 47. 1 1-8
\n
Own use
\n
exemption
\n
Peru PPA Sell fixed price 75,938.8 1-12
\n
Own use
\n
exemption
\n
Peru PPA Sell floating price 115.0 2-5
\n
Own use
\n
exemption
\n
\n\n
\n\n
\n\n
The residual exposure in respect of the sale of energy on
\n
the spot market not hedged with such contracts is aggre-
\n
gated by uniform risk factors that can be managed with
\n
hedging transactions on the market. Proxy hedging tech-
\n
niques can be used for the industrial portfolios when the
\n
hedging instruments for the specific risk factors generat-
\n
ing 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
while always complying with the limits set on the basis of
\n
portfolio risk analysis.
\n
The following table reports the notional amount of out-
\n
standing transactions at December 31, 2023 and Decem-
\n
ber 31, 2022, broken down by type of instrument.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Forward and futures contracts 44,307 114,128
\n
Swaps 7,69 4 11,271
\n
Options 1,407 504
\n
Total 53,408 125,903
\n
For more details, please see note 51 \u201cDerivatives and
\n
hedge 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
\n
in the price curve is primarily due to changes in the price
\n
of electricity, petroleum products and, to a lesser extent,
\n
CO
\n
2
\n
. The Group\u2019s exposure to changes in the prices of
\n
other commodities is not material.
\n
Millions of euro 2023
\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
15% (39) 40 - -
\n
Change in the fair value of derivatives on commodities
\n
designated as hedging instruments
\n
15% (19) 25 (442) 437
\n
\n\n
\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
\n
is attributable to the following types of transactions:
\n
\u2022
\n
the sale and distribution of electricity and gas in free
\n
and regulated markets and the supply of goods and
\n
services (trade receivables in respect of non-Group
\n
debtors);
\n
\u2022
\n
trading activities that involve the physical exchange
\n
of assets or transactions in financial instruments (the
\n
commodity portfolio);
\n
\u2022
\n
trading in derivatives, bank deposits and, more gener-
\n
ally, 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 the region/countries/global
\n
business lines and at the consolidated level \u2013 in measuring
\n
commercial credit exposures in order to promptly identify
\n
any deterioration in the quality of outstanding receivables
\n
and any mitigation actions to be taken.
\n
The policy for managing credit and counterparty risk as-
\n
sociated with commercial activities provides for a prelimi-
\n
nary assessment of the creditworthiness of counterparties
\n
and the adoption of mitigation instruments, such as ob-
\n
taining 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
plementation at the level of region/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, 2023
\n
Staging
\n
Basis for recognition
\n
of expected credit loss
\n
allowance
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Performing 12-month ECL 4.0% 6,664 264 6,400
\n
Underperforming Lifetime ECL 2.8% 321 9 312
\n
Non-performing Lifetime ECL 6.4% 594 38 556
\n
Total 7,579 311 7,268
\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, 2023
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance
\n
Carrying
\n
amount
\n
Contract assets - 83 - 83
\n
Trade receivables
\n
Trade receivables not past due 0.5% 6,225 32 6,193
\n
Trade receivables past due:
\n
- 1-30 days 2.0% 350 7 343
\n
- 31-60 days 1.9% 103 2 101
\n
- 61-90 days 5.3% 38 2 36
\n
- 91-120 days 12.2% 41 5 36
\n
- 121-150 days 13.2% 53 7 46
\n
- 151-180 days 8.2% 49 4 45
\n
- more than 180 days (credit impaired) 83.9% 1 ,474 1,236 238
\n
Total trade receivables 8,333 1,295 7,038
\n
Other financial assets
\n
Other financial assets not past due 0.4% 1,690 7 1,683
\n
Other financial assets past due:
\n
- 1-30 days - 25 - 25
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - 2 - 2
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) 2.7% 75 2 73
\n
Total other financial assets 1,792 9 1,783
\n
TOTAL 10,208 1,304 8,904
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
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
\n\n
\n\n
\n\n
Contract assets, trade receivables and other financial assets: collective measurement
\n
Millions of euro
\n
at Dec. 31, 2023
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance
\n
Carrying
\n
amount
\n
Contract assets 1.3% 150 2 148
\n
Trade receivables
\n
Trade receivables not past due 2.9% 8,322 239 8,083
\n
Trade receivables past due:
\n
- 1-30 days 2.6% 802 21 781
\n
- 31-60 days 44.3% 70 31 39
\n
- 61-90 days 19.5% 210 41 169
\n
- 91-120 days 25.8% 132 34 98
\n
- 121-150 days 50.8% 132 67 65
\n
- 151-180 days 52.9% 119 63 56
\n
- more than 180 days (credit impaired) 57.9% 3,428 1,984 1,444
\n
Total trade receivables 13,215 2,480 10,735
\n
Other financial assets
\n
Other financial assets not past due - 604 - 604
\n
Other financial assets past due:
\n
- 1-30 days 66.7% 3 2 1
\n
- 31-60 days - - - -
\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) 50.0% 2 1 1
\n
Total other financial assets 611 3 608
\n
TOTAL 13,976 2,485 11,491
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
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
\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
\n
of sources of funding on different markets, in different
\n
currencies 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, 2023 at Dec. 31, 2022
\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 823 19,040 355 19,122
\n
Uncommitted credit lines 734 - 980 -
\n
Commercial paper 15,027 - 3,847 -
\n
Total 16,584 19,040 5,182 19,122
\n
Maturity analysis
\n
The table below summarizes the maturity profile of the re-
\n
payment plans of the Group\u2019s gross long- and short-term
\n
financial debt at December 31, 2023.
\n
Millions of euro Maturing in
\n
Less than 3
\n
months
\n
From 3 months
\n
to 1 year 2025 2026 2027 2028 Beyond
\n
Gross long-term financial debt
\n
Bonds:
\n
- listed, fixed rate - 4,686 3,425 3,838 3,764 946 12,504
\n
- listed, floating rate 186 437 342 435 221 117 884
\n
- unlisted, fixed rate - 1,357 1,351 1,126 2,448 2,023 9,824
\n
- unlisted, floating rate - 97 97 97 97 - 40
\n
Total bonds 186 6,577 5,215 5,496 6,530 3,086 23,252
\n
Bank borrowings:
\n
- fixed rate 63 790 231 413 730 1,006 589
\n
- floating rate 126 1,013 1,479 2,489 1,140 1,410 4,972
\n
- use of revolving credit lines - - 23 - 18 - -
\n
Total bank borrowings 189 1,803 1,733 2,902 1,888 2,416 5,561
\n
Leases:
\n
- fixed rate 76 180 267 243 200 166 1,720
\n
- floating rate 3 9 14 9 3 3 12
\n
Total leases 79 189 281 252 203 169 1,732
\n
Other non-bank borrowings:
\n
(1)
\n
- fixed rate 24 39 70 69 44 8 172
\n
- floating rate - - 14 - - - -
\n
Total other non-bank borrowings 24 39 84 69 44 8 172
\n
Total gross long-term financial debt 478 8,608 7,313 8,719 8,665 5,679 30,717
\n
Gross short-term financial debt
\n
Short-term bank borrowings 101 292 - - - - -
\n
Commercial paper 2,499 - - - - - -
\n
Cash collateral and other financing on derivatives 1,383 - - - - - -
\n
Other short-term financial debt
\n
(2)
\n
489 6 - - - - -
\n
Total gross short-term financial debt 4,472 298 - - - - -
\n
TOTAL GROSS FINANCIAL DEBT 4,950 8,906 7,313 8,719 8,665 5,679 30,717
\n
(1) Includes other non-current financial borrowings presented under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(2) Includes other current financial borrowings included in \u201cOther current financial liabilities\u201d in the statement of financial position.
\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 commodi-
\n
ties at a certain future date for its own use, which qualify
\n
for 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, 2023.
\n
Millions of euro
\n
at Dec. 31, 2023 2023-2026 2027-2031 2032-2036 Beyond
\n
Commitments to purchase commodities:
\n
- electricity 63,422 13,820 18,167 12,420 19,015
\n
- fuels 47,666 11,998 23,399 8,802 3,467
\n
Total 111,088 25,818 41,566 21,222 22,482
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag2": { "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
In order to minimize the exposure to currency risk, Enel
\n
implements diversified revenue and cost sources geo-
\n
graphically, and uses indexing mechanisms in commercial
\n
contracts. Enel also uses various types of derivatives, typi-
\n
cally on the OTC market.
\n
The derivatives in the Group\u2019s portfolio of financial in-
\n
struments include cross currency interest rate swaps,
\n
currency forwards and currency swaps. The term of such
\n
contracts does not exceed the maturity of the underlying
\n
instrument, so that any change in the fair value and/or ex-
\n
pected cash flows of such instruments offsets the corre-
\n
sponding change in the fair value and/or cash flows of the
\n
hedged 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
\n
in 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
\n
the actual exchange of the two principal amounts (deliv-
\n
erable forwards) or payment of the difference generated
\n
by differences between the strike exchange rate and the
\n
prevailing exchange rate at maturity (non-deliverable for-
\n
wards). In the latter case, the strike rate and/or the spot
\n
rate can be determined as averages of the rates observed
\n
in a given 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)
\n
that provide for the exchange of principal denominated in
\n
different currencies.
\n
The following table reports the notional amount of trans-
\n
actions outstanding at December 31, 2023 and December
\n
31, 2022, broken down by type of hedged item.
\n
\n
\n\n
Millions of euro Notional amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRSs) hedging debt denominated in
\n
currencies other than the euro
\n
25,890 28,444
\n
Currency forwards hedging currency risk on commodities 6,496 8,392
\n
Currency forwards/CCIRSs hedging future cash flows in currencies other
\n
than the euro
\n
3,134 5,333
\n
Other currency forwards 602 1,497
\n
Total 36,122 43,666
\n
\n\n
More specifically, these include:
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac25,890 million to
\n
hedge the currency risk on debt denominated in cur-
\n
rencies other than the euro (\u20ac28,444 million at Decem-
\n
ber 31, 2022);
\n
\u2022
\n
currency forwards and cross currency swaps with a to-
\n
tal notional amount of \u20ac9,630 million used to hedge the
\n
currency risk associated with purchases of natural gas
\n
and fuel and expected cash flows in currencies other
\n
than the euro (\u20ac13,725 million at December 31, 2022).
\n
\u201cOther currency forwards\u201d include OTC derivatives trans-
\n
actions carried out to mitigate currency risk on expect-
\n
ed cash flows in currencies other than the presentation
\n
currency. This includes transactions connected with the
\n
purchase of investment goods in the renewables sector
\n
(including battery energy storage systems), as well as in-
\n
frastructure and grids sectors (as new generation digital
\n
meters) and operating costs for the supply of cloud ser-
\n
vices and on revenue from the sale of renewable energy.
\n
At December 31, 2023, 49% (51% at December 31, 2022)
\n
of Group long-term debt was denominated in currencies
\n
other than the euro.
\n
Taking account of hedges of currency risk, the percentage
\n
of debt not hedged against that risk amounted to 18% at
\n
December 31, 2023 (18% at December 31, 2022).
\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 poten-
\n
tial impact on profit or loss and equity of market scenarios
\n
that would cause a change in the fair value of derivatives
\n
or in the financial expense associated with unhedged
\n
gross medium/long-term debt.
\n
These scenarios are obtained by simulating the appreci-
\n
ation/depreciation of the euro against all of the curren-
\n
cies compared with the value observed as at the reporting
\n
date.
\n
There were no changes in the methods or assumptions
\n
used in the sensitivity analysis compared with the previous
\n
year.
\n
With all other variables held constant, the pre-tax profit
\n
would be affected by changes in exchange rates as follows.
\n
Millions of euro 2023
\n
Pre-tax impact on
\n
profit or loss
\n
Pre-tax impact
\n
on equity
\n
Exchange rate EUR appr. EUR depr. EUR appr. EUR depr.
\n
Change in the fair value of derivatives classified as non-
\n
hedging instruments
\n
10% 494 (603) - -
\n
Change in the fair value of derivatives designated as
\n
hedging instruments
\n
Cash flow hedges 10% - - (2,883) 3,522
\n
Fair value hedges 10% (44) 53 - -
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
37 - (37) - - 15 - (15) - -
\n
Floating-rate loan
\n
assets
\n
7 - (7) - - 9 - (9) - -
\n
Floating-rate
\n
borrowings
\n
(149) (20) 149 - (1) (327) (28) 326 - 2
\n
Total (105) (20) 105 - (1) (303) (28) 302 - 2
\n
Currency risk
\n
The following table reports the maturity profile of the
\n
notional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2023 and De-
\n
cember 31, 2022.
\n
Millions of euro Maturity
\n
2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 4,562 2,577 1,222 2,337 2,037 13,386 26,121
\n
Notional amount for CCIRSs EUR/USD 2,213 2,036 1,132 1,560 2,037 9,102 18,080
\n
Average exchange rate EUR/USD 1.13 1.07 1.07 1.10 1.18 1.15
\n
Notional amount for CCIRSs EUR/GBP 981 - - 577 - 3,856 5,414
\n
Average exchange rate EUR/GBP 0.88 0.90 0.82
\n
Notional amount for CCIRSs EUR/CHF 242 - - 140 - - 382
\n
Average exchange rate EUR/CHF 1.07 1.21
\n
Notional amount for CCIRSs USD/BRL 279 231 91 - - 387 988
\n
Average exchange rate USD/BRL 5.50 5.22 5.30 4.13
\n
Notional amount for CCIRSs EUR/BRL 445 231 - 60 - - 736
\n
Average exchange rate EUR/BRL 6.25 6.05 3.92
\n
Currency forwards
\n
Total notional amount of forwards 4,616 1,186 507 - - - 6,309
\n
Notional amount - currency forwards EUR/USD 3,144 1,042 507 - - - 4,693
\n
Average currency forward rate - EUR/USD 1.10 1.11 1.13
\n
Notional amount - currency forwards USD/CLP 938 141 - - - - 1,079
\n
Average currency forward rate - USD/CLP 873.05 885.2239
\n
Notional amount - currency forwards EUR/CNH 175 - - - - - 175
\n
Average currency forward rate - EUR/CNH 7.8 1
\n
Notional amount - currency forwards USD/BRL 130 - - - - - 130
\n
Average currency forward rate - USD/BRL 4.95
\n
Notional amount - currency forwards USD/COP 122 2 - - - - 124
\n
Average currency forward rate - USD/COP 4,498.97 4,597.37
\n
\n\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRSs 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 CCIRSs EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount CCIRSs EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRSs 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 CCIRSs 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 - - - 7,6 83
\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
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, 2023 and
\n
December 31, 2022 broken down by type of hedged item.
\n
Millions or 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, 2023 at Dec. 31, 2022
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
12 (78) 1,019 15 (99) 1,097
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings in
\n
foreign currencies
\n
- - - - - -
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings/
\n
financial assets in foreign
\n
currencies
\n
67 (36) 754 95 (76) 1,061
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
5 (220) 2,104 4 (233) 2,445
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate bonds in foreign
\n
currencies
\n
56 - 250 60 - 414
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
965 (1,724) 21,763 1,864 (1,293) 23,381
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Future cash flows denominated
\n
in foreign currencies
\n
- (43) 231 - (50) 335
\n
Currency forwards
\n
Future cash flows denominated
\n
in foreign currencies
\n
2 (1) 117 9 (6) 326
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign
\n
currencies
\n
54 (126) 5,666 192 (135) 7,508
\n
Currency forwards
\n
Purchases of investment goods
\n
and other in foreign currencies
\n
3 (12) 526 19 (23) 1,292
\n
Total 1,164 (2,240) 32,430 2,258 (1,915) 37,859
\n
Cash flow hedges and fair value hedges include:
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac24,886 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro with a negative
\n
fair value of \u20ac1,040 million;
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac1,235 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 \u20ac44 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac5,783
\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 negative fair value of \u20ac71 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac526 mil-
\n
lion and a negative fair value of \u20ac9 million, in respect
\n
of OTC transactions to mitigate the currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of
\n
investment goods in the renewables (including Battery
\n
Energy Storage Systems - BESS) 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 val-
\n
ue of foreign exchange derivatives at December 31, 2023
\n
and December 31, 2022, broken down by type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Fair value hedges
\n
CCIRSs 90 99 12 15 929 998 (78) (99)
\n
Total 90 99 12 15 929 998 (78) (99)
\n
Cash flow hedges
\n
Currency forwards 1,979 4,313 59 220 4,330 4,813 (140) (164)
\n
CCIRSs 13,474 16,695 1,093 2,023 11,628 10,941 (2,022) (1,652)
\n
Total 15,453 21,008 1,152 2,243 15,958 15,754 (2,162) (1,816)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
15,543 21,107 1,164 2,258 16,887 16,752 (2,240) (1,915)
\n
\n\n
The notional amount of CCIRSs at December 31, 2023
\n
amounted to \u20ac26,121 million, a decrease of \u20ac2,612 million
\n
from \u20ac28,733 million at December 31, 2022. In particular:
\n
\u2022
\n
CCIRSs with a total amount of \u20ac737 million expired;
\n
\u2022
\n
a partial unwinding operation of CCIRSs was carried out
\n
following the early repurchase of part of the hybrid bond
\n
denominated in US dollars. That transaction, together
\n
with the natural expiry of the residual portion of that li-
\n
ability and the associated CCIRSs, caused a decrease in
\n
the notional amount compared with December 31, 2022
\n
of \u20ac1,171 million;
\n
\u2022
\n
new derivatives amounted to \u20ac109 million. The notional
\n
amount decreased by \u20ac813 million, reflecting develop-
\n
ments in the exchange rate of the euro against the main
\n
other currencies and the effect of amortization.
\n
The notional amount of currency forwards at December 31,
\n
2023 amounted to \u20ac6,309 million (\u20ac9,126 million at Decem-
\n
ber 31, 2022), a decrease of \u20ac2,817 million. The exposure to
\n
currency risk, especially that associated with the US dollar,
\n
is mainly due to purchases of natural gas, purchases of fuel
\n
and cash flows in respect of investments.
\n
After the turbulence experienced in raw material prices
\n
during 2022, which led to a considerable increase in the
\n
notional amounts hedged, the notional value of currency
\n
hedges on energy commodities returned to normal oper-
\n
ating levels in 2023. The deterioration of net fair value of
\n
\u20ac137 million reflected normal developments in exchange
\n
rates.
\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 2023 and the pre-
\n
vious year.
\n
Millions of euro 2023 2022
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments 20 (119)
\n
Hedged item (12) 129
\n
Ineffective portion 8 10
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 1,019 (66) (68) 1,097 (84) (87)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 bonds in foreign currencies 500 (77) 48 458 (106) 90
\n
Fixed-rate borrowings in foreign
\n
currencies
\n
434 (7) 24 520 (8) (2)
\n
Total 934 (84) 72 978 (114) 88
\n
\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in coming
\n
years from cash flow hedge derivatives on currency risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 1,152 358 216 258 211 273 885
\n
Negative fair value (2,162) (960) (594) (13) (34) (18) (644)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 25,102 (930) (919) 27,636 371 433
\n
Currency forwards 6,309 (80) (73) 9,126 56 56
\n
Total 31,411 (1,010) (992) 36,762 427 489
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
\n
effects
\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
Other
\n
effects
\n
(1)
\n
Floating-rate
\n
borrowings in
\n
foreign currencies
\n
(31) 31 - - - (30) 30 - (11) -
\n
Fixed-rate
\n
borrowings in
\n
foreign currencies
\n
219 (219) 4 - - 225 (225) (4) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(56) 56 - - - (60) 60 - - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
861 (861) (15) - 118 (628) 509 (56) - 118
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
CCIRSs)
\n
43 (43) - - - 50 (50) - - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(1) 1 - - - (3) 3 - - -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
72 (72) (1) - - (60) 59 (1) (1) -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
3 (3) (6) - - 7 (7) 1 2 -
\n
Total 1,110 (1,110) (18) - 118 (499) 379 (60) (10) 118
\n
(1) Impact connected with the change in spot exchange rates between the date the CCIRSs to hedge bonds in foreign currencies were obtained and the
\n
actual disbursement of the loan for the CCIRSs obtained in 2022.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag3": { "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 mar-
\n
gins, in accordance with the policies and operating lim-
\n
its determined by the Group\u2019s governance and leaving an
\n
appropriate margin of flexibility to seize any short-term
\n
opportunities that may present themselves, Enel devel-
\n
ops and plans strategies that impact the various phases
\n
of the industrial process linked to the production and sale
\n
of electricity and gas (such as forward procurement and
\n
long-term commercial agreements), as well as risk miti-
\n
gation plans and techniques using derivative contracts
\n
(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 (Power Purchase Agreements, or PPAs) and finan-
\n
cial contracts (e.g., contracts for differences, Virtual Power
\n
Purchase Agreements or VPPAs, etc.) in which differences
\n
are paid to the counterparty if the market electricity price
\n
exceeds the strike price and to Enel in the opposite case.
\n
\n\n
The table below shows the main characteristics of PPA and
\n
VPPA contracts at December 31, 2023.
\n
at Dec. 31, 2023
\n
Country Type of contract Sell/Buy Price terms
\n
Volume of power
\n
contracted (GWh) Duration (years)
\n
Accounting
\n
treatment
\n
Italy PPA Buy fixed price 17.3 1 FVTPL
\n
Italy PPA Buy fixed price 35.8 1 FVTPL
\n
Italy PPA Buy floating price 1,501.5 1 FVTPL
\n
Italy PPA Buy floating price 28.7 2 FVTPL
\n
Italy PPA Buy fixed price 395.9 10
\n
Own use
\n
exemption
\n
Italy VPPA Sell fixed price 1,801.2 4 CFH
\n
Italy VPPA Sell fixed price 800.0 4 CFH
\n
Iberia VPPA Buy fixed price 30.0 9 FVTPL
\n
Iberia VPPA Buy fixed price 22,650.0 15 CFH
\n
Iberia VPPA Sell fixed price 14,010.0 18 CFH
\n
Germany VPPA Buy floating price 44.7 2 FVTPL
\n
United States VPPA Sell fixed price 49.9 8-20 CFH
\n
United States VPPA Sell fixed price 15.5 8-15 FVTPL
\n
United States VPPA Sell fixed price 2.3 12-20
\n
Own use
\n
exemption
\n
United States VPPA Sell floating price 3.4 12 CFH
\n
United States PPA Sell fixed price 6.0 12 CFH
\n
United States PPA Sell fixed price 6.0 12 FVTPL
\n
United States PPA Sell fixed price 194.4 10-30
\n
Own use
\n
exemption
\n
United States PPA Sell floating price 12.2 12-30
\n
Own use
\n
exemption
\n
South Africa PPA Sell floating price 1.2 20 FVTPL
\n
Brazil PPA Sell fixed price 115,542.6 1-20
\n
Own use
\n
exemption
\n
Brazil PPA Buy fixed price 37,474.9 1-16
\n
Own use
\n
exemption
\n
Chile PPA Sell fixed price 249,377.4 1-15
\n
Own use
\n
exemption
\n
Chile PPA Sell floating price 258.0 1-3
\n
Own use
\n
exemption
\n
Chile VPPA Sell fixed price 27,828.2 4 -10
\n
Own use
\n
exemption
\n
Chile VPPA Buy fixed price 50,101.9 5-15
\n
Own use
\n
exemption
\n
Chile PPA Buy fixed price 98,412.7 1-20
\n
Own use
\n
exemption
\n
Colombia VPPA Sell fixed price 91,509.4 1-16
\n
Own use
\n
exemption
\n
Colombia VPPA Sell floating price 4,546.3 1-10
\n
Own use
\n
exemption
\n
Colombia VPPA Buy fixed price 56,763.5 1-19
\n
Own use
\n
exemption
\n
Guatemala VPPA Sell fixed price 3,336.0 1-15
\n
Own use
\n
exemption
\n
Guatemala VPPA Sell floating price 20.0 1-2
\n
Own use
\n
exemption
\n
Panama VPPA Sell fixed price 23,858.0 3-15
\n
Own use
\n
exemption
\n
Panama VPPA Sell floating price 4,253.0 5-25
\n
Own use
\n
exemption
\n
Panama VPPA Buy fixed price 263.0 7-10
\n
Own use
\n
exemption
\n
Panama VPPA Buy floating price 1,455.0 1-2
\n
Own use
\n
exemption
\n
Peru PPA Buy fixed price 5 47. 1 1-8
\n
Own use
\n
exemption
\n
Peru PPA Sell fixed price 75,938.8 1-12
\n
Own use
\n
exemption
\n
Peru PPA Sell floating price 115.0 2-5
\n
Own use
\n
exemption
\n
\n\n
The residual exposure in respect of the sale of energy on
\n
the spot market not hedged with such contracts is aggre-
\n
gated by uniform risk factors that can be managed with
\n
hedging transactions on the market. Proxy hedging tech-
\n
niques can be used for the industrial portfolios when the
\n
hedging instruments for the specific risk factors generat-
\n
ing 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
while always complying with the limits set on the basis of
\n
portfolio risk analysis.
\n
The following table reports the notional amount of out-
\n
standing transactions at December 31, 2023 and Decem-
\n
ber 31, 2022, broken down by type of instrument.
\n
Millions of euro Notional amount
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Forward and futures contracts 44,307 114,128
\n
Swaps 7,69 4 11,271
\n
Options 1,407 504
\n
Total 53,408 125,903
\n
For more details, please see note 51 \u201cDerivatives and
\n
hedge 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
\n
in the price curve is primarily due to changes in the price
\n
of electricity, petroleum products and, to a lesser extent,
\n
CO
\n
2
\n
. The Group\u2019s exposure to changes in the prices of
\n
other commodities is not material.
\n
Millions of euro 2023
\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
15% (39) 40 - -
\n
Change in the fair value of derivatives on commodities
\n
designated as hedging instruments
\n
15% (19) 25 (442) 437
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag4": { "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
\n
is attributable to the following types of transactions:
\n
\u2022
\n
the sale and distribution of electricity and gas in free
\n
and regulated markets and the supply of goods and
\n
services (trade receivables in respect of non-Group
\n
debtors);
\n
\u2022
\n
trading activities that involve the physical exchange
\n
of assets or transactions in financial instruments (the
\n
commodity portfolio);
\n
\u2022
\n
trading in derivatives, bank deposits and, more gener-
\n
ally, 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 the region/countries/global
\n
business lines and at the consolidated level \u2013 in measuring
\n
commercial credit exposures in order to promptly identify
\n
any deterioration in the quality of outstanding receivables
\n
and any mitigation actions to be taken.
\n
The policy for managing credit and counterparty risk as-
\n
sociated with commercial activities provides for a prelimi-
\n
nary assessment of the creditworthiness of counterparties
\n
and the adoption of mitigation instruments, such as ob-
\n
taining 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
plementation at the level of region/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, 2023
\n
Staging
\n
Basis for recognition
\n
of expected credit loss
\n
allowance
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit
\n
loss allowance
\n
Carrying
\n
amount
\n
Performing 12-month ECL 4.0% 6,664 264 6,400
\n
Underperforming Lifetime ECL 2.8% 321 9 312
\n
Non-performing Lifetime ECL 6.4% 594 38 556
\n
Total 7,579 311 7,268
\n
\n\n
Contract assets, trade receivables and other financial assets: individual measurement
\n
Millions of euro
\n
at Dec. 31, 2023
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance
\n
Carrying
\n
amount
\n
Contract assets - 83 - 83
\n
Trade receivables
\n
Trade receivables not past due 0.5% 6,225 32 6,193
\n
Trade receivables past due:
\n
- 1-30 days 2.0% 350 7 343
\n
- 31-60 days 1.9% 103 2 101
\n
- 61-90 days 5.3% 38 2 36
\n
- 91-120 days 12.2% 41 5 36
\n
- 121-150 days 13.2% 53 7 46
\n
- 151-180 days 8.2% 49 4 45
\n
- more than 180 days (credit impaired) 83.9% 1 ,474 1,236 238
\n
Total trade receivables 8,333 1,295 7,038
\n
Other financial assets
\n
Other financial assets not past due 0.4% 1,690 7 1,683
\n
Other financial assets past due:
\n
- 1-30 days - 25 - 25
\n
- 31-60 days - - - -
\n
- 61-90 days - - - -
\n
- 91-120 days - - - -
\n
- 121-150 days - 2 - 2
\n
- 151-180 days - - - -
\n
- more than 180 days (credit impaired) 2.7% 75 2 73
\n
Total other financial assets 1,792 9 1,783
\n
TOTAL 10,208 1,304 8,904
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
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
\n\n
Contract assets, trade receivables and other financial assets: collective measurement
\n
Millions of euro
\n
at Dec. 31, 2023
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
allowance
\n
Carrying
\n
amount
\n
Contract assets 1.3% 150 2 148
\n
Trade receivables
\n
Trade receivables not past due 2.9% 8,322 239 8,083
\n
Trade receivables past due:
\n
- 1-30 days 2.6% 802 21 781
\n
- 31-60 days 44.3% 70 31 39
\n
- 61-90 days 19.5% 210 41 169
\n
- 91-120 days 25.8% 132 34 98
\n
- 121-150 days 50.8% 132 67 65
\n
- 151-180 days 52.9% 119 63 56
\n
- more than 180 days (credit impaired) 57.9% 3,428 1,984 1,444
\n
Total trade receivables 13,215 2,480 10,735
\n
Other financial assets
\n
Other financial assets not past due - 604 - 604
\n
Other financial assets past due:
\n
- 1-30 days 66.7% 3 2 1
\n
- 31-60 days - - - -
\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) 50.0% 2 1 1
\n
Total other financial assets 611 3 608
\n
TOTAL 13,976 2,485 11,491
\n
Millions of euro
\n
at Dec. 31, 2022
\n
Average loss rate
\n
(PD*LGD)
\n
Gross carrying
\n
amount
\n
Expected credit loss
\n
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
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag5": { "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
\n
of sources of funding on different markets, in different
\n
currencies 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, 2023 at Dec. 31, 2022
\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 823 19,040 355 19,122
\n
Uncommitted credit lines 734 - 980 -
\n
Commercial paper 15,027 - 3,847 -
\n
Total 16,584 19,040 5,182 19,122
\n
Maturity analysis
\n
The table below summarizes the maturity profile of the re-
\n
payment plans of the Group\u2019s gross long- and short-term
\n
financial debt at December 31, 2023.
\n
Millions of euro Maturing in
\n
Less than 3
\n
months
\n
From 3 months
\n
to 1 year 2025 2026 2027 2028 Beyond
\n
Gross long-term financial debt
\n
Bonds:
\n
- listed, fixed rate - 4,686 3,425 3,838 3,764 946 12,504
\n
- listed, floating rate 186 437 342 435 221 117 884
\n
- unlisted, fixed rate - 1,357 1,351 1,126 2,448 2,023 9,824
\n
- unlisted, floating rate - 97 97 97 97 - 40
\n
Total bonds 186 6,577 5,215 5,496 6,530 3,086 23,252
\n
Bank borrowings:
\n
- fixed rate 63 790 231 413 730 1,006 589
\n
- floating rate 126 1,013 1,479 2,489 1,140 1,410 4,972
\n
- use of revolving credit lines - - 23 - 18 - -
\n
Total bank borrowings 189 1,803 1,733 2,902 1,888 2,416 5,561
\n
Leases:
\n
- fixed rate 76 180 267 243 200 166 1,720
\n
- floating rate 3 9 14 9 3 3 12
\n
Total leases 79 189 281 252 203 169 1,732
\n
Other non-bank borrowings:
\n
(1)
\n
- fixed rate 24 39 70 69 44 8 172
\n
- floating rate - - 14 - - - -
\n
Total other non-bank borrowings 24 39 84 69 44 8 172
\n
Total gross long-term financial debt 478 8,608 7,313 8,719 8,665 5,679 30,717
\n
Gross short-term financial debt
\n
Short-term bank borrowings 101 292 - - - - -
\n
Commercial paper 2,499 - - - - - -
\n
Cash collateral and other financing on derivatives 1,383 - - - - - -
\n
Other short-term financial debt
\n
(2)
\n
489 6 - - - - -
\n
Total gross short-term financial debt 4,472 298 - - - - -
\n
TOTAL GROSS FINANCIAL DEBT 4,950 8,906 7,313 8,719 8,665 5,679 30,717
\n
(1) Includes other non-current financial borrowings presented under \u201cOther non-current financial liabilities\u201d in the statement of financial position.
\n
(2) Includes other current financial borrowings included in \u201cOther current financial liabilities\u201d in the statement of financial position.
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag6": { "value": "\n
50. Offsetting financial assets and financial liabilities
\n
At December 31, 2023 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag7": { "value": "\n
51.1 Derivatives designated as hedging
\n
instruments
\n
Derivatives are initially recognized at fair value, on the
\n
trade date of the contract, and are subsequently re-mea-
\n
sured at their fair value. The method of recognizing the
\n
resulting gain or loss depends on whether the derivative is
\n
designated as a hedging instrument, and if so, the nature
\n
of the 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) when all
\n
the criteria provided 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
\n
fair value hedges;
\n
\u2022
\n
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
\n
existence of an economic relationship between hedg-
\n
ing instrument and hedged item;
\n
\u2022
\n
the effect of credit risk does not dominate the value
\n
changes resulting from the economic relationship;
\n
\u2022
\n
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
\n
a qualitative assessment or a quantitative computation,
\n
depending on the following circumstances:
\n
\u2022
\n
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
\n
on the other hand, if the underlying 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 that of the hedged item, different
\n
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
\n\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
\n
the hedge relationships (including commodity price risk
\n
hedging) 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
\n
if the critical terms of the hedged item and hedging
\n
instrument match and there are no other sources of
\n
ineffectiveness including the credit risk adjustment on
\n
the hedging derivative, the hedge relationship will be
\n
considered fully effective on the basis of a qualitative
\n
assessment;
\n
\u2022
\n
if the critical terms of the hedged item and hedging in-
\n
strument do not match or there is at least one source
\n
of ineffectiveness, the hedge ineffectiveness will be
\n
quantified applying the dollar offset cumulative meth-
\n
od with hypothetical derivative. This method compares
\n
changes in the fair value of the hedging instrument and
\n
the hypothetical derivative between the reporting date
\n
and the inception date.
\n
The main causes of hedge ineffectiveness can be the fol-
\n
lowing:
\n
\u2022
\n
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
\n
timing differences (i.e. the hedged item and hedging in-
\n
strument occur or are settled at different dates);
\n
\u2022
\n
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
\n
other risks (i.e. changes in the fair value or cash flows of
\n
a derivative hedging instrument or hedged item relate
\n
to risks other than the specific risk being hedged);
\n
\u2022
\n
credit risk (i.e. the counterparty credit risk differently
\n
impacts the changes in the fair value of the hedging
\n
instruments and hedged items).
\n
Fair value hedges
\n
Fair value hedges are mainly used to protect the Group
\n
against exposures to changes in the fair value of 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 val-
\n
ue of the hedged item that are attributable to the hedged
\n
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 meth-
\n
od is used is amortized to profit or loss over the period to
\n
maturity.
\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 af-
\n
fect 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
\n\n
\n
hedge accounting approach based on specific liquidity
\n
requirements (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 ex-
\n
piry but also during the hedge relationship, if and only if the
\n
new derivative meets both of the following requirements:
\n
\u2022
\n
it represents a best proxy of the old derivative in terms
\n
of ranking;
\n
\u2022
\n
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
\n
the effective fair value of the new derivative will be rec-
\n
ognized in equity (the hedging reserve), while changes in
\n
the fair value of the old derivative are recognized through
\n
profit 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.
\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, the 1-month, 3-month and 6-month
\n
USD LIBOR benchmarks have become unrepresentative
\n
after June 30, 2023 and the alternative reference rate is
\n
the Secured Overnight Financing Rate (SOFR).
\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
\u2022
\n
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
\n
rate (Phase 1); and
\n
\u2022
\n
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 previously been implemented in contracts in-
\n
dexed to GBP LIBOR in 2021 and others have been imple-
\n
mented in 2023, considering that, as already mentioned,
\n
USD LIBOR benchmarks have become unrepresentative as
\n
from June 30, 2023.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and is almost entirely hedged using finan-
\n
cial 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 2023, the Group obtained new dollar loans indexed
\n
to SOFR and focused on the implementation of how to
\n
change all exposures from USD LIBOR to USD SOFR.
\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
\n
rates within the 2006 ISDA definitions to include replace-
\n
ment clauses that would apply upon the permanent discon-
\n
tinuation of specific key benchmarks. These changes took
\n
effect 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
As regards Euribor, the Group is assessing whether to: (i)
\n
adopt that protocol in the light of its exposure and devel-
\n
opments in the IBOR reform or (ii) adjust in advance any
\n
contracts impacted bilaterally by the reform.
\n
\n
\n\n
\n\n
\n\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, SOFR and SONIA.
\n
The Group has assessed the impact of uncertainty en-
\n
gendered by the IBOR reform on hedge relationships at
\n
December 31, 2023 with reference to both hedging in-
\n
struments and hedged items. Both the hedged items and
\n
the hedging instruments have changed their parameter-
\n
ization from interbank market-based benchmarks (IBORs)
\n
to alternative risk-free rates (RFRs) as a result of the con-
\n
tractual amendments that have taken effect.
\n
In particular, in order to manage the uncertainty associ-
\n
ated with both hedging instruments and hedged items
\n
indexed to USD LIBOR, until June 30, 2023 the Group has
\n
continued to apply the temporary exceptions provided for
\n
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
\n
determining if a forecast transaction is highly probable;
\n
\u2022
\n
establishing whether the future hedged cash flows will
\n
arise in a discontinued cash flow hedge relationship;
\n
\u2022
\n
assessing the economic relationship between the
\n
hedged item and the hedging instrument.
\n
The hedge relationships impacted may have become in-
\n
effective due to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In order to
\n
avoid that risk, the Group has sought to implement the
\n
replacements at the same time.
\n
In addition, the Group changed the reference to USD LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically
\n
equivalent, SOFR benchmark in 2023. Consequently, the
\n
Group no longer applies the amendments to IFRS 9 issued
\n
in September 2019 (Phase 1) to these hedge relationships
\n
and, consequently, is applying the amendments to IFRS
\n
9 issued in August 2020 (Phase 2), modifying the formal
\n
designation of the hedge relationship as required by the
\n
IBOR reform and without considering this event as a ter-
\n
mination of the hedge relationship.
\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
\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
2023 and December 31, 2022, broken down by maturity.
\n
Maturity
\n
Millions of euro 2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Interest rate swaps
\n
Total notional amount 708 564 879 1,975 19 3,781 7, 9 2 6
\n
Notional amount related to IRSs in euro 608 564 636 1,532 19 3,141 6,500
\n
Average IRS rate in euro 4.56 1.92 2.12 3.38 0.86 2.37
\n
Notional amount related to IRSs in US dollars 46 - - 444 - 210 700
\n
Average IRS rate in US dollars 0.70 3.28 5.05
\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, 2023 and
\n
December 31, 2022, 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
\n
Assets Liabilities Assets Liabilities
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Fair value hedges
\n
Interest rate swaps
\n
Floating-rate
\n
borrowings/bonds
\n
98 - 544 20 (2) 518
\n
Interest rate swaps
\n
Fixed-rate borrowings/
\n
bonds
\n
3 (44) 1,241 2 (90) 1,239
\n
Cash flow hedges
\n
Interest rate swaps Floating-rate bonds 12 (49) 1,040 29 (44) 1,190
\n
Interest rate swaps
\n
Floating-rate loan
\n
assets
\n
- (7) 145 - (9) 162
\n
Interest rate swaps
\n
Floating-rate
\n
borrowings
\n
163 (35) 4,956 307 (7) 4,646
\n
Total 276 (135) 7, 926 358 (152) 7,755
\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, 2023 and December 31, 2022, broken down
\n
by type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Fair value hedges
\n
Interest rate swaps 556 154 101 22 1,229 1,603 (44) (92)
\n
Total 556 154 101 22 1,229 1,603 (44) (92)
\n
Cash flow hedges
\n
Interest rate swaps 4,144 4,958 175 336 1,997 1,040 (91) (60)
\n
Total 4,144 4,958 175 336 1,997 1,040 (91) (60)
\n
TOTAL INTEREST RATE DERIVATIVES 4,700 5,112 276 358 3,226 2,643 (135) (152)
\n
The notional amount of derivatives classified as hedging
\n
instruments at December 31, 2023 came to \u20ac7,926 million,
\n
with a corresponding positive fair value of \u20ac141 million.
\n
Compared with December 31, 2022, the notional amount
\n
increased by \u20ac171 million, mainly reflecting:
\n
\u2022
\n
the expiry of interest rate swaps amounting to \u20ac159
\n
million;
\n
\u2022
\n
early closure of interest rate swaps for an amount of
\n
\u20ac150 million, following early redemption of the under-
\n
lying;
\n
\u2022
\n
new interest rate swaps amounting to \u20ac800 million;
\n
\u2022
\n
the reduction in the notional amount of amortizing in-
\n
terest rate swaps in the amount of \u20ac320 million.
\n
The deterioration in the fair value of \u20ac65 million mainly re-
\n
flects developments in the 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
\n
interest rate risk both in 2023 and the previous year.
\n
Millions of euro 2023 2022
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments 125 (84)
\n
Hedged item (132) 75
\n
Ineffective portion (7) (9)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Interest rate swaps 1,785 57 57 1,757 (70) (70)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
\n
of fair value
\n
of hedged
\n
item
\n
Fair value used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fixed-rate borrowings 1,186 (43) 44 1,138 (89) (79)
\n
Fixed-rate bonds 14 2 (2) 14 2 (2)
\n
Floating-rate bonds 671 41 (107) 576 (16) (18)
\n
Total 1,871 - (65) 1,728 (103) (99)
\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in
\n
coming years from cash flow hedge derivatives on interest
\n
rate risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on interest rates
\n
Positive fair value 175 86 29 19 14 12 28
\n
Negative fair value (91) (8) (21) (20) (17) (13) (22)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Interest rate swaps 6,141 84 84 5,998 276 276
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\n
Fair value of
\n
the hedged
\n
item used
\n
to measure
\n
ineffectiveness
\n
in the year
\n
Fair value
\n
through
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
\n
P&L of CFH
\n
derivatives
\n
designated
\n
after initial
\n
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
37 - (37) - - 15 - (15) - -
\n
Floating-rate loan
\n
assets
\n
7 - (7) - - 9 - (9) - -
\n
Floating-rate
\n
borrowings
\n
(149) (20) 149 - (1) (327) (28) 326 - 2
\n
Total (105) (20) 105 - (1) (303) (28) 302 - 2
\n
Currency risk
\n
The following table reports the maturity profile of the
\n
notional amount and associated average contractual ex-
\n
change rate for the instruments hedging currency risk on
\n
transactions outstanding at December 31, 2023 and De-
\n
cember 31, 2022.
\n
Millions of euro Maturity
\n
2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 4,562 2,577 1,222 2,337 2,037 13,386 26,121
\n
Notional amount for CCIRSs EUR/USD 2,213 2,036 1,132 1,560 2,037 9,102 18,080
\n
Average exchange rate EUR/USD 1.13 1.07 1.07 1.10 1.18 1.15
\n
Notional amount for CCIRSs EUR/GBP 981 - - 577 - 3,856 5,414
\n
Average exchange rate EUR/GBP 0.88 0.90 0.82
\n
Notional amount for CCIRSs EUR/CHF 242 - - 140 - - 382
\n
Average exchange rate EUR/CHF 1.07 1.21
\n
Notional amount for CCIRSs USD/BRL 279 231 91 - - 387 988
\n
Average exchange rate USD/BRL 5.50 5.22 5.30 4.13
\n
Notional amount for CCIRSs EUR/BRL 445 231 - 60 - - 736
\n
Average exchange rate EUR/BRL 6.25 6.05 3.92
\n
Currency forwards
\n
Total notional amount of forwards 4,616 1,186 507 - - - 6,309
\n
Notional amount - currency forwards EUR/USD 3,144 1,042 507 - - - 4,693
\n
Average currency forward rate - EUR/USD 1.10 1.11 1.13
\n
Notional amount - currency forwards USD/CLP 938 141 - - - - 1,079
\n
Average currency forward rate - USD/CLP 873.05 885.2239
\n
Notional amount - currency forwards EUR/CNH 175 - - - - - 175
\n
Average currency forward rate - EUR/CNH 7.8 1
\n
Notional amount - currency forwards USD/BRL 130 - - - - - 130
\n
Average currency forward rate - USD/BRL 4.95
\n
Notional amount - currency forwards USD/COP 122 2 - - - - 124
\n
Average currency forward rate - USD/COP 4,498.97 4,597.37
\n
\n\n
\n\n
\n\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Cross currency interest rate swaps (CCIRSs)
\n
Total notional amount of CCIRSs 1,908 4,831 2,648 1,265 2,380 15,701 28,733
\n
Notional amount for CCIRSs 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 CCIRSs EUR/GBP - 958 - - 564 3,721 5,243
\n
Average exchange rate EUR/GBP 0.88 0.90 0.81
\n
Notional amount CCIRSs EUR/CHF - 228 - - 132 - 360
\n
Average exchange rate EUR/CHF 1.06 1.21
\n
Notional amount for CCIRSs 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 CCIRSs 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 - - - 7,6 83
\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
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, 2023 and
\n
December 31, 2022 broken down by type of hedged item.
\n
Millions or 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, 2023 at Dec. 31, 2022
\n
Fair value hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/bonds in
\n
foreign currencies
\n
12 (78) 1,019 15 (99) 1,097
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings in
\n
foreign currencies
\n
- - - - - -
\n
Cash flow hedges
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate borrowings/
\n
financial assets in foreign
\n
currencies
\n
67 (36) 754 95 (76) 1,061
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate borrowings/financial
\n
assets in foreign currencies
\n
5 (220) 2,104 4 (233) 2,445
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Floating-rate bonds in foreign
\n
currencies
\n
56 - 250 60 - 414
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Fixed-rate bonds in foreign
\n
currencies
\n
965 (1,724) 21,763 1,864 (1,293) 23,381
\n
Cross currency interest rate swaps
\n
(CCIRSs)
\n
Future cash flows denominated
\n
in foreign currencies
\n
- (43) 231 - (50) 335
\n
Currency forwards
\n
Future cash flows denominated
\n
in foreign currencies
\n
2 (1) 117 9 (6) 326
\n
Currency forwards
\n
Future commodity purchases
\n
denominated in foreign
\n
currencies
\n
54 (126) 5,666 192 (135) 7,508
\n
Currency forwards
\n
Purchases of investment goods
\n
and other in foreign currencies
\n
3 (12) 526 19 (23) 1,292
\n
Total 1,164 (2,240) 32,430 2,258 (1,915) 37,859
\n
Cash flow hedges and fair value hedges include:
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac24,886 million used
\n
to hedge the currency risk on fixed-rate debt denomi-
\n
nated in currencies other than the euro with a negative
\n
fair value of \u20ac1,040 million;
\n
\u2022
\n
CCIRSs with a notional amount of \u20ac1,235 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 \u20ac44 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac5,783
\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 negative fair value of \u20ac71 million;
\n
\u2022
\n
currency forwards with a notional amount of \u20ac526 mil-
\n
lion and a negative fair value of \u20ac9 million, in respect
\n
of OTC transactions to mitigate the currency risk on
\n
expected cash flows in currencies other than the pre-
\n
sentation currency connected with the purchase of
\n
investment goods in the renewables (including Battery
\n
Energy Storage Systems - BESS) 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 val-
\n
ue of foreign exchange derivatives at December 31, 2023
\n
and December 31, 2022, broken down by type of hedge.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
Derivatives
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Fair value hedges
\n
CCIRSs 90 99 12 15 929 998 (78) (99)
\n
Total 90 99 12 15 929 998 (78) (99)
\n
Cash flow hedges
\n
Currency forwards 1,979 4,313 59 220 4,330 4,813 (140) (164)
\n
CCIRSs 13,474 16,695 1,093 2,023 11,628 10,941 (2,022) (1,652)
\n
Total 15,453 21,008 1,152 2,243 15,958 15,754 (2,162) (1,816)
\n
TOTAL EXCHANGE RATE
\n
DERIVATIVES
\n
15,543 21,107 1,164 2,258 16,887 16,752 (2,240) (1,915)
\n
\n\n
\n\n
\n\n
The notional amount of CCIRSs at December 31, 2023
\n
amounted to \u20ac26,121 million, a decrease of \u20ac2,612 million
\n
from \u20ac28,733 million at December 31, 2022. In particular:
\n
\u2022
\n
CCIRSs with a total amount of \u20ac737 million expired;
\n
\u2022
\n
a partial unwinding operation of CCIRSs was carried out
\n
following the early repurchase of part of the hybrid bond
\n
denominated in US dollars. That transaction, together
\n
with the natural expiry of the residual portion of that li-
\n
ability and the associated CCIRSs, caused a decrease in
\n
the notional amount compared with December 31, 2022
\n
of \u20ac1,171 million;
\n
\u2022
\n
new derivatives amounted to \u20ac109 million. The notional
\n
amount decreased by \u20ac813 million, reflecting develop-
\n
ments in the exchange rate of the euro against the main
\n
other currencies and the effect of amortization.
\n
The notional amount of currency forwards at December 31,
\n
2023 amounted to \u20ac6,309 million (\u20ac9,126 million at Decem-
\n
ber 31, 2022), a decrease of \u20ac2,817 million. The exposure to
\n
currency risk, especially that associated with the US dollar,
\n
is mainly due to purchases of natural gas, purchases of fuel
\n
and cash flows in respect of investments.
\n
After the turbulence experienced in raw material prices
\n
during 2022, which led to a considerable increase in the
\n
notional amounts hedged, the notional value of currency
\n
hedges on energy commodities returned to normal oper-
\n
ating levels in 2023. The deterioration of net fair value of
\n
\u20ac137 million reflected normal developments in exchange
\n
rates.
\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 2023 and the pre-
\n
vious year.
\n
Millions of euro 2023 2022
\n
Net gain/(loss) Net gain/(loss)
\n
Interest rate hedging instruments 20 (119)
\n
Hedged item (12) 129
\n
Ineffective portion 8 10
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 1,019 (66) (68) 1,097 (84) (87)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 bonds in foreign currencies 500 (77) 48 458 (106) 90
\n
Fixed-rate borrowings in foreign
\n
currencies
\n
434 (7) 24 520 (8) (2)
\n
Total 934 (84) 72 978 (114) 88
\n
\n\n
\n\n
\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in coming
\n
years from cash flow hedge derivatives on currency risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on exchange rates
\n
Positive fair value 1,152 358 216 258 211 273 885
\n
Negative fair value (2,162) (960) (594) (13) (34) (18) (644)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 (CCIRSs) 25,102 (930) (919) 27,636 371 433
\n
Currency forwards 6,309 (80) (73) 9,126 56 56
\n
Total 31,411 (1,010) (992) 36,762 427 489
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
\n
effects
\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
Other
\n
effects
\n
(1)
\n
Floating-rate
\n
borrowings in
\n
foreign currencies
\n
(31) 31 - - - (30) 30 - (11) -
\n
Fixed-rate
\n
borrowings in
\n
foreign currencies
\n
219 (219) 4 - - 225 (225) (4) - -
\n
Floating-rate bonds
\n
in foreign currencies
\n
(56) 56 - - - (60) 60 - - -
\n
Fixed-rate bonds in
\n
foreign currencies
\n
861 (861) (15) - 118 (628) 509 (56) - 118
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
CCIRSs)
\n
43 (43) - - - 50 (50) - - -
\n
Future cash flows
\n
denominated in
\n
foreign currencies
\n
(hedged with
\n
forwards)
\n
(1) 1 - - - (3) 3 - - -
\n
Future commodity
\n
purchases
\n
denominated in
\n
foreign currencies
\n
72 (72) (1) - - (60) 59 (1) (1) -
\n
Purchases of
\n
investment goods
\n
and other in foreign
\n
currencies
\n
3 (3) (6) - - 7 (7) 1 2 -
\n
Total 1,110 (1,110) (18) - 118 (499) 379 (60) (10) 118
\n
(1) Impact connected with the change in spot exchange rates between the date the CCIRSs to hedge bonds in foreign currencies were obtained and the
\n
actual disbursement of the loan for the CCIRSs obtained in 2022.
\n
\n\n
\n\n
Commodity price risk
\n
Millions of euro Maturity
\n
2024 2025 2026 2027 2028 Beyond Total
\n
At Dec. 31, 2023
\n
Commodity swaps
\n
Notional amount on power 128 106 100 284 91 286 995
\n
Average commodity swap price on power (\u20ac/MWh) 87.0 44.0 37.0 59.6 32.0 34.0
\n
Notional amount on coal/shipping - - - - - - -
\n
Average commodity swap price on coal/shipping ($/ton) - - - - - -
\n
Notional amount on gas 1,551 1,747 296 - - 125 3,719
\n
Average commodity swap price on gas (\u20ac/MWh) 41.8 40.4 27.0 - - 7.0
\n
Notional amount on oil 1,016 106 10 - - - 1,132
\n
Average commodity swap price on oil ($/barrel) 86.0 78.0 69.0 - - -
\n
Commodity forwards/futures
\n
Notional amount on power 2,506 388 297 258 151 606 4,206
\n
Average commodity forward/future price on power (\u20ac/MWh) 114.9 18.0 18.0 16.0 18.0 16.0
\n
Notional amount on coal/shipping 38 - - - - - 38
\n
Average commodity forward/future price on coal/shipping ($/ton) 175.0 - - - - -
\n
Notional amount on gas 4,432 377 626 - - - 5,435
\n
Average commodity forward/future price on gas (\u20ac/MWh) 71.4 48.9 32.0 - - -
\n
Notional amount on CO
\n
2
\n
662 336 21 - - - 1,019
\n
Average commodity forward/future price on CO
\n
2
\n
(\u20ac/ton) 91.9 93.0 84.0 - - -
\n
Notional amount on oil 354 - - - - - 354
\n
Average commodity forward/future price on oil ($/barrel) 74.6 - - - - -
\n
Commodity options
\n
Notional amount on power 24 39 44 39 39 342 527
\n
Average commodity option price on power (\u20ac/MWh) 27.5 30.0 30.5 34.0 34.0 34.0
\n
Notional amount on gas - - - - - - -
\n
Average commodity option price on gas (\u20ac/MWh) - - - - - -
\n
Notional amount on oil - - - - - - -
\n
Average commodity option price on oil ($/barrel) - - - - - -
\n
Millions of euro Maturity
\n
2023 2024 2025 2026 2027 Beyond Total
\n
At Dec. 31, 2022
\n
Commodity swaps
\n
Notional amount on power 653 164 143 139 132 333 1,564
\n
Average commodity swap price on power (\u20ac/MWh) 162.5 77.9 48.9 47. 2 45.8 29.0
\n
Notional amount on coal/shipping 1,037 - - - - - 1,037
\n
Average commodity swap price on coal/shipping ($/ton) 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 ($/barrel) 105.0 93.0 82.0 - - -
\n
Commodity forwards/futures
\n
Notional amount on power 2,906 509 388 294 249 720 5,066
\n
Average commodity forward/future price on power (\u20ac/MWh) 148.1 35.2 17.4 17. 8 15.8 15.6
\n
Notional amount on coal/shipping - - - - - - -
\n
Average commodity forward/future price on coal/shipping ($/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
1,635 226 50 - - - 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 ($/barrel) 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 oil 70 - - - - - 70
\n
Average commodity option price on oil (\u20ac/barrel) 133 - - - - - -
\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, 2023 and De-
\n
cember 31, 2022, 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
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Derivatives
\n
Cash flow hedges
\n
Derivatives on power:
\n
- swaps 684 1,213 357 982 311 352 (233) (498)
\n
- forwards/futures 1,636 1,535 162 89 2,570 3,510 (763) (898)
\n
- options 527 218 93 36 - - (62) (12)
\n
Total derivatives on power 2,847 2,966 612 1,107 2,881 3,862 (1,058) (1,408)
\n
Derivatives on coal/shipping:
\n
- swaps - 9 - 2 - 1,028 - (373)
\n
- forwards/futures - - - - 38 - (17) -
\n
- options - - - - - - - -
\n
Total derivatives on coal/shipping - 9 - 2 38 1,028 (17) (373)
\n
Derivatives on gas and oil:
\n
- swaps 2,785 2,302 623 666 2,066 2,729 (468) (765)
\n
- forwards/futures 3,382 4,734 1,375 1,714 2,407 8,085 (1,198) (5,182)
\n
- options - 22 - 4 - 48 - (4)
\n
Total derivatives on gas and oil 6,167 7,058 1,998 2,384 4,473 10,862 (1,666) (5,951)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps - - - - - - - -
\n
- forwards/futures 640 1,704 91 143 379 207 (29) (7)
\n
- options - - - - - - - -
\n
Total derivatives on CO
\n
2
\n
640 1,704 91 143 379 207 (29) (7)
\n
TOTAL COMMODITY DERIVATIVES 9,654 11,737 2,701 3,636 7,77 1 15,959 (2,770) (7,739)
\n
The table reports the notional amount and fair value of
\n
derivatives hedging commodity price risk at December
\n
31, 2023 and December 31, 2022, broken down by type
\n
of 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 \u20ac1,998 million, derivatives on CO
\n
2
\n
\n
in the amount of \u20ac 91 million and derivatives on power for
\n
\u20ac612 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 \u20ac1,666 million, derivatives on power in the
\n
amount of \u20ac1,058 million and, to a lesser extent, deriva-
\n
tives on coal and CO
\n
2
\n
in the amount of respectively \u20ac17
\n
million and \u20ac29 million.
\n
\n\n
Cash flow hedge derivatives
\n
The following table shows the cash flows expected in
\n
coming years from cash flow hedge derivatives on com-
\n
modity price risk.
\n
Millions of euro Fair value Distribution of expected cash flows
\n
at Dec. 31, 2023 2024 2025 2026 2027 2028 Beyond
\n
Cash flow hedge derivatives on commodities
\n
Positive fair value 2,701 1,861 428 153 85 55 246
\n
Negative fair value (2,770) (1,727) (430) (217) (216) (72) (235)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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
Power swaps 995 124 126 1,564 485 469
\n
Coal/shipping swaps - - - 1,037 (371) (371)
\n
Gas and oil swaps 4,850 155 155 5,031 (99) (98)
\n
Power forwards/futures 4,206 (602) (638) 5,045 (809) (938)
\n
Coal/shipping forwards/futures 38 (17) (17) - - -
\n
Gas and oil forwards/futures 5,789 178 92 12,820 (3,469) (3,673)
\n
CO
\n
2
\n
forwards/futures 1,019 62 62 1,911 136 138
\n
Power options 528 31 31 218 24 24
\n
Gas and oil options - - - 70 - -
\n
Total 17,425 (69) (189) 27,696 (4,103) (4,449)
\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, 2023 and December 31, 2022.
\n
Millions of euro at Dec. 31, 2023 at Dec. 31, 2022
\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 491 (491) 12 (59) 602 (602) 15 (32)
\n
Future transactions in coal/shipping 17 (17) - - 371 (371) - -
\n
Future transactions in gas and oil (422) 422 - (118) 3,360 (3,360) - (232)
\n
Future transactions in CO
\n
2
\n
(62) 62 - - (133) 133 - -
\n
Total 24 (24) 12 (177) 4,200 (4,200) 15 (264)
\n
With regard to cash flow hedge derivatives on commodity
\n
prices, 2023 was marked by a progressive reduction in the
\n
extreme price volatility seen in past years.
\n
The greatest impact in terms of changes in the cash flow
\n
hedge reserve is mainly attributable to future transac-
\n
tions in gas and power, which experience a reduction in
\n
the magnitude of the amount to defer to future years be-
\n
cause those commodities were the most affected by the
\n
high price volatility.
\n
Moreover, the change is also attributable to the usual re-
\n
\n\n
lease of the impact on profit or loss of amounts accrued in
\n
2023, which were the most affected by major price swings
\n
of the past years.
\n
The ineffectiveness recognized in 2023 on future trans-
\n
actions in gas is mainly related to proxy hedging opera-
\n
tions in Spain, while ineffectiveness on future transactions
\n
in power is mainly related to proxy hedging operations in
\n
North America.
\n
51.2 Derivatives at fair value through profit or
\n
loss
\n
The following table shows the notional amount and the fair
\n
value of derivatives at FVTPL as at December 31, 2023 and
\n
December 31, 2022.
\n
Millions of euro Notional amount Fair value assets Notional amount Fair value liabilities
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
at Dec. 31,
\n
2023
\n
at Dec. 31,
\n
2022
\n
Derivatives at FVTPL
\n
on interest rates:
\n
- interest rate swaps - - - - 100 100 (29) (23)
\n
- interest rate options - - - - - - - -
\n
on exchange rates:
\n
- currency forwards 1,818 3,659 25 75 1 ,874 2,102 (29) (34)
\n
- CCIRSs - - - - - 46 - (1)
\n
on commodities
\n
Derivatives on power:
\n
- swaps 243 595 24 106 68 245 (16) (180)
\n
- forwards/futures 5,294 6,903 905 872 5,039 5,620 (906) (908)
\n
- options 46 7 4 15 80 140 (171) (172)
\n
Total derivatives on power 5,583 7,505 933 993 5,187 6,005 (1,093) (1,260)
\n
Derivatives on coal:
\n
- swaps - - - - - - - -
\n
- forwards/futures 156 115 23 21 112 1,291 (43) (9)
\n
- options - - - - - - - -
\n
Total derivatives on coal 156 115 23 21 112 1,291 (43) (9)
\n
Derivatives on gas and oil:
\n
- swaps 969 1,964 295 806 529 834 (167) (550)
\n
- forwards/futures 10,687 40,669 2,970 10,456 10,856 38,651 (2,963) (10,280)
\n
- options 448 34 344 8 278 33 (232) (22)
\n
Total derivatives on gas and oil 12,104 42,667 3,609 11,270 11,663 39,518 (3,362) (10,852)
\n
Derivatives on CO
\n
2
\n
:
\n
- swaps - - - - - - - -
\n
- forwards/futures 498 725 41 115 426 361 (42) (35)
\n
- options 12 2 14 2 11 - (14) -
\n
Total derivatives on CO
\n
2
\n
510 727 55 117 437 361 (56) (35)
\n
Derivatives on other:
\n
- swaps - - - - 39 - (6) -
\n
- forwards/futures 16 13 4 72 171 5 (71) (16)
\n
- options - - - - 5 - - -
\n
Total derivatives on other 16 13 4 72 215 5 (77) (16)
\n
TOTAL 20,187 54,686 4,649 12,548 19,588 49,428 (4,689) (12,230)
\n
\n\n
At December 31, 2023 the notional amount of trading de-
\n
rivatives on interest rates came to \u20ac100 million. The nega-
\n
tive fair value of \u20ac29 million deteriorated by \u20ac6 million on
\n
the previous year mainly due to developments in the yield
\n
curve.
\n
At December 31, 2023 the notional amount of derivatives
\n
on exchange rates was \u20ac3,692 million. After the strains ex-
\n
perienced in raw material prices during 2022, which led to
\n
a considerable increase in the notional amounts hedged,
\n
the notional value of currency hedges on energy com-
\n
modities returned to normal operating levels in 2023. This
\n
produced an overall decrease in the value of the hedges of
\n
\u20ac2,069 million. The deterioration of net fair value of \u20ac45
\n
million reflected normal developments in exchange rates.
\n
At December 31, 2023, the notional amount of deriva-
\n
tives on commodities came to \u20ac35,983 million. In absolute
\n
terms, the notional amounts decreased compared with
\n
2022 in line with the gradual decline observed in the pric-
\n
es of energy commodities. The fair value of trading deriv-
\n
atives on commodities classified as assets mainly reflects
\n
the market valuation of hedges of gas and oil amount-
\n
ing to \u20ac3,609 million, derivatives on power amounting to
\n
\u20ac933 million, derivatives on CO
\n
2
\n
amounting to \u20ac55 million
\n
and, to a lesser extent, derivatives on coal and other com-
\n
modities totaling \u20ac23 million and \u20ac4 million, respectively.
\n
The fair value of trading derivatives on commodities
\n
classified as liabilities mainly regards hedges of gas and
\n
oil amounting to \u20ac3,362 million, derivatives on power
\n
amounting to \u20ac1,093 million, and derivatives on CO
\n
2
\n
, coal
\n
and other commodities in the amount of \u20ac56 million, \u20ac43
\n
million and \u20ac77 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
In addition to weather derivative hedges, the \u201cother\u201d cat-
\n
egory includes hedges carried out on guarantees of or-
\n
igin and green certificates, i.e. incentive mechanisms for
\n
the production of electricity from renewable sources. In
\n
addition to the commodity price risk, the Group compa-
\n
nies have to manage the risk of fluctuations in the price of
\n
these certificates which were recently affected by greater
\n
market volatility compared with the past, due to the in-
\n
creasing market attention to environmental sustainability
\n
issues.
\n
\n", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag8": { "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.
\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, the 1-month, 3-month and 6-month
\n
USD LIBOR benchmarks have become unrepresentative
\n
after June 30, 2023 and the alternative reference rate is
\n
the Secured Overnight Financing Rate (SOFR).
\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
\u2022
\n
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
\n
rate (Phase 1); and
\n
\u2022
\n
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 previously been implemented in contracts in-
\n
dexed to GBP LIBOR in 2021 and others have been imple-
\n
mented in 2023, considering that, as already mentioned,
\n
USD LIBOR benchmarks have become unrepresentative as
\n
from June 30, 2023.
\n
Debt and derivatives
\n
The Group\u2019s floating rate debt is mainly benchmarked
\n
against Euribor and is almost entirely hedged using finan-
\n
cial 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 2023, the Group obtained new dollar loans indexed
\n
to SOFR and focused on the implementation of how to
\n
change all exposures from USD LIBOR to USD SOFR.
\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
\n
rates within the 2006 ISDA definitions to include replace-
\n
ment clauses that would apply upon the permanent discon-
\n
tinuation of specific key benchmarks. These changes took
\n
effect 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
As regards Euribor, the Group is assessing whether to: (i)
\n
adopt that protocol in the light of its exposure and devel-
\n
opments in the IBOR reform or (ii) adjust in advance any
\n
contracts impacted bilaterally by the reform.
\n
\n
\n\n
Hedge relationships
\n
At the reporting date, hedged items and hedging instru-
\n
ments are primarily indexed to Euribor, SOFR and SONIA.
\n
The Group has assessed the impact of uncertainty en-
\n
gendered by the IBOR reform on hedge relationships at
\n
December 31, 2023 with reference to both hedging in-
\n
struments and hedged items. Both the hedged items and
\n
the hedging instruments have changed their parameter-
\n
ization from interbank market-based benchmarks (IBORs)
\n
to alternative risk-free rates (RFRs) as a result of the con-
\n
tractual amendments that have taken effect.
\n
In particular, in order to manage the uncertainty associ-
\n
ated with both hedging instruments and hedged items
\n
indexed to USD LIBOR, until June 30, 2023 the Group has
\n
continued to apply the temporary exceptions provided for
\n
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
\n
determining if a forecast transaction is highly probable;
\n
\u2022
\n
establishing whether the future hedged cash flows will
\n
arise in a discontinued cash flow hedge relationship;
\n
\u2022
\n
assessing the economic relationship between the
\n
hedged item and the hedging instrument.
\n
The hedge relationships impacted may have become in-
\n
effective due to different replacements of existing bench-
\n
marks with alternative risk-free benchmarks. In order to
\n
avoid that risk, the Group has sought to implement the
\n
replacements at the same time.
\n
In addition, the Group changed the reference to USD LI-
\n
BOR in its interest rate hedging instruments used in cash
\n
flow hedge relationships with the new, economically
\n
equivalent, SOFR benchmark in 2023. Consequently, the
\n
Group no longer applies the amendments to IFRS 9 issued
\n
in September 2019 (Phase 1) to these hedge relationships
\n
and, consequently, is applying the amendments to IFRS
\n
9 issued in August 2020 (Phase 2), modifying the formal
\n
designation of the hedge relationship as required by the
\n
IBOR reform and without considering this event as a ter-
\n
mination of the hedge relationship.
\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
\n
\n", "dimensions": { "concept": "ifrs-full:DescriptionOfChangesToEntitysRiskManagementStrategyArisingFromEntitysExposureToFinancialInstrumentsSubjectToInterestRateBenchmarkReformExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag10": { "value": "\n\n
Fair value measurement
\n
52. Assets and liabilities measured at 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 ac-
\n
cordance with the three-level hierarchy described below,
\n
depending on the inputs and valuation techniques used in
\n
determining their fair value:
\n
\u2022
\n
Level 1, where the fair value is determined on the ba-
\n
sis of quoted prices (unadjusted) in active markets for
\n
identical assets or liabilities that the entity can access
\n
at the measurement date;
\n
\u2022
\n
Level 2, where the fair value is determined on the ba-
\n
sis of inputs other than quoted prices included within
\n
Level 1 that are observable for the asset or liability, ei-
\n
ther directly (such as prices) or indirectly (derived from
\n
prices);
\n
\u2022
\n
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
\n
recurring fair value measurements of assets or liabili-
\n
ties are those required or permitted by the IFRS in the
\n
statement of financial position at the close of each pe-
\n
riod;
\n
\u2022
\n
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
\n\n
\n\n

