Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy |
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group\u2019s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future. The group\u2019s assumptions for investment appraisal form part of an investment decision-making framework for currently unsanctioned future capital expenditure on property, plant and equipment, and intangibles including exploration and appraisal assets, that is designed to support the effective and resilient implementation of bp\u2019s strategy. The price assumptions used for investment appraisal include oil and gas price assumptions, which are producer prices and are therefore net of any future carbon prices that the purchaser may be required to pay, and an assumption of a single carbon emissions cost imposed on the producer in respect of operational greenhouse gas (GHG) emissions (carbon dioxide and methane) in order to incentivize engineering solutions to mitigate GHG emissions on projects. The group's oil and gas price assumptions for value-in-use impairment testing are aligned with those investment appraisal assumptions. The assumptions for future carbon emissions costs in value-in-use impairment testing differ from the investment appraisal assumptions and are described below. Management has also not identified any off-balance sheet commodity purchase obligations to be onerous contracts as result of the transition to a lower carbon economy at 31 December 2025. |
Impairment of property, plant and equipment and goodwill |
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment and goodwill in the oil and gas industry. Management\u2019s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised during 2025. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced in the short-term reflecting greater crude supply. Medium to long term prices steadily decline to a higher price of $60 per barrel in 2050 continuing to reflect the assumption that the energy system decarbonises but at a slower rate. The price assumptions for Henry Hub gas price have been reduced in the short term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand rebalance before remaining steady at $4.50 per mmBtu up to 2050. The revised assumptions for Brent oil and Henry Hub gas sit within the range of external scenarios considered by management and are in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2\u00b0C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5\u00b0C above pre-industrial levels. |
As noted above, the group\u2019s investment appraisal process includes a carbon emissions price series for the investment economics which is applied to bp's anticipated share of bp's forecast of the investment assets' scope 1 and 2 GHG emissions where they exceed defined thresholds, and is assumed to apply whether or not bp is the asset operator. However, for value-in-use impairment testing on bp's existing cash generating units (CGUs), consistent with all other relevant cash flows estimated, bp is required to reflect management's best estimate of any expected applicable carbon emission costs payable by bp, including where bp is not the operator, in the future for each jurisdiction in which the group has interests. This requires management\u2019s best estimate of how future changes to relevant carbon emission cost policies and/or legislation are likely to affect the future cash flows of the group\u2019s applicable CGUs, whether currently enacted or not. Future potential carbon pricing and/or costs of carbon emissions allowances are included in the value-in-use calculations to the extent management has sufficient information to make such an estimate. Currently this results in limited application of carbon price assumptions in value-in-use impairment tests given that carbon pricing legislation in most impacted jurisdictions where the group has interests is not in place and there is not sufficient information available as to the relevant policy makers' future intentions regarding carbon pricing to support an estimate. A key input into the determination of impairment is the assumption, aligned with bp\u2019s aim to reach net zero greenhouse gas emissions by 2050 or sooner, that the current recognized portfolio of oil and gas properties and refining assets will have an immaterial carrying value by 2050. |
Where we consider that the outcome of a value-in-use impairment test could be significantly affected by a carbon price in place in any jurisdiction, this is incorporated into the value-in use impairment testing cash flows. The most significant instances where a carbon price has been incorporated in the 2025 value-in-use impairment tests is for the UK North Sea. The assumptions for UK North Sea were \u00a365 /tCO2 e in 2026 gradually increasing to \u00a3243 /tCO2e in 2050. However, as bp\u2019s forecast future prices are producer prices, the group considers it reasonable to assume that if, in addition to the costs already in place, further scope 1 and 2 emission costs were partially to be borne directly by oil and gas producers including bp in future and the prevalence of such costs were to become widespread, the gross oil and gas prices realized by producers would be correspondingly higher over the long term, resulting in no expected overall materially negative impacts on the group\u2019s net cash flows. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions and carbon costs. Production assumptions within upstream property, plant and equipment and goodwill value-in-use impairment tests reflect management\u2019s current best estimate of future production of the existing upstream portfolio. See significant judgements and estimates: recoverability of asset carrying values and Note 14 for sensitivity analyses in relation to reasonably possible changes in production for upstream oil and gas properties and goodwill respectively. For the customers & products segment, though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery\u2019s useful life. Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future. |