\n\n
\n

\n

\n
52.1 Assets measured at fair value in the 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
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, 2023 at Dec. 31, 2023
\n
Equity investments in other
\n
companies at FVOCI
\n
29 338 15 28 295 - - - -
\n
Securities at FVOCI 29.1, 30.1 505 505 - - 81 81 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
39 - - 39 - - - -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 8 - - 8 - - - -
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 4,080 - 4,080 - - - - -
\n
Financial assets from JDA at FVTPL 123 41 - 82 - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
169 - - 169 190 131 - 59
\n
Other cash investments at FVTPL - - - - 29 29 - -
\n
Fair value hedge derivatives:
\n
- on interest rates 51 101 - 101 - - - - -
\n
- on exchange rates 51 12 - 12 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 174 - 174 - 1 - 1 -
\n
- on exchange rates 51 1,007 - 1,007 - 145 - 145 -
\n
- on commodities 51 883 173 375 335 1,818 1,311 413 94
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 24 - 24 -
\n
- on commodities 51 205 27 178 - 4,419 3,038 1,381 -
\n
Non-monetary grants in respect
\n
of environmental certificates
\n
- - - - 18 1 11 6
\n
Inventories measured at fair value 51 48 48 - - 3 - 3 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n\n\n\n\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, 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
Level 3 of the non-current portion of \u201cloan assets and oth-
\n
er financial assets at FVTPL\u201d reports the receivable in re-
\n
spect of the sale of Slovak Power Holding, which amount-
\n
ed to \u20ac39 million at December 31, 2023. Its fair value was
\n
determined using the contractual price formula.
\n
The current portion of \u201cloans assets and other financial
\n
assets at FVTPL\u201d includes mainly under Level 1 financial
\n
deposits held by Latin American companies.
\n
In addition, \u201cloan assets and other financial assets at FVT-
\n
PL\u201d include the non-current portion (\u20ac130 million) and the
\n
current portion (\u20ac59 million) of \u201csuper-eco-sisma bonus\u201d
\n
receivables purchased after the enactment of the Revival
\n
Decree and assigned to banks, the measurement of which
\n
falls within Level 3.
\n
The current portion of \u201cother cash investments at FVTPL\u201d
\n
at Level 1 mainly refers to investment in money-market
\n
funds to manage the liquidity of Enel Insurance.
\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

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n\n

\n\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
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
Certain long-term financial contracts in Spain (Virtual
\n
Power Purchase Agreements, or VPPAs), for which inter-
\n
nal measurement models were also used in part in order
\n
to measure these instruments over longer time horizons,
\n
given the illiquidity of the underlying variables fall within
\n
Level 3.
\n
In accordance with the IFRS, the Group assesses credit
\n
risk, both of the counterparty (Credit Valuation Adjustment
\n
or 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/
\n
DVA using a Potential Future Exposure valuation technique
\n
for the net exposure of the position and subsequently al-
\n
locating the adjustment to the individual financial instru-
\n
ments that make up the overall portfolio. All of the inputs
\n
used in this technique are observable on the market.
\n
52.2 Assets not measured at fair value in the 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, 2023 at Dec. 31, 2023
\n
Investment property 22 98 7 - 91 - - - -
\n
Inventories 33 - - - - 45 - - 45
\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 \u20ac98 million and \u20ac45 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 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, 2023 at Dec. 31, 2023
\n
Fair value hedge derivatives:
\n
- on interest rates 51 27 - 27 - 17 - 17 -
\n
- on exchange rates 51 78 - 78 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 91 - 91 - - - - -
\n
- on exchange rates 51 1,830 - 1,830 - 332 - 332 -
\n
- on commodities 51 1,143 43 922 178 1,627 1,030 555 42
\n
Trading derivatives:
\n
- on interest rates 51 - - - - 29 - 29 -
\n
- on exchange rates 51 1 - 1 - 28 - 28 -
\n
- on commodities 51 203 102 100 1 4,428 3,154 1,268 6
\n
Contingent consideration 41 - - 41 26 - 26 -
\n

\n\n\n\n\n\n\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 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
Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2023
\n
Bonds:
\n
- fixed rate 45,727 43,287 2,440 -
\n
- floating rate 3,097 66 3,031 -
\n
Bank borrowings:
\n
- fixed rate 3,746 - 3,746 -
\n
- floating rate 12,933 - 12,933 -
\n
Non-bank borrowings:
\n
- fixed rate 3,278 - 3,278 -
\n
- floating rate 59 - 59 -
\n
Total 68,840 43,353 25,487 -
\n
For listed debt instruments, the fair value is given by of-
\n
ficial prices. For unlisted instruments the fair value is de-
\n
termined using appropriate valuation techniques for each
\n
category of financial instrument and market data at the
\n
close of the year, including the credit spreads of Enel.
\n

\n\n\n\n\n\n\n\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag9": { "value": "\n
Fair value measurement
\n
52. Assets and liabilities measured at 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 ac-
\n
cordance with the three-level hierarchy described below,
\n
depending on the inputs and valuation techniques used in
\n
determining their fair value:
\n
\u2022
\n
Level 1, where the fair value is determined on the ba-
\n
sis of quoted prices (unadjusted) in active markets for
\n
identical assets or liabilities that the entity can access
\n
at the measurement date;
\n
\u2022
\n
Level 2, where the fair value is determined on the ba-
\n
sis of inputs other than quoted prices included within
\n
Level 1 that are observable for the asset or liability, ei-
\n
ther directly (such as prices) or indirectly (derived from
\n
prices);
\n
\u2022
\n
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
\n
recurring fair value measurements of assets or liabili-
\n
ties are those required or permitted by the IFRS in the
\n
statement of financial position at the close of each pe-
\n
riod;
\n
\u2022
\n
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
\n\n
\n

\n

\n
52.1 Assets measured at fair value in the 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
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, 2023 at Dec. 31, 2023
\n
Equity investments in other
\n
companies at FVOCI
\n
29 338 15 28 295 - - - -
\n
Securities at FVOCI 29.1, 30.1 505 505 - - 81 81 - -
\n
Loan assets and other financial
\n
assets at FVOCI
\n
39 - - 39 - - - -
\n
Equity investments in other
\n
companies at FVTPL
\n
29 8 - - 8 - - - -
\n
Financial assets from service
\n
concession arrangements at
\n
FVTPL
\n
29 4,080 - 4,080 - - - - -
\n
Financial assets from JDA at FVTPL 123 41 - 82 - - - -
\n
Loan assets and other financial
\n
assets at FVTPL
\n
169 - - 169 190 131 - 59
\n
Other cash investments at FVTPL - - - - 29 29 - -
\n
Fair value hedge derivatives:
\n
- on interest rates 51 101 - 101 - - - - -
\n
- on exchange rates 51 12 - 12 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 174 - 174 - 1 - 1 -
\n
- on exchange rates 51 1,007 - 1,007 - 145 - 145 -
\n
- on commodities 51 883 173 375 335 1,818 1,311 413 94
\n
Trading derivatives:
\n
- on interest rates 51 - - - - - - - -
\n
- on exchange rates 51 1 - 1 - 24 - 24 -
\n
- on commodities 51 205 27 178 - 4,419 3,038 1,381 -
\n
Non-monetary grants in respect
\n
of environmental certificates
\n
- - - - 18 1 11 6
\n
Inventories measured at fair value 51 48 48 - - 3 - 3 -
\n
Contingent consideration 5 - - 5 2 - 2 -
\n

\n\n\n\n\n\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, 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
Level 3 of the non-current portion of \u201cloan assets and oth-
\n
er financial assets at FVTPL\u201d reports the receivable in re-
\n
spect of the sale of Slovak Power Holding, which amount-
\n
ed to \u20ac39 million at December 31, 2023. Its fair value was
\n
determined using the contractual price formula.
\n
The current portion of \u201cloans assets and other financial
\n
assets at FVTPL\u201d includes mainly under Level 1 financial
\n
deposits held by Latin American companies.
\n
In addition, \u201cloan assets and other financial assets at FVT-
\n
PL\u201d include the non-current portion (\u20ac130 million) and the
\n
current portion (\u20ac59 million) of \u201csuper-eco-sisma bonus\u201d
\n
receivables purchased after the enactment of the Revival
\n
Decree and assigned to banks, the measurement of which
\n
falls within Level 3.
\n
The current portion of \u201cother cash investments at FVTPL\u201d
\n
at Level 1 mainly refers to investment in money-market
\n
funds to manage the liquidity of Enel Insurance.
\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

\n\n\n\n\n\n\n\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
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
Certain long-term financial contracts in Spain (Virtual
\n
Power Purchase Agreements, or VPPAs), for which inter-
\n
nal measurement models were also used in part in order
\n
to measure these instruments over longer time horizons,
\n
given the illiquidity of the underlying variables fall within
\n
Level 3.
\n
In accordance with the IFRS, the Group assesses credit
\n
risk, both of the counterparty (Credit Valuation Adjustment
\n
or 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/
\n
DVA using a Potential Future Exposure valuation technique
\n
for the net exposure of the position and subsequently al-
\n
locating the adjustment to the individual financial instru-
\n
ments that make up the overall portfolio. All of the inputs
\n
used in this technique are observable on the market.
\n
52.2 Assets not measured at fair value in the 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, 2023 at Dec. 31, 2023
\n
Investment property 22 98 7 - 91 - - - -
\n
Inventories 33 - - - - 45 - - 45
\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 \u20ac98 million and \u20ac45 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 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, 2023 at Dec. 31, 2023
\n
Fair value hedge derivatives:
\n
- on interest rates 51 27 - 27 - 17 - 17 -
\n
- on exchange rates 51 78 - 78 - - - - -
\n
Cash flow hedge derivatives:
\n
- on interest rates 51 91 - 91 - - - - -
\n
- on exchange rates 51 1,830 - 1,830 - 332 - 332 -
\n
- on commodities 51 1,143 43 922 178 1,627 1,030 555 42
\n
Trading derivatives:
\n
- on interest rates 51 - - - - 29 - 29 -
\n
- on exchange rates 51 1 - 1 - 28 - 28 -
\n
- on commodities 51 203 102 100 1 4,428 3,154 1,268 6
\n
Contingent consideration 41 - - 41 26 - 26 -
\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 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
Fair value Level 1 Level 2 Level 3
\n
at Dec. 31, 2023
\n
Bonds:
\n
- fixed rate 45,727 43,287 2,440 -
\n
- floating rate 3,097 66 3,031 -
\n
Bank borrowings:
\n
- fixed rate 3,746 - 3,746 -
\n
- floating rate 12,933 - 12,933 -
\n
Non-bank borrowings:
\n
- fixed rate 3,278 - 3,278 -
\n
- floating rate 59 - 59 -
\n
Total 68,840 43,353 25,487 -
\n
For listed debt instruments, the fair value is given by of-
\n
ficial prices. For unlisted instruments the fair value is de-
\n
termined using appropriate valuation techniques for each
\n
category of financial instrument and market data at the
\n
close of the year, including the credit spreads of Enel.
\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1110": { "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
\n
the management of Enel and/or its subsidiaries pursuant
\n
to 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, the
\n
2023 Long-Term Incentive Plan, referred to hereinafter,
\n
respectively, the \u201c2019 LTI Plan\u201d, \u201c2020 LTI Plan\u201d, the \u201c2021
\n
LTI Plan\u201d, the \u201c2022 LTI Plan\u201d, the \u201c2023 LTI Plan\u201d and, jointly,
\n
the \u201cPlans\u201d) provides for the grant of ordinary Company
\n
shares (\u201cShares\u201d) to the respective beneficiaries subject to
\n
the achievement of specific performance targets.
\n
Plan beneficiaries are the Chief Executive Officer/General
\n
Manager of Enel and Enel Group managers in the posi-
\n
tions most directly responsible for company performance
\n
or 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
\n
to a maximum of 280% or 180% of the base value in the
\n
case, respectively, of the Chief Executive Officer/General
\n
Manager or the other beneficiaries.
\n
The Plans establish that, of the total incentive effectively
\n
vested, the bonus will be fully paid in Shares: (a) for the
\n
LTI 2019, 2020, 2021, 2022 and 2023 Plans (i) up to 100%
\n
of the base value for the Chief Executive Officer/General
\n
Manager (up to 130% for the 2022 LTI Plan), and (ii) up to
\n
50% of the base value for the other beneficiaries (up to
\n
65% for the 2022 LTI Plan); (b) for the LTI 2023 Plan (i) up
\n
to 150% of the base value for the Chief Executive Officer/
\n
General Manager, (ii) up to 100% of the base value for offi-
\n
cers reporting directly to the Chief Executive Officer/Gen-
\n

\n\n\n\n\n\n\n\n
eral Manager, including key management personnel, and
\n
(iii) up to 65% of the base value for the other beneficiaries,
\n
other than those indicated under (i) and (ii) above.
\n
The actual award of the bonus under the Plans is sub-
\n
ject to the achievement of specific performance targets
\n
during the three-year performance period. If these targets
\n
are achieved, 30% of both the stock and cash compo-
\n
nents of the incentive will be paid in the first year following
\n
the end of the performance period and the remaining 70%
\n
will be paid in the second year following the end of the
\n
performance 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, the 2022 LTI Plan,
\n
and the 2023 LTI 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 Share-
\n
holders\u2019 Meetings held respectively on May 16, 2019, May
\n
14, 2020, May 20, 2021, May 19, 2022 and May 10, 2023.
\n
Grant date Performance period
\n
Verification of
\n
achievement of targets Payout
\n
2019 LTI Plan 12.11.2019
\n
(55)
\n
2019-2021 2022
\n
(56)
\n
2022-2023
\n
(57)
\n
2020 LTI Plan 17.09.2020
\n
(58)
\n
2020-2022 2023
\n
(59)
\n
2023-2024
\n
(60)
\n
2021 LTI Plan 16.09.2021
\n
(61)
\n
2021-2023 2024
\n
(62)
\n
2024-2025
\n
2022 LTI Plan 21.09.2022
\n
(63)
\n
2022-2024 2025
\n
(64)
\n
2025-2026
\n
2023 LTI Plan 05.10.2023
\n
(65)
\n
2023-2025 2026
\n
(66)
\n
2026-2027
\n
In implementation of the authorizations granted by the
\n
Shareholders\u2019 Meetings held on the dates indicated above
\n
and in compliance with the associated terms and condi-
\n
tions, the Board of Directors approved \u2013 at its meetings of
\n
September 19, 2019, July 29, 2020, June 17, 2021, June 16,
\n
2022 and October 5, 2023 \u2013 the launch of share buyback
\n
programs to serve the 2019 LTI Plan, the 2020 LTI Plan, the
\n
2021 LTI Plan, the 2022 LTI Plan, and the 2023 LTI Plan re-
\n
spectively. The number of Shares whose purchase was au-
\n
thorized by the Board of Directors for each Plan, the actual
\n
number of Shares purchased, the associated weighted
\n
average price and total value are shown below.
\n
(55) 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
(56) 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
(57) 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 with
\n
the Plan rules. The remainder of the equity component of the bonus vested by the beneficiaries of the 2019 LTI Plan was awarded on September 5, 2023.
\n
(58) 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
(59) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2022, the Board of Directors verified the level
\n
of achievement of the performance targets of the 2020 LTI Plan.
\n
(60) On September 5, 2023 the Company awarded part of the equity component of the bonus vested by the beneficiaries of the 2020 LTI Plan, in accordance
\n
with the Plan rules.
\n
(61) 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
(62) 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
(63) 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
(64) 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
(65) The date on which the Board of Directors approved the procedures and timing for granting the 2023 LTI Plan to the beneficiaries (taking account of the
\n
proposal issued by the Nomination and Compensation Committee at its meeting of October 4, 2023).
\n
(66) On the occasion of the approval of the consolidated financial statements of the Enel Group at December 31, 2025, the Board of Directors will verify the level
\n
of achievement of the performance targets of the 2023 LTI Plan.
\n

\n\n\n\n\n\n\n\n
Purchases authorized by the
\n
Board of Directors Actual purchases
\n
Number of Shares
\n
Number of
\n
Shares
\n
Weighted average price
\n
(euros per Share) Total value (euros)
\n
2019 LTI Plan
\n
No more than 2,500,000 for a
\n
maximum amount of \u20ac10,500,000
\n
million
\n
1,549,152
\n
(67)
\n
6.7779 10,499,999
\n
2020 LTI Plan 1,720,000 1,720,000
\n
(68)
\n
7.4366 12,790,870
\n
2021 LTI Plan 1,620,000 1,620,000
\n
(69)
\n
7.8737 12,755,459
\n
2022 LTI Plan 2,700,000 2,700,000
\n
(70)
\n
5.1951 14,026,715
\n
2023 LTI Plan 4,200,000 3,377,224
\n
(71)
\n
6.2205
\n
(72)
\n
21,007,908
\n
(73)
\n
As a result of the purchases made to support the 2019 LTI
\n
Plan, the 2020 LTI Plan, the 2021 LTI Plan, the 2022 LTI Plan,
\n
and the 2023 LTI Plan, and taking into account the award
\n
on September 5, 2022 of 435,357 Shares to the bene-
\n
ficiaries of the 2019 LTI Plan and on September 5, 2023
\n
of 1,268,689 Shares to the beneficiaries of the 2019 LTI
\n
Plan and 2020 LTI Plan, at December 31, 2023 Enel holds
\n
a total of 9,262,330 treasury shares, equal to about 0.09%
\n
of share capital. The share buyback program to serve the
\n
2023 LTI Plan was completed with the purchases made
\n
on January 18, 2024. Taking account of the total number
\n
of Shares purchased to serve the 2023 LTI Plan, at the
\n
publication date of this document Enel holds a total of
\n
10,085,106 treasury shares, equal to about 0.1% of share
\n
capital.
\n
The following information concerns the equity instru-
\n
ments granted in 2019, 2020, 2021, 2022 and 2023.
\n
2023 2022
\n

\n
Number of
\n
Shares granted
\n
at the grant
\n
date
\n
Fair value per
\n
Share at the
\n
grant date
\n

\n
Number of Shares
\n
potentially available
\n
for award
\n
Number of
\n
Shares awarded
\n
Number of
\n
Shares potentially
\n
available for award
\n
Number of Shares
\n
awarded
\n
2019 LTI Plan 1,538,547 6.983 0 956,562
\n
(74)
\n
1,021,328 435,357
\n
(75)
\n
2020 LTI Plan 1,638,775 7.380 728,265 312,127
\n
(76)
\n
1,631,951 -
\n
2021 LTI Plan 1,577,773 7.0010 1,375,671 - 1,577,773 -
\n
2022 LTI Plan 2,398,143 4.8495 2,023,677 - 2,395,323 -
\n
2023 LTI Plan 4,040,820 5.5540 4,040,820 - -
\n
(67) Shares purchased in the period between September 23 and December 2, 2019, equal to about 0.015% of share capital.
\n
(68) Shares purchased in the period between September 3 and October 28, 2020, equal to about 0.017% of share capital.
\n
(69) Shares purchased in the period between June 18 and July 21, 2021, equal to about 0.016% of share capital.
\n
(70) Shares purchased in the period between June 17 and July 20, 2022, equal to about 0.026% of share capital.
\n
(71) Number of Shares purchased to serve the 2023 LTI Plan at December 31, 2023. The share buyback programs to serve the 2023 LTI Plan, launched on Oc-
\n
tober 16, 2023, was completed with the purchases made on January 18, 2024. The program involved the purchase of a total of 4,200,000 Shares, equal to
\n
about 0.04% of share capital, at the weighted average price of \u20ac6.3145 per share and with a total value of \u20ac26,520,849.002.
\n
(72) Weighted average price of the Shares purchased to serve the 2023 LTI Plan at December 31, 2023.
\n
(73) Total value of the Shares purchased to serve the 2023 LTI Plan at December 31, 2023.
\n
(74) The table shows the number of Shares awarded on September 5, 2023, to the beneficiaries of the 2019 LTI Plan, which make up the remaining portion of
\n
the equity component of the bonus vested by the beneficiaries following the achievement of the performance objectives of the Plan.
\n
(75) The table shows the number of Shares awarded on September 5, 2022, to the beneficiaries of the 2019 LTI Plan, which make up part of the equity com-
\n
ponent of the bonus vested by the beneficiaries following the achievement of the performance objectives of the Plan. The remaining portion of the equity
\n
component of the bonus, in accordance with the terms and procedures of the rules of the 2019 LTI Plan, was paid on September 5, 2023.
\n
(76) The table shows the number of Shares awarded on September 5, 2023, to the beneficiaries of the 2020 LTI Plan, which make up part of the equity compo-
\n
nent of the bonus vested by the beneficiaries following the achievement of the performance objectives of the Plan. Disbursement of the remaining portion
\n
of the equity component of the bonus is deferred to 2024, in accordance with the terms and procedures of the rules of the 2020 LTI Plan.
\n

\n\n\n\n\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
(77)
\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 \u20ac6 million in 2023 (\u20ac11 million in 2022).
\n
There have been no terminations or amendments involv-
\n
ing the 2019 LTI Plan, the 2020 LTI Plan, the 2021 LTI Plan,
\n
the 2022 LTI Plan, or the 2023 LTI Plan.
\n

\n\n\n\n\n\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1111": { "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
\n
for the Economy and Finance
\n
Purchase of electricity for the enhanced protection market
\n
Cassa Depositi e Prestiti Group
\n
Directly controlled by the Ministry for the
\n
Economy and 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 Services Operator
\n
Fully controlled (directly) by the Ministry
\n
for the Economy and Finance
\n
Sale of subsidized electricity
\n
Payment of A3 component for renewable resource incentives
\n
EMO - Energy 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
\n
Economy and 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
The following tables summarize transactions with relat-
\n
ed parties, associated companies and joint ventures out-
\n
standing at December 31, 2023 and December 31, 2022
\n
and carried out during the period.
\n
(77) 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
For the 2023 LTI Plan, the grant date is October 5, 2023, i.e. the date of the meeting of the Board of Directors that approved the procedures and timing of
\n
the grant under the 2023 LTI Plan to the beneficiaries.
\n

\n\n\n\n\n\n\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Other Total 2023
\n
Associates and joint
\n
ventures Overall total 2023
\n
Total in financial
\n
statements % of total
\n
Income statement
\n
Revenue from sales and services - 3,172 14 3,626 224
\n
7,03 6 224 7,260 92,882 7.8%
\n
Other income - - - 10 3 13 5 18 2,683 0.7%
\n
Other financial income - - - 2 - 2 237 239 2,916 8.2%
\n
Electricity, gas and fuel purchases 2,035 7,098 11 2,304 2 11,450 128 11,578 46,270 25.0%
\n
Costs for services and other materials - 63 2 2,751 72 2,888 463 3,351 18,304 18.3%
\n
Other operating costs 11 201 355 51 2 620 - 620 6,125 10.1%
\n
Net results from commodity contracts - - - - - - (7) (7) (2,966) 0.2%
\n
Other financial expense 1 - - 29 - 30 59 89 5,966 1.5%
\n
(1) Includes balances mainly referring to: Terna, Cassa Depositi e Prestiti SpA, Eni, Snam, Poste Italiane, Ansaldo Energia and Italgas.
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Other Total at Dec. 31, 2023
\n
Associates and joint
\n
ventures
\n
Overall total at Dec. 31,
\n
2023
\n
Total in financial
\n
statements % of total
\n
Statement of financial position
\n
Other non-current financial assets - - - - 1
\n
1 1,929 1,930 8,750 22.1%
\n
Non-current financial derivative assets - - - - - - 4 4 2,383 0.2%
\n
Other non-current assets - - - 6 - 6 - 6 2,249 0.3%
\n
Trade receivables - 84 7 940 59 1,090 176 1,266 17,773 7. 1%
\n
Other current financial assets - - - 5 1 6 168 174 4,329 4.0%
\n
Other current assets - - 17 23 3 43 49 92 4,099 2.2%
\n
Long-term borrowings - - - 357 - 357 302 659 61,085 1.1%
\n
Non-current contract liabilities - - - 11 7 18 - 18 5,743 0.3%
\n
Non-current financial derivative liabilities - - - - - - 8 8 3,373 0.2%
\n
Short-term borrowings - - - - - - 3 3 4,769 0.1%
\n
Current portion of long-term borrowings - - - 89 - 89 22 111 9,086 1.2%
\n
Trade payables 497 201 378 1,616 8 2,700 129 2,829 15,821 17.9%
\n
Current financial derivative liabilities - - - - - - 15 15 6,461 0.2%
\n
Current contract liabilities - - - 31 22 53 - 53 2,126 2.5%
\n
Other current liabilities - - - 3 34 37 3 40 14,760 0.3%
\n
Other information
\n
Guarantees issued - - - 10 60
\n
70 - 70
\n
Guarantees received - - - 136 36 172 - 172
\n
Commitments - - - 23 - 23 - 23
\n
(1) Includes balances mainly referring to: Terna, Cassa Depositi e Prestiti SpA, Eni, Snam, Poste Italiane, Ansaldo Energia and Italgas.
\n

\n\n\n\n\n
Other Total 2023
\n
Associates and joint
\n
ventures Overall total 2023
\n
Total in financial
\n
statements % of total
\n
Income statement
\n
Revenue from sales and services - 3,172 14 3,626 224
\n
7,03 6 224 7, 260 92,882 7.8%
\n
Other income - - - 10 3 13 5 18 2,683 0.7%
\n
Other financial income - - - 2 - 2 237 239 2,916 8.2%
\n
Electricity, gas and fuel purchases 2,035 7,098 11 2,304 2 11,450 128 11,578 46,270 25.0%
\n
Costs for services and other materials - 63 2 2,751 72 2,888 463 3,351 18,304 18.3%
\n
Other operating costs 11 201 355 51 2 620 - 620 6,125 10.1%
\n
Net results from commodity contracts - - - - - - (7) (7) (2,966) 0.2%
\n
Other financial expense 1 - - 29 - 30 59 89 5,966 1.5%
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Other Total at Dec. 31, 2023
\n
Associates and joint
\n
ventures
\n
Overall total at Dec. 31,
\n
2023
\n
Total in financial
\n
statements % of total
\n
Statement of financial position
\n
Other non-current financial assets - - - - 1
\n
1 1,929 1,930 8,750 22.1%
\n
Non-current financial derivative assets - - - - - - 4 4 2,383 0.2%
\n
Other non-current assets - - - 6 - 6 - 6 2,249 0.3%
\n
Trade receivables - 84 7 940 59 1,090 176 1,266 17,773 7. 1%
\n
Other current financial assets - - - 5 1 6 168 174 4,329 4.0%
\n
Other current assets - - 17 23 3 43 49 92 4,099 2.2%
\n
Long-term borrowings - - - 357 - 357 302 659 61,085 1.1%
\n
Non-current contract liabilities - - - 11 7 18 - 18 5,743 0.3%
\n
Non-current financial derivative liabilities - - - - - - 8 8 3,373 0.2%
\n
Short-term borrowings - - - - - - 3 3 4,769 0.1%
\n
Current portion of long-term borrowings - - - 89 - 89 22 111 9,086 1.2%
\n
Trade payables 497 201 378 1,616 8 2,700 129 2,829 15,821 17.9%
\n
Current financial derivative liabilities - - - - - - 15 15 6,461 0.2%
\n
Current contract liabilities - - - 31 22 53 - 53 2,126 2.5%
\n
Other current liabilities - - - 3 34 37 3 40 14,760 0.3%
\n
Other information
\n
Guarantees issued - - - 10 60
\n
70 - 70
\n
Guarantees received - - - 136 36 172 - 172
\n
Commitments - - - 23 - 23 - 23
\n

\n\n\n\n\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Other Total 2022
\n
Associates and joint
\n
ventures Overall total 2022
\n
Total in financial
\n
statements % of total
\n
Income statement
\n
Revenue from sales and services - 7,949 87 4,497 196
\n
12,729 210 12,939 135,653 9.5%
\n
Other income - - - 389 - 389 - 389 4,864 8.0%
\n
Other financial income - - - - - - 154 154 3,430 4.5%
\n
Electricity, gas and fuel purchases 6,379 16,817 2 4,266 3 27,467 413 27,880 96,896 28.8%
\n
Costs for services and other materials - 220 2 3,258 73 3,553 247 3,800 20,228 18.8%
\n
Other operating costs 10 147 - 420 3 580 1 581 4,685 12.4%
\n
Net results from commodity contracts - - - 50 - 50 - 50 2,365 2.1%
\n
Other financial expense 1 - 2 10 - 13 21 34 5,880 0.6%
\n
(1) Includes balances mainly referring to: Terna, Cassa Depositi e Prestiti SpA, Eni, Snam, Poste Italiane, Ansaldo Energia and Italgas.
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Other Total at Dec. 31, 2022
\n
Associates and joint
\n
ventures
\n
Overall total at Dec. 31,
\n
2022
\n
Total in financial
\n
statements % of total
\n
Statement of financial position
\n
Other non-current financial assets - - - - -
\n
- 1,885 1,885 8,359 22.6%
\n
Trade receivables - 220 6 1,040 38 1,304 259 1,563 16,605 9.4%
\n
Current financial derivative assets - - - - - - 5 5 14,830 -
\n
Other current financial assets - - - 5 - 5 99 104 13,753 0.8%
\n
Other current assets - - 30 58 2 90 63 153 4,314 3.5%
\n
Long-term borrowings - - - 447 - 447 327 774 68,191 1.1%
\n
Non-current contract liabilities - - - 9 8 17 - 17 5,747 0.3%
\n
Non-current financial derivative liabilities - - - - - - 9 9 5,895 0.2%
\n
Short-term borrowings - - - - - - 14 14 18,392 0.1%
\n
Current portion of long-term borrowings - - - 89 - 89 21 110 2,835 3.9%
\n
Trade payables 1,211 305 6 1,097 (1) 2,618 192 2,810 17,641 15.9%
\n
Other current financial liabilities - - - - - - 1 1 853 0.1%
\n
Current contract liabilities - - - 23 20 43 - 43 1,775 2.4%
\n
Other current liabilities - - - 3 23 26 21 47 11,713 0.4%
\n
Other information
\n
Guarantees issued - 20 - 11 58
\n
89 - 89
\n
Guarantees received - - - 134 36 170 - 170
\n
Commitments - - - 149 - 149 - 149
\n
(1) Includes balances mainly referring to: Terna, Cassa Depositi e Prestiti SpA, Eni, Snam, Poste Italiane, Ansaldo Energia and Italgas.
\n

\n\n\n\n\n
Total 2022
\n
Associates and joint
\n
ventures Overall total 2022
\n
Total in financial
\n
statements % of total
\n
Income statement
\n
Revenue from sales and services - 7,949 87 4,497 196
\n
12,729 210 12,939 135,653 9.5%
\n
Other income - - - 389 - 389 - 389 4,864 8.0%
\n
Other financial income - - - - - - 154 154 3,430 4.5%
\n
Electricity, gas and fuel purchases 6,379 16,817 2 4,266 3 27,467 413 27,880 96,896 28.8%
\n
Costs for services and other materials - 220 2 3,258 73 3,553 247 3,800 20,228 18.8%
\n
Other operating costs 10 147 - 420 3 580 1 581 4,685 12.4%
\n
Net results from commodity contracts - - - 50 - 50 - 50 2,365 2.1%
\n
Other financial expense 1 - 2 10 - 13 21 34 5,880 0.6%
\n
Millions of euro
\n
Single Buyer EMO ESO
\n
Cassa Depositi e
\n
Prestiti Group
\n
(1)
\n
Total at Dec. 31, 2022
\n
Associates and joint
\n
ventures
\n
Overall total at Dec. 31,
\n
2022
\n
Total in financial
\n
statements % of total
\n
Statement of financial position
\n
Other non-current financial assets - - - - -
\n
- 1,885 1,885 8,359 22.6%
\n
Trade receivables - 220 6 1,040 38 1,304 259 1,563 16,605 9.4%
\n
Current financial derivative assets - - - - - - 5 5 14,830 -
\n
Other current financial assets - - - 5 - 5 99 104 13,753 0.8%
\n
Other current assets - - 30 58 2 90 63 153 4,314 3.5%
\n
Long-term borrowings - - - 447 - 447 327 774 68,191 1.1%
\n
Non-current contract liabilities - - - 9 8 17 - 17 5,747 0.3%
\n
Non-current financial derivative liabilities - - - - - - 9 9 5,895 0.2%
\n
Short-term borrowings - - - - - - 14 14 18,392 0.1%
\n
Current portion of long-term borrowings - - - 89 - 89 21 110 2,835 3.9%
\n
Trade payables 1,211 305 6 1,097 (1) 2,618 192 2,810 17,641 15.9%
\n
Other current financial liabilities - - - - - - 1 1 853 0.1%
\n
Current contract liabilities - - - 23 20 43 - 43 1,775 2.4%
\n
Other current liabilities - - - 3 23 26 21 47 11,713 0.4%
\n
Other information
\n
Guarantees issued - 20 - 11 58
\n
89 - 89
\n
Guarantees received - - - 134 36 170 - 170
\n
Commitments - - - 149 - 149 - 149
\n

\n\n\n\n\n
\n\n
With regard to disclosures on the remuneration of di-
\n
rectors, members of the Board of Statutory Auditors, the
\n
General Manager and key management personnel, provid-
\n
ed for under IAS 24, please see the following tables.
\n
Millions of euro
\n
2023 2022 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
Termination benefits 5 - 5 -
\n
Share-based payments 1 1 - -
\n
Total 11 6 5 83.3%
\n
Millions of euro
\n
2023 2022 Change
\n
Remuneration of key management personnel
\n
Short-term employee benefits 8 13 (5) -38.5%
\n
Termination benefits 4 - 4 -
\n
Share-based payments 1 2 (1) -50.0%
\n
Total 13 15 (2) -13.3%
\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 (Enel Procedure for Trans-
\n
actions with Related Parties). The procedure (available at
\n
https://www.enel.com/investors/bylaws-rules-and-pol-
\n
icies/transactions-with-related-parties/) sets out rules
\n
designed to ensure the transparency and procedural and
\n
substantive propriety of transactions with related parties.
\n
It was adopted in implementation of the provisions of Arti-
\n
cle 2391-bis of the Italian Civil Code and the implementing
\n
regulations issued by CONSOB with Resolution no. 17221
\n
of March 12, 2010, as amended (\u201cCONSOB Regulation\u201d).
\n
No related-party transactions requiring disclosure in the
\n
financial statements pursuant to the CONSOB Regulation
\n
were carried out in 2023.
\n
\n\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag11": { "value": "\n
55. Government grants \u2013 Disclosure pursuant
\n
to Article 1, 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 2023,
\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 institution/
\n
Grantor Beneficiary Amount Notes
\n
Regione Sicilia
\n
Enel X Mobility Srl (Enel
\n
X Way Italia Srl as from
\n
July 1, 2023)
\n
(1.03)
\n
Instalment of grant for the Sicilia Smart Charging project, financed
\n
under the PNIRE Regione Sicilia
\n
MIUR Enel X Srl (0.38)
\n
Instalment of grant for the SE4I project application, financed under
\n
the PON MIUR R&SSI PNR 2015-2020
\n
MIMIT Enel Produzione SpA (0.04)
\n
Balance of grant for the Hydrostore project financed under the
\n
2015 Bando Industria
\n
MASE e-distribuzione SpA (347.79)
\n
10% advance payment of the SmartGrid and Resilience projects of
\n
the NRRP
\n
MASE e-distribuzione SpA (15.68)
\n
Progress payment for PON IC 2014/2020 FESR, ASSE IV, AZIONE
\n
4,3,1, of the projects: Agrigento, Pachino, Priolo, Campagna,
\n
Ciminna, Valguarnera, Santa Croce Camerina, Mussomeli, Scordia,
\n
Ragusa 3
\n
European Commission e-distribuzione SpA (0.10)
\n
Progress payment for R&D project Life Lanario (LIFE funding
\n
program)
\n
European Commission e-distribuzione SpA (0.02)
\n
Progress payment for R&D project Flexplan (H2020 funding
\n
program)
\n
MASE e-distribuzione SpA (10.69)
\n
Progress payment for R&D project Puglia Active Network (NER 300
\n
funding program)
\n
(375.73) Total
\n
\n\n
Grants made in millions of euro
\n
Grantor Beneficiary Amount Notes
\n
Enel SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.10 Donation
\n
Enel SpA Enel Cuore Onlus 0.59 Donation in support of projects identified in 2023
\n
Enel SpA Luiss Guido Carli 0.07
\n
Donation for the development and transmission of scientific,
\n
technological and humanistic knowledge
\n
Enel SpA Human Foundation 0.05
\n
Donation to generate and develop innovative solutions to social
\n
problems
\n
Enel SpA FGS Onlus 0.03 Donation to promote equal opportunities
\n
Enel X Srl Enel Cuore Onlus 0.04 2023 contribution
\n
Enel Green Power Italia
\n
Lega Navale Italiana
\n
Sezione Belluno
\n
0.04 Donation for the \u201cVela per Tutti\u201d project
\n
Enel Green Power Italia
\n
Lega Navale Italiana
\n
Sezione Belluno
\n
0.02 Donation for the \u201cVela per Tutti\u201d project
\n
Enel Produzione SpA
\n
Fondazione Vajont 9
\n
Ottobre 1963 Onlus
\n
0.05 Donation Vajont Foundation
\n
Enel Produzione SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.41 1st Instalment 2023 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.15 1st Instalment 2023 grant
\n
Enel Produzione SpA Enel Cuore Onlus 0.70 Balance 2022 grant
\n
Enel Produzione SpA
\n
Comune di
\n
Civitavecchia
\n
0.08 Sustainability Plan City of Civitavecchia
\n
Enel Produzione SpA
\n
Capitaneria di Porto
\n
Empedocle
\n
0.03
\n
Design, construction and installation of removable metal structure
\n
to shade area of Port Authority of Porto Empedocle for parking of
\n
associated military vehicles
\n
Enel Energia SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.90 50% advance on 2023 contribution
\n
Enel Energia SpA Enel Cuore Onlus 0.33 20% advance on 2023 contribution
\n
Enel Energia SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.89 Balance 2022 contribution
\n
Enel Italia SpA Enel Cuore Onlus 0.07 Balance 2022 extraordinary contribution
\n
Enel Italia SpA Capone Valentina 0.01 Modal donation \u201cAlleva la Speranza\u201d project
\n
Enel Italia SpA
\n
Fondazione Nazionale
\n
Accademia Santa
\n
Cecilia
\n
0.60 Donation to support the Foundation cultural activities
\n
Enel Italia SpA
\n
Teatro alla Scala di
\n
Milano
\n
0.60
\n
Donation to the Teatro alla Scala to support the cultural activities of
\n
the Foundation
\n
Enel Italia SpA Fondazione MAXXI 0.60 Donation to support the Foundation cultural activities
\n
Enel Italia SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.05
\n
2022 contribution to support research and higher education
\n
projects
\n
Enel Italia SpA Croce Rossa Italiana 0.26
\n
Donation of medical-health equipment/materials purchased for
\n
COVID vaccination centers in Enel locations
\n
Enel Global Trading SpA
\n
Fondazione Centro
\n
Studi Enel
\n
1.02
\n
Contribution aimed at supporting and developing research and
\n
higher education projects
\n
e-distribuzione SpA Enel Cuore Onlus 1.89 80% balance of 2022 grant
\n
e-distribuzione SpA Enel Cuore Onlus 0.33 20% balance of 2023 grant
\n
e-distribuzione SpA
\n
Fondazione Centro
\n
Studi Enel
\n
1.28 50% balance of 2022 grant
\n
e-distribuzione SpA
\n
Fondazione Centro
\n
Studi Enel
\n
0.88 50% balance of 2023 grant
\n
e-distribuzione SpA
\n
Dipartimento della
\n
Protezione Civile
\n
Presidenza del
\n
Consiglio dei Ministri
\n
0.67
\n
Free transfer of company assets to be transported and delivered
\n
to the Ukrainian authorities as part of the initiative to support
\n
the energy sector in Ukraine promoted by Energy Community in
\n
collaboration with the European Union Civil Protection Mechanism
\n
(UCPM)
\n
12.74 Total
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfGovernmentGrantsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1080": { "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, 2023 at Dec. 31, 2022 Change
\n
Guarantees given:
\n
- sureties and other guarantees granted to third parties 3,407 4,296 (889)
\n
Commitments to suppliers for:
\n
- electricity purchases 63,422 64,878 (1,456)
\n
- fuel purchases 47,666 96,996 (49,330)
\n
- various supplies 3,017 2,449 568
\n
- tenders 6,982 6,165 817
\n
- other 6,483 6,889 (406)
\n
Total 127,570 177,377 (49,807)
\n
TOTAL 130,977 181,673 (50,696)
\n
Compared with December 31, 2022, the decrease of
\n
\u20ac1,456 million in commitments for \u201celectricity purchases\u201d
\n
is essentially attributable to companies in Latin America, in
\n
particular in Chile, and developments in electricity prices.
\n
The decrease of \u20ac49,330 million in commitments for \u201cfuel
\n
purchases\u201d mainly regards the decrease in gas prices, es-
\n
pecially in Italy and Spain, compared to 2022.
\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", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1081": { "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, 2023 at Dec. 31, 2022 Change
\n
Guarantees given:
\n
- sureties and other guarantees granted to third parties 3,407 4,296 (889)
\n
Commitments to suppliers for:
\n
- electricity purchases 63,422 64,878 (1,456)
\n
- fuel purchases 47,666 96,996 (49,330)
\n
- various supplies 3,017 2,449 568
\n
- tenders 6,982 6,165 817
\n
- other 6,483 6,889 (406)
\n
Total 127,570 177,377 (49,807)
\n
TOTAL 130,977 181,673 (50,696)
\n
Compared with December 31, 2022, the decrease of
\n
\u20ac1,456 million in commitments for \u201celectricity purchases\u201d
\n
is essentially attributable to companies in Latin America, in
\n
particular in Chile, and developments in electricity prices.
\n
The decrease of \u20ac49,330 million in commitments for \u201cfuel
\n
purchases\u201d mainly regards the decrease in gas prices, es-
\n
pecially in Italy and Spain, compared to 2022.
\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:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1082": { "value": "\n
57. Contingent assets and liabilities
\n
The following reports the main contingent assets and lia-
\n
bilities at December 31, 2023, which are not recognized in
\n
the consolidated financial statements as they do not meet
\n
the requirements provided for in IAS 37.
\n
Hydroelectric concessions \u2013 Italy
\n
Italian regulations governing large-scale hydroelectric con-
\n
cessions were most recently modified by the \u201cSimplifica-
\n
tions Decree\u201d (Decree Law 135 of 2018 ratified with Law 12
\n
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
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
\n
a fixed and variable component of fees, as well as an ob-
\n
ligation 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 of
\n
this national law and under specific enabling authority, as
\n
of today various regions (Lombardy, Piedmont, Emilia-Ro-
\n
magna, Friuli-Venezia Giulia, the Province of Trento, Veneto,
\n
Calabria, Basilicata, Abruzzo and Umbria) have enacted re-
\n
gional laws implementing state legislation, and requested
\n
payment of the dual-component fee and the monetization
\n
of free electricity supplies.
\n
Enel Produzione SpA and Enel Green Power SpA challenged
\n
before the Superior Public Water Resources Court imple-
\n
menting acts issued under the individual regional laws and
\n
the subsequent payment notices of fees and the monetiza-
\n
tion of free electricity supplies, asking that they be declared
\n
void and raising the question of constitutional illegitimacy
\n
of both the national law and the regional laws.
\n
The companies initiated the proceedings by complaining
\n
that the regional implementing acts \u2013 as well as the region-
\n
al legislation which they implement \u2013 were constitutionally
\n
illegitimate, first for violation of national legislation and var-
\n
ious primary principles protected both by the Italian Con-
\n
stitution and European law concerning legitimate expecta-
\n
tions, property rights, reasonableness, private initiative, and
\n
concessions, where:
\n
\u2022
\n
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 equivalent;
\n
\u2022
\n
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

\n\n\n\n
into a fixed component and a variable component) and to
\n
supply a certain annual quantity of electricity free of charge
\n
in the form of payment of the associated monetary value,
\n
which is also to be paid by the holders of valid concessions
\n
that have not yet expired, creates an unexpected and un-
\n
reasonable financial imbalance in the concession relation-
\n
ships. This circumstance is in evident contrast with the
\n
principles of reasonableness, proportionality and legitimate
\n
expectation of concession fees, compliance with which is
\n
required by constitutional case law if, in the context of long-
\n
term relationships, pejorative modifications are introduced.
\n
Both the national law and the regional implementing legis-
\n
lation violate Community principles and constitutional prin-
\n
ciples such as property rights, the principle of legal certain-
\n
ty, and the freedom of enterprise. In particular, the rules do
\n
not expressly provide for the transfer of the business unit
\n
from the outgoing to the successor concession holder, and
\n
also establish inadequate criteria for the valorization of the
\n
works to be transferred, which threatens to create what is
\n
essentially a mechanism for expropriation, in violation of
\n
constitutional principles.
\n
The pending cases against the regions of Lombardy and
\n
Piedmont have been adjourned to the collegial hearings of
\n
April 24, 2024 and June 12, 2024, while the remaining pro-
\n
ceedings are still pending in the preliminary investigation
\n
phase.
\n
Antitrust proceeding 12461 - EE - Contract
\n
renewals \u2013 Italy
\n
On December 13, 2022, the Competition Authority noti-
\n
fied Enel Energia SpA (\u201cthe Company\u201d or \u201cEE\u201d) and six other
\n
companies (Hera, A2A, Acea, Eni Plenitude, Engie, Edison)
\n
that it had initiated a proceeding for unfair commercial
\n
practices (violation of certain provisions of the Consumer
\n
Code and Article 3 of Legislative Decree 115/2022, the sec-
\n
ond \u201cAid Decree\u201d).
\n
In particular, the Competition Authority, among other thing,
\n
argued that EE had sent its customers, in the period from
\n
May to October 2022, notices of price changes that were
\n
allegedly generic and omissive to the extent that they did
\n
not specify the expiry date of the financial conditions sub-
\n
ject to renewal and represented an unwarranted exercise
\n
of ius variandi in modification of the financial conditions of
\n
the supply relationship, in violation of the aforementioned
\n
Article 3 of the second Aid Decree.
\n
With the measure initiating the procedure, the Competition
\n
Authority simultaneously prohibited on a precautionary ba-
\n
sis the sending of new price change notices and ordered
\n
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, then extended until June 30, 2023 by Legislative
\n
Decree 198/2022, the \u201cMilleproroghe Decree\u201d).
\n
Following the pronouncement of the Council of State of
\n
December 22, 2022 and the Milleproroghe Decree of De-
\n
cember 29, 2022, which excluded the applicability of Arti-
\n
cle 3 of the Decree to contract renewals (of expiring offers)
\n
in compliance with the contractual terms of notice and
\n
without prejudice to the right of withdrawal of the coun-
\n
terparty, thus distinguishing them from those covered by
\n
the ius variandi, the Competition Authority, with a new pre-
\n
cautionary measure on December 29, 2022, ordered the
\n
partial upholding of the original precautionary measure and
\n
confirmed the prohibition on changes or renewals of the fi-
\n
nancial conditions of expiring contracts for which the expiry
\n
date was not specifically identified or in any case predeter-
\n
minable in the associated notice sent to the customer. EE
\n
filed an appeal for additional reasons against this measure.
\n
With a ruling published on May 19, 2023, the Lazio Region-
\n
al Administrative Court accepted the arguments of EE and
\n
voided the two precautionary measures of the Competition
\n
Authority on December 12, 2022 and December 29, 2022,
\n
disagreeing with the logical process established by the
\n
Competition Authority as a basis for the provisions, which
\n
were deemed to lack grounds for success. In particular,
\n
according to the Court, the legislator intended to suspend
\n
only the changes to the rules portion of the agreement and
\n
not also the updating of expired or expiring prices, as this
\n
would fix the previous pricing conditions indefinitely. Both
\n
AGCM and EE appealed the Court ruling before the Council
\n
of State and the proceeding is pending.
\n
In the meantime, on November 15, 2023, the Competition
\n
Authority, acting in the proceeding for unfair commercial
\n
practices, issued a ruling finding a violation of Articles 24
\n
and 25 of the Consumer Code, levying a fine of \u20ac10 million
\n
on EE, which was paid by EE on December 15, 2023. On Jan-
\n
uary 15, 2024, EE appealed to void the fine before the Lazio
\n
Regional Administrative Court.
\n
In an order issued following the hearing held on March
\n
20, 2024, the Lazio Regional Administrative Court granted
\n
a petition presented jointly by the parties to address the
\n
grounds for appeal at the hearing on the merits scheduled
\n
for July 17, 2024.
\n
Criminal proceeding against e-distribuzione
\n
concerning an accident \u2013 Italy
\n
On July 1, 2021, e-distribuzione SpA was notified of a pro-
\n
ceeding against a number of its employees and managers
\n
and e-distribuzione SpA itself pursuant to Legislative De-
\n
cree 231/2001, initiated by the Public Prosecutor\u2019s Office of
\n
Taranto, following the accident that occurred on the night
\n
between June 27 and 28, 2021 in which an employee of a
\n
contractor was injured and subsequently died.
\n
During the investigative phase, an unrepeatable technical
\n
assessment was ordered and the report of the Technical
\n
Consultant of the Public Prosecutor, dated December 15,
\n
2021, was filed and incorporated in the Public Prosecutor\u2019s
\n
case.
\n