Exploration and appraisal intangible assets |
The energy transition may affect the future development or viability of exploration prospects. The recoverability of the group's exploration and appraisal intangible assets was considered during 2025. No significant write-offs were identified. These assets will continue to be assessed as the energy transition progresses. See significant judgement: exploration and appraisal intangible assets and Note 8 for further information. |
Property, plant and equipment \u2013 depreciation and expected useful lives |
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, a significant majority of bp\u2019s existing upstream oil and natural gas properties are likely to have immaterial carrying values within the next 12 years and, as outlined in bp's strategy, oil and natural gas production will remain an important part of bp\u2019s business activities over that period. The significant majority of refining assets, recognized on the group\u2019s balance sheet at 31 December 2025 that are subject to depreciation, will be depreciated within the next 11 years; demand for refined products is expected to remain sufficient to support the remaining useful lives of existing assets. Therefore, management does not expect the useful lives of bp\u2019s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects as well as renewal and/or replacement of aged assets and therefore the useful lives of future capital expenditure may be different. See material accounting policy: property, plant and equipment for more information. |
Provisions: decommissioning |
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp\u2019s existing upstream oil and gas properties are expected to start decommissioning within the next two decades. Currently, the expected timing of decommissioning expenditures for the upstream oil and gas assets in the group\u2019s portfolio has not materially been brought forward. Management does not expect a reasonably possible change of two years in the expected timing of all decommissioning to have a material effect on the upstream decommissioning provisions, assuming cost assumptions remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management does not expect manufacturing to cease at refineries within a determinate period of time, as existing property, plant and equipment is expected to be renewed or replaced. Management will continue to review facts and circumstances, including where cessation of manufacturing decisions have been made, to assess if decommissioning provisions need to be recognized. Decommissioning provisions relating to refineries at 31 December 2025 are not material. See significant judgements and estimates: provisions for further information. |
Judgements and estimates made in assessing the impact of the geopolitical and economic environment |
In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the current geopolitical and economic environment. |
Oil and gas price assumptions |
Oil and gas price assumptions applied in value-in-use impairment testing have been updated (as noted above) including for inflation and have been rebased in real 2024 terms. See significant judgements and estimates: recoverability of asset carrying values for further information. |
Discount rate assumptions |
The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact on the nominal discount rate applied to provisions was determined not to be significant and so the rate remained unchanged from 2024. The post-tax impairment discount rate remained consistent with 2024 as did the risk premium applied to the majority of countries classified as higher-risk. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information. |
Pensions and other post-employment benefits |
Volatility in financial markets impact assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group\u2019s defined benefit pension plans. See significant estimate: pensions and other post-employment benefits and Note 24 for further information. |
Significant judgement: investment in Aker BP |
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Aker BP, a Norwegian oil and gas company, is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Aker BP's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Aker BP's oil and natural gas reserves would be reported. Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those decisions. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. bp owned 15.9% of the voting shares at 31 December 2025. bp\u2019s senior vice president North Sea, Doris Reiter, was appointed a member of the Aker BP board during 2024. bp\u2019s other nominated director, group chief financial officer, Kate Thomson, has been a member of the Aker BP board since formation of that company in 2016. She is also a member of the Aker BP board\u2019s Audit and Risk Committee. bp also holds the voting rights at general meetings of shareholders conferred by its stake in Aker BP. bp's management considers, therefore, that the group continues to have significant influence at 31 December 2025. |
Significant judgements and estimate: investment in Rosneft |