\n\n\n\n
A notice of dismissal of charges was subsequently sent
\n
to some of the defendants and the subcontractor with
\n
whom the deceased worker was employed. A notice of
\n
conclusion of the preliminary investigation pursuant to Ar-
\n
ticle 415-bis of the Code of Criminal Procedure was sent
\n
to the remaining defendants and the company and, on
\n
April 17, 2023, a notice was served to set the preliminary
\n
hearing before the Preliminary Hearing Judge of the Court
\n
of Taranto for May 23, 2023. Following adjournments, the
\n
preliminary hearing was scheduled to continue on Febru-
\n
ary 20, 2024, when the parties were heard, including the
\n
request for a plea deal from one of the defendants. The
\n
Court then rescheduled the hearing to May 21, 2024 for
\n
the decision to send the case to trial.
\n
In agreement with the insurance company, a process was
\n
defined to reach a settlement with the heirs of the de-
\n
ceased to extinguish the claims formulated by the injured
\n
parties without admission of liability.
\n
Arbitration proceedings Enel Produzione SpA
\n
\u2013 Italy
\n
In the 4th Quarter of 2023 a coal supplier initiated an ar-
\n
bitration proceeding against Enel Produzione requesting
\n
the fulfillment by the latter of certain coal supply contracts
\n
stipulated between the parties during 2021, performance
\n
of which was suspended by Enel Produzione in March
\n
2022 due to the sanctions imposed with EU Regulations
\n
no. 269/2014 and no. 833/2014. A claim of about $11 mil-
\n
lion was filed for supplies already executed and about $62
\n
million for expected supplier, plus interest. The arbitration
\n
proceedings are pending and are currently expected to be
\n
completed in 2025.
\n
Green Network litigation \u2013 Italy
\n
With a summons dated May 8, 2019, Green Network SpA
\n
(GN) sued Enel Energia SpA (EE) before the Court of Rome
\n
to ascertain alleged anti-competitive conduct (including
\n
illegal win-back practices) that EE carried out in an at-
\n
tempt to recover customers who would have moved to the
\n
competing trader and, as a result, order EE to pay damag-
\n
es quantified at \u20ac116,049,056, plus interest and monetary
\n
revaluation, in addition to the publication of the sentence.
\n
EE formally appeared in court, contesting the validity of
\n
the opposing party\u2019s claim in fact and law and requesting
\n
the complete denial of the claims, as well as an order for
\n
the plaintiff to pay damages for frivolous litigation. After
\n
conducting the preliminary investigation phase, during
\n
which a court-ordered phonic assessment was performed,
\n
the Court rejected the plaintiff\u2019s further preliminary inves-
\n
tigation requests and adjourned the case for summing up
\n
to a hearing scheduled for June 27, 2024.
\n
Penalty proceeding for Enel Energia \u2013 Italy
\n
On February 29, 2024, the Personal Data Protection Au-
\n
thority (DPA) announced that it was levying a fine of
\n
\u20ac79,107,101 on Enel Energia SpA, in addition to a number
\n
of prescriptive measures.
\n
The action originates with a proceeding undertaken by the
\n
DPA in July 2023, during which the company was accused
\n
of failing to adopt an adequate system for monitoring and
\n
controlling the operation of its agencies, which, in the pe-
\n
riod from 2015 to 2022, also made use of operators who
\n
were not officially appointed, for the sole purpose of max-
\n
imizing their profits even to the detriment of the company
\n
itself.
\n
In the meantime, the company, acting for its own protec-
\n
tion, had already taken all the contractually established
\n
measures against the agencies involved in the circum-
\n
stances addressed by the penalty measure and had also
\n
filed criminal complaints against the operators who had
\n
acted abusively.
\n
The company, considering the objections raised by the
\n
DPA to be unfounded, intends to challenge the provision
\n
before the Civil Court of Rome, filing a request for suspen-
\n
sion of both the payment of the fine and the prescriptive
\n
measures.
\n
BEG litigation \u2013 Italy, France, Luxembourg
\n
Following an arbitration proceeding initiated by BEG SpA
\n
(BEG) in Italy, Enelpower SpA (now Enelpower Srl) obtained
\n
a ruling in its favor in 2002, which was upheld by the Court
\n
of Cassation in 2010, which entirely rejected the petition
\n
for damages with regard to alleged breach by Enelpower
\n
of an agreement concerning the assessment of the possi-
\n
ble construction of a hydroelectric power station in Albania.
\n
Subsequently, BEG, acting through its subsidiary Albania
\n
BEG Ambient, filed suit against Enelpower and Enel SpA
\n
(Enel) in Albania concerning the matter, obtaining a ruling
\n
from the District Court of Tirana on March 24, 2009, upheld
\n
by the Albanian Court of Cassation, ordering Enelpower and
\n
Enel to pay tortious damages of about \u20ac25 million for 2004
\n
as well as an unspecified amount of tortious damages for
\n
subsequent years. Following the ruling, Albania BEG Ambi-
\n
ent demanded payment of more than \u20ac430 million.
\n
In November 2016, Enel and Enelpower filed a petition with
\n
the Albanian Court of Cassation, asking for the ruling is-
\n
sued 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
\n\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 \u20ac15,000 in non-pecuniary
\n
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 lia-
\n
bility. With an order of June 14, 2022, the Court of Milan, in
\n
accepting the objection of territorial incompetence raised
\n
by the State Attorney, declared its incompetence to hear
\n
the dispute in favor of the Court of Rome, the court exclu-
\n
sively competent to hear the causes in which the Italian
\n
State is involved, ordering BEG to pay the costs of the pro-
\n
ceedings in favor of the defendants. BEG did not resume
\n
the judgment before the Court of Rome within the legal
\n
term of October 14, 2022 and therefore the proceeding
\n
was extinguished.
\n
A short time later, on November 3, 2022, BEG resubmit-
\n
ted the same claims for damages of the terminated pro-
\n
ceeding, serving a new writ of summons before the Court
\n
of Milan against the same defendants, with the exception
\n
of the Italian State, which BEG declared not to wishing
\n
to agree to this judgement. Enel and Enelpower are pre-
\n
paring their defenses to proceed with the appearance in
\n
court in order to contest the claim, which is considered
\n
entirely specious and unfounded, like the previous similar
\n
initiative. Following the hearing for admission of evidence,
\n
the Court issued an order on October 26, 2023 denying
\n
the preliminary requests of the plaintiff and, considering
\n
the case ready for decision, scheduled final arguments for
\n
October 17, 2024.
\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
Italy
\n
With an appeal notified on September 11, 2023, Albania BEG
\n
Ambient ShpK (ABA) initiated a proceeding before the Court
\n
of Appeal of Rome against Enel SpA and Enelpower Srl, in
\n
order to obtain, pursuant to Article 67 of Law 218/1995, en-
\n
forcement of the ruling of the Court of Tirana of March 24,
\n
2009. The two companies are preparing their defense to
\n
contest the claim for execution in Italy as well. Following the
\n
initial hearing, the Court of Appeal adjourned the proceed-
\n
ing until September 18, 2025 for oral arguments.
\n
France
\n
In 2012, ABA filed suit against Enel and Enelpower with the
\n
Tribunal de Grande Instance in Paris in order to render the
\n
ruling of the Albanian court enforceable in France.
\n
On January 29, 2018, the Tribunal de Grande Instance re-
\n
jected ABA claim. Among other issues, the Tribunal de
\n
Grande Instance ruled that: (i) the Albanian ruling conflict-
\n
ed with an existing decision (the arbitration ruling of 2002)
\n
and that (ii) the fact that BEG sought to obtain in Albania
\n
what it was not able to obtain in the Italian arbitration pro-
\n
ceeding, resubmitting the same claim through ABA, rep-
\n
resented fraud.
\n
Subsequently, with a ruling of May 4, 2021, the Paris Court
\n
of Appeal denied the appeal by ABA, in full, upholding the
\n
ruling at first instance and, in particular, fully upholding the
\n
non-compatibility of the Albanian ruling with the arbitra-
\n
tion award of 2002, ordering it to reimburse Enel and Enel-
\n
power \u20ac200,000.00 each for legal costs.
\n
With a ruling of May 17, 2023 the French Cour de Cassa-
\n
tion rejected ABA\u2019s appeal, thereby definitively denying the
\n
ABA\u2019s petition for execution.
\n
Following the favorable ruling of the Court of Appeal, Enel
\n
initiated a separate proceeding to obtain release of the
\n
precautionary attachments granted to ABA of any receiv-
\n
ables of Enel in respect of Enel France. With an order of
\n
June 16, 2022, the Court of Paris ordered the release of
\n
the precautionary attachments while also ordering ABA to
\n
pay Enel a total of about \u20ac146,000 in damages and legal
\n
costs. ABA challenged the aforementioned release order
\n
and the appeal was granted by the Paris Court of Appeal
\n
with a decision of May 17, 2023. On June 16, 2023 Enel filed
\n
a petition and on December 15, 2023 formally appealed
\n
that ruling before the French Cour de Cassation.
\n
The Netherlands
\n
In 2014, ABA filed suit with the Court of Amsterdam to
\n
render the ruling of the Albanian court enforceable in the
\n
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, ruling
\n
that the Albanian judgment cannot be recognized and en-
\n
forced in the Netherlands, as it was arbitrary and manifest-
\n
ly 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 rejected any claim made by ABA, thereby
\n
confirming the denial of recognition and enforcement of
\n
the Albanian ruling in the Netherlands. Moreover, having
\n
re-analyzed the merits of the case under Albanian law,
\n
\n\n
the Court found no tortious liability on the part of Enel and
\n
Enelpower and ordered ABA to reimburse the companies
\n
for the losses incurred in illegitimate conservative sei-
\n
zures, to be quantified as part of a specific procedure, and
\n
the costs of the trial and appeal proceedings.
\n
On July 16, 2021 the Supreme Court completely rejected
\n
ABA\u2019s appeals, ordering it to reimburse court costs.
\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. In particular,
\n
after several legal representatives appointed by ABA with-
\n
drew from the cause, in September 2023 the court sus-
\n
pended the proceeding.
\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 - Endesa
\n
Generaci\u00f3n SA \u2013 Spain
\n
Following the Decision of November 27, 2017 (the \u201cDeci-
\n
sion\u201d) of the European Commission on the issue of envi-
\n
ronmental incentives for thermal power plants, on March
\n
2, 2018 the Commission\u2019s Directorate-General for Com-
\n
petition has initiated a formal enquiry pursuant to Article
\n
108, paragraph 2, of the Treaty on the Functioning of the
\n
European Union, in order to establish whether the envi-
\n
ronmental incentive for coal power plants provided for in
\n
Spain\u2019s Order ITC/3860/2007 represents State aid com-
\n
patible with the internal market. On April 13, 2018, acting
\n
as an interested third party, Endesa Generaci\u00f3n submitted
\n
comments contesting this interpretation. Subsequently,
\n
on September 8, 2021, the appeal of the decision lodged
\n
by Gas Natural (now Naturgy) with the General Court of the
\n
European Union was denied. The ruling was appealed by
\n
Naturgy and EDP Espa\u00f1a before the Court of Justice of the
\n
European Union (CJEU). Endesa Generaci\u00f3n filed a request
\n
to participate in the proceeding and, with an order of June
\n
1, 2022, the CJEU allowed that participation. Subsequently,
\n
following the filing of the ruling of the Advocate General,
\n
on December 14, 2023, the CJEU voided both the decision
\n
and ruling of the General Court.
\n
Bono Social \u2013 Spain
\n
In relation to the various financing schemes for the Bono
\n
Social adopted by the Spanish government, with ruling
\n
no. 212/2022 of February 21, 2022 the Tribunal Supremo
\n
ruled on the appeals filed by Endesa SA, Endesa Energ\u00eda
\n
SAU and Energ\u00eda XXI Comercializadora de Referencia SLU
\n
(Endesa) and other companies in the energy sector against
\n
the third scheme for financing the Bono Social, and for
\n
co-financing with government authorities of the supply to
\n
vulnerable consumers, envisaged under Article 45, para-
\n
graph 4 of Spain\u2019s Electricity Industry Law 24/2013, Roy-
\n
al Decree Law 7/2016 of December 23 and Royal Decree
\n
897/2017 of October 6.
\n
With the ruling, the Tribunal Supremo, partially allowing
\n
the appeals, found that (i) the aforesaid regime was inap-
\n
plicable; (ii) Articles 12 to 17 of Royal Decree 897/2017 are
\n
inapplicable and void, and (iii) the appellants were entitled
\n
to be compensated for the amounts paid to finance the
\n
Bono Social 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 immediate payment
\n
of the uncontested part, equal to about \u20ac152 million, for fi-
\n
nancing costs associated with customers in the regulated
\n
market, as well as payment of other amounts as quantified
\n
in the technical studies prepared by the companies. With
\n
an order of May 26, 2023 the Tribunal Supremo (i) ordered
\n
the government to pay Endesa \u20ac152,272,229.83, plus in-
\n
terest, (ii) required the Ministry for the Ecological Transi-
\n
tion and the Demographic Challenge (MITECO) to quantify
\n
as soon as possible the additional amounts to be paid to
\n
Endesa in respect of (a) costs to finance the Bono Social
\n
for the free market, deducting any amounts transferred
\n
to customers, and (b) investments made to implement the
\n
Bono Social, and to pay Endesa those amounts, plus in-
\n
terest, within two months. On July 28, 2023, the Secretary
\n
of State for Energy (MITECO) announced a resolution that
\n
grants Endesa (i) an indemnity of \u20ac171.6 million (including
\n
interest) for financing costs associated with customers in
\n
the regulated market and (ii) an additional indemnity of
\n
\u20ac6.6 million (including interest) for costs incurred to im-
\n
plement the Bono Social. However, the resolution does not
\n
provide for any indemnity for the financing costs of the
\n
Bono Social for the free market. Therefore, on September
\n
18, 2023 Endesa filed arguments supported by technical
\n
studies with the Tribunal Supremo to demonstrate Ende-
\n
sa\u2019s entitlement to be indemnified for the free market seg-
\n
ment as well.
\n

\n\n\n\n
\u201cEndesa I and II\u201d industrial relations dispute \u2013
\n
Spain
\n
After being signed by the social partners and entering
\n
force on January 23, 2020, the 5th Endesa Collective Bar-
\n
gaining Agreement was published in the Spanish Official
\n
Journal (Bolet\u00edn Oficial del Estado) on June 17, 2020, taking
\n
full effect.
\n
On December 30, 2020, the Audiencia Nacional notified
\n
Endesa a new petition for a \u201ccollective dispute\u201d initiated
\n
by three trade unions with minority representation filed on
\n
December 1, 2020, concerning the cancellation of some
\n
\u201cderogatory provisions\u201d of the 5th Endesa Collective Bar-
\n
gaining Agreement. The plaintiffs claim that the contested
\n
\u201cderogatory provisions\u201d would imply the illegitimate abo-
\n
lition of social benefits and economic rights of workers.
\n
Endesa considers these provisions to be fully legitimate,
\n
in line with the arguments made during proceeding con-
\n
cerning the reduction of social benefits for retired person-
\n
nel. With a ruling of November 15, 2021, the petitions of
\n
the plaintiff unions were rejected, with verification of the
\n
legitimacy of the 5th Endesa Collective Bargaining Agree-
\n
ment. The ruling was appealed by the trade unions before
\n
the Tribunal Supremo and the proceeding is currently un-
\n
der way.
\n
Moreover, with reference to the 4th Endesa Collective Bar-
\n
gaining Agreement, on July 7, 2021 the Tribunal Supremo
\n
issued a definitive ruling denying the appeals lodged by
\n
the aforementioned unions against the termination of
\n
the agreement by Endesa, affirming that social benefits
\n
(including those relating to electricity prices) originate ex-
\n
clusively in the collective bargaining agreements, both for
\n
employees currently in service and those who have retired,
\n
as well as for their family members, with the consequence
\n
that the termination of such agreements produces the
\n
general contractual regulation of the conditions estab-
\n
lished therein for employees currently in service and, for
\n
those who have retired and their family members, the de-
\n
finitive extinction of all their rights, until new regulations
\n
(which came with the 5th Endesa Collective Bargaining
\n
Agreement). That decision is also definitive for the individ-
\n
ual proceeding brought concerning the same issue.
\n
GNL Endesa Generaci\u00f3n SA arbitration
\n
proceeding I \u2013 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 about $1.283 billion at September
\n
30, 2023. The proceeding was concluded with an award on
\n
November 15, 2023, with the partial grant of the counter-
\n
claim. Both parties filed petitions for clarification and cor-
\n
rection of the award; a decision is pending. Meanwhile, the
\n
defendant issued an invoice in the amount of $587 million.
\n
GNL Endesa Generaci\u00f3n SA arbitration
\n
proceeding II \u2013 Spain
\n
In March 2023, a liquefied natural gas (LNG) producer initi-
\n
ated an arbitration proceeding within the context of a pro-
\n
ceeding for the revision of the price of a long-term supply
\n
contract for LNG against Endesa Generaci\u00f3n SA, demand-
\n
ing payment of about $585 million at December 31, 2023.
\n
The amount of the claim could be revised depending on
\n
market developments in months up to the completion of
\n
arbitration proceeding, which is scheduled for the 2nd
\n
Half of 2024. The company believes that this counterclaim
\n
is unfounded.
\n
Tractebel litigation \u2013 Brazil
\n
In 1998 the Brazilian company CIEN (now Enel CIEN) signed
\n
an agreement with Tractebel (now Engie Brasil Energia SA)
\n
for the delivery of electricity from Argentina through its
\n
Argentina-Brazil interconnection line. As a result of Argen-
\n
tine regulatory changes introduced as a consequence of
\n
the economic crisis in 2002, Enel CIEN was unable to make
\n
the electricity available to Tractebel.
\n
In October 2009, Tractebel sued Enel CIEN for alleged
\n
breach of contract. Enel CIEN submitted its defense cit-
\n
ing force majeure as a result of the Argentine crisis as the
\n
main argument. Out of court, Tractebel indicated that it
\n
plans to acquire 30% of the interconnection line involved
\n
in the dispute. With a ruling of February 16, 2023, the court
\n
of first instance denied the grounds of the claim submitted
\n
by Tractebel against Enel CIEN. The ruling was appealed
\n
by Tractebel on March 20, 2023, but on February 29, 2024
\n
the Court of Appeal upheld the decision at first instance in
\n
favor of Enel CIEN. The amount involved in the dispute is
\n
estimated at about R$715 million (about \u20ac133 million), plus
\n
damages to be quantified.
\n
For similar reasons, the company Furnas, in May 2010, had
\n
also presented a sue against Enel CIEN for the failure to
\n
deliver electricity, requesting payment of about R$571.6
\n
million (about \u20ac91 million), plus damages to be quantified,
\n
with a claim to acquire 70% of the interconnection line.
\n
The trial concluded in favor of Enel CIEN with a sentence
\n
issued by the Tribunal de Justi\u00e7a, which became final on
\n
October 18, 2019, which rejected all of Furnas\u2019 claims.
\n
Cibran litigation \u2013 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

\n\n\n\n
which led to the denial of part of Cibran\u2019s petitions. Cibran
\n
subsequently challenged the findings of the new study,
\n
but without success.
\n
The first suit, regarding the years from 1995 to 1999, was
\n
denied in full with a ruling that became definitive on Au-
\n
gust 24, 2020.
\n
With regard to the second case, filed in 2006 and re-
\n
garding the years from 1987 to 1994, on June 1, 2015, the
\n
courts issued a ruling ordering Enel Distribui\u00e7\u00e3o Rio de Ja-
\n
neiro to pay R$96 million (about \u20ac23 million) plus interest
\n
in pecuniary damages and R$80,000 (about \u20ac19,000) in
\n
non-pecuniary damages. On November 6, 2019, the Tri-
\n
bunal de Justi\u00e7a of Rio de Janeiro issued a ruling granting
\n
Enel Distribui\u00e7\u00e3o Rio de Janeiro\u2019s petition, and denying all
\n
of Cibran\u2019s claims. Subsequently, all the appeals submitted
\n
by Cibran between 2019 and 2022 were denied in full and,
\n
accordingly, the decision of November 6, 2019 in favor of
\n
Enel Distribui\u00e7\u00e3o Rio de Janeiro became final on March 24,
\n
2023.
\n
The remaining four suits for the years 2001 and 2002,
\n
which had been suspended pending the decision con-
\n
cerning the petition filed in 2006, are waiting to be tak-
\n
en up again. The value of all the disputes is estimated at
\n
about R$729 million (about \u20ac131 million).
\n
Coperva litigation \u2013 Brazil
\n
As part of the project to expand the grid in rural areas of
\n
Brazil, in 1982 Coelce Companhia Energ\u00e9tica do Cear\u00e1 SA
\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, did not specifically identify the
\n
grids governed by the agreements, which prompted a
\n
number of the cooperatives to sue Enel Distribui\u00e7\u00e3o
\n
Cear\u00e1 asking for, among other things, a revision of the
\n
fees agreed.
\n
These proceedings include: (a) the suit filed by Cooperati-
\n
va de Eletrifica\u00e7\u00e3o Rural do Vale do Acarau Ltda (Coperva)
\n
with a value of about R$475 million (about \u20ac89 million): Enel
\n
Distribui\u00e7\u00e3o Cear\u00e1 was granted rulings in its favor from the
\n
trial court and the Court of Appeal, but Coperva filed an
\n
appeal (embargo de declara\u00e7\u00e3o) based on procedural is-
\n
sues, which was also denied by the Court of Appeal in a
\n
ruling of January 11, 2016. On February 3, 2016, Coperva
\n
lodged an extraordinary appeal before the Tribunal Supe-
\n
rior de Justi\u00e7a (TSJ) against the ruling on the merits, which
\n
was granted on November 5, 2018 for the ruling issued in
\n
the previous appeal (embargo de declara\u00e7\u00e3o). On Decem-
\n
ber 3, 2018, Enel Distribui\u00e7\u00e3o Cear\u00e1 filed an appeal (agravo
\n
interno) against this ruling of the TSJ and the proceeding
\n
is currently pending; and (b) the suit filed by Cooperativa
\n
de Energia, Telefonia e Desenvolvimento Rural do Sert\u00e3o
\n
Central Ltda (COERCE) with a value of about R$285 mil-
\n
lion (about \u20ac53 million): in the suit COERCE requested a
\n
revision of the fee agreed for the use of its grids to be
\n
calculated on the basis of 2% of their value. The judgment
\n
is pending before the court of first instance, pending the
\n
performance of an engineering appraisal.
\n
ANEEL litigation \u2013 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 Na-
\n
cional de Energia El\u00e9trica (ANEEL, the national electricity
\n
agency), which in 2012 retroactively introduced a nega-
\n
tive coefficient to be applied in determining rates for the
\n
following regulatory period (2011-2015). With this provi-
\n
sion, ANEEL ordered the restitution of the value of some
\n
components of the network previously included in rates
\n
because they were considered non-existent and denied
\n
Enel Distribui\u00e7\u00e3o S\u00e3o Paulo\u2019s request to include addition-
\n
al components in rates. The administrative measure of
\n
ANEEL was challenged and on September 9, 2014, it was
\n
suspended on a precautionary basis. The first-instance
\n
proceeding has concluded and we are awaiting the de-
\n
cision. The value of the suit is about R$1,3 billion (about
\n
\u20ac245 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$500 million (about \u20ac93 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 of
\n
the contracts and from the abusive exercise of contractual
\n
rights by the latter, which is alleged to have produced a
\n
loss on the management of the contracts. Following the
\n
revocation on May 10, 2022 of the precautionary measure
\n
that had been previously notified to the companies, on
\n
December 2, 2021, Enel Distribui\u00e7\u00e3o Rio de Janeiro and
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 presented their defenses in the
\n
proceedings on the merits, and the evidentiary stage of
\n
the first-instance proceeding is continuing.
\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

\n\n\n\n
during the proceedings, Socrel\u2019s request was quanti-
\n
fied at R$321 million (about \u20ac61 million). With the ruling
\n
of March 27, 2023, the Tribunal de Justi\u00e7a do Estado de
\n
S\u00e3o Paulo denied the entire substance of the Socrel claim.
\n
Socrel challenged the ruling, which was overturned with a
\n
ruling of November 7, 2023 and remanded for trial at first
\n
instance to hear oral evidence not allowed in the first pro-
\n
ceeding.
\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 it
\n
authorized an average 24.85% rate increase for 2022 for
\n
the electricity distribution services performed by Enel Dis-
\n
tribui\u00e7\u00e3o Cear\u00e1. Both private individuals and public insti-
\n
tutions have challenged this resolution before the Federal
\n
Regional Court of the district of Cear\u00e1, for a total of six
\n
proceedings requesting, on precautionary basis, the can-
\n
cellation of the effects of the resolution and, on a perma-
\n
nent basis, the voidance of the resolution itself, arguing
\n
that the rate increase is illegitimate. In all proceedings,
\n
Enel Distribui\u00e7\u00e3o Cear\u00e1 has contested the petitioners\u2019
\n
claims, arguing the legitimacy of the rate adjustment. On
\n
June 21, 2022, the Federal Regional Court rejected the pre-
\n
cautionary request and joindered the six proceedings in a
\n
single proceeding in consideration of fact that the relief
\n
sought and the cause of action are the same. On Septem-
\n
ber 23, 2022, Enel Distribui\u00e7\u00e3o Cear\u00e1 also submitted that,
\n
as a result of certain subsequent legislative measures, the
\n
rate had been reduced following an extraordinary rate re-
\n
view and a reduction in taxes. The ruling remains pending.
\n
The estimated value of the proceeding has not been de-
\n
termined. Moreover, on July 31, 2023, an additional action
\n
was filed by one of the public petitioners with the Federal
\n
Regional Court for reasons connected with the previous
\n
actions, arguing that the rate increase was excessive in
\n
relation to the poor quality of service provided and al-
\n
leged contractual breaches, as well as asking for collec-
\n
tive non-pecuniary damages of about R$55 million (about
\n
\u20ac10.6 million).
\n
CTEEP \u2013 Brazil
\n
On March 16, 2021 Enel Distribui\u00e7\u00e3o S\u00e3o Paulo (formerly
\n
Eletropaulo Metropolitana Eletricidade de S\u00e3o Paulo SA -
\n
Eletropaulo) filed a debt collection action before the Tri-
\n
bunal de Justi\u00e7a do Estado de S\u00e3o Paulo in the amount
\n
of about R$1.5 billion against the transmission system
\n
operator ISA CTEEP - Companhia de Transmiss\u00e3o de En-
\n
ergia El\u00e9trica (CTEEP) as the original debtor for a liability
\n
arising prior to the privatization of Eletropaulo, against
\n
Centrais El\u00e9tricas Brasileiras SA (Eletrobras), which had
\n
initially been paid by Eletropaulo to the latter as part of a
\n
settlement agreement. With a decision of September 26,
\n
2023, the competent Court of Appeal upheld the ruling
\n
at first instance, which had denied Enel Distribui\u00e7\u00e3o S\u00e3o
\n
Paulo\u2019s claim, also quantifying the defense\u2019s legal costs
\n
due for losing the cast at 13% of the present value of the
\n
claim, for an amount equal, at December 2023, to about
\n
R$365 million (about \u20ac 68 million). With a ruling of January
\n
12, 2024 the Court of Appeal denied the appeal of that
\n
decision by Enel Distribui\u00e7\u00e3o S\u00e3o Paulo. On February 23,
\n
2024 the company also appealed the latter ruling before
\n
the higher courts.
\n
Black-out November 2023 S\u00e3o Paulo \u2013 Brazil
\n
Following the severe weather events that on November
\n
3, 2023 hit the concession area of Enel Distribui\u00e7\u00e3o S\u00e3o
\n
Paulo (ED SP), on December 31, 2023, 341 individual ac-
\n
tions and 6 collective actions were filed by representa-
\n
tives of municipalities, unions, political parties, the public
\n
prosecutor and the public defender\u2019s office requesting
\n
the grant of precautionary measures, the provision of as-
\n
sistance by ED SP, the provision of information/documen-
\n
tation, the maintenance of distribution service levels and
\n
the payment of individual and collective pecuniary and
\n
non-pecuniary damages to be determined in court. At De-
\n
cember 31, 2023, the overall value of the individual actions
\n
was about R$6.2 million (about \u20ac1.2 million) while the value
\n
of the collective actions was undetermined.
\n
Black-out November 2023 Rio de Janeiro \u2013
\n
Brazil
\n
Following the severe weather events that on November
\n
18, 2023 hit the concession area of Enel Distribui\u00e7\u00e3o Rio
\n
de Janeiro (ED RJ), on December 31, 2023, 3,308 individual
\n
actions and 16 collective actions were filed by represen-
\n
tatives of municipalities, the public prosecutor and the
\n
public defender\u2019s office requesting the grant of precau-
\n
tionary measures, the provision of assistance by ED RJ, the
\n
provision of information/documentation, the maintenance
\n
of assistance measures and the payment of individual
\n
and collective pecuniary and non-pecuniary damages to
\n
be determined in court. At December 31, 2023 the over-
\n
all value of the individual actions was about R$61.3 million
\n
(about \u20ac11.4 million) while the value of the collective ac-
\n
tions was undetermined.
\n
GasAtacama Chile \u2013 Chile
\n
In January 2020, the appeal proceeding was completed for
\n
the administrative fine levied in August 2016 by the Super-
\n
intendencia de Electricidad y Combustibles (SEC) against
\n
GasAtacama Chile (now Enel Generaci\u00f3n Chile) concern-
\n
ing the information provided to the CDEC- SING (Centro
\n
de Despacho Econ\u00f3mico de Carga) in relation to the vari-
\n
ables of the Technical Minimum and the Minimum Opera-
\n
tion Time at the Atacama power station. Upon completion
\n
of the proceeding, the amount of the fine was reduced
\n
from approximately $6 million to about $432,000 and the
\n
amount was paid by the company.
\n
\n\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
\n
and Engie Energ\u00eda Chile SA, sued GasAtacama Chile in
\n
2017 seeking damages for a total amount of about \u20ac189
\n
million. On October 17, 2023, the Civil Court of Santiago
\n
issued a ruling partially upholding the plaintiffs\u2019 petitions
\n
in an amount to be quantified at a subsequent stage of
\n
the proceeding. On October 31, 2023 the ruling was chal-
\n
lenged by all the defendants and the appeal proceeding is
\n
pending. The company and its external legal counsel feel
\n
that the likelihood of the plaintiffs\u2019 claim being upheld on
\n
appeal is remote.
\n
Compa\u00f1\u00eda Minera Arbiodo \u2013 Chile
\n
In 2016, Compa\u00f1\u00eda Minera Arbiodo and Ingenieros Ase-
\n
sores Limitada filed a suit against the Ministerio de Bienes
\n
Nacionales, the Ministerio de Energ\u00eda, the Ministerio de
\n
Miner\u00eda (together, the \u201cMinistry\u201d), the Servicio Nacional de
\n
Geolog\u00eda y Miner\u00eda (Sernageomin), Enel Green Power Chile
\n
(EGP Chile) and Parque E\u00f3lico Taltal SA seeking damages
\n
for alleged losses incurred as a result of presumed viola-
\n
tions of mining rights to the soil underneath the land on
\n
which the Taltal wind farm, which was built under a minis-
\n
terial concession granted in 2012, is located.
\n
With decision of December 6, 2023, the Civil Court of
\n
Santiago ordered Parque E\u00f3lico Taltal and EGP Chile, joint-
\n
ly and severally with Sernageomin, to pay an amount of
\n
about 346 billion Chilean pesos (equal to about \u20ac367 mil-
\n
lion) in favor of the plaintiffs.
\n
The decision was challenged by the Group companies on
\n
December 22, 2023 and the appeal proceeding is pend-
\n
ing. The companies and their external legal counsel feel
\n
that the likelihood of the plaintiffs\u2019 claim being upheld on
\n
appeal is remote.
\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 by
\n
around 1,140 residents of the municipality of Garz\u00f3n, who
\n
claim that the construction of the plant would reduce their
\n
business revenue by 30%. A second action was brought,
\n
between August 2011 and December 2012, by residents
\n
and businesses/associations of five municipalities of Hui-
\n
la claiming damages related to the closing of a bridge
\n
(Paso El Colegio). With regard to acciones populares, or
\n
class action lawsuits, in 2008 a suit was filed by a number
\n
of residents of the area demanding, among other things,
\n
that the environmental permit be suspended. As part of
\n
this action, on September 11, 2020, the Huila Court issued
\n
a partially unfavorable ruling against Emgesa, sentencing it
\n
to fulfill the obligations already provided for in the environ-
\n
mental license. Both the Autoridad Nacional de Licencias
\n
Ambientales (ANLA) and Emgesa challenged this decision
\n
before the Council of State. On September 20, 2022, AN-
\n
LA\u2019s appeal was denied because it had been filed late. The
\n
proceeding continues in relation 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). The Huila Court sub-
\n
sequently extended the six-month time limit, and there-
\n
fore, in the absence of contrary court rulings the Quimbo
\n
plant is continuing to generate electricity as the oxygen-
\n
ation system installed by Emgesa has so far demonstrat-
\n
ed that it can maintain the oxygen levels required by the
\n
court. On March 22, 2018, ANLA and CAM jointly presented
\n
the final report on the monitoring of water quality down-
\n
stream of the dam of the El Quimbo hydroelectric plant.
\n
Both authorities confirmed the compliance of Emgesa
\n
with the oxygen level requirements. On January 12, 2021,
\n
it was learned that the ruling of first instance of the Court
\n
of Huila had been issued. The ruling, while acknowledging
\n
that the oxygenation system implemented by Emgesa had
\n
mitigated the risks associated with the protection of fau-
\n
na in the Bethany basin, imposed a series of obligations
\n
on the environmental authorities involved, as well as on
\n
Emgesa itself. In particular, the latter is required to imple-
\n
ment a decontamination project to ensure that the water
\n
in the basin does not generate risks for the flora and fauna
\n
of the river, which will be subject to verification by ANLA,
\n
and to make permanent the operation of the oxygenation
\n
system, adapting it to comply with the parameters estab-
\n
lished by ANLA. On March 4, 2021, Emgesa challenged the
\n
appeal ruling before the Council of State. On December
\n
31, 2021, the Council of State ruled that Emgesa\u2019s appeal
\n
was admissible. The proceeding is continuing at the ap-
\n
peal level.
\n
Nivel de Tensi\u00f3n Uno proceedings \u2013 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, as
\n
amended by Resolution no. 97/2008. The preliminary stage
\n
\n\n
has been completed and a ruling is pending. The estimat-
\n
ed value of the proceeding is about 337 billion Colombian
\n
pesos (about \u20ac96 million).
\n
Group actions for flooding in Bosa and
\n
Kennedy neighborhoods of Bogot\u00e1 \u2013
\n
Colombia
\n
Emgesa SA (now Enel Colombia SA) was sued with an \u201cac-
\n
ci\u00f3n de grupo\u201d brought by the residents of the Bosa and
\n
Kennedy neighborhoods of Bogot\u00e1 (Colombia) seeking
\n
damages for flooding that occurred in 2010 and 2011 after
\n
the Bogot\u00e1 overflowed its banks. The proceeding is at the
\n
preliminary stage. The estimated value of the proceeding
\n
is about 2.2 billion Colombian pesos (about \u20ac518 million).
\n
Kino arbitration \u2013 Mexico
\n
On September 16, 2020, Kino Contractor SA de Cv (Kino
\n
Contractor), Kino Facilities Manager SA de Cv (Kino Facili-
\n
ties) and Enel SpA (Enel) were notified of a request for arbi-
\n
tration filed by Parque Solar Don Jos\u00e9 SA de Cv, Villanueva
\n
Solar SA de Cv and Parque Solar Villanueva Tres SA de Cv
\n
(together, \u201cProject Companies\u201d) in which the Project Com-
\n
panies alleged the violation (i) by Kino Contractor of certain
\n
provisions of the EPC Contract and (ii) by Kino Facilities of
\n
certain provisions of the Asset Management Agreement,
\n
both contracts concerning solar projects owned by the
\n
three companies filing for arbitration. Enel \u2013 which is the
\n
guarantor of the obligations assumed by Kino Contractor
\n
and Kino Facilities under the above contracts \u2013 has also
\n
been called into the arbitration proceeding, but no specif-
\n
ic claims have been filed against it for the moment.
\n
The Project Companies, in which Enel Green Power SpA
\n
is a non-controlling shareholder, are controlled by CDPQ
\n
Infraestructura Participaci\u00f3n SA de Cv (which is controlled
\n
by Caisse de D\u00e9p\u00f4t et Placement du Qu\u00e9bec) and CKD In-
\n
fraestructura M\u00e9xico SA de Cv.
\n
On August 4, 2023, the arbitration ruling was notified. The
\n
arbitration board declared that it did not have jurisdiction
\n
against Enel SpA and, in partially granting the claim of the
\n
Project Companies, ordered Kino Contractor and Kino Fa-
\n
cilities (now Enel Services Mexico SA de Cv - Enel Services)
\n
to pay penalties totaling about $77 million, plus interest at
\n
an annual rate of 6%. Subsequently, Kino Contractor and
\n
Enel Services filed a petition requesting correction of the
\n
arbitration award, which was partially granted and, on De-
\n
cember 13, 2023, they filed a petition to void the award
\n
before the Mexican courts. The proceeding is pending.
\n
In December 2023, the Project Companies filed a suit be-
\n
fore the Supreme Court of the State of New York against
\n
Enel, in its capacity as guarantor of the obligations as-
\n
sumed by Kino Contractor, to request payment due by the
\n
latter under the provisions of the arbitration award. The
\n
substance and legal grounds of the suit are being con-
\n
tested in full and the proceeding is pending.
\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 2021, in connec-
\n
tion with a Proxy Revenue Swap. The claim is being con-
\n
tested in its entirety. The proceedings are currently pend-
\n
ing before the Southern District Court in New York.
\n
Osage Wind \u2013 North America
\n
As part of a lawsuit filed by the United States (in its capac-
\n
ity as trustee of the Osage Nation) and the Osage Miner-
\n
al Council against Enel Green Power North America, Enel
\n
Kansas LLC and Osage Wind LLC, on December 20, 2023 a
\n
ruling of the Oklahoma District Court ordered the removal
\n
of the wind farm and the continuation of the proceeding
\n
for damages, which were quantified by the plaintiffs in the
\n
amount of at least $25 million. The proceeding is continu-
\n
ing at first instance and the plaintiffs\u2019 claims have been
\n
contested. The ruling, which is not final, will be appealed at
\n
the appropriate time.
\n
Gastalsa \u2013 Peru
\n
In February 2022, Enel Generaci\u00f3n Piura SA (EGPIURA)
\n
learned of a precautionary measure issued by the Civil
\n
Court of Talara of the Superior Court of Justice of Sullana
\n
(Juzgado Civil de Talara de la Corte Superior de Justicia de
\n
Sullana) in favor of Empresa de Gas de Talara SA (Gastal-
\n
sa) which orders the Direcci\u00f3n General de Hidrocarburos
\n
del Ministerio de Energ\u00eda y Minas, the Organismo Superior
\n
de la Inversi\u00f3n en Energ\u00eda y Miner\u00eda (OSINERGMIN) and the
\n
Ministry of Energy to (i) restore the natural gas concession
\n
of the Parinas district in favor of Gastalsa; and (ii) pro-
\n
ceed with the upgrade and transfer of the pipeline owned
\n
by EGPIURA (which supplies natural gas to the Malacas
\n
thermal power station) to Gastalsa. That precautionary
\n
measure was a consequence of the ruling issued by the
\n
Court of Talara partially granting a claim filed by Gastalsa
\n
requesting to revoke the measure that canceled the con-
\n
cession granted to Gastalsa and the consequent transfer
\n
of the gas pipeline owned by EGPIURA to Gastalsa itself.
\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 had
\n
granted the petition of the system operator, an interest-
\n
ed third party, acknowledging that the original petition of
\n
Gastalsa had been filed after the time limit. On January 24,
\n
2023 the Constitutional Court also denied the appeal of
\n
that measure, which has thus become final, and ordered
\n
the Court of Appeal to issue a new decision concerning
\n
the forfeiture of the petition.
\n
\n\n
With a ruling of June 27, 2023, the Court of Appeal denied
\n
the claim of forfeit advanced by an affected third party,
\n
while with a decision of July 25, 2023 the court of first in-
\n
stance revoked the suspension of the proceeding that had
\n
been ordered and took up the case for a decision. With a
\n
measure of September 15, 2023, the court found the claim
\n
that the provision was null raised by EGPIURA and the oth-
\n
er party was unfounded and scheduled oral arguments for
\n
September 25, 2023. EGPIURA and the other party in the
\n
proceeding appealed that ruling with the Court of Appeal,
\n
which, with decision of January 20, 2024, revoked the ap-
\n
pealed measure and remanded the suit for trial at first in-
\n
stance. A decision is pending.
\n
In the meantime, on August 9, 2023 EGPIURA also filed an
\n
appeal with the Superior Court of Justice of Lima against
\n
the decision of June 27, 2023 of the Court of Appeal, argu-
\n
ing that it conflicted with the ruling of the Constitutional
\n
Court of January 24, 2023.
\n
The hearing to argue the case is scheduled for August 7,
\n
2024.
\n
Gab\u010d\u00edkovo litigation \u2013 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
\n
by Vodohospod\u00e1rska V\u00fdsatavba \u0160t\u00e1tny Podnik (VV) and
\n
whose operation and maintenance, as part of the privat-
\n
ization of SE in 2006, had been entrusted to SE for a pe-
\n
riod of 30 years under an operating agreement (the VEG
\n
Operating 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
\n
November 2011 the trial court ruled in favor of SE, where-
\n
upon 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 with
\n
a ruling on January 18, 2017, which then became final.
\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, both VV and
\n
MHM filed two suits in the Slovakian courts to void the VEG
\n
Indemnity Agreement owing to the alleged connection of
\n
the latter with the VEG Operating Agreement. These pro-
\n
ceedings were rejected for procedural reasons on Sep-
\n
tember 27, 2017. Both VV and MHM appealed that decision,
\n
and both the appeals were denied upholding the trial court
\n
decision in favor of SE. VV filed a further appeal (dovolanie)
\n
against that decision on March 9, 2020, with the Supreme
\n
Court, to which SE replied with a brief submitted on June
\n
8, 2020. SE also filed an appeal before the Slovak Constitu-
\n
tional Court, which was denied on July 29, 2021. On March
\n
24, 2021, the Supreme Court overturned the decision of
\n
the Bratislava Court of Appeal, referring the judgment to
\n
the latter court, and the 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 counterclaims for all of the proceedings under way.
\n
Developments in those proceedings can be summarized
\n
as follows:
\n
i. 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 Appe-
\n
al of Bratislava. The proceedings relating to 2006 were
\n
completed with the decision of December 6, 2022,
\n
notified to SE on February 18, 2023, which upheld the
\n
ruling in first instance. In April 2023, both SE and VV
\n
filed extraordinary appeals before the Supreme Court
\n
against the Court of Appeal ruling and the proceeding
\n
is pending. As regards the proceedings relating to 2007,
\n
the Court of Appeal, in a ruling dated January 31, 2023,
\n
notified to SE on April 12, 2023, voided the decision of
\n
first instance, referring the case back to the Court of
\n
Bratislava for a new judgment. The first hearing was held
\n
on January 8, 2024 and the proceeding was adjourned
\n
to a hearing scheduled for September 11, 2024. The
\n
proceedings relating to 2008 are still pending;
\n
ii. the proceedings relating to the years 2011 and 2015 are
\n
all pending before the court of first instance and briefs
\n
have been exchanged between the parties. For both
\n
proceedings, hearings before the court of first instance
\n
were postponed several times owing to the pandemic
\n
and are now postponed to dates to be determined;
\n
iii. the proceedings relating to the years 2009, 2010 and
\n
2013 were completed in the court of first instance with
\n
ruling issued by the Court of Bratislava on, respecti-
\n
vely, November 24, 15 and 22, 2022, rejecting both VV\u2019s
\n
\n\n
claim and SE\u2019s counterclaim. Between December 2022
\n
and January 2023 both SE and VV filed appeals against
\n
the rulings relating to the years 2009, 2010 and 2013,
\n
and the proceeding is now pending. The proceedings
\n
relating to 2014 were completed at first instance with
\n
a ruling of the Court of Bratislava of October 10, 2023,
\n
which has not yet been published, rejecting the primary
\n
claim of VV and, consequently, the counterclaim of SE;
\n
iv. as regards the proceeding relating to the year 2012, on
\n
February 2, 2023 SE was notified of the appeal ruling
\n
upholding the ruling of first instance denying of both
\n
VV\u2019s claim and SE\u2019s counterclaim. Both VV and SE, on
\n
March 17, 2023 and March 31, 2023, respectively, have
\n
filed an extraordinary appeal with the Supreme Court
\n
against the appellate ruling and the proceeding is pen-
\n
ding.
\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 issu-
\n
ing a preliminary decision on the case in which it noted the
\n
lack of standing of VV, on December 18, 2020, the Court
\n
issued a decision in favor of SE, rejecting VV\u2019s claims. On
\n
January 4, 2021, VV filed an appeal against that decision,
\n
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 carried out a spin-off that in-
\n
volved the transfer of the residual FRN debt and the as-
\n
sociated rights and obligations to Ampla Investimentos e
\n
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 prompt-
\n
ly 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, now Enel Distribui\u00e7\u00e3o
\n
Rio de Janeiro, provided the additional documentation
\n
and, in view of the conclusions presented by the expert,
\n
requested a further expert opinion. The case has been re-
\n
ferred to the expert for clarifications regarding the posi-
\n
tion expressed by the company.
\n
In July 2021, the supplementary report was filed by the ex-
\n
pert in which the existence of the loan agreements was
\n
acknowledged and the bond loan was terminated, both
\n
for the principal amount and for interest, mainly through a
\n
capital increase. The company, called to pronounce on the
\n
report filed, requests the full cancellation of the tax debt.
\n
The amount involved in the dispute at December 31, 2023
\n
was about \u20ac270 million.
\n
PIS/COFINS/ICMS \u2013 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 Circu-
\n
la\u00e7\u00e3o de Mercadorias e Servi\u00e7os, tax on the circulation of
\n
goods and services) tax was not included in the calculation
\n
basis of the PIS and COFINS.
\n
In May 2021, the STF established that the ruling would
\n
have effect from the judgment of March 2017, except for
\n
taxpayers who had filed an appeal before that date.
\n
The Group\u2019s Brazilian companies affected by the STF rul-
\n
ing had already initiated legal action in their respective
\n
federal regional courts. Subsequently, the latter notified
\n
them of the final decision, recognizing the right to deduct
\n
the ICMS applied to their operations from the calculation
\n
basis of the PIS and COFINS. Since the excess payment
\n
of the PIS and COFINS taxes had been transferred to final
\n
customers, at the same time as the recognition of these
\n
recoverable taxes, a liability in respect of those customers
\n
was recognized in the same amount, net of any costs in-
\n
curred or to be incurred in the legal proceedings. These
\n
liabilities represent an obligation to reimburse the recov-
\n
ered taxes to 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 regarded
\n
the periods from December 2003 to December 2014 and
\n
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 adverse-
\n
ly 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. During 2023, following an adverse ruling at the ap-
\n
\n\n
peal level, the company filed a new appeal seeking clarifi-
\n
cation of the ruling.
\n
The estimated amount involved in the proceeding at De-
\n
cember 31, 2023 was about \u20ac235 million.
\n
IRPJ/CSLL \u2013 Eletropaulo
\n
On October 5, 2021, Eletropaulo received an assessment
\n
notice from the Brazilian tax authorities contesting the
\n
deductibility for income tax purposes (Imposto sobre a
\n
Renda das Pessoas Jur\u00eddicas - IRPJ and Contribui\u00e7\u00e3o So-
\n
cial sobre o Lucro L\u00edquido - CSLL) of the amortization of
\n
the increased values generated by extraordinary corpo-
\n
rate transactions carried out before the acquisition of the
\n
company by the Enel Group. The contested period runs
\n
from 2017 to 2019.
\n
Considering its position sound, the company presented
\n
its defense at the first level of administrative adjudication.
\n
The amount involved in the dispute at December 31, 2023
\n
was about \u20ac158 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, 2023
\n
was about \u20ac134 million.
\n
ICMS \u2013 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-
\n
2012, 2015, 2016 and 2018) and Eletropaulo (2008-2021),
\n
challenging the deduction of ICMS (Imposto sobre Circu-
\n
la\u00e7\u00e3o de Mercadorias e Servi\u00e7os, tax on the circulation of
\n
goods and services) in relation to the purchase of certain
\n
non-current assets. The companies challenged the as-
\n
sessments, arguing that they correctly deducted the tax
\n
and asserting that the assets, the purchase of which gen-
\n
erated the ICMS, are intended for use in their electricity
\n
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
\u20ac106 million at December 31, 2023.
\n
Withholding Tax \u2013 Endesa Brasil
\n
On November 4, 2014, the Brazilian tax authorities issued
\n
an assessment against Endesa Brasil SA (now Enel Brasil
\n
SA) alleging the failure to apply withholding tax to divi-
\n
dends, reclassified as payment of income to non-resident
\n
recipients.
\n
More specifically, in 2009, Endesa Brasil, as a result of
\n
the first-time application of the IFRS, had derecognized
\n
goodwill, recognizing the effects in equity, on the basis of
\n
the 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
\n
by the company was agreed with the external auditor and
\n
also confirmed by a specific legal opinion issued by a local
\n
firm.
\n
Following unfavorable rulings from the administrative
\n
courts, the company is continuing to defend its actions
\n
in court and the appropriateness of the accounting treat-
\n
ment.
\n
The overall amount involved in the dispute at December
\n
31, 2022 was about \u20ac77 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 over the years
\n
(for tax periods 2015-2018), as well as against all other en-
\n
ergy distributors in Brazil, demanding the ICMS (Imposto
\n
sobre Circula\u00e7\u00e3o de Mercadorias e Servi\u00e7os, tax on the
\n
circulation of goods and services) on the subsidies paid by
\n
the Federal government against the regulatory discounts
\n
granted to certain consumers.
\n
The company has appealed the individual assessments
\n
and is defending its actions in the various levels of juris-
\n
diction.
\n
The overall amount involved in the dispute at December
\n
31, 2023 was about \u20ac69 million.
\n
PIS/COFINS \u2013 Eletropaulo
\n
Starting from June 2017, the Federal Tax Authority served a
\n
number of tax assessment notices against Eletropaulo (for
\n
the 2013-2018 tax periods) contesting the offsetting of tax
\n
credits relating to social security contributions (PIS and
\n
COFINS), requesting the payment of those contributions.
\n
The tax authorities argue that the company has claimed
\n
PIS and COFINS credits for the purchase of goods and
\n
\n\n
services that cannot be considered fiscally relevant since
\n
they are not essential for the distribution of electricity. Fur-
\n
thermore, it disputes the claim of a tax credit associated
\n
with \u201cnon-technical\u201d losses on the electricity purchased.
\n
The company has promptly defended the accuracy of its
\n
calculations in the various levels of jurisdiction and argued
\n
the validity of the offsets claimed.
\n
The estimated amount involved in the proceeding at De-
\n
cember 31, 2023 was about \u20ac55 million.
\n
ICMS (pro-rata) \u2013 Coelce
\n
The State of Cear\u00e1 has filed various tax assessments against
\n
Companhia Energ\u00e9tica do Cear\u00e1 SA over the years (for tax
\n
periods from 2005 to 2014), contesting the determination
\n
of the deductible portion of the ICMS (Imposto sobre Cir-
\n
cula\u00e7\u00e3o de Mercadorias e Servi\u00e7os, tax on the circulation of
\n
goods and services) and in particular the method of calcula-
\n
tion of the pro-rata deduction with reference to the revenue
\n
deriving from the application of a special rate envisaged by
\n
the Brazilian government for the sale of electricity to low-in-
\n
come 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 ju-
\n
risdiction.
\n
The overall amount involved in the dispute at December 31,
\n
2023 was about \u20ac52 million.
\n
PIS \u2013 Eletropaulo
\n
In December 1995, the Brazilian government increased the
\n
rate of the federal PIS (Programa Integra\u00e7\u00e3o Social) tax from
\n
0.50% to 0.65% with the issue of a provisional measure (Ex-
\n
ecutive Provisional Order).
\n
Subsequently, the provisional measure was re-issued five
\n
times before its definitive ratification into law in 1998. Under
\n
Brazilian legislation, an increase in the tax rate (or the estab-
\n
lishment of a new tax) can only be ordered by law and take
\n
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 the
\n
last Provisional Order, claiming that the effects of the first
\n
four provisional measures should be considered void (since
\n
they were never ratified into law). This dispute ended in April
\n
2008 with recognition of the validity of the increase in the
\n
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 the
\n
notice of assessment had lapsed. In particular, since more
\n
than five years have passed since the taxable event (Decem-
\n
ber 1995, the date of the first provisional measure) without
\n
issuing any formal instrument, the right of the tax authorities
\n
to request the payment of additional taxes and the author-
\n
ity to undertake legal action to obtain payment have been
\n
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 Gen-
\n
eral of the Brazilian National Treasury Department to replace
\n
the bank guarantee with a deposit in court, the court of sec-
\n
ond instance granted the petition. The company therefore
\n
replaced the bank guarantee with a cash deposit and filed
\n
a clarification motion against the related decision, which is
\n
currently awaiting a decision.
\n
The overall amount involved in the dispute at December 31,
\n
2023 was about \u20ac48 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 (social
\n
contributions) relating to sums paid from September 1989
\n
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 legitima-
\n
cy 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 31,
\n
2023 was about \u20ac48 million.
\n
Tax litigation in Spain
\n
Income tax \u2013 Enel Iberia, Endesa and subsidiaries
\n
In 2018, the Spanish tax authorities completed a general
\n
audit involving the companies of the Group participating in
\n
the Spanish tax consolidation mechanism. This audit, which
\n
began in 2016, involved corporate income tax, value added
\n
tax and withholding taxes (mainly for the years 2011 to 2014).
\n
With reference to the main claims, the companies involved
\n
have challenged the related assessments at the first admin-
\n
istrative level (Tribunal Econ\u00f3mico-Administrativo Central -
\n
TEAC), defending the correctness of their actions.
\n
On April 4, 2022, the TEAC rejected the appeal and the com-
\n
panies are continuing to defend their actions in court (Audi-
\n
encia Nacional).
\n
With regard to the disputes concerning corporate income
\n
tax, the issues for which an unfavorable outcome is consid-
\n
ered possible amounted to about \u20ac134 million at December
\n
31, 2023:
\n

\n\n\n
i. 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
ii. Endesa and its subsidiaries are mainly defending the ap-
\n
propriateness of the criteria adopted for the deductibility
\n
of certain financial expense (about \u20ac25 million) and co-
\n
sts for decommissioning nuclear power plants (about \u20ac6
\n
million).
\n
In 2021, the Spanish tax authorities completed a new gener-
\n
al audit for the years 2015 to 2018. The companies involved
\n
have challenged the related assessments at the first admin-
\n
istrative level (TEAC), defending the correctness of their ac-
\n
tions.
\n
With reference to the main claims concerning corporate tax
\n
and regarding the deductibility of certain financial expense,
\n
the dispute that could produce an adverse ruling amounts
\n
to about \u20ac226 million at December 31, 2023 (Enel Iberia
\n
\u20ac213 million; Endesa SA \u20ac13 million).
\n
Income tax \u2013 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 Renov-
\n
ables SA (EUFER) into Enel Green Power Espa\u00f1a SL in 2011 as
\n
a tax neutral transaction, asserting that the transaction had
\n
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 actions
\n
in court (Audiencia Nacional).
\n
The overall amount involved in the dispute at December 31,
\n
2023 was about \u20ac98 million.
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag1109": { "value": "\n
58. Environmental programs
\n
Some Group companies are affected by national or supra-
\n
national environmental regulatory standards designed to
\n
develop the use of environmental protection mechanisms
\n
in accordance with the environmental policies of the Euro-
\n
pean Union and global international agreements.
\n
58.1 Terms and nature of environmental
\n
programs
\n
The main environmental programs affecting Group com-
\n
panies are summarized in the following table in accor-
\n
dance with ESMA Public Statement of October 25, 2023
\n
\u2013 Priority 1: Climate-related matters.
\n
Program Terms of the mechanism Nature
\n
EU ETS
\n
(78)
\n
The scheme, which applies in all EU countries, sets an annual cap on emissions that
\n
is being progressively reduced to bring down the total emissions in Europe.
\n
The fourth trading period (2021-2030) has been tightened up as part of the EU\u2019s
\n
contribution to the Paris Climate Agreement.
\n
At the annual cap correspond a specific number of allowances (for each authorized
\n
industrial plant) that are granted, through participation in auctions or for free, by the
\n
competent local authority, freely transferable and traded between operators.
\n
The obliged companies shall surrender several allowances equivalent to their
\n
polluting emissions for each reporting period.
\n
Mandatory by law \u201ccap and trade\u201d scheme.
\n
Within the Group, CO
\n
2
\n
allowances are
\n
applicable to the thermal power generation
\n
companies operating in Italy and Spain.
\n
In those countries in which the Group is
\n
engaged in thermal power generation
\n
activity, European regulations have required
\n
that EU Allowances (EUAs) are assigned via
\n
auction, and they are not granted for free.
\n
Energy
\n
efficiency
\n
certificates
\n
The scheme has the objective to reduce the energy consumption by end-users
\n
through various measures developed in application of European Union Directives
\n
and by national laws.
\n
These marketable certificates are issued, over a period of several years, by the
\n
competent local authorities to companies that carry out directly or indirectly
\n
initiatives/projects to improve energy efficiency.
\n
At the end of the period, obliged companies are required to present certificates
\n
corresponding to their obligatory energy savings.
\n
Mandatory by law.
\n
The Group currently holds energy efficiency
\n
certificates in Italy and Spain where the
\n
obliged companies are, respectively,
\n
electricity distribution and sale companies.
\n
Guarantees of
\n
origin (GoOs)
\n
This European scheme has the objective to encourage use of energy produced from
\n
renewable sources.
\n
These certificates are issued by the competent local authorities to renewable
\n
generation plants that meet specific standards. They are marketable and traded, also
\n
separately from the electricity to which they refer, during their term of validity until
\n
they are cancelled by the issuer at the request of the user of the certificates.
\n
This mechanism currently affects the Group
\n
Italian and Spanish sale companies that have
\n
an obligation to surrender a certain volume
\n
of GoOs depending on the level of sales to
\n
customers.
\n
Renewable
\n
Energy
\n
Certificates
\n
(RECs)
\n
These certificates are granted in countries outside Europe to renewable energy
\n
generation companies to prove that consumed electricity has been generated in a
\n
renewable way.
\n
The functioning of this scheme is analogous to European GoOs.
\n
This mechanism is voluntary and currently
\n
affects some Group companies in North and
\n
Latin America.
\n

\n\n\n
\n\n
58.2 Accounting policies
\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:
\n
\u2022
\n
any environmental certificates received free of charge
\n
and those self-produced as a result of Group\u2019s oper-
\n
ations that will be used for compliance purposes are
\n
recognized at nominal value (nil);
\n
\u2022
\n
charges incurred for obtaining (in the market or in
\n
some other transaction for consideration) any missing
\n
certificates to fulfil compliance requirements for the
\n
reporting period are recognized through profit or loss
\n
under other operating costs, as they represent \u201csystem
\n
charges\u201d consequent to compliance with a regulatory
\n
requirement;
\n
\u2022
\n
if the number of environmental certificates available at
\n
the reporting date is not sufficient to fulfill the related
\n
obligation (a certificate \u201cdeficit\u201d), a provision is accrued
\n
under \u201cprovisions for risks and charges\u201d. Conversely,
\n
any \u201csurplus\u201d of certificates purchased at the reporting
\n
date is recognized in \u201cinventories\u201d in accordance with
\n
the general principles referred to in note 2.2 \u201cMaterial
\n
accounting policies\u201d.
\n
Some types of environmental certificates accrue in pro-
\n
portion to:
\n
\u2022
\n
electricity generated by plants that use renewable re-
\n
sources (for example, guarantees of origin and renew-
\n
able energy certificates);
\n
\u2022
\n
energy savings certified by the competent authority
\n
(energy efficiency certificates).
\n
In these cases, the right to obtain such certificates can be
\n
treated as a non-monetary government operating grant
\n
and, as such, the Group recognizes that right at fair value
\n
under \u201cother non-current/current non-financial assets\u201d.
\n
When the certificates are credited to the ownership ac-
\n
count, they are reclassified from other assets to invento-
\n
ries.
\n
The corresponding income is recognized under other op-
\n
erating profit.
\n
For Group companies involved in trading activities, envi-
\n
ronmental certificates represent goods exchanged as part
\n
of their normal business activity and, as such, the pur-
\n
chased certificates are recognized under \u201cservices and
\n
other materials\u201d.
\n
Revenue from the sale of such certificates is recognized
\n
under \u201crevenue\u201d, with a corresponding decrease in inven-
\n
tories.
\n
Contracts for the purchase or sale of environmental cer-
\n
tificates settled at a future date (for example, forward con-
\n
tracts, etc.) that comply with the definition of derivative are
\n
recognized and measured in accordance with the \u201cown
\n
use exemption\u201d, at fair value through profit or loss, or with
\n
hedge accounting rules based on specific circumstanc-
\n
es. For further details, please see note 51 \u201cDerivatives and
\n
hedge accounting\u201d.
\n
\n
\n\n
58.3 Financial impact
\n
Charges for environmental certificates
\n
The following table reports system charges recognized by
\n
obligated Group companies in respect of the certificates
\n
necessary to meet compliance obligations for the year
\n
based on national and supranational regulations.
\n
Millions of euro
\n
2023 2022 Change
\n
Charges for environmental certificates
\n
System charges \u2013 Emissions allowances 2,038 2,216 (178) -8.0%
\n
System charges \u2013 Energy efficiency certificates 244 182 62 34.1%
\n
System charges \u2013 Guarantees of origin 321 112 209 -
\n
Total 2,603 2,510 93 3.7%
\n
The increase in costs for environmental certificates com-
\n
pared with the previous year is mainly attributable to the
\n
increase in charges recognized for guarantees of origin
\n
by Enel Energia and the Endesa Group, which reflects the
\n
increase in the quantity of green energy sold to customers
\n
and the prices of those certificates.
\n
This effect was partially offset by a decrease in charges for
\n
emissions allowances, essentially in Italy, mainly connected
\n
with a decline in the quantity of electricity produced from
\n
fossil sources.
\n

\n\n\n
The following table reports the quantities of environmental
\n
certificates used by Group companies to meet compliance
\n
obligations under national and supranational regulations.
\n
2023 2022 2023 2022 2023 2022
\n
Emissions allowances
\n
(thousands of metric tons)
\n
Guarantees of origin
\n
(GWh)
\n
Energy efficiency certificates
\n
(TOE)
\n
Opening balance at January 1 34,494 28,350 20,565 11,417 416,174 257,940
\n
Self-produced certificates - - 24,845 29,540 - -
\n
Purchases of certificates 34,699 32,925 28,362 20,316 925,187 678,808
\n
Sales of certificates (2,500) - (1,464) - - -
\n
Certificates delivered for compliance
\n
(1)
\n
(35,456) (26,781) (53,075) (40,708) (863,526) (520,574)
\n
Closing balance at December 31 31,237 34,494 19,233 20,565 477,835 416,174
\n
(1) Certificates delivered in 2023 and 2022 regard compliance for previous years, in line with the time limits envisaged in the applicable regulations.
\n
Provisions for environmental certificates
\n
Provisions for risks and charges for environmental certifi-
\n
cates include charges in respect of the certificate shortfall
\n
for fulfillment of compliance obligations for the year under
\n
national and supranational regulations.
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Provisions for risk and charges for environmental certificates \u2013 current portion
\n
Emissions allowances 33 209
\n
Energy efficiency certificates 3 -
\n
Guarantees of origin 214 83
\n
Total 250 292
\n
The reduction in provisions for risks and charges (\u20ac42 mil-
\n
lion) is attributable to the decline in the provision for emis-
\n
sions allowances recognized by the Endesa Group, partial-
\n
ly offset by an increase in the provision for guarantees of
\n
origin recognized by Enel Energia.
\n
Changes in provisions for risks and charges for environ-
\n
mental certificates in 2023 are detailed below.
\n
Millions of euro Provisions Uses Other changes
\n
at Dec. 31, 2022 at Dec. 31, 2023
\n
Provisions for risk and charges for environmental
\n
certificates \u2013 current portion
\n
Emissions allowances 209 33 (209) - 33
\n
Energy efficiency certificates - 2 - 1 3
\n
Guarantees of origin 83 206 (104) 29 214
\n
Total 292 241 (313) 30 250
\n

\n\n\n
Income from government grants for environmental
\n
certificates
\n
The table reports non-monetary government grants for
\n
environmental certificates accrued during the year and
\n
certified by the competent authorities. They mainly regard
\n
guarantees of origin accrued in proportion to electricity
\n
generated by renewable resource plants.
\n
Monetary government grants for energy efficiency certifi-
\n
cates are paid by the Electricity Sector Equalization Fund
\n
to e-distribuzione for energy efficiency certificates pur-
\n
chased in the year.
\n
Millions of euro
\n
2023 2022 Change
\n
Grants for environmental certificates
\n
Non-monetary grants \u2013 Guarantees of origin 111 48 63 -
\n
Non-monetary grants \u2013 Other environmental certificates 4 1 3 -
\n
Total non-monetary grants for environmental certificates 115 49 66 -
\n
Monetary grants \u2013 Energy efficiency certificates 231 171 60 35.1%
\n
TOTAL 346 220 126 57.3%
\n
The increase of \u20ac126 million in grants for environmental
\n
certificates compared with the previous year mainly reflects:
\n
\u2022
\n
an increase in non-monetary grants for guarantees of
\n
origin registered in Spain (\u20ac44 million) and Italy (\u20ac19 mil-
\n
lion), due to an increase in prices and the quantity of en-
\n
ergy generated from renewable resources;
\n
\u2022
\n
an increase in monetary grants for energy efficiency cer-
\n
tificates (\u20ac60 million) recognized by e-distribuzione, due
\n
to an increase in the volume of certificates purchased in
\n
2023 compared with the previous year.
\n
Non-monetary grants to be received for environmental
\n
certificates
\n
The following table reports environmental certificates ac-
\n
crued at the end of the year but not yet accredited by
\n
the competent authorities to the Group companies that
\n
produced them. They are recognized under other current
\n
non-financial assets and mainly regard guarantees of origin.
\n
Millions of euro
\n
at Dec. 31, 2023 at Dec. 31, 2022
\n
Non-monetary grants to be received for environmental certificates
\n
Guarantees of origin 23 15
\n
Other certificates 1 1
\n
Total 24 16
\n
The increase of \u20ac8 million is attributable to an increase in
\n
non-monetary grants to be received for guarantees of or-
\n
igin recorded in Italy and Spain.
\n
Other items
\n
With regard to the impacts of environmental certificates
\n
on the other items of the income statement and state-
\n
ment of financial position, please see:
\n
\u2022
\n
note 11.a \u201cRevenue from sales and services\u201d for revenue
\n
from the sale of environmental certificates;
\n
\u2022
\n
note 12.b \u201cServices and other materials\u201d for purchas-
\n
es of environmental certificates not used to meet the
\n
year\u2019s compliance obligation;
\n
\u2022
\n
note 33 \u201cInventories\u201d for inventories of certificates not
\n
used to meet the year\u2019s compliance obligation.
\n

\n\n", "dimensions": { "concept": "enel:DiscolureOfEnvironmentalSchemesExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag939": { "value": "\n
59. 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, 2023.
\n
\u2022
\n
\u201cAmendments to IAS 1 \u2013 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
\n
the criteria to adopt in classifying a liability as cur-
\n
rent or non-current, specifying the meaning of right
\n
to defer settlement and that that right must exist at
\n
the end of the reporting period;
\n
\u2013
\n
that the classification is unaffected by the intentions
\n
or expectations of management about the exercise
\n
of the right to defer settlement of a liability;
\n
\u2013
\n
that the right to defer exists if and only if the entity
\n
satisfies the terms of the liability at the end of the
\n
reporting period, even if the creditor does not verify
\n
compliance with those terms until later; and
\n
\u2013
\n
that settlement regards the transfer to the coun-
\n
terparty of cash, equity instruments, other assets or
\n
services.
\n
The amendments take effect for annual periods begin-
\n
ning on or after January 1, 2024.
\n
(79)
\n
\n
\u2022
\n
\u201cAmendments to IAS 1 \u2013 Non-current Liabilities with
\n
Covenants\u201d, issued in October 2022. IAS 1 requires clas-
\n
sification of liabilities as non-current only where an en-
\n
tity has a right to defer settlement in the 12 months fol-
\n
lowing the reporting date. Nevertheless, the right to do
\n
so is often subject to compliance with covenants. The
\n
amendments of the standard improve disclosure when
\n
the right to defer settlement of a liability for at least 12
\n
months is subject to compliance with covenants and
\n
specify that the classification of the liability as current
\n
or non-current at the reporting date is not affected by
\n
covenants that must be complied with subsequent to
\n
the reporting date.
\n
The amendments take effect for annual periods begin-
\n
ning on or after January 1, 2024.
\n
\u2022
\n
\u201cAmendments to IFRS 10 and IAS 28 \u2013 Sale or Contri-
\n
bution of Assets between an Investor and its Associ-
\n
ate or Joint Venture\u201d, issued in September 2014. The
\n
amendments clarify the accounting treatment for sales
\n
or contribution of assets between an investor and its
\n
associates or joint ventures. They confirm that the ac-
\n
counting treatment depends on whether the assets
\n
sold or contributed to an associate or joint venture
\n
constitute a \u201cbusiness\u201c (as defined in IFRS 3). The IASB
\n
has deferred the effective date of these amendments
\n
indefinitely.
\n
\u2022
\n
\u201cAmendments to IFRS 16 \u2013 Lease Liability in a Sale and
\n
Leaseback\u201d, issued in September 2022. The amend-
\n
ments require the seller-lessee to measure the right-
\n
of-use asset arising from a sale and leaseback trans-
\n
action in proportion to the previous carrying amount of
\n
the asset involved in the arrangement and in line with
\n
the retained right-of-use. Consequently, the seller-les-
\n
see will be allowed to recognize only the amount of any
\n
capital gain or loss relating to the rights transferred to
\n
the buyer-lessor.
\n
The amendments do not prescribe specific measure-
\n
ment requirements for liabilities deriving from a lease-
\n
back. However, they include examples that illustrate the
\n
initial and subsequent measurement of the liability by
\n
including variable payments that do not depend on an
\n
index or a rate. This representation is a departure from
\n
the general accounting model required by IFRS 16, in
\n
which variable payments that do not depend on an in-
\n
dex or a rate are recognized through profit or loss in the
\n
period in which the event or condition that determines
\n
these payments occurs. In this regard, the seller-lessee
\n
will have to develop and apply an accounting policy to
\n
determine the lease payments such that any amount of
\n
retained right-of-use gain or loss is not recognized.
\n
The amendments take effect for annual periods begin-
\n
ning January 1, 2024. In conformity with \u201cIAS 8 - Ac-
\n
counting Policies, Changes in Accounting Estimates
\n
and Errors\u201d, retrospective application is permitted for
\n
sale and leaseback transactions entered into after the
\n
date of initial application of IFRS 16.
\n
\u2022
\n
\u201cAmendments to IAS 21 \u2013 The Effects of Changes in For-
\n
eign Exchange Rates: Lack of Exchangeability\u201d, issued
\n
in August 2023. The amendments require the applica-
\n
tion of a consistent approach in determining whether
\n
a currency is exchangeable for another and, when it is
\n
not, in determining the exchange rate to be used and
\n
the disclosure to be provided.
\n
The amendments will take effect, subject to endorse-
\n
ment, for annual periods beginning January 1, 2025
\n
(earlier application is permitted).
\n
\u2022
\n
\u201cAmendments to IAS 7 and IFRS 7 \u2013 Supplier Finance
\n
Arrangements\u201d, issued in May 2023.
\n
The amendments clarify the characteristics of supplier
\n
finance arrangements and require additional disclo-
\n
sures concerning these agreements in order to assist
\n
users of the financial statements in understanding their
\n
related impacts on an entity\u2019s liabilities, cash flows and
\n
exposure to liquidity risk.
\n
The IASB granted a transitional exemption by requiring
\n
neither comparative information in the first year of ap-
\n
(79) In 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
plication nor disclosure of specific opening balances.
\n
Furthermore, the information requested is applicable
\n
only for the first year of application. Accordingly, con-
\n
sidering that the amendments will take effect, subject
\n
to endorsement, for annual reporting periods begin-
\n
ning on or after January 1, 2024, the new disclosures
\n
must be provided no earlier than the annual financial
\n
report at December 31, 2024.
\n
The Group is assessing the potential impact of the future
\n
application of the new provisions.
\n

\n\n", "dimensions": { "concept": "ifrs-full:ExplanationOfNotAppliedNewStandardsOrInterpretations", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag940": { "value": "\n
60. Events after the reporting period
\n
Finalized the agreement to sell a geothermal and solar
\n
portfolio in the United States to Ormat
\n
On January 4, 2024, Enel SpA, acting through its whol-
\n
ly-owned subsidiary Enel Green Power North America Inc.
\n
(EGPNA), closed an agreement with Ormat Technologies
\n
Inc. on the sale of a renewable asset portfolio in the United
\n
States for a total of $271 million, equivalent to \u20ac250 mil-
\n
lion, subject to customary transactional adjustments. The
\n
assets sold include EGPNA\u2019s entire geothermal portfolio as
\n
well as a number of small solar plants, with a total capacity
\n
of about 150 MW of operating plants.
\n
The overall transaction, which was closed following the
\n
fulfillment of a number of conditions, had a positive effect
\n
on the Enel Group\u00b4s consolidated net debt of about \u20ac250
\n
million, and a negative impact of around \u20ac30 million on
\n
Group profit, which had already been recognized in 2023
\n
as impairment losses in compliance with IFRS 5.
\n
Enel issues a dual-tranche \u20ac1.75 billion sustainability-
\n
linked bond in the Eurobond market
\n
On January 16, 2024, Enel Finance International NV, a fi-
\n
nance company controlled by Enel SpA, issued a du-
\n
al-tranche sustainability-linked bond for institutional
\n
investors in the Eurobond market in the total amount of
\n
\u20ac1.75 billion.
\n
The new issue envisages the use of two sustainability Key
\n
Performance Indicators for each tranche, illustrated in the
\n
Sustainability-Linked Financing Framework, last updated
\n
in January 2024.
\n
The issue is structured in the following two tranches:
\n
\u2022
\n
\u20ac750 million at a fixed rate of 3.375%, with settlement
\n
date set on January 23, 2024, maturing July 23, 2028;
\n
\u2022
\n
\u20ac1,000 million at a fixed rate of 3.875%, with settle-
\n
ment date set on January 23, 2024, maturing January
\n
23, 2035.
\n
Enel issues a new \u20ac900 million perpetual hybrid bond
\n
with coupon at 4.75%
\n
On February 20, 2024, Enel SpA issued a non-convertible,
\n
subordinated perpetual hybrid bond for institutional in-
\n
vestors on the European market, denominated in euros,
\n
with an aggregate principal amount of \u20ac900 million.
\n
The transaction refinanced the \u20ac900 million equity-ac-
\n
counted perpetual hybrid bond with first call date in Feb-
\n
ruary 2025 and a 3.5% coupon.
\n
The bond has no fixed maturity, and is due and payable
\n
only in the event of the winding up or liquidation of the
\n
Company. An annual fixed coupon of 4.75% will be paid
\n
until (but excluding) the first reset date of May 27, 2029,
\n
which is the last day for the first optional redemption.
\n
Partnership with Sosteneo to develop battery and open-
\n
cycle plant projects in Italy
\n
On March 1, 2024, Enel SpA, acting through its subsidiary
\n
Enel Italia SpA, signed an agreement with Sosteneo Fund
\n
1 HoldCo S\u00e0rl, for the acquisition by the latter of 49% of
\n
the share capital of Enel Libra Flexsys Srl, a company whol-
\n
ly-owned by Enel Italia and established for the implemen-
\n
tation and operation of a portfolio of Battery Energy Stor-
\n
age Systems (BESS) and open-cycle gas turbines (OCGT).
\n
The agreement provides for payment by Sosteneo HoldCo
\n
of approximately \u20ac1.1 billion. The price is also subject to an
\n
adjustment mechanism customary for this type of trans-
\n
action. The enterprise value on a 100% basis of Enel Libra
\n
Flexsys recognized in the agreement is equal to around
\n
\u20ac2.5 billion once the investment cycle foreseen by the
\n
project is completed.
\n
The transaction is expected to generate upon closing a
\n
positive impact of about \u20ac1.1 billion on the Enel Group\u2019s
\n
consolidated net debt, while it is set to bear no impact on
\n
the Group\u2019s performance, as Enel will continue to maintain
\n
control and fully consolidate Enel Libra Flexsys upon the
\n
closing of the transaction.
\n
Agreement with A2A on electricity distribution
\n
operations in a number of municipalities in Lombardy
\n
On March 9, 2024, the Enel subsidiary e-distribuzione SpA
\n
signed an agreement with A2A SpA for the sale to the lat-
\n
ter of 90% of the capital of a newly incorporated vehicle
\n
to which electricity distribution operations in a number of
\n
municipalities of the provinces of Milan and Brescia will be
\n
transferred.
\n
The agreement provides for A2A to pay about \u20ac1.2 billion,
\n
based on an enterprise value (for 100% of the company) of
\n
around \u20ac1.35 billion. The price, which will be paid at clos-
\n
ing, is subject to an adjustment mechanism customary for
\n
these kinds of transactions.
\n
Upon completion of the transaction, e-distribuzione will
\n
retain a 10% stake in NewCo\u2019s capital to support the start-
\n
up phase of the company, and which will be subject to a
\n
put and call option mechanism that can be triggered start-
\n
ing from the first year from completion of the transaction.
\n

\n\n\n
Furthermore, specific agreements between the parties
\n
provide for e-distribuzione to guarantee supporting activ-
\n
ities to ensure continuity of service.
\n
The transaction is expected to generate a positive ef-
\n
fect on the Enel Group\u2019s consolidated net debt in 2024 of
\n
about \u20ac1.2 billion and a positive impact on Group reported
\n
profit for 2024 of about \u20ac1 billion. If, before the closing of
\n
the transaction, a precise specification of further activities
\n
that e-distribuzione may carry out for NewCo is reached
\n
and such activities are reflected in specific agreements,
\n
thereby forming an industrial Stewardship relationship, the
\n
aforementioned performance effects could also be recog-
\n
nized on the Group\u2019s ordinary results.
\n
The closing of the transaction, which is expected to occur
\n
by December 31, 2024, is subject to a number of condi-
\n
tions, including receipt of antitrust clearance, the suc-
\n
cessful completion of the golden power procedure by the
\n
Presidency of Italy\u2019s Council of Ministers and receipt of au-
\n
thorization to transfer the electricity distribution service
\n
concessions to NewCo.
\n

\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag941": { "value": "\n
61. Fees of the Audit Firm pursuant to
\n
Article 149-duodecies of the CONSOB
\n
Issuers Regulation
\n
Fees pertaining to 2023 paid by Enel SpA and its subsid-
\n
iaries at December 31, 2023 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

\n\n\n
Millions of euro
\n
Type of service Entity providing the service Fees
\n
Enel SpA
\n
Auditing
\n
of which:
\n
- KPMG SpA 0.9
\n
- entities of the KPMG network -
\n
Certification services
\n
of which:
\n
- KPMG SpA 1.8
\n
- entities of the KPMG network -
\n
Other services
\n
of which:
\n
- KPMG SpA -
\n
- entities of the KPMG network -
\n
Total 2.7
\n
Enel SpA subsidiaries
\n
Auditing
\n
of which:
\n
- KPMG SpA 4.6
\n
- entities of the KPMG network 9.5
\n
Certification services
\n
of which:
\n
- KPMG SpA 1.3
\n
- entities of the KPMG network 1.2
\n
Other services
\n
of which:
\n
- KPMG SpA -
\n
- entities of the KPMG network -
\n
Total 16.6
\n
TOTAL 19.3
\n

\n\n", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag237": { "value": "\n
ATTACHMENTS
\n
Subsidiaries, associates and other significant equity
\n
investments of the Enel Group at December 31, 2023
\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, 2023, pursuant to Article 2359 of the Ital-
\n
ian 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, meth-
\n
od of consolidation, Group companies that have a stake
\n
in the company and their respective ownership share, and
\n
the 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
End-user Markets
\n
Enel X
\n
e-Mobility
\n
Services
\n
Finance
\n