Since the first quarter 2022, bp accounts for its interest in Rosneft and its other businesses with Rosneft within Russia, as financial assets measured at fair value within \u2018Other investments\u2019. bp is not able to sell its Rosneft shares on the Moscow Stock Exchange and is unable to ascribe probabilities to possible outcomes of any exit process. It is considered by management that any measure of fair value, other than nil, would be subject to such high measurement uncertainty, considering the sanctions and restrictions implemented by Russia on Russian assets held by foreign investors, that no estimate would provide useful information even if it were accompanied by a description of the estimate made in producing it and an explanation of the uncertainties that affect the estimate. Accordingly, it is not currently possible to estimate any carrying value other than zero when determining the measurement of the interest in Rosneft and the other businesses with Rosneft within Russia as at 31 December 2025. Events or outcomes within the next financial year, that are different to those outlined above, could materially change the fair value of the investment. Russia has imposed restrictions on the payments of dividends to certain foreign shareholders, including those based in the UK, requiring such dividends to be paid in roubles into restricted bank accounts and a requirement for approval of the Russian government for transfers from any such bank accounts out of Russia. Given the restrictions applicable to such accounts, management has made the significant judgement that the criteria for recognizing any dividend income from Rosneft and its other businesses with Rosneft within Russia, for the years to 31 December 2023, 31 December 2024 and 31 December 2025 have not been met. |
Significant judgement: exploration and appraisal intangible assets |
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed. The carrying amount of capitalized costs are included in Note 8. |
15\u00a0to\u00a025\u00a0years | |
20\u00a0to\u00a050\u00a0years | |
20\u00a0to\u00a030 years | |
10 to 50 years | |
15 years | |
3 to 10 years | |
5 to 15 years |
Significant judgements and estimates: recoverability of asset carrying values |
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, carbon pricing (where applicable), production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, power and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15. The estimates for assumptions made in impairment tests in 2025 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment including as a result of the energy transition or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. |
Discount rates |
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use a post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and, in 2025, the post-tax discount rate was 8% (2024 8% ) other than for renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of 1% to 3% was reflected in the post-tax discount rate (2024 1% to 3%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from 9% to 18% (2024 9% to 20%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. For renewable power assets tested on a value-in-use basis, primarily the CGUs for which goodwill was allocated following the Lightsource bp acquisition, a WACC-based post- tax discount rate of 7% was used. For renewable power assets tested on a fair-value basis, primarily offshore wind assets (including those in equity accounted entities), a post-tax cost of equity-based discount rate range of 8.75% to 9.5% (2024 8.75% to 9.5%) was used. |
Oil and natural gas properties |
For oil and natural gas properties in the oil production & operations and gas & low carbon energy segments, expected future cash flows are estimated using management\u2019s best estimate of future oil and natural gas prices, production and reserves and certain resources volumes. Forecast cash flows include the impact of all approved emission reduction projects. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. In 2025, the group identified oil and gas properties in these segments with carrying amounts totalling $20,341 million (2024 $17,853\u00a0million) where the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year, see Sensitivity analyses, below. The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above. |
Oil and natural gas prices |
The price assumptions used for value-in-use impairment testing are based on those used for investment appraisal. bp\u2019s carbon emissions cost assumptions and their interrelationship with oil and gas prices are described in 'Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy' on page 160. The investment appraisal price assumptions were recommended by the senior vice president economic & energy insights after considering a range of external price sets, and supply and demand profiles associated with various energy transition scenarios. They were reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the scenarios considered include those where those goals are met as well as those where they are not met. During the year, bp's price assumptions applied in value-in-use impairment testing were revised. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced to $70 per barrel. Medium to long term prices steadily decline to a higher price of $60 per barrel by 2050 continuing to reflect the assumption that the energy system decarbonizes but at a slower rate. The price assumptions for the Henry Hub price have been reduced in the near term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand remain steady at $4.50 per mmBtu up to 2050. These price assumptions are derived from the central case investment appraisal assumptions. A summary of the group\u2019s revised price assumptions for Brent oil and Henry Hub gas, applied in 2025 and 2024, in real 2024 terms, is provided below. The assumptions represent management\u2019s best estimate of future prices at the balance sheet date, which sit within the range of external scenarios considered as appropriate for the purpose. They are considered by bp to be in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2\u00b0C above pre- industrial levels and pursuing efforts to limit the temperature increase to 1.5\u00b0C above pre-industrial levels. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2.0% - 3.0% (2024 2.0%-2.5%) is applied to determine the price assumptions in nominal terms. |