\n\n\n\n
Company name Headquarters 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 EUR
\n
Holding Enel SpA 100.00% 100.00%
\n
Subsidiaries
\n
25 Mile Creek Windfarm LLC Andover US 1 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
25 Mile PPA LLC Andover US 1 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
25RoseFarms Holdings LLC Andover US 1 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 EUR
\n
Held for sale
\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 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 Tradewind Energy Inc. 100.00% 100.00%
\n
Ables Springs Solar LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ables Springs Storage LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Abu Renewables India Private
\n
Limited
\n
Gurugram IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Ace High Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aced Renewables Hidden
\n
Valley (RF) (Pty) Ltd
\n
Johannesburg ZA 1,000 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 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Adams Solar PV Project Two
\n
(RF) (Pty) Ltd
\n
Johannesburg ZA 10,000,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
60.00% 60.00%
\n
Adria Link Srl Gorizia IT 300,297 EUR
\n
Equity Enel Produzione SpA 50.00% 50.00%
\n
Aferkat Wind Farm Casablanca MA 389,600 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco S\u00e0rl
\n
99.97% 99.97%
\n
Agassiz Beach LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Agatos Green Power Trino Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Solar Energy Srl
\n
100.00% 100.00%
\n
Aguill\u00f3n 20 SA Zaragoza ES 2,682,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Aidon Oy Jyv\u00e4skyl\u00e4 FI 5,112,572 EUR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Alba Energia Ltda Rio de Janeiro BR 16,045,169 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
Albany Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74. 13 %
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Almyros Ape Single Member
\n
PC
\n
Maroussi GR 20,001 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
100.00% 50.00%
\n
Alpe Adria Energia Srl Udine IT 900,000 EUR
\n
Equity Enel Produzione SpA 50.00% 50.00%
\n
Alta Farms Azure Ranchland
\n
Holdings LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Alta Farms Wind Project
\n
II LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
Alvorada Energia SA Niter\u00f3i BR 22,317,416 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ampla Energia e Servi\u00e7os SA Rio de Janeiro BR 4,438,230,387 BRL
\n
Line-by-line Enel Brasil SA 99.83% 82.13%
\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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Aquilla Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Aragonesa de Actividades
\n
Energ\u00e9ticas SAU
\n
Teruel ES 60,100 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Aranort Desarrollos SLU Madrid ES 3,010 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 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Arcadia Power Inc. Washington DC US - USD
\n
-
\n
Enel X North America
\n
Inc.
\n
0.14% 0.14%
\n
Arena Green Power 1 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power 2 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power 3 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power 4 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Green Power 5 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Arena Power Solar 11 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 12 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 13 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 20 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 33 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 34 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Arena Power Solar 35 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Arrow Head Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Arrow Hills Solar Project Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Asociaci\u00f3n Nuclear Asc\u00f3-
\n
Vandell\u00f3s II AIE
\n
Vandell\u00f3s ES 19,232,400 EUR Proportional
\n
Endesa Generaci\u00f3n
\n
SAU
\n
85.41% 59.89%
\n
Ateca Renovables SL Madrid ES 3,000 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
Atl\u00e1ntico Photovoltaic SAS
\n
ESP
\n
Barranquilla CO 50,587,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\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 Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Solar Holdings
\n
LLC
\n
74. 13% 74. 13%
\n
Aurora Land Holdings LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Solar Holdings LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Holdings LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Aurora Wind Project LLC Andover US 1 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Autumn Waltz Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Avikiran Energy India Private
\n
Limited
\n
Gurugram IN 100,000,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Avikiran Solar India Private
\n
Limited
\n
New Delhi IN 4,918,810,370 INR
\n
Equity
\n
Enel Green Power
\n
India Private Limited
\n
51.00% 51.00%
\n
Avikiran Surya India Private
\n
Limited
\n
Gurugram IN 875,350 INR
\n
Equity
\n
Enel Green Power
\n
India Private Limited
\n
51.00% 51.00%
\n
Avikiran Vayu India Private
\n
Limited
\n
Gurugram IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Azure Blue Jay Holdings LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Azure Blue Jay Solar Holdings
\n
LLC
\n
Andover US 1 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 LLC Andover US 1 USD
\n
Line-by-line
\n
Azure Blue Jay Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind Holdings LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Azure Sky Wind Project LLC Andover US 1 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Azure Sky Wind Storage LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
AzureRanchII Wind Holdings
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Green Power
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Baikal Enterprise SLU Palma de Mallorca ES 3,006 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Baleares Energy SLU Palma de Mallorca ES 4,509 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 Tradewind Energy Inc. 100.00% 100.00%
\n
Baylio Solar SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Beacon Harbor Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Beaver Falls Water Power
\n
Company
\n
Wilmington US - USD
\n
Line-by-line
\n
Beaver Valley
\n
Holdings LLC
\n
67.50% 67.50%
\n
Beaver Valley Holdings LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Bejaad Solar Plant Casablanca MA 10,000 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco S\u00e0rl
\n
99.90% 99.90%
\n
Belltail Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Belomechetskaya WPS Moscow RU 3,010,000 RUB
\n
Line-by-line
\n
Enel Green Power
\n
Rus Limited Liability
\n
Company
\n
100.00% 100.00%
\n
Betwa Renewable Energy
\n
Private Limited
\n
Gurgaon IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Bijou Hills Wind LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Bioenergy Casei Gerola Srl Rome IT 100,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Bison Meadows Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Bison Meadows Wind Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Blair Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Blanche BESS (Pty) Ltd Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Blanche Holding
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Blanche BESS Trust Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Blanche Holding Trust
\n
100.00% 50.00%
\n
Blue Jay Solar I LLC Andover US 1 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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Blue Star Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Bogot\u00e1 ZE SAS Bogot\u00e1 CO 1,189,706,920 COP
\n
Equity Colombia ZE SAS 100.00% 9.44%
\n
Boitumelo Solar Power Plant
\n
(RF) (Pty) Ltd
\n
Gauteng ZA 100 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Bold Elk Wind Limited
\n
Partnership
\n
Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 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 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 I LLC Andover US 1 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Bottom Grass Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Boujdour Wind Farm Casablanca MA 300,000 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
90.00% 45.00%
\n
Bouldercombe Solar Farm
\n
Trust
\n
Sydney AU 10 AUD
\n
Equity
\n
Enel Green Power
\n
Bouldercombe Trust
\n
100.00% 50.00%
\n
Bouldercombe Solar (Pty) Ltd Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Bouldercombe
\n
Holding (Pty) Ltd
\n
100.00% 50.00%
\n
Box Canyon Energy Storage
\n
Project LLC
\n
Andover US 1 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 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Bravo Dome Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Brazatortas 220 Renovables
\n
SL
\n
Madrid ES 3,000 EUR
\n
Equity
\n
Baylio Solar SLU 16.98%
\n
23.81%
\n
Furatena Solar 1 SLU 16.98%
\n
Brazoria West Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Brazos Flat Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brick Road Solar Holdings
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Bronco Hills Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Brush County Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Buck Canyon Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buckshutem Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Buckshutem Solar II LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Buffalo Dunes Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Buffalo Dunes Wind Project
\n
LLC
\n
Topeka US - USD
\n
Line-by-line
\n
EGPNA Development
\n
Holdings LLC
\n
75.00% 75.00%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Buffalo Jump LP Alberta CA 10 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Buffalo Spirit Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Bungala One Finco (Pty) Ltd Sydney AU 1,000 AUD
\n
Equity
\n
Bungala One
\n
Property Trust
\n
100.00% 25.50%
\n
Bungala One Operation
\n
Holding Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 25.00%
\n
Bungala One Operations
\n
Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 25.50%
\n
Bungala One Operations
\n
(Pty) Ltd
\n
Sydney AU 1,000 AUD
\n
Equity
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala One Operations
\n
Trust
\n
Sydney AU - AUD
\n
Equity
\n
Bungala One
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala One Property
\n
Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 25.50%
\n
Bungala One Property
\n
Holding Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 25.00%
\n
Bungala One Property
\n
(Pty) Ltd
\n
Sydney AU 1,000 AUD
\n
Equity
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala One Property Trust Sydney AU - AUD
\n
Equity
\n
Bungala One
\n
Property Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala Two Finco (Pty) Ltd Sydney AU - AUD
\n
Equity
\n
Bungala Two Property
\n
Trust
\n
100.00% 25.50%
\n
Bungala Two Operations
\n
Holding (Pty) Ltd
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 25.50%
\n
Bungala Two Operations
\n
Holding Trust
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 25.00%
\n
Bungala Two Operations
\n
(Pty) Ltd
\n
Sydney AU - AUD
\n
Equity
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala Two Operations
\n
Trust
\n
Sydney AU - AUD
\n
Equity
\n
Bungala Two
\n
Operations Holding
\n
(Pty) Ltd
\n
100.00% 25.50%
\n
Bungala Two Property
\n
Holding (Pty) Ltd
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
51.00% 25.50%
\n
Bungala Two Property
\n
Holding Trust
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Bungala (Pty) Ltd
\n
50.00% 25.00%
\n
Bungala Two Property (Pty)
\n
Ltd
\n
Sydney AU - AUD
\n
Equity
\n
Bungala Two Property
\n
Holding (Pty) Ltd
\n
100.00% 25.50%
\n
Bungala Two Property Trust Sydney AU 1 AUD
\n
Equity
\n
Bungala Two Property
\n
Holding (Pty) Ltd
\n
100.00% 25.50%
\n
Burgundy Spruce Solar LP Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Business Venture
\n
Investments 1468 (Pty) Ltd
\n
Johannesburg ZA 100 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
Butterfly Meadows Solar
\n
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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
C&C Uno Energy Srl Rome IT 118,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cactus Mesa Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Campos Promotores
\n
Renovables SL
\n
Elche ES 3,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.30% 17.74%
\n
Canastota Wind Power LLC Andover US - USD
\n
Line-by-line
\n
Fenner Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Caney River Wind Project
\n
LLC
\n
Overland Park US - USD
\n
Equity
\n
Rocky Caney Wind
\n
LLC
\n
100.00% 10.00%
\n
Canyon Top Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Castle Rock Ridge Limited
\n
Partnership
\n
Alberta CA - CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Catalana d\u2019Iniciatives SA in
\n
liquidation
\n
Barcelona ES 30,862,800 EUR
\n
- Endesa SA 0.94% 0.66%
\n
Cattle Drive Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cdec - Sic Ltda Santiago de Chile CL 709,783,206 CLP
\n
-
\n
Enel Green Power
\n
Chile SA
\n
6.00% 3.90%
\n
Cedar Run Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Central Geradora
\n
Fotovoltaica Bom Nome Ltda
\n
Salvador BR 4,979,739 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 Francisco
\n
Ltda
\n
Niter\u00f3i BR 268,128,917 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 G\u00fcejar-
\n
Sierra SL
\n
Granada ES 364,213 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.30% 23.35%
\n
Central T\u00e9rmica de Anllares
\n
AIE
\n
Madrid ES 595,000 EUR Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
33.33% 23.37%
\n
Central Vuelta de Obligado
\n
SA
\n
Buenos Aires AR 500,000 ARS
\n
-
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
33.20% 17.95%
\n
Centrales Nucleares Almaraz-
\n
Trillo AIE
\n
Madrid ES - EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
24.18% 16.95%
\n
Centrum Pre Vedu A Vyskum
\n
Sro
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 6,639 EUR
\n
Equity
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
100.00% 33.00%
\n
CES 2 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 3 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 4 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 5 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 6 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 7 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n
CES 8 Private Company Athens GR 501 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.20% 0.10%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
CESI - Centro Elettrotecnico
\n
Sperimentale Italiano
\n
Giacinto Motta SpA
\n
Milan IT 8,550,000 EUR
\n
Equity Enel SpA 42.70% 42.70%
\n
Champagne Storage LLC Wilmington US 1 USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Checkerboard Plains Solar
\n
Project Limited Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Cheyenne Ridge II Wind
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cheyenne Ridge Wind
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 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 LLC 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 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 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chi Power Marketing Inc. Wilmington US 100 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 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Chinango SAC San Miguel PE 295,249,298 SOL
\n
Held for sale
\n
Enel Generaci\u00f3n
\n
Per\u00fa SAA
\n
80.00% 57. 2 3 %
\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 Holding LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Chisholm View Wind Project
\n
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 Project
\n
LLC
\n
New York US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
Cimarron Bend Assets LLC Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend Wind
\n
Project I LLC
\n
49.00%
\n
100.00%
\n
Cimarron Bend Wind
\n
Project II LLC
\n
49.00%
\n
Cimarron Bend Wind
\n
Project III LLC
\n
1.00%
\n
Enel Kansas LLC 1.00%
\n
Cimarron Bend III HoldCo
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Green Power
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
100.00% 100.00%
\n
Cimarron Bend Solar Project
\n
LLC
\n
Andover US 1 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 Wind
\n
Holdings II LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind
\n
Holdings II LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Cimarron Bend Wind
\n
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

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Cimarron Bend Wind
\n
Holdings LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind Project
\n
I LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend Wind
\n
Holdings I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind Project
\n
II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend Wind
\n
Holdings I LLC
\n
100.00% 100.00%
\n
Cimarron Bend Wind Project
\n
III LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Cimarron Bend Wind
\n
Holdings III LLC
\n
100.00% 100.00%
\n
Cinch Top Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cipher Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
CityPoste Payment Digital Srl
\n
Mosciano
\n
Sant\u2019Angelo
\n
IT 10,000 EUR
\n
Equity Mooney SpA 100.00% 50.00%
\n
Clear Fork Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Clear Sky Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Clinton Farms Battery Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Clinton Farms Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Clinton Farms Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Cloudwalker Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cogein Sannio Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Cogeneraci\u00f3n el Salto SL in
\n
liquidation
\n
Zaragoza ES 36,061 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
20.00% 14.02%
\n
Cogenio Iberia SL Madrid ES 2,874,622 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
20.00% 14.02%
\n
Cogenio Srl Rome IT 2,310,000 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Cohuna Solar Farm (Pty) Ltd Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Cohuna Holdings
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Cohuna Solar Farm Trust Sydney AU 1 AUD
\n
Equity
\n
Enel Green Power
\n
Cohuna Trust
\n
100.00% 50.00%
\n
Colombia ZE SAS Bogot\u00e1 CO 11,872,499,000 COP
\n
Equity
\n
Enel Colombia SA
\n
ESP
\n
20.00% 9.44%
\n
Comanche Crest Ranch LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Comercializadora El\u00e9ctrica
\n
de C\u00e1diz SA
\n
C\u00e1diz ES 600,000 EUR
\n
Equity Endesa SA 33.50% 23.49%
\n
Compagnia Porto di
\n
Civitavecchia SpA in
\n
liquidation
\n
Rome IT 15,130,800 EUR
\n
Equity Enel Produzione SpA 24.34% 24.34%
\n
Companhia Energ\u00e9tica do
\n
Cear\u00e1 - Coelce
\n
Fortaleza BR 1,282,346,886 BRL
\n
Line-by-line Enel Brasil SA 74.05% 60.92%
\n
Compa\u00f1\u00eda de Trasmisi\u00f3n del
\n
Mercosur SA - CTM
\n
Buenos Aires AR 2,025,191,313 ARS
\n
Held for sale
\n
Enel Brasil SA 74. 15%
\n
82.27%Enel CIEN SA 25.85%
\n
Enel SpA 0.00%
\n

\n\n\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Compa\u00f1\u00eda Energ\u00e9tica
\n
Veracruz SAC
\n
San Miguel PE 37,721,314 SOL
\n
Held for sale Enel Per\u00fa SAC 100.00% 82.27%
\n
Compa\u00f1\u00eda E\u00f3lica Tierras
\n
Altas SA
\n
Soria ES 13,222,000 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 Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Concert Srl Rome IT 10,000 EUR Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Concho Solar I LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Concord Vine Solar Project
\n
LLC
\n
Andover US 1 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 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
81.83% 81.83%
\n
Conza Green Energy Srl Rome IT 73,000 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 Empresarial de
\n
Extremadura SA
\n
Badajoz ES 44,538,000 EUR
\n
- Endesa SA 1.01% 0.71%
\n
Corporaci\u00f3n E\u00f3lica de
\n
Zaragoza SL
\n
La Puebla de
\n
Alfind\u00e9n
\n
ES 271,652 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
25.00% 17.53%
\n
Country Roads Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Cow Creek Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Cr\u00e9dito F\u00e1cil Codensa SA
\n
Compa\u00f1\u00eda de Financiamiento
\n
in liquidation
\n
Bogot\u00e1 CO 32,000,000,000 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 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Dairy Meadows Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Daisy Patch Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Danax Energy (Pty) Ltd Sandton ZA 100 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
Dappled Colt Storage Project
\n
Limited Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Storage
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Dauphin Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Daybreak Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Decimalfigure - Unipessoal
\n
Ltda
\n
Pego PT 2,000 EUR
\n
Equity
\n
Tejo Energia
\n
- Produ\u00e7\u00e3o e
\n
Distribui\u00e7\u00e3o de
\n
Energia El\u00e9ctrica SA
\n
100.00% 30.68%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Dehesa de los Guadalupes
\n
Solar SLU
\n
Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 03 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Dehesa PV Farm 04 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Derivex SA Bogot\u00e1 CO 938,734,000 COP
\n
-
\n
Enel Colombia SA
\n
ESP
\n
5.20% 2.46%
\n
Desarrollo de Fuerzas
\n
Renovables S de RL de Cv
\n
Mexico City MX 53,104,350 MXN Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
100.00%
\n
100.00%
\n
Enel Services M\u00e9xico
\n
SA de Cv
\n
0.00%
\n
Desert Willow Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
DI.T.N.E. - Distretto
\n
Tecnologico Nazionale
\n
sull\u2019Energia - Societ\u00e0
\n
Consortile a Responsabilit\u00e0
\n
Limitata
\n
Rome IT 451,878 EUR
\n
- Enel Produzione SpA 1.79% 1.79%
\n
Diamond Vista Holdings LLC Wilmington US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Diamond Vista Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Dispatch Renewable Energy
\n
Societe Anonyme
\n
Heraklion, Crete GR 740,000 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas SA
\n
0.00% 0.00%
\n
Distretto Tecnologico Sicilia
\n
Micro e Nano Sistemi Scarl
\n
Catania IT 628,978 EUR
\n
- 3SUN Srl 5.56% 5.56%
\n
Distribuidora de Energ\u00eda
\n
El\u00e9ctrica del Bages SA
\n
Barcelona ES 108,240 EUR
\n
Line-by-line
\n
Endesa SA 55.00%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
45.00%
\n
Distribuidora El\u00e9ctrica del
\n
Puerto de la Cruz SAU
\n
Santa Cruz de
\n
Tenerife
\n
ES 12,621,210 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Distrilec Inversora SA Buenos Aires AR 497,612,021 ARS
\n
Line-by-line Enel Am\u00e9ricas SA 51.50% 42.37%
\n
Dodge Center Distributed
\n
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 4,151,197,627 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
1.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.00%
\n
Dominica Energ\u00eda Limpia
\n
SA de Cv
\n
Mexico City MX 2,070,600,646 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Dorset Ridge Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Dover Solar I LLC Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Dragonfly Fields Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Drift Sand Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Equity Enel Kansas LLC 50.00% 50.00%
\n
Drift Sand Wind Project LLC 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 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
E.S.CO. Comuni Srl Bergamo IT 1,000,000 EUR
\n
Line-by-line Enel X Italia Srl 60.00% 60.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Earthly Reflections Solar
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Eastern Rise Solar Project
\n
LLC
\n
Andover US 1 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 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ecosolar2 Private Company Grevena GR 1,000 EUR
\n
-
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.10%
\n
Edgartown Depot Solar 1 LLC Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Edistribuci\u00f3n Redes Digitales
\n
SLU
\n
Madrid ES 1,204,540,060 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
e-distribuzione SpA Rome IT 2,600,000,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
EF Divesture LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Efficientya Srl Bergamo IT 100,000 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
EGP Australia (Pty) Ltd Sydney AU 10,000 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
EGP BESS 1 (RF) (Pty) Ltd Gauteng ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
EGP Bioenergy Srl Rome IT 1,000,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Puglia Srl
\n
100.00% 100.00%
\n
EGP fotovoltaica La Loma
\n
SAS in liquidation
\n
Bogot\u00e1 CO 8,000,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
EGP Geronimo Holding
\n
Company Inc.
\n
Wilmington US 1,000 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP GulfStar Solar PPA LLC Andover US 1 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\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
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\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
EGP HoldCo 7 LLC Andover US - USD
\n
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 SA
\n
de Cv
\n
Mexico City MX 1,258,077,873 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
99.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.50%
\n
EGP Matimba NewCo 1 Srl Rome IT 10,000 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
EGP Matimba NewCo 2 Srl Rome IT 10,000 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
Held for sale
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP North America PPA LLC Andover US 1 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP Sabaudia Srl Rome IT 1,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
EGP Salt Wells Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGP San Leandro Microgrid
\n
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 Enel Kansas LLC 100.00% 100.00%
\n
EGP Solar V SAU
\n
San Salvador de
\n
Jujuy
\n
AR 500,000 ARS
\n
Line-by-line
\n
Enel Green Power
\n
Argentina
\n
100.00% 82.27%
\n
EGP Solar VI SAU
\n
San Salvador de
\n
Jujuy
\n
AR 500,000 ARS
\n
Line-by-line
\n
Enel Green Power
\n
Argentina
\n
100.00% 82.27%
\n
EGP Stillwater Solar LLC Wilmington US - USD
\n
Held for sale Enel Stillwater LLC 100.00% 100.00%
\n
EGP Stillwater Solar PV II LLC Wilmington US 1 USD
\n
Held for sale
\n
Stillwater Woods Hill
\n
Holdings LLC
\n
100.00% 100.00%
\n
EGP Terracina 01 Srl Rome IT 1,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
EGP Terracina 02 Srl Rome IT 1,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGP Timber Hills Project LLC Los Angeles US - USD
\n
Line-by-line
\n
Padoma Wind Power
\n
LLC
\n
100.00% 100.00%
\n
EGPE Solar 2 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
EGPNA 2020 HoldCo 1 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 10 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 11 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 12 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 13 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 14 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 15 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 16 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 17 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 18 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 19 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 2 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 20 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 21 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 22 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 23 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 24 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 25 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 26 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 27 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 28 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 29 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2020 HoldCo 3 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 30 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 4 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 5 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 6 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 7 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 8 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2020 HoldCo 9 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 1 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 10 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 11 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 12 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 13 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 14 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 15 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 16 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 17 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 18 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 19 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 2 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 20 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 3 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 4 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 5 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
EGPNA 2023 HoldCo 6 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 7 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 8 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA 2023 HoldCo 9 LLC Andover US 1 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 LLC 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 1 LLC Dover US 100 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
EGPNA Project HoldCo 2 LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo 5 LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo 6 LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Project HoldCo 7 LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA Renewable Energy
\n
Partners LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA REP Holdings
\n
LLC
\n
10.00% 10.00%
\n
EGPNA REP Holdings LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
EGPNA REP Solar 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 Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Renewable
\n
Energy Partners LLC
\n
100.00% 10.00%
\n
EGPNA Wind Holdings 1 LLC Wilmington US - USD
\n
Equity
\n
EGPNA REP Wind
\n
Holdings LLC
\n
100.00% 10.00%
\n
EGPNA-SP Seven Cowboy
\n
Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Elcogas SA in liquidation Puertollano ES 809,690 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
40.99%
\n
33.06%
\n
Enel SpA 4.32%
\n
Elecgas SA Pego PT 50,000 EUR Equity
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
50.00% 35.06%
\n
Electra Capital (RF) (Pty) Ltd Johannesburg ZA 10,000,000 ZAR Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
60.00% 60.00%
\n
El\u00e9ctrica de Jafre SA Barcelona ES 165,876 EUR
\n
Line-by-line
\n
Endesa SA 52.54%
\n
70.12%
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
47.46%
\n
El\u00e9ctrica de Lijar SL C\u00e1diz ES 1,081,822 EUR
\n
Equity Endesa SA 50.00% 35.06%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
El\u00e9ctrica del Ebro SAU Barcelona ES 500,000 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Electricidad de Puerto
\n
Real SA
\n
Puerto Real ES 4,960,246 EUR
\n
Equity Endesa SA 50.00% 35.06%
\n
Electro Metal\u00fargica del
\n
Ebro SL
\n
Madrid ES 2,906,862 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
0.18% 0.12%
\n
Electrotest Instalaciones,
\n
Montajes y Mantenimientos
\n
SL
\n
Puerto Real ES 10,000 EUR
\n
- Epresa Energ\u00eda SA 50.00% 17.53%
\n
Eletropaulo Metropolitana
\n
Eletricidade de S\u00e3o Paulo SA
\n
S\u00e3o Paulo BR 3,079,524,934 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Emerald Crescent Solar
\n
Limited Partnership
\n
Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Emeroo BESS (Pty) Ltd Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Emeroo Holding
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Emintegral Cycle SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Empresa Carbon\u00edfera del Sur
\n
- ENCASUR SAU
\n
Madrid ES 18,030,000 EUR 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 EUR
\n
Line-by-line
\n
Empresa de
\n
Alumbrado El\u00e9ctrico
\n
de Ceuta SA
\n
100.00% 67.61 %
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta Energ\u00eda
\n
SLU
\n
Ceuta ES 10,000 EUR
\n
Line-by-line Endesa Energ\u00eda SAU 100.00% 70.12%
\n
Empresa de Alumbrado
\n
El\u00e9ctrico de Ceuta SA
\n
Ceuta ES 16,562,250 EUR
\n
Line-by-line Endesa SA 96.42% 67.61%
\n
Empresa Distribuidora Sur
\n
SA - Edesur
\n
Buenos Aires AR 898,585,028 ARS
\n
Line-by-line
\n
Distrilec Inversora SA 56.36%
\n
59.33%
\n
Enel Argentina SA 43.10%
\n
Empresa El\u00e9ctrica
\n
Pehuenche SA
\n
Santiago de Chile CL 175,774,920,733 CLP
\n
Line-by-line
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
92.65% 56.27%
\n
Empresa Propietaria de la
\n
Red SA
\n
Panama City PA 58,500,000 USD
\n
- Enel SpA 11.11% 11.11%
\n
EN. Solar 4 Single Member
\n
Private Company
\n
Maroussi GR 1,000 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
100.00% 50.00%
\n
Endesa Capital SAU Madrid ES 60,200 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Energ\u00eda Renovable
\n
SLU
\n
Madrid ES 100,000 EUR
\n
Line-by-line Endesa Energ\u00eda SAU 100.00% 70.12%
\n
Endesa Energ\u00eda SAU Madrid ES 14,445,576 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Financiaci\u00f3n Filiales
\n
SAU
\n
Madrid ES 4,621,003,006 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n II SAU Seville ES 63,107 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Generaci\u00f3n Nuclear
\n
SAU
\n
Seville ES 60,000 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Endesa Generaci\u00f3n Portugal
\n
SA
\n
Lisbon PT 50,000 EUR
\n
Line-by-line
\n
Endesa Energ\u00eda SAU 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 SAU Seville ES 1,940,379,735 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Endesa Ingenier\u00eda SLU Seville ES 965,305 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Medios y Sistemas
\n
SLU
\n
Madrid ES 89,999,790 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Mobility SLU Madrid ES 10,000,000 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa Operaciones y
\n
Servicios Comerciales SLU
\n
Madrid ES 10,138,580 EUR
\n
Line-by-line Endesa Energ\u00eda SAU 100.00% 70.12%
\n
Endesa X Servicios SLU Madrid ES 32,396 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Endesa X Way SL Madrid ES 600,000 EUR
\n
Line-by-line
\n
Endesa Mobility SLU 49.00%
\n
85.36%
\n
Enel X Way Srl 51.00%
\n
Endesa SA Madrid ES 1,270,502,540 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 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Alberta Storage Inc. Calgary CA 1 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 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
100.00% 100.00%
\n
Enel Am\u00e9ricas SA Santiago de Chile CL 15,799,226,825 USD
\n
Line-by-line Enel SpA 82.27% 82.27%
\n
Enel Argentina SA Buenos Aires AR 2,297,711,908 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 Storage
\n
LLC
\n
Wilmington US - USD Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Enel Brasil SA Niter\u00f3i BR 43,393,413,243 BRL
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 99.61%
\n
82.27%
\n
Enel Brasil SA 0.39%
\n
Enel Chile SA Santiago de Chile CL 3,882,103,470,184 CLP
\n
Line-by-line Enel SpA 64.93% 64.93%
\n
Enel CIEN SA Rio de Janeiro BR 285,044,682 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Colina SA Santiago de Chile CL 82,222,000 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 COP
\n
Line-by-line Enel Am\u00e9ricas SA 57.34% 47. 1 8%
\n
Enel Costa Rica CAM SA San Jos\u00e9 CR 27,500,000 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
Enel Cove Fort II LLC Wilmington US - USD
\n
Held for sale
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Cove Fort LLC Beaver US - USD
\n
Held for sale Enel Geothermal LLC 100.00% 100.00%
\n
Enel Distribuci\u00f3n Chile SA Santiago de Chile CL 177,568,664,063 CLP
\n
Line-by-line Enel Chile SA 99.09% 64.34%
\n
Enel Distribuci\u00f3n Per\u00fa SAA San Miguel PE 3,033,046,862 SOL
\n
Held for sale Enel Per\u00fa SAC 83.15% 68.41%
\n
Enel Energia SpA Rome IT 10,000,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Energia SA de Cv Mexico City MX 25,000,100 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Enel Energy Australia (Pty) Ltd Sydney AU 200,100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Energy North America
\n
Illinois LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North America
\n
Ohio LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North America
\n
Pennsylvania LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North America
\n
Texas LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Energy North
\n
America LLC
\n
100.00% 100.00%
\n
Enel Energy North America
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Energy South Africa Wilmington ZA 100 ZAR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel Energy Storage
\n
Holdings LLC (formerly EGP
\n
Energy Storage Holdings
\n
LLC)
\n
Andover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Erre SpA Rome IT 3,000,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Finance America LLC Wilmington US 200,000,000 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Finance International NV Amsterdam NL 1,478,810,371 EUR
\n
Line-by-line
\n
Enel Holding Finance
\n
Srl
\n
75.00%
\n
100.00%
\n
Enel SpA 25.00%
\n
Enel Fortuna SA Panama City PA 100,000,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 50.06% 23.62%
\n
Enel Future Project 2020
\n
#1 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#10 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#11 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#12 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#13 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#14 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#15 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#16 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#17 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#18 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#19 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#2 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#20 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Future Project 2020
\n
#3 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#4 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#5 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#6 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#7 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#8 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Future Project 2020
\n
#9 LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Enel Generaci\u00f3n Chile SA Santiago de Chile CL 552,777,320,871 CLP
\n
Line-by-line Enel Chile SA 93.55% 60.74%
\n
Enel Generaci\u00f3n El Choc\u00f3n
\n
SA
\n
Buenos Aires AR 18,321,776,559 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 SAA San Miguel PE 3,134,886,677 SOL
\n
Held for sale
\n
Enel Am\u00e9ricas SA 20.46%
\n
71.54%
\n
Enel Per\u00fa SAC 66.49%
\n
Enel Generaci\u00f3n Piura SA San Miguel PE 249,202,667 SOL
\n
Held for sale Enel Per\u00fa SAC 96.50% 79.39%
\n
Enel Generaci\u00f3n SA de Cv Mexico City MX 7,100,100 MXN Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Enel Geothermal LLC Wilmington US - USD
\n
Held for sale
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Global Services Srl Rome IT 10,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Global Trading SpA Rome IT 90,885,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power
\n
25RoseFarms Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Argentina Buenos Aires AR 463,577,761 ARS
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Enel Green Power Aroeira
\n
01 SA
\n
Rio de Janeiro BR 334,518,402 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 Aroeira
\n
02 SA
\n
Rio de Janeiro BR 284,501,000 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 Aroeira
\n
03 SA
\n
Rio de Janeiro BR 284,501,000 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 Aroeira
\n
04 SA
\n
Rio de Janeiro BR 430,299,146 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.97%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.03%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Aroeira
\n
05 SA
\n
Rio de Janeiro BR 284,501,000 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 Aroeira
\n
06 SA
\n
Rio de Janeiro BR 284,511,002 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 Aroeira
\n
07 SA
\n
Rio de Janeiro BR 284,501,000 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 Aroeira
\n
08 SA
\n
Rio de Janeiro BR 284,501,000 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 Australia
\n
(Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Enel Green Power Australia
\n
Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Enel Green Power Azure Blue
\n
Jay Solar Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Azure
\n
Ranchland Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
AzureRanchII Wind Holdings
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Blanche
\n
Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity EGP Australia (Pty) Ltd 100.00% 50.00%
\n
Enel Green Power Blanche
\n
Holding Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power Boa Vista
\n
01 Ltda
\n
Salvador BR 3,554,607 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 Vista
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 42,890,000 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 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power
\n
Bouldercombe Trust
\n
Sydney AU 10 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power Bungala
\n
(Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power Bungala
\n
Trust
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power Cabe\u00e7a
\n
de Boi SA
\n
Niter\u00f3i BR 270,114,539 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Cachoeira
\n
Dourada SA
\n
Cachoeira
\n
Dourada
\n
BR 64,339,836 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 Canada
\n
Inc.
\n
Montreal CA 85,681,857 CAD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power Cerrado
\n
Solar SA
\n
Rio de Janeiro BR 1,000 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Chile SA Santiago de Chile CL 842,121,531 USD
\n
Line-by-line
\n
Enel Chile SA 99.99%
\n
64.93%
\n
Enel SpA 0.01%
\n
Enel Green Power Cimarron
\n
Bend Wind Holdings III LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Cohuna
\n
Holdings (Pty) Ltd
\n
Sydney AU 3,419,700 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power Cohuna
\n
Trust
\n
Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power Cove Fort
\n
Solar LLC
\n
Wilmington US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Cristal
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 87,784,899 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.63%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
1.37%
\n
Enel Green Power Cumaru
\n
01 SA
\n
Niter\u00f3i BR 204,653,591 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 Cumaru
\n
02 SA
\n
Niter\u00f3i BR 107,601,273 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 Cumaru
\n
03 SA
\n
Rio de Janeiro BR 225,021,296 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 Cumaru
\n
04 SA
\n
Rio de Janeiro BR 230,869,708 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 Cumaru
\n
05 SA
\n
Rio de Janeiro BR 180,208,001 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.94%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Cumaru
\n
Participa\u00e7\u00f5es SA
\n
Rio de Janeiro BR 1,000 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 Cumaru
\n
Solar 01 SA
\n
Rio de Janeiro BR 1,000 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 Cumaru
\n
Solar 02 SA
\n
Rio de Janeiro BR 1,000 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 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 Delfina A
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 284,062,483 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Delfina B
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 93,068,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Delfina C
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 31,105,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Delfina D
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 105,864,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Delfina E
\n
E\u00f3lica SA
\n
Niter\u00f3i BR 105,936,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power
\n
Desenvolvimento Ltda
\n
Rio de Janeiro BR 61,617,590 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Development Srl
\n
Rome IT 20,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Diamond
\n
Vista Wind Project LLC
\n
Wilmington US 1 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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Egypt SAE Cairo EG 250,000 EGP
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power El Salvador
\n
SA de Cv
\n
El Salvador SV 22,860 USD
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.04%
\n
99.99%
\n
Enel Green Power
\n
SpA
\n
99.96%
\n
Enel Green Power Elkwater
\n
Wind Limited Partnership
\n
Alberta CA 1,000 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 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power Emeroo
\n
Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity EGP Australia (Pty) Ltd 100.00% 50.00%
\n
Enel Green Power Emiliana
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 97,191,530 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 Espa\u00f1a
\n
Solar 1 SLU
\n
Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Enel Green Power Espa\u00f1a
\n
SLU
\n
Madrid ES 11,153 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
SAU
\n
100.00% 70.12%
\n
Enel Green Power Esperan\u00e7a
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 99,418,174 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 Estonian
\n
Solar Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Fazenda
\n
SA
\n
Niter\u00f3i BR 264,141,174 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Fence Post
\n
Solar Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Flat Rocks
\n
One Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity EGP Australia (Pty) Ltd 100.00% 50.00%
\n
Enel Green Power Flat Rocks
\n
One Holding Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power Fontes dos
\n
Ventos 2 SA
\n
Rio de Janeiro BR 183,315,219 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 Fontes dos
\n
Ventos 3 SA
\n
Rio de Janeiro BR 221,001,000 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 Fontes II
\n
Participa\u00e7\u00f5es SA
\n
Rio de Janeiro BR 1,000 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Fontes
\n
Solar SA
\n
Rio de Janeiro BR 1,000 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 Ganado
\n
Solar Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Germany
\n
GmbH
\n
Berlin DE 25,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Girgarre
\n
Holdings (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power Girgarre
\n
Trust
\n
Sydney AU 10 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power Global
\n
Investment BV
\n
Amsterdam NL 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Hadros
\n
Wind Limited Partnership
\n
- CA 1,000 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 1.00%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.00%
\n
Enel Green Power Hellas SA Maroussi GR 40,187,850 EUR
\n
Equity
\n
Hellas Res Holdings
\n
Single Member
\n
Societe Anonyme
\n
100.00% 50.00%
\n
Enel Green Power Hellas
\n
Supply Single Member SA
\n
Maroussi GR 13,357,770 EUR
\n
Equity
\n
Hella Res Societe
\n
Anonyme
\n
100.00% 50.00%
\n
Enel Green Power Hellas
\n
Wind Parks South Evia Single
\n
Member SA
\n
Maroussi GR 140,669,641 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 50.00%
\n
Enel Green Power HF101
\n
GmbH & Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power Hilltopper
\n
Wind LLC (formerly Hilltopper
\n
Wind Power LLC)
\n
Dover US 1 USD
\n
Line-by-line
\n
Hilltopper Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power Holding
\n
Crocodile Creek (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity EGP Australia (Pty) Ltd 100.00% 50.00%
\n
Enel Green Power Horizonte
\n
MP Solar SA
\n
Rio de Janeiro BR 431,566,053 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 INR
\n
Line-by-line
\n
Enel Green Power
\n
Development Srl
\n
100.00% 100.00%
\n
Enel Green Power Italia Srl Rome IT 272,000,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Green Power Ituverava
\n
Norte Solar SA
\n
Rio de Janeiro BR 219,806,646 BRL
\n
Line-by-line
\n
Bondia Energia Ltda 0.08%
\n
82.27%
\n
Enel Brasil SA 99.92%
\n
Enel Green Power Ituverava
\n
Solar SA
\n
Rio de Janeiro BR 227,810,333 BRL
\n
Line-by-line
\n
Bondia Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power Ituverava
\n
Sul Solar SA
\n
Rio de Janeiro BR 408,949,643 BRL
\n
Line-by-line
\n
Bondia Energia Ltda 0.00%
\n
82.27%
\n
Enel Brasil SA 100.00%
\n
Enel Green Power Joana
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 90,259,530 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 Kenya
\n
Limited
\n
Nairobi KE 100,000 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) Ltd
\n
1.00%
\n
Enel Green Power Korea LLC Seoul KR 7,880,000,000 KRW
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Lagoa do
\n
Sol 01 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 02 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 03 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 04 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 05 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 06 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 07 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 08 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 09 SA
\n
Teresina BR 1,000 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 Lagoa do
\n
Sol 10 SA
\n
Rio de Janeiro BR 1,000 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 Lagoa do
\n
Sol 11 SA
\n
Rio de Janeiro BR 1,000 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 Lagoa do
\n
Sol 12 SA
\n
Rio de Janeiro BR 1,000 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 Lagoa do
\n
Sol 13 SA
\n
Rio de Janeiro BR 1,000 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 Lagoa II
\n
Participa\u00e7\u00f5es SA
\n
Rio de Janeiro BR 1,000 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 Lagoa III
\n
Participa\u00e7\u00f5es SA
\n
Rio de Janeiro BR 1,000 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 Lagoa
\n
Participa\u00e7\u00f5es SA (formerly
\n
Enel Green Power Projetos
\n
45 SA)
\n
Rio de Janeiro BR 1,000 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 Solar
\n
Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Mani\u00e7oba
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 90,722,530 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 Matimba
\n
Srl in liquidation
\n
Rome IT 10,000 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Enel Green Power Metehara
\n
Solar Private Limited
\n
Company
\n
- ET 5,600,000 ETB
\n
Line-by-line
\n
Enel Green Power
\n
Solar Metehara SpA
\n
80.00% 80.00%
\n
Enel Green Power M\u00e9xico S
\n
de RL de Cv
\n
Mexico City MX 10,595,218,475 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
66.67%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
33.33%
\n
Enel Green Power MM GmbH
\n
& Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power Modelo I
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 70,842,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Modelo II
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 63,742,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Morocco
\n
S\u00e0rl
\n
Casablanca MA 839,000,000 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 Morro do
\n
Chap\u00e9u I E\u00f3lica SA
\n
Rio de Janeiro BR 248,138,287 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Morro do
\n
Chap\u00e9u II E\u00f3lica SA
\n
Rio de Janeiro BR 206,050,114 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Morro do
\n
Chap\u00e9u Solar 01 SA (formerly
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo III Participa\u00e7\u00f5es SA)
\n
Rio de Janeiro BR 1,000 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 Morro
\n
Norte 02 SA
\n
Rio de Janeiro BR 1,000 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 Morro
\n
Norte 03 SA
\n
Rio de Janeiro BR 1,000 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 Morro
\n
Norte 04 SA
\n
Rio de Janeiro BR 1,000 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 Mour\u00e3o SA Rio de Janeiro BR 25,600,100 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Namibia
\n
(Pty) Ltd
\n
Windhoek NA 10,000 NAD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power North
\n
America 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 North
\n
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 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 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Nova
\n
Olinda 03 SA
\n
Teresina BR 1,000 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 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 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 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 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 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 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 10 SA
\n
Rio de Janeiro BR 1,000 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 11 SA (formerly Enel
\n
Green Power Aroeira 09 SA)
\n
Rio de Janeiro BR 1,000 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 12 SA
\n
Rio de Janeiro BR 1,000 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 13 SA (formerly Enel
\n
Brasil Central SA)
\n
Rio de Janeiro BR 10,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Novo Lapa
\n
01 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
02 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
03 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
04 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
05 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
06 SA
\n
Rio de Janeiro BR 1,000 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Novo Lapa
\n
07 SA
\n
Rio de Janeiro BR 1,000 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 Lapa
\n
08 SA
\n
Rio de Janeiro BR 1,000 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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power
\n
Partecipazioni Speciali Srl
\n
Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Pau Ferro
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 74,124,000 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 Pedra do
\n
Ger\u00f4nimo E\u00f3lica SA
\n
Rio de Janeiro BR 119,319,528 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 PO11
\n
GmbH & Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power PO133
\n
GmbH & Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power PO25
\n
GmbH & Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power Primavera
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 95,674,900 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 Puglia Srl Rome IT 1,000,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Enel Green Power Quorn
\n
Holding (Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity EGP Australia (Pty) Ltd 100.00% 50.00%
\n
Enel Green Power Quorn
\n
Holding Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Green Power RA SAE in
\n
liquidation
\n
Cairo EG 15,000,000 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power
\n
Rattlesnake Creek Wind
\n
Project LLC (formerly
\n
Rattlesnake Creek Wind
\n
Project LLC)
\n
Delaware US 1 USD
\n
Line-by-line
\n
Rattlesnake Creek
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar Project
\n
Holdings II LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar Project
\n
Holdings LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power
\n
Roadrunner Solar Project
\n
II LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings II LLC
\n
100.00% 100.00%
\n
Enel Green Power Rockhaven
\n
Ranchland Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Enel Green Power Roseland
\n
Solar LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
25RoseFarms
\n
Holdings LLC
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power RSA
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000 ZAR
\n
Equity
\n
EGP Matimba NewCo
\n
1 Srl
\n
100.00% 50.00%
\n
Enel Green Power RSA 2 (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 120 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA (Pty) Ltd
\n
100.00% 50.00%
\n
Enel Green Power Rus
\n
Limited Liability Company
\n
Moscow RU 60,500,000 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 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Green Power Salto
\n
Apiac\u00e1s SA (formerly Enel
\n
Green Power Damascena
\n
E\u00f3lica SA)
\n
Rio de Janeiro BR 274,420,832 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Sannio Srl Rome IT 750,000 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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o Cirilo
\n
02 SA
\n
Rio de Janeiro BR 1,000 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 Cirilo
\n
03 SA
\n
Rio de Janeiro BR 1,000 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
Gon\u00e7alo 01 SA (formerly Enel
\n
Green Power Projetos 10)
\n
Teresina BR 81,960,397 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 02 SA (formerly Enel
\n
Green Power Projetos 11)
\n
Teresina BR 82,268,019 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 07 SA (formerly Enel
\n
Green Power Projetos 42 SA)
\n
Teresina BR 114,522,005 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 08 SA (formerly Enel
\n
Green Power Projetos 43 SA)
\n
Teresina BR 109,281,818 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 10 SA (formerly Enel
\n
Green Power Projetos 15)
\n
Teresina BR 82,871,484 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 11 SA (formerly Enel
\n
Green Power Projetos 44 SA)
\n
Teresina BR 114,475,155 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 12 SA (formerly Enel
\n
Green Power Projetos 22 SA)
\n
Teresina BR 108,022,915 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 147,279,288 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 120,057,469 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 122,007,043 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 18 SA (formerly
\n
Enel Green Power Ventos de
\n
Santa \u00c2ngela 13 SA)
\n
Teresina BR 120,981,744 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power S\u00e3o
\n
Gon\u00e7alo 19 SA
\n
Teresina BR 122,467,789 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 21 SA (formerly Enel
\n
Green Power Projetos 16)
\n
Teresina BR 99,994,198 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 22 SA
\n
Teresina BR 99,787,960 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 Enel
\n
Green Power Projetos 12)
\n
Teresina BR 91,324,686 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 Enel
\n
Green Power Projetos 13)
\n
Teresina BR 90,925,258 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 Enel
\n
Green Power Projetos 15)
\n
Teresina BR 98,230,525 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 Enel
\n
Green Power Projetos 19 SA)
\n
Teresina BR 183,602,691 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power S\u00e3o Judas
\n
E\u00f3lica SA
\n
Niter\u00f3i BR 82,674,900 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 Micael
\n
01 SA (formerly Enel Green
\n
Power S\u00e3o Gon\u00e7alo 9 SA)
\n
Teresina BR 1,000 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 Micael
\n
02 SA (formerly Enel Green
\n
Power S\u00e3o Gon\u00e7alo 13)
\n
Teresina BR 1,000 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 Micael
\n
03 SA (formerly Enel Green
\n
Power S\u00e3o Gon\u00e7alo 16 SA)
\n
Teresina BR 1,000 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 Micael
\n
04 SA (formerly Enel Green
\n
Power S\u00e3o Gon\u00e7alo 20 SA)
\n
Teresina BR 1,000 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 Micael
\n
05 SA
\n
Teresina BR 1,000 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 Services
\n
LLC
\n
Wilmington US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Enel Green Power Shu SAE in
\n
liquidation
\n
Cairo EG 15,000,000 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power Singapore
\n
Pte Ltd
\n
Singapore SG 8,000,000 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 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 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 Enel
\n
Green Power Africa Srl)
\n
Rome IT 50,000 EUR
\n
Held for sale
\n
EGP Matimba NewCo
\n
2 Srl
\n
100.00% 100.00%
\n
Enel Green Power South
\n
Africa (Pty) Ltd
\n
Johannesburg ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power South
\n
Africa 3 (Pty) Ltd
\n
Gauteng ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Stampede
\n
Solar Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Swift
\n
Wind LP
\n
Calgary CA 1,000 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Enel Green Power Tacaic\u00f3
\n
E\u00f3lica SA
\n
Rio de Janeiro BR 50,034,360 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 Tefnut SAE
\n
in liquidation
\n
Cairo EG 15,000,000 EGP
\n
Line-by-line
\n
Enel Green Power
\n
Egypt SAE
\n
100.00% 100.00%
\n
Enel Green Power Turkey
\n
Enerj\u00ed Yatirimlari Anon\u00edm
\n
\u015e\u00edrket\u00ed
\n
Istanbul TR 37,141,108 TRY
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power UB33
\n
GmbH & Co. KG
\n
Berlin DE 75,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power UB43
\n
GmbH & Co. KG
\n
Berlin DE 50,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power Ventos de
\n
Santa \u00c2ngela 1 SA
\n
Teresina BR 182,273,006 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 Ventos
\n
de Santa \u00c2ngela 10 SA
\n
(formerly Enel Green Power
\n
Projetos 21)
\n
Teresina BR 122,100,849 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 Ventos
\n
de Santa \u00c2ngela 11 SA
\n
(formerly Enel Green Power
\n
Projetos 23)
\n
Teresina BR 132,786,606 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 Ventos
\n
de Santa \u00c2ngela 14 SA
\n
(formerly Enel Green Power
\n
Projetos 24)
\n
Teresina BR 198,554,956 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 Ventos
\n
de Santa \u00c2ngela 15 SA
\n
(formerly Enel Green Power
\n
Projetos 25)
\n
Teresina BR 125,100,849 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 Ventos de
\n
Santa \u00c2ngela 17 SA (formerly
\n
Enel Green Power Projetos
\n
26)
\n
Teresina BR 152,022,288 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 Ventos
\n
de Santa \u00c2ngela 19 SA
\n
(formerly Enel Green Power
\n
Projetos 27)
\n
Teresina BR 95,587,248 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 Ventos de
\n
Santa \u00c2ngela 2 SA
\n
Teresina BR 299,922,006 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 Ventos
\n
de Santa \u00c2ngela 20 SA
\n
(formerly Enel Green Power
\n
Projetos 28)
\n
Teresina BR 92,895,409 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 Ventos
\n
de Santa \u00c2ngela 21 SA
\n
(formerly Enel Green Power
\n
Projetos 29)
\n
Teresina BR 85,179,410 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 Ventos de
\n
Santa \u00c2ngela 3 SA (formerly
\n
Enel Green Power Projetos 4)
\n
Teresina BR 99,786,606 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 Ventos de
\n
Santa \u00c2ngela 4 SA (formerly
\n
Enel Green Power Projetos 6)
\n
Teresina BR 100,732,205 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Ventos de
\n
Santa \u00c2ngela 5 SA (formerly
\n
Enel Green Power Projetos 7)
\n
Teresina BR 84,786,606 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 Ventos de
\n
Santa \u00c2ngela 6 SA (formerly
\n
Enel Green Power Projetos 8)
\n
Teresina BR 83,786,606 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 Ventos de
\n
Santa \u00c2ngela 7 SA (formerly
\n
Enel Green Power Projetos 9)
\n
Teresina BR 81,245,806 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 Ventos de
\n
Santa \u00c2ngela 8 SA (formerly
\n
Enel Green Power Projetos
\n
18)
\n
Teresina BR 91,786,606 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 Ventos de
\n
Santa \u00c2ngela 9 SA (formerly
\n
Enel Green Power Projetos
\n
20)
\n
Teresina BR 118,786,606 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 Ventos
\n
de Santa \u00c2ngela ACL 12
\n
(formerly Enel Green Power
\n
Projetos 36)
\n
Teresina BR 94,727,364 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 Ventos
\n
de Santa \u00c2ngela ACL 13 SA
\n
(formerly Enel Green Power
\n
Projetos 17 SA)
\n
Teresina BR 77,496,725 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 Ventos
\n
de Santa \u00c2ngela ACL 16 SA
\n
(formerly Enel Green Power
\n
Projetos 38 SA)
\n
Teresina BR 89,917,563 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 Ventos
\n
de Santa \u00c2ngela ACL 18 SA
\n
(formerly Enel Green Power
\n
Projetos 47 SA)
\n
Teresina BR 86,496,703 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 Ventos
\n
de Santa Esperan\u00e7a 08 SA
\n
(formerly Enel Green Power
\n
Projetos 34 SA)
\n
Rio de Janeiro BR 173,154,501 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 Ventos
\n
de Santa Esperan\u00e7a 1 SA
\n
(formerly Enel Green Power
\n
Fonte dos Ventos 1 SA)
\n
Rio de Janeiro BR 1,000 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 Ventos de
\n
Santa Esperan\u00e7a 13 (formerly
\n
Enel Green Power Projetos
\n
33 SA)
\n
Rio de Janeiro BR 221,832,010 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 Ventos de
\n
Santa Esperan\u00e7a 15 SA
\n
Rio de Janeiro BR 152,494,014 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 Ventos
\n
de Santa Esperan\u00e7a 16 SA
\n
(formerly Enel Green Power
\n
Projetos 35 SA)
\n
Rio de Janeiro BR 252,240,013 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 Ventos
\n
de Santa Esperan\u00e7a 17 SA
\n
(formerly Enel Green Power
\n
Projetos 31 SA)
\n
Rio de Janeiro BR 252,240,013 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 Ventos
\n
de Santa Esperan\u00e7a 21 SA
\n
(formerly Enel Green Power
\n
Projetos 37 SA)
\n
Rio de Janeiro BR 225,898,777 BRL
\n
Line-by-line
\n
Enel Brasil SA 98.67%
\n
81.18%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.00%
\n
Enel Green Power Ventos
\n
de Santa Esperan\u00e7a 22 SA
\n
(formerly Enel Green Power
\n
Projetos 39 SA)
\n
Rio de Janeiro BR 124,625,154 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Ventos
\n
de Santa Esperan\u00e7a 25 SA
\n
(formerly Enel Green Power
\n
Projetos 40 SA)
\n
Rio de Janeiro BR 171,324,008 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 Ventos
\n
de Santa Esperan\u00e7a 26 SA
\n
(formerly Enel Green Power
\n
Projetos 41 SA)
\n
Rio de Janeiro BR 344,251,126 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 Ventos de
\n
Santa Esperan\u00e7a 3 SA
\n
Rio de Janeiro BR 1,000 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 Ventos
\n
de Santa Esperan\u00e7a 7 SA
\n
(formerly Enel Green Power
\n
Lagedo Alto SA)
\n
Rio de Janeiro BR 1,000 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 Ventos
\n
de Santa Esperan\u00e7a
\n
Participa\u00e7\u00f5es SA (formerly
\n
Enel Green Power Cumaru
\n
06 SA)
\n
Rio de Janeiro BR 1,000 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 Ventos de
\n
Santo Orestes 1 SA
\n
Rio de Janeiro BR 1,000 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 Ventos de
\n
Santo Orestes 2 SA
\n
Rio de Janeiro BR 1,000 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 Ventos de
\n
S\u00e3o Roque 01 SA
\n
Teresina BR 383,436,551 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 Ventos de
\n
S\u00e3o Roque 02 SA
\n
Teresina BR 369,758,651 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 Ventos de
\n
S\u00e3o Roque 03 SA
\n
Teresina BR 262,576,701 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 Ventos de
\n
S\u00e3o Roque 04 SA
\n
Teresina BR 379,980,531 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 Ventos de
\n
S\u00e3o Roque 05 SA
\n
Teresina BR 362,501,000 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 Ventos de
\n
S\u00e3o Roque 06 SA
\n
Teresina BR 262,501,000 BRL
\n
Line-by-line
\n
Enel Brasil SA 99.96%
\n
82.27%
\n
Enel Green Power
\n
Desenvolvimento
\n
Ltda
\n
0.04%
\n
Enel Green Power Ventos de
\n
S\u00e3o Roque 07 SA
\n
Teresina BR 262,501,000 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 Ventos de
\n
S\u00e3o Roque 08 SA
\n
Teresina BR 337,473,758 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 Ventos de
\n
S\u00e3o Roque 11 SA
\n
Teresina BR 318,740,451 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 Ventos de
\n
S\u00e3o Roque 13 SA
\n
Teresina BR 262,501,000 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 Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Green Power Ventos de
\n
S\u00e3o Roque 16 SA
\n
Teresina BR 353,284,551 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 Ventos de
\n
S\u00e3o Roque 17 SA
\n
Teresina BR 298,952,101 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 Ventos de
\n
S\u00e3o Roque 18 SA
\n
Teresina BR 332,473,759 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 Ventos de
\n
S\u00e3o Roque 19 SA
\n
Teresina BR 262,501,000 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 Ventos de
\n
S\u00e3o Roque 22 SA
\n
Teresina BR 262,501,000 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 Ventos de
\n
S\u00e3o Roque 26 SA
\n
Teresina BR 262,501,000 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 Ventos de
\n
S\u00e3o Roque 29 SA
\n
Teresina BR 262,501,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Germany GmbH
\n
100.00% 100.00%
\n
Enel Green Power Vietnam
\n
LLC (C\u00f4ng ty TNHH Enel
\n
Green Power Vi\u1ec7t Nam)
\n
Ho Chi Minh City VN 2,431,933 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Enel Green Power Villoresi Srl Rome IT 1,200,000 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 Enel
\n
Green Power Projetos 1 SA)
\n
Niter\u00f3i BR 565,756,528 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Zambia
\n
Limited
\n
Lusaka ZM 15,000 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) Ltd
\n
99.00%
\n
Enel Green Power Zeus II -
\n
Delfina 8 SA
\n
Rio de Janeiro BR 77,939,980 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Green Power Zeus Sul
\n
1 Ltda
\n
Rio de Janeiro BR 6,986,993 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 Grids Srl Rome IT 10,100,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Guatemala SA Guatemala City GT 67,208,000 GTQ
\n
Line-by-line
\n
Enel Am\u00e9ricas SA 0.00%
\n
47. 1 8 %
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
Enel Holding Finance Srl Rome IT 10,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Iberia SRLU Madrid ES 336,142,500 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Innovation Hubs Srl Rome IT 1,100,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Insurance NV Amsterdam NL 60,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Investment Holding BV Amsterdam NL 1,000,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Italia SpA Rome IT 100,000,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Kansas Development
\n
Holdings 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 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Minnesota Holdings LLC Minneapolis US - USD
\n
Line-by-line
\n
EGP Geronimo
\n
Holding Company
\n
Inc.
\n
100.00% 100.00%
\n
Enel Mobility Chile SpA Santiago de Chile CL 504,094,780 CLP
\n
Line-by-line Enel Chile SA 100.00% 64.93%
\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 USD
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel Operations Canada Ltd Alberta CA 1,000 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 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 SOL
\n
Line-by-line Enel Am\u00e9ricas SA 100.00% 82.27%
\n
Enel Produzione SpA Rome IT 1,800,000,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel QPSF (Pty) Ltd Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Australia Trust
\n
100.00% 50.00%
\n
Enel Renovable Srl Panama City PA 40,320 USD
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
0.79%
\n
47. 19%
\n
Enel Panam\u00e1 CAM Srl 99.21%
\n
Enel Rinnovabile SA de Cv Mexico City MX 12,645,490,022 MXN
\n
Line-by-line
\n
Enel Green Power
\n
Global Investment BV
\n
100.00%
\n
100.00%
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.00%
\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 USD
\n
Line-by-line
\n
Enel Green Power
\n
Roadrunner Solar
\n
Project Holdings LLC
\n
100.00% 100.00%
\n
Enel Salt Wells LLC Fallon US - USD
\n
Held for sale Enel Geothermal LLC 100.00% 100.00%
\n
Enel Services M\u00e9xico SA
\n
de Cv
\n
Mexico City MX 6,339,849 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
46.27%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
53.73%
\n
Enel Guatemala SA 0.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Enel Sole Srl Rome IT 4,600,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel Solu\u00e7\u00f5es Energ\u00e9ticas
\n
Ltda
\n
Rio de Janeiro BR 42,863,000 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 Stillwater LLC Wilmington US - USD
\n
Held for sale Enel Geothermal LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel Surprise Valley LLC Wilmington US - USD
\n
Held for sale Enel Kansas LLC 100.00% 100.00%
\n
Enel Texkan Inc. Wilmington US 100 USD
\n
Line-by-line Chi Power Inc. 100.00% 100.00%
\n
Enel Trading Argentina Srl Buenos Aires AR 14,012,000 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 54,280,312 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Trading North America
\n
LLC
\n
Wilmington US 10,000,000 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel Uruguay SA Montevideo UY 20,000 UYU
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel Vayu (Project 2) Private
\n
Limited
\n
Gurugram IN 45,000,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Enel Wind Project (Amberi)
\n
Private Limited
\n
New Delhi IN 5,000,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Enel X Advisory Services
\n
Germany GmbH
\n
Frankfurt DE 50,000 EUR
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory Services
\n
Japan GK
\n
Tokyo JP 100,000,000 JPY
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory Services
\n
North America 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 Services Srl Rome IT - EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Advisory Services UK
\n
Limited
\n
London GB 30,000 GBP
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Advisory Services
\n
USA LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X Advisory
\n
Services North
\n
America Inc.
\n
100.00% 100.00%
\n
Enel X Arecibo LLC Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel X Argentina SAU Buenos Aires AR 127,800,000 ARS
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Asputeck Ave. 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 Australia Holding
\n
(Pty) Ltd
\n
Melbourne AU 45,424,578 AUD
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Australia (Pty) Ltd Melbourne AU 24,209,880 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 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 Beech Road Project
\n
LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Brasil Gerenciamento
\n
de Energia Ltda
\n
Sorocaba BR 5,538,403 BRL
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Enel X Brasil SA S\u00e3o Paulo BR 766,725,892 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enel X Canada Holding Inc. Oakville CA 1,000 CAD
\n
Line-by-line Enel X Canada Ltd 100.00% 100.00%
\n
Enel X Canada Ltd Mississauga CA 1,000 CAD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Chile SpA Santiago de Chile CL 2,837,737,149 CLP
\n
Line-by-line Enel Chile SA 100.00% 64.93%
\n
Enel X College Ave. Project
\n
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 ESP Bogot\u00e1 CO 230,368,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Cosgray Road Project
\n
LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Demand Response SA S\u00e3o Paulo BR 2,000,000 BRL
\n
Line-by-line Enel X Brasil SA 100.00% 82.27%
\n
Enel X Demand Response
\n
LLC
\n
Boston US 100 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Federal LLC Boston US 5,000 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Finance Partner LLC Boston US 100 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Germany GmbH Berlin DE 25,000 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 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 EUR
\n
Line-by-line Enel X Srl 100.00% 100.00%
\n
Enel X Ireland Limited Dublin IE 10,841 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 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Enel X Japan KK Tokyo JP 1,030,000,000 JPY
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X KOMIPO Solar Limited Seoul KR 11,054,000,000 KRW
\n
Line-by-line Enel X Korea Limited 80.00% 80.00%
\n
Enel X Korea Limited Seoul KR 11,800,000,000 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 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio 1 LLC Boston US - USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X MA PV Portfolio 2 LLC 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 3 LLC Boston US - USD
\n
Line-by-line
\n
Enel X Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enel X M\u00e9xico S de RL de Cv Mexico City MX 264,303,595 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.00%
\n
100.00%
\n
Enel X International
\n
Srl
\n
100.00%
\n
Enel X Mobilidade Urbana SA S\u00e3o Paulo BR 163,642,000 BRL
\n
Line-by-line Enel X Brasil SA 100.00% 82.27%
\n
Enel X Morrissey Blvd. Project
\n
LLC
\n
Boston US 100 USD
\n
Line-by-line
\n
Enel X MA Holdings
\n
LLC
\n
100.00% 100.00%
\n
Enel X New Zealand Limited Wellington NZ 313,606 AUD
\n
Line-by-line
\n
Energy Response
\n
Holdings (Pty) Ltd
\n
100.00% 100.00%
\n
Enel X Newton Court Project
\n
LLC
\n
Boston US 10,000 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X North America Inc. Boston US 1,000 USD
\n
Line-by-line
\n
Enel North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Per\u00fa SAC San Miguel PE 1,020,815 SOL
\n
Held for sale Enel Per\u00fa SAC 100.00% 82.27%
\n
Enel X Polska Sp. Zo.o. Warsaw PL 12,275,150 PLN
\n
Line-by-line Enel X Ireland Limited 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 Holdings
\n
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 Sponsor
\n
LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Enel X Rus LLC Moscow RU 8,000,000 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 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Services India Private
\n
Limited
\n
Mumbai IN 1,497,290 INR
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00%
\n
100.00%
\n
Enel X North America
\n
Inc.
\n
0.00%
\n
Enel X Storage LLC Boston US 100 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enel X Taiwan Co. Ltd Taipei TW 271,100,000 TWD
\n
Line-by-line Enel X Ireland Limited 100.00% 100.00%
\n
Enel X UK Limited London GB 32,626 GBP
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Enel X Warner Road Project
\n
LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel X Finance
\n
Partner LLC
\n
100.00% 100.00%
\n
Enel X Way (Shanghai) Co. Ltd Shanghai CN 10,500,000 CNY
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Brasil SA Rio de Janeiro BR 20,045,337 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 Holding
\n
Ltd
\n
Vancouver CA - CAD
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Chile SpA Santiago de Chile CL 14,229,030,071 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 Colombia SAS Bogot\u00e1 CO 15,036,000,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
40.00%
\n
78.87%
\n
Enel X Way Srl 60.00%
\n
Enel X Way France SAS Paris FR 6,101,000 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Germany GmbH Berlin DE 25,000 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way Italia Srl Rome IT 5,000,000 EUR
\n
Line-by-line Enel X Way Srl 100.00% 100.00%
\n
Enel X Way M\u00e9xico SA de Cv Mexico City MX 6,479,171 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.00%
\n
100.00%
\n
Enel X Way Srl 100.00%
\n
Enel X Way North America
\n
Inc.
\n
San Carlos US - 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 SOL
\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 Srl Rome IT 6,026,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Enel X Way UK Limited London GB 1 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 LLC 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 Project MP
\n
Holdings LLC
\n
100.00% 100.00%
\n
Enelpower Contractor and
\n
Development Saudi Arabia
\n
Ltd
\n
Riyadh SA 5,000,000 SAR
\n
Line-by-line Enelpower Srl 51.00% 51.00%
\n
Enelpower do Brasil Ltda Rio de Janeiro BR 5,689,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Enelpower Srl Milan IT 2,000,000 EUR
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Energ\u00e9tica Monz\u00f3n SAC San Miguel PE 118,321,846 SOL
\n
Held for sale
\n
Enel Generaci\u00f3n
\n
Per\u00fa SAA
\n
100.00%
\n
71.54%
\n
Enel Per\u00fa SAC 0.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Energ\u00eda Base Natural SLU Madrid ES 3,000 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 EUR
\n
Line-by-line Endesa Energ\u00eda SAU 100.00% 70.12%
\n
Energ\u00eda E\u00f3lica \u00c1brego SLU Madrid ES 3,576 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Galerna SLU Madrid ES 3,413 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda E\u00f3lica Gregal SLU Madrid ES 3,250 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda Global de M\u00e9xico
\n
(Enermex) SA de Cv
\n
Mexico City MX 50,000 MXN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
99.00% 99.00%
\n
Energ\u00eda Limpia de Amistad
\n
SA de Cv
\n
Mexico City MX 33,452,769 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de Palo Alto
\n
SA de Cv
\n
Mexico City MX 673,583,489 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Energ\u00eda Limpia de Puerto
\n
Libertad S de RL de Cv
\n
Mexico City MX 2,953,980 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.01%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.99%
\n
Energ\u00eda Marina SpA Santiago de Chile CL 2,404,240,000 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 Mallorca ES 9,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00eda XXI Comercializadora
\n
de Referencia SLU
\n
Madrid ES 2,000,000 EUR
\n
Line-by-line Endesa Energ\u00eda SAU 100.00% 70.12%
\n
Energ\u00eda y Naturaleza SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Energ\u00edas Alternativas del
\n
Sur SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 546,919 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
54.95% 38.53%
\n
Energ\u00eda de Arag\u00f3n I SLU Zaragoza ES 3,200,000 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Energ\u00eda de Graus SL Zaragoza ES 1,298,160 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.74%
\n
Energ\u00edas Especiales de
\n
Care\u00f3n SA
\n
Santiago de
\n
Compostela
\n
ES 270,450 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
97.00% 68.01%
\n
Energ\u00edas Especiales del Alto
\n
Ulla SAU
\n
Madrid ES 9,210,840 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 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 EUR
\n
Equity
\n
Enviatos Promoci\u00f3n
\n
I SLU
\n
6.25%
\n
13.15%
\n
Enviatos Promoci\u00f3n
\n
II SLU
\n
6.25%
\n
Enviatos Promoci\u00f3n
\n
III SLU
\n
6.25%
\n
Energ\u00edas Renovables La Mata
\n
SA de Cv
\n
Mexico City MX 3,011,133,575 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
99.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.50%
\n
Energie Electrique de
\n
Tahaddart SA
\n
Tangiers MA 306,160,000 MAD Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
32.00% 22.44%
\n
Energotel AS Bratislava SK 2,191,200 EUR
\n
-
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
20.00% 6.60%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Energy Podium Private
\n
Company
\n
Katerini Pieria GR 4,001 EUR
\n
-
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.02% 0.01%
\n
Energy Response Holdings
\n
(Pty) Ltd
\n
Melbourne AU 52,128,517 AUD
\n
Line-by-line
\n
Enel X Australia
\n
Holding (Pty) Ltd
\n
100.00% 100.00%
\n
EnergyQ1BESS Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
EnerNOC GmbH Munich DE 25,000 EUR
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
EnerNOC Ireland Limited Dublin IE 10,589 EUR
\n
Line-by-line Enel X Ireland Limited 100.00% 100.00%
\n
EnerNOC UK II Limited London GB 21,000 GBP
\n
Line-by-line Enel X UK Limited 100.00% 100.00%
\n
Enigma Green Power 1 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Entech Utility Service Bureau
\n
Inc.
\n
Lutherville US 1,500 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Enviatos Promoci\u00f3n I SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Enviatos Promoci\u00f3n II SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Enviatos Promoci\u00f3n III SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Enviatos Promoci\u00f3n XX SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Eojin Wind Power Co. Ltd Seoul KR 301,000,000 KRW
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
E\u00f3lica Valle del Ebro SA Zaragoza ES 3,561,343 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.50% 35.41%
\n
E\u00f3lica Zopiloapan SA de Cv Mexico City MX 1,877,201,544 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
56.98%
\n
100.00%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
43.02%
\n
E\u00f3licas de Agaete SL
\n
Las Palmas de
\n
Gran Canaria
\n
ES 240,400 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
E\u00f3licas de Fuencaliente SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 216,360 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
55.00% 38.56%
\n
E\u00f3licas de Fuerteventura AIE
\n
Puerto del
\n
Rosario
\n
ES 4,558,427 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
E\u00f3licas de la Patagonia SA Buenos Aires AR 480,930 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 1,758,226 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 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Epresa Energ\u00eda SA Puerto Real ES 2,500,000 EUR
\n
Equity Endesa SA 50.00% 35.06%
\n
Ermis 2 Energeiaki Private
\n
Company
\n
Grevena GR 1,002 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas SA
\n
0.10% 0.05%
\n
E-Solar 2 Srl Rome IT 2,500 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
E-Solar Srl Rome IT 2,500 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 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
Estonian Solar PPA LLC Andover US 1 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
European Energy Exchange
\n
AG
\n
Leipzig DE 40,050,000 EUR
\n
-
\n
Enel Global Trading
\n
SpA
\n
2.38% 2.38%
\n
EV Gravitational Energy
\n
Storage LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Evacuaci\u00f3n Carmona 400-
\n
220 kV Renovables SL
\n
Seville ES 10,003 EUR
\n
Equity
\n
Enviatos Promoci\u00f3n
\n
I SLU
\n
3.13%
\n
6.58%
\n
Enviatos Promoci\u00f3n
\n
II SLU
\n
3.13%
\n
Enviatos Promoci\u00f3n
\n
III SLU
\n
3.13%
\n
Evolution Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ewiva Srl Milan IT 1,000,000 EUR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Expedition Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explorer Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Explotaciones E\u00f3licas de
\n
Escucha SA
\n
Zaragoza ES 3,505,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
70.00% 49.08%
\n
Explotaciones E\u00f3licas el
\n
Puerto SA
\n
Zaragoza ES 3,230,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
73.60% 51.61%
\n
Explotaciones E\u00f3licas Santo
\n
Domingo de Luna SA
\n
Zaragoza ES 100,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Explotaciones E\u00f3licas Saso
\n
Plano SA
\n
Zaragoza ES 5,488,500 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
65.00% 45.58%
\n
Explotaciones E\u00f3licas Sierra
\n
Costanera SA
\n
Zaragoza ES 8,046,800 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.10%
\n
Explotaciones E\u00f3licas Sierra
\n
la Virgen SA
\n
Zaragoza ES 4,200,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.10%
\n
Falls Park Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Farrier Station Energy
\n
Storage Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Fayette Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fazenda Aroeira
\n
Empreendimento de Energia
\n
Ltda
\n
Rio de Janeiro BR 2,362,046 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fence Post Solar Holdings
\n
LLC
\n
Andover US 1 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 Project LLC Andover US - USD
\n
Line-by-line
\n
Fence Post Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Fenner Wind Holdings LLC Dover US 100 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Field Day Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Finocchiara Solar Srl Rome IT 10,000 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 ILS
\n
Held for sale Enel X Srl 30.00% 30.00%
\n
Flagpay Srl Milan IT 10,000 EUR
\n
Equity Mooney SpA 100.00% 50.00%
\n
Flat Rock Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Flat Rocks Girgarre Cohuna
\n
Finco (Pty) Ltd
\n
Sydney AU 120 AUD
\n
Equity
\n
Cohuna Solar Farm
\n
Trust
\n
33.33%
\n
50.00%
\n
Flat Rocks One Wind
\n
Farm Trust
\n
33.33%
\n
Girgarre Solar Farm
\n
Trust
\n
33.33%
\n
Flat Rocks One Wind Farm
\n
(Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding (Pty) Ltd
\n
100.00% 50.00%
\n
Flat Rocks One Wind Farm
\n
Trust
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Flat Rocks One
\n
Holding Trust
\n
100.00% 50.00%
\n
Flat Top Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Flint Rock Solar Project LLC 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Flowing Spring Farms LLC Andover US 1 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 434,359,750 COP
\n
Equity Bogot\u00e1 ZE SAS 100.00% 9.44%
\n
F\u00f3tons de Santo Anchieta
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 577,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Fotovoltaica Yunclillos SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Fourmile Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Fox Run Energy Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Franklintown Farm LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Freedom Energy Storage LLC Andover US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Front Mar\u00edtim del Bes\u00f2s SL Barcelona ES 9,000 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
61.37% 43.03%
\n
Frontiersman Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
FRV Corchitos I SLU Madrid ES 75,800 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Corchitos II Solar SLU Madrid ES 22,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Gibalb\u00edn - Jerez SLU Madrid ES 23,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
FRV Tarifa SLU Madrid ES 3,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 1 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
FRV Zamora Solar 3 SLU Madrid ES 3,000 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 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Fundamental Recognized
\n
Systems SLU
\n
Andorra ES 3,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Ganado Solar Holdings LLC Andover US 1 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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Garob Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 100 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 Mallorca ES 213,775,700 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 LLC 100.00% 50.00%
\n
Gauley River Management
\n
LLC
\n
Willison US 1 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Generadora de Occidente SA Guatemala City GT 16,262,000 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
99.00%
\n
47. 1 8 %
\n
Enel Guatemala SA 1.00%
\n
Generadora Montecristo SA Guatemala City GT 3,820,000 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47. 1 8 %
\n
Enel Guatemala SA 0.00%
\n
Generadora Solar Austral SA Panama City PA 10,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 100.00% 47. 19 %
\n
Generadora Solar de
\n
Occidente SA
\n
Panama City PA 10,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 100.00% 47. 19 %
\n
Generadora Solar El Puerto
\n
SA
\n
Panama City PA 10,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 100.00% 47. 19 %
\n
Geot\u00e9rmica del Norte SA Santiago de Chile CL 326,577,419,702 CLP
\n
Line-by-line
\n
Enel Green Power
\n
Chile SA
\n
84.59% 54.92%
\n
Gibson Bay Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
60.00% 60.00%
\n
Girgarre Solar Farm (Pty) Ltd Sydney AU - AUD
\n
Equity
\n
Enel Green Power
\n
Girgarre Holdings
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Girgarre Solar Farm Trust Sydney AU 10 AUD
\n
Equity
\n
Enel Green Power
\n
Girgarre Trust
\n
100.00% 50.00%
\n
Glass Top Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Global Commodities
\n
Holdings Limited
\n
London GB 4,042,375 GBP
\n
-
\n
Enel Global Trading
\n
SpA
\n
4.68% 4.68%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Globyte SA San Jos\u00e9 CR 910,000 CRC
\n
-
\n
Enel Costa Rica
\n
CAM SA
\n
10.00% 4.72%
\n
Gloucester Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
GNL Chile SA Santiago de Chile CL 3,026,160 USD
\n
Equity
\n
Enel Generaci\u00f3n
\n
Chile SA
\n
33.33% 20.25%
\n
Golden Terrace Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Goodwell Wind Project LLC Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Goose Foot Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gooseneck Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gorona del Viento El Hierro
\n
SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 30,936,736 EUR
\n
Equity
\n
Uni\u00f3n El\u00e9ctrica de
\n
Canarias Generaci\u00f3n
\n
SAU
\n
23.21% 16.28%
\n
Grand Prairie Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Gridspertise Iberia SL Madrid ES 3,000 EUR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise India Private
\n
Limited
\n
Gurugram IN 19,759,130 INR
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Gridspertise Latam SA S\u00e3o Paulo BR 2,010,000 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 EUR
\n
Equity Enel Grids Srl 50.00% 50.00%
\n
Gridspertise LLC Dover US 160,000 USD
\n
Equity Gridspertise Srl 100.00% 50.00%
\n
Grineo Gesti\u00f3n Circular SL Ponferrada ES 3,000 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
35.00% 24.54%
\n
GRPP Holdings LLC Andover US 2 USD
\n
Equity
\n
EGPNA REP Holdings
\n
LLC
\n
50.00% 50.00%
\n
Guadarranque Solar 4 SLU Seville ES 3,006 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 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
Guir Wind Farm Casablanca MA 10,000 MAD
\n
Line-by-line
\n
Enel Green Power
\n
Morocco S\u00e0rl
\n
99.90% 99.90%
\n
GulfStar Power LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Gusty Hill Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Hadley Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Hamilton County Solar
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Hamlet Mill Storage Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hansborough Valley Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Harmony Plains Solar I LLC Andover US 1 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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Hellas Res Holdings Single
\n
Member Societe Anonyme
\n
Maroussi GR 478,746,698 EUR
\n
Equity
\n
Hella Res Societe
\n
Anonyme
\n
100.00% 50.00%
\n
Hella Res Societe Anonyme Maroussi GR 491,738,436 EUR
\n
Equity
\n
Enel Green Power
\n
SpA
\n
50.00% 50.00%
\n
Hidroel\u00e9ctrica de Catalunya
\n
SLU
\n
Barcelona ES 126,210 EUR
\n
Line-by-line Endesa SA 100.00% 70.12%
\n
Hidroel\u00e9ctrica de Ourol SL A Coru\u00f1a ES 1,608,200 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.03%
\n
Hidroelectricidad del Pac\u00edfico
\n
S de RL de Cv
\n
Colima MX 100,000,000,000 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
99.99% 99.99%
\n
Hidroflamicell SL Barcelona ES 78,120 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 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 Santiago de Chile CL 6,303,000 USD
\n
Equity
\n
Enel Green Power
\n
Chile SA
\n
50.00% 32.46%
\n
High Chaparral Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Storage LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind
\n
Holdings LLC
\n
Wilmington US 100 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Lonesome Wind Power
\n
LLC
\n
Boston US 100 USD
\n
Line-by-line
\n
High Lonesome Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
High Noon Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
High Street Corporation
\n
(Pty) Ltd
\n
Melbourne AU 2 AUD
\n
Equity
\n
Enel Green Power
\n
Australia (Pty) Ltd
\n
100.00% 50.00%
\n
Hilltopper Wind Holdings LLC Wilmington US 1,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Honey Stone Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Honeybee Solar Project LLC 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Hope Ridge Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Horse Run Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Horse Wrangler Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Hubject GmbH Berlin DE 65,943 EUR
\n
- Enel X Way Srl 12.50% 12.50%
\n
Ice Tudela SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.12% 3.59%
\n
Idalia Park Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Idrosicilia SpA Milan IT 22,520,000 EUR
\n
Equity Enel SpA 1.00% 1.00%
\n
IIK Energ\u00eda de Dzemul SA
\n
de Cv
\n
Mexico City MX 6,204,259 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
Ilary Energia Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Impofu Cluster Investment
\n
SPV (RF) (Pty) Ltd
\n
Gauteng ZA 2,000,000 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA (Pty) Ltd
\n
100.00% 50.00%
\n
Infinitesun Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
96.74%
\n
100.00%
\n
Enel Green Power
\n
SpA
\n
3.26%
\n
Infraestructura de
\n
Evacuaci\u00f3n Pe\u00f1aflor 220
\n
kV SL
\n
Madrid ES 3,500 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
41.14% 28.85%
\n
Infraestructuras Puerto Santa
\n
Mar\u00eda 220 SL
\n
Madrid ES 3,000 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 Serv\u00e1n
\n
220 SL
\n
Madrid ES 12,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.80% 21.60%
\n
Infraestructuras San Serv\u00e1n
\n
Set 400 SL
\n
Madrid ES 90,000 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
6.41%
\n
13.48%
\n
Baylio Solar SLU 6.41%
\n
Furatena Solar 1 SLU 6.41%
\n
Ingwe Solar Power Plant (RF)
\n
(Pty) Ltd
\n
Gauteng ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Inkolan Informaci\u00f3n y
\n
Coordinaci\u00f3n de Obras AIE
\n
Bilbao ES 84,142 EUR
\n
-
\n
Edistribuci\u00f3n Redes
\n
Digitales SLU
\n
14.29% 10.02%
\n
Instalaciones San Serv\u00e1n II
\n
400 SL
\n
Madrid ES 11,026 EUR
\n
Equity
\n
Aranort Desarrollos
\n
SLU
\n
7.94%
\n
16.69%
\n
Baylio Solar SLU 7.94%
\n
Furatena Solar 1 SLU 7.94%
\n
International Multimedia
\n
University Srl in bankruptcy
\n
- IT 24,000 EUR
\n
- Enel Italia SpA 13.04% 13.04%
\n
Ipsomata DPGU Private
\n
Company
\n
Heraklion, Crete GR 5,000 EUR
\n
-
\n
Enel Green Power
\n
Hellas SA
\n
0.02% 0.02%
\n
Iris Bloom Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Belt Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Iron Bull Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Isamu Ikeda Energia SA Niter\u00f3i BR 16,474,476 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Italgest Energy (Pty) Ltd Johannesburg ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Jack River LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Jackrabbit Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Jade Energia Ltda Rio de Janeiro BR 4,107,097 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Jaguito Solar 10 MW SA Panama City PA 10,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 100.00% 47. 19 %
\n
Jessica Mills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Julia Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Junia Insurance Srl
\n
Mosciano
\n
Sant\u2019Angelo
\n
IT 10,000 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Juniper Canyon Energy
\n
Storage Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Keeneys Creek Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ken Renewables India Private
\n
Limited
\n
Gurugram IN 12,100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
King Branch Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Kingston Energy Storage LLC Wilmington US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Kino Contractor SA de Cv Mexico City MX 1,000,100 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
100.00%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
0.00%
\n
Knickerbocker Energy
\n
Storage Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Kokkinari DPGU Private
\n
Company
\n
Heraklion, Crete GR 15,000 EUR
\n
-
\n
Enel Green Power
\n
Hellas SA
\n
0.01% 0.01%
\n
Korea Line Corporation Seoul KR 122,132,520,000 KRW
\n
-
\n
Enel Global Trading
\n
SpA
\n
0.25% 0.25%
\n
Koukos Energy Private
\n
Company
\n
Athens GR 4,003 EUR
\n
-
\n
Enel Green Power
\n
Hellas SA
\n
0.07%
\n
0.01%
\n
Enel Green Power
\n
Hellas Supply Single
\n
Member SA
\n
0.02%
\n
Kromschroeder SA
\n
L\u2019Hospitalet de
\n
Llobregat
\n
ES 627,126 EUR
\n
Equity
\n
Endesa Medios y
\n
Sistemas SLU
\n
29.26% 20.52%
\n
Kutlwano Solar Power Plant
\n
(RF) (Pty) Ltd
\n
Gauteng ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\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 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Land Run Wind Project LLC Dover US 100 USD
\n
Line-by-line
\n
Sundance Wind
\n
Project LLC
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Lantana Springs Hydrogen
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lantern Trail Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lariat Energy Storage Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lasso Solar Project LLC Andover US 1 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 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
Latamsolar Fotovoltaica
\n
Fundaci\u00f3n SAS
\n
Bogot\u00e1 CO 8,000,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
Latamsolar Fotovoltaica
\n
Sahagun SAS
\n
Bogot\u00e1 CO 8,000,000 COP
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00% 47. 1 8 %
\n
Lathrop Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Lava Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lawrence Creek Solar LLC Minneapolis US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74. 13 %
\n
Layerx Security Ltd Tel Aviv IL 20,112 ILS
\n
- Finsec Lab Ltd 3.00% 0.90%
\n
Lebanon Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Legacy Blossom Storage
\n
Project Limited Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Storage
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Lemonade Solar Project LLC Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Lerato Solar Power Plant (RF)
\n
(Pty) Ltd
\n
Gauteng ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Liberty Energy Storage LLC Andover US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Libyan Italian Joint Company
\n
- Azienda Libico-Italiana
\n
(A.L.I.)
\n
Tripoli LY 1,350,000 EUR
\n
- Enelpower Srl 0.33% 0.33%
\n
Libra Flexsys Srl Rome IT 10,000 EUR
\n
Line-by-line Enel Italia SpA 100.00% 100.00%
\n
Light Cirrus Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Lily Solar Holdings LLC Andover US 1 USD
\n
Line-by-line
\n
Enel Green Power Lily
\n
Solar Holdings LLC
\n
100.00% 100.00%
\n
Lily Solar LLC Andover US - USD
\n
Line-by-line
\n
Lily Solar Holdings
\n
LLC
\n
100.00% 100.00%
\n
Lindahl Wind Holdings LLC Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings LLC
\n
100.00% 100.00%
\n
Lindahl Wind Project LLC Wilmington US - USD
\n
Line-by-line
\n
Lindahl Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Elk Wind Holdings LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Little Elk Wind Project LLC Wilmington US - USD
\n
Line-by-line
\n
Little Elk Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Little Salt Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Litus Energy Storage LLC Andover US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\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 LP 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 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
35.29% 24.74%
\n
Luminary Highlands Solar
\n
Project LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Luz de Angra Energia SA Rio de Janeiro BR 14,304,790 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Caruaru Energia SA Rio de Janeiro BR 21,027,600 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Cataguases SA Cataguases BR 4,800,000 BRL
\n
Line-by-line Enel X Brasil SA 60.00% 49.36%
\n
Luz de Caxias do Sul SA Rio de Janeiro BR 31,017,000 BRL
\n
Line-by-line Enel X Brasil SA 80.00% 65.82%
\n
Luz de Itanha\u00e9m SA Itanha\u00e9m BR 22,700,000 BRL
\n
Line-by-line Enel X Brasil SA 60.00% 49.36%
\n
Luz de Jaboat\u00e3o Energia SA Rio de Janeiro BR 21,114,200 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Macap\u00e1 Energia SA Rio de Janeiro BR 24,338,000 BRL
\n
Line-by-line Enel X Brasil SA 51.00% 41.96%
\n
Luz de Ponta Grossa SA Rio de Janeiro BR 17,889,000 BRL
\n
Line-by-line Enel X Brasil SA 80.00% 65.82%
\n
Maicor Wind Srl Rome IT 20,850,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Mansar Renewable Energy
\n
Private Limited
\n
Gurgaon IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Maple Canada Solutions
\n
Holdings Ltd
\n
- CA - CAD
\n
Equity Enel X Canada Ltd 20.00% 20.00%
\n
Maple Energy Solutions LP - CA - CAD
\n
Equity
\n
Enel X Canada
\n
Holding Inc.
\n
20.00% 20.00%
\n
Maple Run Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Mar\u00eda Renovables SL Zaragoza ES 3,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.36% 31.80%
\n
Marshoy Energy Advisory
\n
Services Private Limited
\n
Mumbai IN 313,709,000 INR
\n
Line-by-line
\n
Enel X Advisory
\n
Services Srl
\n
100.00% 100.00%
\n
Marte Srl Rome IT 6,100,000 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 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
M\u00e1s Energ\u00eda S de RL de Cv Mexico City MX 61,873,926 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
66.67%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
33.33%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mason Jar Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Mason Mountain Wind
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind Power
\n
LLC
\n
100.00% 100.00%
\n
Matrigenix (Pty) Ltd Johannesburg ZA 1,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
Maty Energia Srl Rome IT 10,000 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 LLC Wilmington US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Merit Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Metro Wind LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Mexicana de
\n
Hidroelectricidad Mexhidro S
\n
de RL de Cv
\n
Mexico City MX 181,728,901 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
99.99% 99.99%
\n
Mibgas SA Madrid ES 3,000,000 EUR
\n
- Endesa SA 1.35% 0.95%
\n
Midelt Wind Farm SA Casablanca MA 145,000,000 MAD
\n
Equity
\n
Nareva Enel Green
\n
Power Morocco SA
\n
70.00% 35.00%
\n
Millstone Junction Solar
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Minglanilla Renovables 400
\n
kV AIE
\n
Valencia ES - EUR
\n
Proportional
\n
Energ\u00eda Base Natural
\n
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 Gregal
\n
SLU
\n
9.31%
\n
Energ\u00eda y Naturaleza
\n
SLU
\n
4.79%
\n
Minicentrales Acequia Cinco
\n
Villas AIE
\n
Ejea de los
\n
Caballeros
\n
ES 3,346,993 EUR
\n
-
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
5.39% 3.78%
\n
Minicentrales del Canal de las
\n
B\u00e1rdenas AIE
\n
Ejea de los
\n
Caballeros
\n
ES 1,202,000 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 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.50% 25.59%
\n
Mira Energy (Pty) Ltd Johannesburg ZA 100 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
Miranda Plataforma Log\u00edstica
\n
SA
\n
Miranda de Ebro ES 1,800,000 EUR
\n
- Nuclenor SA 0.22% 0.08%
\n
MO Land Holdings 1358 LLC Andover US 1 USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Monte Reina Renovables SL Madrid ES 4,000 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 Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Mooney Group SpA Milan IT 10,050,000 EUR
\n
Equity Enel X Srl 50.00% 50.00%
\n
Mooney SpA Milan IT 87,833,331 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Mooney Servizi SpA Milan IT 8,549,999 EUR
\n
Equity Mooney Group SpA 100.00% 50.00%
\n
Morgan Branch Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Morning Light Energy
\n
Storage Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Mount Pleasant Energy
\n
Storage 1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Mountrail Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
MPG Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Mucho Viento Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Mule Bit Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Muskegon County Solar
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Muskegon Green Wind
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Mustang Run Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
MyCicero Srl Senigallia IT 1,142,857 EUR
\n
Equity
\n
Mooney Servizi SpA 30.00%
\n
39.50%
\n
Pluservice Srl 70.00%
\n
Nabb Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Napolean Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Nareva Enel Green Power
\n
Morocco SA
\n
Casablanca MA 98,750,000 MAD
\n
Equity
\n
Enel Green Power
\n
Morocco S\u00e0rl
\n
50.00% 50.00%
\n
Neugemacht GmbH Frankfurt DE 25,000 EUR
\n
Equity Gridspertise Srl 51.00% 25.50%
\n
Nevkan Renewables LLC 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 America
\n
Inc.
\n
100.00% 100.00%
\n
Ngonye Power Company
\n
Limited
\n
Lusaka ZM 10 ZMW
\n
Held for sale
\n
Enel Green Power
\n
Solar Ngonye SpA
\n
(formerly Enel Green
\n
Power Africa Srl)
\n
80.00% 80.00%
\n
Nojoli Wind Farm (RF) (Pty)
\n
Ltd
\n
Johannesburg ZA 10,000,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
60.00% 60.00%
\n
North English Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
North Rock Wind LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Northland Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Northstar Wind Project LLC Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Northwest Hydro LLC Wilmington US - USD
\n
Line-by-line Chi West LLC 100.00% 100.00%
\n
Notch Butte Hydro Company
\n
Inc.
\n
Wilmington US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Novolitio Recuperaci\u00f3n de
\n
Bater\u00edas SL
\n
Ponferrada ES 180,000 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
45.00% 31.55%
\n
Nuclenor SA Valle de Tobalina ES 5,406,000 EUR Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
50.00% 35.06%
\n
Nuove Energie Srl Porto Empedocle IT 5,204,029 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 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
51.00% 25.50%
\n
NYC Storage (353 Chester)
\n
SPE LLC
\n
Wilmington US 1 USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Ochrana A Bezpecnost
\n
Se Sro
\n
Kaln\u00e1 Nad
\n
Hronom
\n
SK 33,194 EUR
\n
Equity
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
100.00% 33.00%
\n
Olathe Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Old Sport Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Olivum PV Farm 01 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
OMIP - Operador do
\n
Mercado Ib\u00e9rico (Portugal)
\n
SGPS SA
\n
Lisbon PT 2,610,000 EUR
\n
-
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
5.00% 3.51%
\n
Open Range Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Operador del Mercado
\n
Ib\u00e9rico de Energ\u00eda - Polo
\n
Espa\u00f1ol SA
\n
Madrid ES 1,999,998 EUR
\n
- Endesa SA 5.00% 3.51%
\n
Operadora Distrital de
\n
Transporte SAS
\n
Bogot\u00e1 CO 12,500,000,000 COP
\n
Equity
\n
Enel Colombia SA
\n
ESP
\n
20.00% 9.44%
\n
Orchid Acres Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Origin Goodwell Holdings
\n
LLC
\n
Wilmington US - USD
\n
Equity
\n
EGPNA Wind
\n
Holdings 1 LLC
\n
100.00% 10.00%
\n
Origin Wind Energy LLC Wilmington US - USD
\n
Equity
\n
Origin Goodwell
\n
Holdings LLC
\n
100.00% 10.00%
\n
Osage Wind Holdings LLC Wilmington US 100 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Osage Wind LLC Wilmington US - USD
\n
Line-by-line
\n
Osage Wind Holdings
\n
LLC
\n
100.00% 100.00%
\n
Ossining Energy Storage
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Oxagesa AIE in liquidation Alca\u00f1iz ES 6,010 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Oyster Bay Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Padoma Wind Power LLC Elida US - USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Painted Rose Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Palo Alto Farms Wind Project
\n
LLC
\n
Dallas US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pampinus PV Farm 01 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Paradise Creek Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Paravento SL Paradela ES 3,006 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.10%
\n
Parc E\u00f2lic La Tossa-La Mola
\n
d\u2019en Pascual SL
\n
Madrid ES 1,183,100 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.03%
\n
Parc E\u00f2lic Los Aligars SL Madrid ES 1,313,100 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.03%
\n
Parco Eolico Monti Sicani Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Parque Amistad II SA de Cv Mexico City MX 2,589,177,005 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad III SA de Cv Mexico City MX 1,706,287,200 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque Amistad IV SA de Cv Mexico City MX 2,728,499,160 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.50%
\n
100.00%
\n
Enel Rinnovabile SA
\n
de Cv
\n
99.50%
\n
Parque E\u00f3lico A Capelada
\n
SLU
\n
Santiago de
\n
Compostela
\n
ES 5,857,704 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico Belmonte SA Madrid ES 120,400 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.17% 35.17%
\n
Parque E\u00f3lico BR-1 SA de Cv Mexico City MX 50,000 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
0.00%
\n
25.50%
\n
Enel Rinnovabile SA
\n
de Cv
\n
100.00%
\n
Parque E\u00f3lico Carretera de
\n
Arigana SA
\n
Las Palmas de
\n
Gran Canaria
\n
ES 1,007,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
80.00% 56.09%
\n
Parque E\u00f3lico de Barbanza
\n
SA
\n
Santiago de
\n
Compostela
\n
ES 3,606,073 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.00% 52.59%
\n
Parque E\u00f3lico de San Andr\u00e9s
\n
SA
\n
Santiago de
\n
Compostela
\n
ES 552,920 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 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
90.00% 63.10%
\n
Parque E\u00f3lico Montes de las
\n
Navas SA
\n
Madrid ES 6,540,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
75.50% 52.94%
\n
Parque E\u00f3lico Muniesa SLU Madrid ES 3,006 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Parque E\u00f3lico Palmas dos
\n
Ventos Ltda
\n
Salvador BR 4,096,626 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 SA Buenos Aires AR 477,139,364 ARS
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Parque E\u00f3lico Punta de
\n
Teno SA
\n
Santa Cruz de
\n
Tenerife
\n
ES 528,880 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
58.00% 40.67%
\n
Parque Salitrillos SA de Cv Mexico City MX 100 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Parque Solar Cauchari IV SA
\n
San Salvador de
\n
Jujuy
\n
AR 500,000 ARS
\n
Line-by-line
\n
Enel Green Power
\n
Argentina
\n
100.00% 82.27%
\n
Parque Solar Don Jos\u00e9 SA
\n
de Cv
\n
Mexico City MX 100 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Parque Solar Villanueva Tres
\n
SA de Cv
\n
Mexico City MX 306,024,631 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Parque Talinay Oriente SA Santiago de Chile CL 66,092,165,173 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 Nazionale per
\n
la ricerca e lo sviluppo dei
\n
materiali SCPA in liquidation
\n
Brindisi IT 2,065,000 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 EUR
\n
Equity Mooney SpA 100.00% 50.00%
\n
PDP Technologies Ltd Kfar Saba IL 1,129,252 ILS
\n
- Enel Grids Srl 4.75% 4.75%
\n
Pearl Star Wind Limited
\n
Partnership
\n
Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Pebble Stream Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pegop - Energia El\u00e9ctrica SA Pego PT 50,000 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 Chuc\u00e1s SA San Jos\u00e9 CR 100,000 CRC
\n
Line-by-line
\n
Enel Costa Rica
\n
CAM SA
\n
65.00% 30.67%
\n
PH Don Pedro SA San Jos\u00e9 CR 100,001 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 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 Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pike Den Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pilesgrove Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Pincher Creek LP Alberta CA - CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
50.50%
\n
51.01%
\n
Pincher Creek
\n
Management Inc.
\n
1.00%
\n
Pincher Creek Management
\n
Inc.
\n
Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
51.00% 51.00%
\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
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Playa Flat Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pluservice Srl Senigallia IT 450,000 EUR
\n
Equity Mooney Servizi SpA 70.00% 35.00%
\n
Point Bar Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Point Rider Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Polka Dot Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Pomerado Energy Storage
\n
LLC
\n
Wilmington US 1 USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
PowerCrop Macchiareddu Srl Russi IT 100,000 EUR
\n
Equity
\n
PowerCrop SpA
\n
(formerly PowerCrop
\n
Srl)
\n
100.00% 50.00%
\n
PowerCrop Russi Srl Russi IT 100,000 EUR
\n
Equity
\n
PowerCrop SpA
\n
(formerly PowerCrop
\n
Srl)
\n
100.00% 50.00%
\n
PowerCrop SpA (formerly
\n
PowerCrop Srl)
\n
Russi IT 4,000,000 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Prairie Rose Transmission
\n
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 36,965,445 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Productive Solar Systems
\n
SLU
\n
Andorra ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Productora de Energ\u00edas SA Barcelona ES 60,101 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
30.00% 21.03%
\n
Productora El\u00e9ctrica
\n
Urgellenca SA
\n
La Seu d\u2019Urgell ES 8,400,000 EUR
\n
- Endesa SA 8.43% 5.91%
\n
Progreso Solar 20 MW SA Panama City PA 10,000 USD
\n
Line-by-line Enel Panam\u00e1 CAM Srl 100.00% 47. 19 %
\n
Promociones Energ\u00e9ticas del
\n
Bierzo SLU
\n
Madrid ES 12,020 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Promotores Mud\u00e9jar 400
\n
kV SL
\n
Zaragoza ES 3,000 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 Mediavilla
\n
SLU
\n
5.69%
\n
Proveedora de Electricidad
\n
de Occidente S de RL de Cv
\n
Mexico City MX 89,708,835 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
99.99% 99.99%
\n
Proyectos Universitarios de
\n
Energ\u00edas Renovables SL
\n
Alicante ES 27,000 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 SOL
\n
Line-by-line
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
99.90%
\n
99.98%
\n
Enel Per\u00fa SAC 0.10%
\n
PSG Energy Private Limited - IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
PT Enel Green Power Optima
\n
Way Ratai
\n
Jakarta ID 10,002,740 USD
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
90.00% 90.00%
\n
Puerto Santa Mar\u00eda Energ\u00eda
\n
I SLU
\n
Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Puerto Santa Mar\u00eda Energ\u00eda
\n
II SLU
\n
Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Pulida Energy (RF) (Pty) Ltd Johannesburg ZA 10,000,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
52.70% 52.70%
\n
Pumpkin Vine Wind Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Quatiara Energia SA Niter\u00f3i BR 13,766,119 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Queens Energy Storage LLC Andover US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Quorn Park Solar Farm
\n
(Pty) Ltd
\n
Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Quorn Holding
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Quorn Park Solar Farm Trust Sydney AU 100 AUD
\n
Equity
\n
Enel Green Power
\n
Quorn Holding Trust
\n
100.00% 50.00%
\n
Raleigh Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Solar Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Ranchland Wind Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ranchland Wind Project
\n
II LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
AzureRanchII Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Ranchland Wind Project LLC Andover US - USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland Holdings
\n
LLC
\n
100.00% 100.00%
\n
Ranchland Wind Storage LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rattlesnake Creek Holdings
\n
LLC
\n
Delaware US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rausch Creek Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
RC Wind Srl Milan IT 10,000 EUR
\n
-
\n
Enel Green Power
\n
Italia Srl
\n
0.50% 0.50%
\n
RE Arroyo LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Reaktortest Sro Trnava SK 66,389 EUR
\n
-
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
49.00% 16.17%
\n
Rebuilding Agente
\n
Rehabilitador SL
\n
Madrid ES 250,000 EUR
\n
Equity
\n
Endesa X Servicios
\n
SLU
\n
50.00% 35.06%
\n
Red Cap Impofu (Pty) Ltd Sandton ZA 20,000,000 ZAR
\n
Equity
\n
Impofu Cluster
\n
Investment SPV (RF)
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Red Cap Impofu East (Pty)
\n
Ltd
\n
Gauteng ZA 35,059,068 ZAR
\n
Equity
\n
Impofu Cluster
\n
Investment SPV (RF)
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
Red Cap Impofu West
\n
(Pty) Ltd
\n
Gauteng ZA 10,000 ZAR
\n
Equity
\n
Impofu Cluster
\n
Investment SPV (RF)
\n
(Pty) Ltd
\n
100.00% 50.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Red Cardinal Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Centroamericana de
\n
Telecomunicaciones SA
\n
Panama City PA 2,700,000 USD
\n
- Enel SpA 11.11% 11.11%
\n
Red Dirt Wind Holdings I LLC Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Red Dirt Wind Holdings LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Dirt Wind Project LLC Dover US 1 USD
\n
Line-by-line
\n
Red Dirt Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Red Fox Wind Project LLC Wilmington US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Stag Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Top Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Red Yucca Energy Storage
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Regal Rising Solar Project
\n
Limited Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Ren Wave Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Renovables Andorra SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Brovales 400
\n
kV SL
\n
Seville ES 5,000 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 SLU 16.99%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
22.20%
\n
Furatena Solar 1 SLU 6.24%
\n
Seguidores Solares
\n
Planta 2 SLU
\n
6.24%
\n
Renovables Brovales Segura
\n
de Le\u00f3n 400 kV SL
\n
Seville ES 5,000 EUR
\n
Equity
\n
Emintegral Cycle SLU 33.02%
\n
44.91%
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
31.03%
\n
Renovables de Guatemala SA Guatemala City GT 1,924,465,600 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
100.00%
\n
47. 1 8 %
\n
Enel Guatemala SA 0.00%
\n
Renovables La Pedrera SLU Zaragoza ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Renovables Manzanares
\n
400 kV SL
\n
Madrid ES 5,000 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 SLU Zaragoza ES 3,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Reservoir Falls Energy
\n
Storage Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rhinestone Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ribina Renovables 400 SL
\n
Pozuelo de
\n
Alarc\u00f3n
\n
ES 3,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.21% 28.19%
\n
River Mill Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
River Point Wind Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Riverbend Farms Wind
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Riverview LP Alberta CA - CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
50.50%
\n
51.01%
\n
Riverview
\n
Management Inc.
\n
1.00%
\n
Riverview Management Inc. Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Green Power
\n
Canada Inc.
\n
51.00% 51.00%
\n
Riverview Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Solar Project
\n
LLC
\n
Andover US 100 USD
\n
Line-by-line
\n
Enel Roadrunner
\n
Solar Project
\n
Holdings LLC
\n
100.00% 100.00%
\n
Roadrunner Storage LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rock Creek Wind Holdings
\n
I LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Rock Creek Wind Holdings
\n
II LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Creek Wind Holdings
\n
LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
EGPNA Preferred
\n
Wind Holdings II LLC
\n
100.00% 100.00%
\n
Rock Creek Wind Project LLC Clayton US 1 USD
\n
Line-by-line
\n
Rock Creek Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Rock Prairie Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Ranchland
\n
Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Rockhaven Wind Project LLC Andover US 1 USD
\n
Line-by-line
\n
Rockhaven
\n
Ranchland Holdings
\n
LLC
\n
100.00% 100.00%
\n
Rocky Caney Holdings LLC Oklahoma City US 1 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 Project
\n
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 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 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Rolling Farms Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Rosy Range Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ruthton Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
S4ma Developments
\n
Sp\u00f3\u0142ka z Ograniczon\u0105
\n
Odpowiedzialno\u015b\u0105
\n
Wroc\u0142aw PL 5,000 PLN
\n
Line-by-line
\n
Enel Green Power
\n
SpA
\n
100.00% 100.00%
\n
Sacme SA Buenos Aires AR 12,000 ARS
\n
Equity
\n
Empresa
\n
Distribuidora Sur SA
\n
- Edesur
\n
50.00% 29.66%
\n
Saddle House Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Salt Springs Wind Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Salto de San Rafael SL Seville ES 462,186 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
San Francisco de Borja SA Zaragoza ES 60,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
66.67% 46.74%
\n
San Juan Mesa Wind Project
\n
II LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Padoma Wind Power
\n
LLC
\n
100.00% 100.00%
\n
Sanosari Energy Private
\n
Limited
\n
Gurugram IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Santo Rostro Cogeneraci\u00f3n
\n
SA in liquidation
\n
Seville ES 207,340 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Sardhy Green Hydrogen Srl Sarroch IT 10,000 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
Saugus River Energy Storage
\n
LLC
\n
Dover US 100 USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Savanna Power Solar 10 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 12 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 13 SLU Seville ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 4 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 5 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 6 SLU Madrid ES 3,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Savanna Power Solar 9 SLU Madrid ES 3,000 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 EUR Equity
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
100.00% 33.00%
\n
Seaway Landing Solar Project
\n
LLC
\n
Andover US 1 USD Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seccionadora Almod\u00f3var
\n
Renovables SL
\n
M\u00e1laga ES 5,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
37.50% 26.29%
\n
Seguidores Solares Planta
\n
2 SLU
\n
Madrid ES 3,010 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Servizio Elettrico Nazionale
\n
SpA
\n
Rome IT 10,000,000 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 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
16.00% 11.22%
\n
Setyl Srl Bergamo IT 100,000 EUR
\n
Equity Enel X Italia Srl 27.50% 27.50%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Seven Cowboy PPA LLC Andover US 1 USD
\n
Line-by-line
\n
EGP North America
\n
PPA LLC
\n
100.00% 100.00%
\n
Seven Cowboy Wind Project
\n
Holdings LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind Project
\n
II LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Seven Cowboy Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Seven Cowboy Wind
\n
Project Holdings LLC
\n
100.00% 100.00%
\n
Seven Cowboys Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shark Power 10 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 4 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 5 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 6 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 7 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 8 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power 9 SLU Madrid ES 3,000 EUR
\n
Line-by-line Shark Power SLU 100.00% 70.12%
\n
Shark Power SLU Madrid ES 143,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Shepherd Pass Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Shiawassee Wind Project
\n
LLC
\n
Wilmington US 1 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 Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
Shikhar Surya (One) Private
\n
Limited
\n
Gurugram IN 340,100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Sicilhy Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
SIET - Societ\u00e0 Informazioni
\n
Esperienze Termoidrauliche
\n
SpA
\n
Piacenza IT 697,820 EUR
\n
Equity
\n
Enel Innovation
\n
Hubs Srl
\n
41.55% 41.55%
\n
Silt Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Silver Dollar Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Silverware Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sinergia EWR4 Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Sinergia GP6 Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Sinergia GP7 Srl Rome IT 10,000 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 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
28.13% 19.72%
\n
Sistemas Energ\u00e9ticos Ma\u00f1\u00f3n
\n
Ortigueira SA
\n
Santiago de
\n
Compostela
\n
ES 2,007,750 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
96.00% 67.31%
\n
Skyview Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Skyview Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
SL Energy SAC Lima PE 1,000 SOL
\n
Held for sale
\n
Enel Generaci\u00f3n
\n
Per\u00fa SAA
\n
99.90%
\n
71.55%
\n
Enel Per\u00fa SAC 0.10%
\n
Sleep Hollow Solar I LLC Andover US 1 USD
\n
Line-by-line
\n
Brick Road Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Slovak Power Holding BV Amsterdam NL 25,010,000 EUR
\n
Equity Enel Produzione SpA 50.00% 50.00%
\n
Slovensk\u00e9 elektr\u00e1rne -
\n
Energetick\u00e9 Slu\u017eby Sro
\n
Bratislava SK 4,505,000 EUR
\n
Equity
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
100.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne AS Bratislava SK 1,269,295,725 EUR
\n
Equity
\n
Slovak Power Holding
\n
BV
\n
66.00% 33.00%
\n
Slovensk\u00e9 elektr\u00e1rne \u010cesk\u00e1
\n
Republika Sro
\n
Moravsk\u00e1 Ostrava CZ 295,819 CZK
\n
Equity
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
100.00% 33.00%
\n
Smoky Hill Holdings II LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Smoky Hills Wind Farm LLC Topeka US - USD
\n
Line-by-line
\n
EGPNA Project
\n
HoldCo 1 LLC
\n
100.00% 100.00%
\n
Smoky Hills Wind Project
\n
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 Project
\n
LLC
\n
Andover US 1 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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Sociedad Agr\u00edcola de
\n
Cameros Ltda
\n
Santiago de Chile CL 5,738,046,495 CLP
\n
Line-by-line Enel Chile SA 57.50% 37.33%
\n
Sociedad E\u00f3lica de Andaluc\u00eda
\n
SA
\n
Seville ES 4,507,591 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
64.75% 45.40%
\n
Sociedad E\u00f3lica el Puntal SL Seville ES 1,643,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
50.00% 35.06%
\n
Sociedad E\u00f3lica Los Lances
\n
SA
\n
Seville ES 2,404,048 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.00% 42.07%
\n
Societ\u00e0 Elettrica Trigno Srl Rome IT 100,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Soetwater Wind Farm (RF)
\n
(Pty) Ltd
\n
Johannesburg ZA 1,000 ZAR
\n
Equity
\n
Enel Green Power
\n
RSA 2 (RF) (Pty) Ltd
\n
55.00% 27.50%
\n
Solana Renovables SL Madrid ES 6,246 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
39.90% 27.97%
\n
Soliloquoy Ridge LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Sona Enerj\u00ed \u00dcret\u00edm Anon\u00edm
\n
\u015e\u00edrket\u00ed
\n
Istanbul TR 50,000 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
Sonak Solar Project LLC Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Sone Renewable Energy
\n
Private Limited
\n
Gurgaon IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Sotavento Galicia SA
\n
Santiago de
\n
Compostela
\n
ES 601,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
36.00% 25.24%
\n
South Italy Green Hydrogen
\n
Srl
\n
Rome IT 10,000 EUR
\n
Equity
\n
Enel Green Power
\n
Italia Srl
\n
50.00% 50.00%
\n
South Rock Wind Project LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
South Sky Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Southern Star Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Southwest Transmission LLC Cedar Bluff US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Southwestern Rays Solar
\n
Project LLC
\n
Andover US 1 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Spinazzola SPV Srl Rome IT 10,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Italia Srl
\n
100.00% 100.00%
\n
Spring Wheat Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Square Dance Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sreeja Infrastructure Private
\n
Limited
\n
Hyderabad IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Stable Brook Storage Project
\n
Limited Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Storage
\n
Inc.
\n
0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Stampede Solar Holdings
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
Enel Green Power
\n
Stampede Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Stampede Solar Project LLC Andover US - USD
\n
Line-by-line
\n
Fence Post Solar
\n
Holdings LLC
\n
100.00% 100.00%
\n
Star Catcher Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Star Energy Single Member
\n
PC
\n
Maroussi GR 63,010 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas SA
\n
100.00% 50.00%
\n
Station Tales Solar Limited
\n
Partnership
\n
Calgary CA 100 CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Sterling and Wilson Enel X
\n
e-Mobility Private Limited
\n
Mumbai IN 90,000,000 INR
\n
Equity Enel X Way Srl 50.00% 50.00%
\n
Stillman Valley Solar LLC Wilmington US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stillwater Woods Hill
\n
Holdings LLC
\n
Wilmington US 1 USD
\n
Held for sale Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Stipa Naya\u00e1 SA de Cv Mexico City MX 1,811,016,347 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL de Cv
\n
55.21%
\n
99.99%
\n
Enel Green Power
\n
Partecipazioni
\n
Speciali Srl
\n
44.79%
\n
Stockyard Solar Project LLC Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stone Belt Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stonewood Desarrollos SLU Madrid ES 4,053,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Storey Plains Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Stormy Hills Wind Project
\n
LLC
\n
Andover US 1 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 de Cv Mexico City MX 1,000 MXN
\n
Line-by-line
\n
Enel Green Power
\n
M\u00e9xico S de RL 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 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
57.00% 57.00%
\n
Sugar Pine Solar Project LLC Andover US 1 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 EUR
\n
Line-by-line
\n
Endesa Generaci\u00f3n
\n
Portugal SA
\n
100.00% 70.12%
\n
Suministradora El\u00e9ctrica de
\n
C\u00e1diz SA
\n
C\u00e1diz ES 12,020,240 EUR
\n
Equity Endesa SA 33.50% 23.49%
\n
Suministro de Luz y Fuerza
\n
SL
\n
Barcelona ES 2,800,000 EUR
\n
Line-by-line
\n
Hidroel\u00e9ctrica de
\n
Catalunya SLU
\n
60.00% 42.07%
\n
Summit Energy Storage Inc. Wilmington US 1,000 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Sun Rock Solar Limited
\n
Partnership
\n
Calgary CA - CAD
\n
Line-by-line
\n
Enel Alberta Solar Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Sun Up Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sun4 Koryta Sp\u00f3\u0142ka
\n
z Ograniczon\u0105
\n
Odpowiedzialno\u015bci\u0105
\n
Wroc\u0142aw PL 5,750 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka z Ograniczon\u0105
\n
Odpowiedzialno\u015b\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 PLN
\n
Line-by-line
\n
S4ma Developments
\n
Sp\u00f3\u0142ka z Ograniczon\u0105
\n
Odpowiedzialno\u015b\u0105
\n
80.00% 80.00%
\n
Sundance Wind Project LLC Dover US 100 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 LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Sweet Apple Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
TAE Technologies Inc. Pauling US 53,207,936 USD
\n
- Enel Produzione SpA 1.02% 1.02%
\n
Tasseling Jewel Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tauste Energ\u00eda Distribuida SL Zaragoza ES 60,508 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
51.00% 35.76%
\n
Teal Canoe Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tecnoguat SA Guatemala City GT 30,948,000 GTQ
\n
Line-by-line
\n
Enel Colombia SA
\n
ESP
\n
75.00% 35.38%
\n
Tejo Energia - Produ\u00e7\u00e3o
\n
e Distribui\u00e7\u00e3o de Energia
\n
El\u00e9ctrica SA
\n
Lisbon PT 5,025,000 EUR
\n
Equity
\n
Endesa Generaci\u00f3n
\n
SAU
\n
43.75% 30.68%
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y Viento SAPI
\n
de Cv
\n
Mexico City MX 2,892,643,576 MXN
\n
Equity
\n
Enel Green Power
\n
SpA
\n
32.90% 32.90%
\n
Tera Renewables India Private
\n
Limited
\n
Gurugram IN 100,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Termica Colleferro SpA Bologna IT 6,100,000 EUR
\n
Equity Cogenio Srl 60.00% 12.00%
\n
Termoel\u00e9ctrica Jos\u00e9 de San
\n
Mart\u00edn SA
\n
Buenos Aires AR 7,078,298 ARS
\n
-
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
5.60% 3.03%
\n
Termoel\u00e9ctrica Manuel
\n
Belgrano SA
\n
Buenos Aires AR 7,078,307 ARS
\n
-
\n
Enel Generaci\u00f3n El
\n
Choc\u00f3n SA
\n
6.23% 3.37%
\n
Termotec Energ\u00eda AIE in
\n
liquidation
\n
La Pobla de
\n
Vallbona
\n
ES 481,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
45.00% 31.55%
\n
Terrer Renovables SL Madrid ES 5,000 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
Texas Sage Solar Project LLC Andover US 1 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 Limited Gurgaon IN 1,127,840 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 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 Project
\n
LLC
\n
Dover US 1 USD
\n
Line-by-line
\n
Thunder Ranch Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
Thunderegg Storage Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Thunderegg Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tico Solar 1 SLU Zaragoza ES 3,000 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 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
100.00% 70.12%
\n
Tieton Storage Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Tobivox (RF) (Pty) Ltd Johannesburg ZA 10,000,000 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
60.00% 60.00%
\n
Toledo PV AIE Madrid ES 26,888 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
33.33% 23.37%
\n
Toro Renovables 400 kV SL Madrid ES 3,000 EUR
\n
Equity
\n
FRV Zamora Solar
\n
1 SLU
\n
8.28% 5.81%
\n
Torrepalma Energy 1 SLU Madrid ES 3,100 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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trading Post Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Trail Ride Canyon Wind
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Transformadora Almod\u00f3var
\n
Renovables SL
\n
Seville ES 5,000 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
60.53% 42.44%
\n
Transportadora de Energ\u00eda
\n
SA - TESA
\n
Buenos Aires AR 2,584,473,416 ARS
\n
Held for sale
\n
Enel Argentina SA 0.00%
\n
82.27%Enel Brasil SA 60.15%
\n
Enel CIEN SA 39.85%
\n
Transportes y Distribuciones
\n
El\u00e9ctricas SA in liquidation
\n
Olot ES 72,121 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 EUR
\n
Equity
\n
Furatena Solar 1 SLU 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Tulip Grove Solar Project LLC 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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Tunga Renewable Energy
\n
Private Limited
\n
Gurugram IN 96,300,000 INR
\n
Line-by-line
\n
Avikiran Energy India
\n
Private Limited
\n
100.00% 100.00%
\n
TWE Franklin Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
TWE ROT DA LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Twin Lake Hills LLC Minneapolis US - USD
\n
Line-by-line
\n
Chi Minnesota Wind
\n
LLC
\n
100.00% 100.00%
\n
Twin Saranac Holdings LLC 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 EUR
\n
Equity Enel X Italia Srl 50.00% 50.00%
\n
Uni\u00f3n El\u00e9ctrica de Canarias
\n
Generaci\u00f3n SAU
\n
Las Palmas de
\n
Gran Canaria
\n
ES 190,171,521 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 ZAR
\n
Line-by-line
\n
Enel Green Power
\n
South Africa (Pty) Ltd
\n
100.00% 100.00%
\n
Usina E\u00f3lica Pedra Pintada
\n
A Ltda
\n
Rio de Janeiro BR 286,427,454 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra Pintada
\n
B Ltda
\n
Rio de Janeiro BR 135,748,697 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Usina E\u00f3lica Pedra Pintada
\n
C Ltda
\n
Rio de Janeiro BR 135,805,024 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra Pintada
\n
D Ltda
\n
Rio de Janeiro BR 135,653,327 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra Pintada
\n
E Ltda
\n
Rio de Janeiro BR 653 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra Pintada
\n
F Ltda
\n
Rio de Janeiro BR 653,327 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina E\u00f3lica Pedra Pintada
\n
G Ltda
\n
Rio de Janeiro BR 653,327 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
11 Ltda
\n
Rio de Janeiro BR 249,033,267 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
12 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
13 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
14 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
15 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
16 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
17 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
21 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
22 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
23 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Usina Fotovoltaica Arinos E
\n
24 Ltda
\n
Rio de Janeiro BR 221,724,006 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
USME ZE SAS Bogot\u00e1 CO 739,653,977 COP
\n
Equity Bogot\u00e1 ZE SAS 100.00% 9.44%
\n
Ustav Jadern\u00e9ho V\u00fdzkumu
\n
Rez AS
\n
\u0158e\u017e CZ 524,139,000 CZK
\n
-
\n
Slovensk\u00e9 elektr\u00e1rne
\n
AS
\n
27.77% 9. 17%
\n
Vayu (Project 1) Private
\n
Limited
\n
Gurugram IN 30,000,000 INR
\n
Line-by-line
\n
Enel Green Power
\n
India Private Limited
\n
100.00% 100.00%
\n
Vekt\u00f6r Enerj\u00ed \u00dcret\u00edm Anon\u00edm
\n
\u015e\u00edrket\u00ed
\n
Istanbul TR 3,500,000 TRY
\n
Line-by-line Enel SpA 100.00% 100.00%
\n
Velvet Wheat Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Ventos de Santa \u00c2ngela
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 7,315,000 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santa Esperan\u00e7a
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 4,727,414 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de Santo Orestes
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 1,754,031 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Ventos de S\u00e3o Cirilo Energias
\n
Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,572,010 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Ventos de S\u00e3o M\u00e1rio
\n
Energias Renov\u00e1veis SA
\n
Rio de Janeiro BR 2,492,000 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 BRL
\n
Line-by-line Enel Brasil SA 100.00% 82.27%
\n
Vientos del Altiplano SA
\n
de Cv
\n
Mexico City MX 1,455,854,094 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Villanueva Solar SA de Cv Mexico City MX 205,316,027 MXN
\n
Equity
\n
Tenedora de Energ\u00eda
\n
Renovable Sol y
\n
Viento SAPI de Cv
\n
60.80% 20.00%
\n
Viruleiros SL
\n
Santiago de
\n
Compostela
\n
ES 160,000 EUR
\n
Line-by-line
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
67.00% 46.98%
\n
Viva Labs AS Oslo NO 1,250,000 NOK
\n
Line-by-line
\n
Enel X International
\n
Srl
\n
100.00% 100.00%
\n
Wagon Train Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Walking Horse Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wapella Bluffs Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 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 LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Weber Energy Storage
\n
Project LLC
\n
Wilmington US - USD
\n
Line-by-line
\n
Enel Energy Storage
\n
Holdings LLC
\n
(formerly EGP Energy
\n
Storage Holdings
\n
LLC)
\n
100.00% 100.00%
\n
West Faribault Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74. 13 %
\n
West Waconia Solar LLC Wilmington US - USD
\n
Line-by-line
\n
Aurora Distributed
\n
Solar LLC
\n
100.00% 74. 13 %
\n
Western New York Wind
\n
Corporation
\n
Albany US 300 USD
\n
Line-by-line
\n
Enel Green Power
\n
North America Inc.
\n
100.00% 100.00%
\n
Western Trails Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wharton-El Campo Solar
\n
Project LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
White Cloud Wind Holdings
\n
LLC
\n
Andover US - USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
White Cloud Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line
\n
White Cloud Wind
\n
Holdings LLC
\n
100.00% 100.00%
\n
White Peaks Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitetail Trails Solar Project
\n
LLC
\n
Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Whitney Hill Wind Power
\n
Holdings LLC
\n
Andover US 99 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Whitney Hill Wind Power LLC Andover US - USD
\n
Line-by-line
\n
Whitney Hill Wind
\n
Power Holdings LLC
\n
100.00% 100.00%
\n
Whittle\u2019s Ferry Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Wild Ox Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wild Run LP Alberta CA 10 CAD
\n
Line-by-line
\n
Enel Alberta Wind Inc. 0.10%
\n
100.00%
\n
Enel Green Power
\n
Canada Inc.
\n
99.90%
\n
Wild Six Solar Project LLC Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildcat Flats Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Wilderness Range Solar
\n
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 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wildflower Flats Solar Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Wind Belt Transco LLC Andover US 1 USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
Wind Parks Anatolis - Prinias
\n
Single Member SA
\n
Maroussi GR 15,803,388 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Katharas Single
\n
Member SA
\n
Maroussi GR 19,932,048 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Kerasias Single
\n
Member SA
\n
Maroussi GR 26,107,790 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Milias Single
\n
Member SA
\n
Maroussi GR 19,909,374 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Mitikas Single
\n
Member SA
\n
Maroussi GR 22,268,039 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Platanos Single
\n
Member SA
\n
Maroussi GR 13,342,867 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Wind Parks Spilias Single
\n
Member SA
\n
Maroussi GR 28,267,490 EUR
\n
Equity
\n
Enel Green Power
\n
Hellas Wind Parks
\n
South Evia Single
\n
Member SA
\n
100.00% 50.00%
\n
Windbreaker Storage Project
\n
LLC
\n
Andover US 1 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 Wind
\n
LLC
\n
100.00% 100.00%
\n
Wkn Basilicata Development
\n
PE1 Srl
\n
Rome IT 10,000 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
Held for sale
\n
Stillwater Woods Hill
\n
Holdings LLC
\n
100.00% 100.00%
\n
X-bus Italia Srl Milan IT 15,000 EUR
\n
Equity Enel X Italia Srl 20.00% 20.00%
\n
Yacylec SA Buenos Aires AR 20,000,000 ARS
\n
Held for sale Enel Am\u00e9ricas SA 33.33% 27.42 %
\n
Yedesa Cogeneraci\u00f3n SA in
\n
liquidation
\n
Almer\u00eda ES 234,395 EUR
\n
Equity
\n
Enel Green Power
\n
Espa\u00f1a SLU
\n
40.00% 28.05%
\n
\n\n
Company name Headquarters Country Share capital Currency Segment
\n
Consolidation
\n
method Held by % holding
\n
Group %
\n
holding
\n
Yellow Rose Wind Project
\n
LLC
\n
Andover US 1 USD
\n
Line-by-line Enel Kansas LLC 100.00% 100.00%
\n
Yorktown Energy Storage
\n
1 LLC
\n
Boston US - USD
\n
Line-by-line
\n
Enel X North America
\n
Inc.
\n
100.00% 100.00%
\n
Zacapa Topco S\u00e0rl Luxembourg LU 29,970,000 EUR
\n
-
\n
Enel X International
\n
Srl
\n
19.50% 19.50%
\n
Zoo Solar Project LLC Andover US - USD
\n
Line-by-line Tradewind Energy Inc. 100.00% 100.00%
\n
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfCompositionOfGroupExplanatory", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "Tag238": { "value": "Enel SpA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:WOCMU6HCI0OJWNPRZS33", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "footnote1": { "value": "
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cShare of profit/(loss) of equity-accounted investments\u201d referring to Rusenergo-
\n
sbyt LLC, a Russian company sold in December 2023, to \u201cdiscontinued operations\u201d.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote1", "language": "en" } }, "footnote5": { "value": "
1) In order to improve presentation, for comparative purposes only, realized financial income and expense connected solely with borrowings have been reclas-
\n
sified from \u201cCollections/(Payments) associated with derivatives connected with borrowings\u201d in the section on cash flows from financing activities to the items
\n
\u201cInterest income and other financial income collected\u201d and \u201cInterest expense and other financial expense paid\u201d
\n
included in cash flows from operating activities.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote5", "language": "en" } }, "footnote2": { "value": "
(1) The figure for 2022 has been adjusted to reflect the classification of the \u201cChange in translation reserve\u201d referring to Rusenergosbyt LLC, a Russian company
\n
sold in December 2023, to \u201cdiscontinued operations\u201d.
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote2", "language": "en" } }, "footnote3": { "value": "
(1) Figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote3", "language": "en" } }, "footnote4": { "value": "
(1) Figures for 2022 have been adjusted to take account of the effects of the Amendment to IAS 12, which took effect for annual reporting periods beginning
\n
on or after January 1, 2023. For more information, please see note 8 \u201cRestatement of comparative disclosures\u201d
", "dimensions": { "concept": "xbrl:note", "noteId": "footnote4", "language": "en" } } } }