The majority of bp\u2019s reserves and resources that support the carrying value of the group\u2019s existing oil and gas properties are expected to be produced over the next 12 years. |
The recoverability of deferred tax assets is also affected by the group\u2019s oil and natural gas price assumptions as these could impact the estimate of future taxable profits. See Note 9 for further information. |
2025 price assumptions | 2026 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | 70 | 70 | 67 | 60 | |
Henry Hub gas ($/mmBtu) | 3.80 | 4.10 | 4.50 | 4.50 |
2024 price assumptions | 2025 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | 71 | 71 | 64 | 50 | |
Henry Hub gas ($/mmBtu) | 4.07 | 4.04 | 4.04 | 4.04 |
Global oil production increased by 3mmb/d (3%) in 2025, with non-OPEC+ countries contributing nearly 60% of the growth. Global oil demand grew by only 0.8% in 2025, almost entirely accounted for by non-OECD countries, following sharp fall in oil demand from Brazil, India and China. The global supply/demand imbalance of around 2.2mmb/d weighed on prices, with Dated Brent down by nearly $12 per barrel. While geopolitical risk (e.g., tariffs, sanctions) may support prices in the short-term, bp's long-term assumption for oil prices is lower than the 2025 average as oil demand is likely to fall such that the price levels needed to encourage sufficient investment to meet global oil demand will also be lower. The US Henry Hub (HH) spot price averaged $3.5 per mmBtu in 2025, up from $2.2 per mmBtu in 2024 and the highest level since 2022, driven by increased LNG export demand and a colder-than-normal start to the year. Higher gas prices supported a recovery in drilling activity in non- associated (dry) shale plays which, combined with well productivity gains, increasing gas-to-oil ratios in the Permian, and increased pipeline connectivity, meant that US dry gas production grew by 4% year on year and reached record high levels.The level of US gas prices in 2025 was below bp\u2019s long term price assumption based on the judgment of the price level required to incentivize new production. |
Oil and natural gas reserves |
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group\u2019s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group\u2019s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable. |
Sensitivity analyses |
Management considers discount rates, oil and natural gas prices and production to be the key sources of estimation uncertainty in determining the recoverable amount of upstream oil and gas assets. The sensitivity analyses below, in addition to covering the key sources of estimation uncertainty, also indicate how the energy transition, potential future carbon emissions costs for operational GHG emissions and/or reduced demand for oil and gas may further impact forecast revenue cash inflows to a greater extent than currently anticipated in the group\u2019s value-in-use estimates for oil and gas CGUs, if carbon emissions costs were to be implemented as a deduction against revenue cash flows. The analyses therefore represent a net revenue sensitivity. A change in net revenue from upstream oil and gas properties can arise either due to changes in oil and natural gas prices, carbon emissions costs/carbon prices, changes in oil and natural gas production, or a combination of these. Management tested the impact of changes in net revenue cash flows in value-in-use impairment testing under the following sensitivity analyses: an increase in net revenues of 8% in all years up to 2040, and 25% in all remaining years to 2050; and a decrease in net revenues of 20% in all years up to 2030, 35% in all subsequent years to 2040 and 50% in all remaining years to 2050. Net revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp\u2019s currently held upstream oil and gas properties in the range of $20-21 billion which is approximately 34% of the associated net book value of property, plant and equipment as at 31 December 2025. If this net revenue reduction was due to reductions in prices in isolation, it reflects an indicative decrease in the carrying amount of using price assumptions for Brent oil trending broadly towards the bottom of the range of prices associated with the 'family' of scenarios in our Transition Scenario Catalogue considered, by source data providers, to be consistent with limiting global average temperature to 1.5\u00b0C above pre-industrial levels. This Catalogue of scenarios is also used in bp's TCFD resilience scenario analysis. Net revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp\u2019s currently held upstream oil and gas properties in the range of $1-2 billion which is approximately 2-3% of the associated net book value of property, plant and equipment as at 31 December 2025. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments and represents approximately 15% of the total impairment reversal capacity available at 31 December 2025. If this net revenue increase was due to increases in prices in isolation, it reflects an indicative increase in the carrying amount of using price assumptions for Brent oil trending broadly aligned with the top end until the mid-2040s, and then towards the mean average at 2050, of the range of prices associated with the Transition Scenario Catalogue of scenarios (which included the IEA\u2019s World Energy Outlook Net Zero Emissions by 2050 (NZE) scenario) considered by IEA to be consistent with limiting global average temperature to 1.5\u00b0C above pre-industrial levels. |
These sensitivity analyses do not, however, represent management\u2019s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The analyses also assume the impact of increases in carbon price on operational GHG emissions are fully absorbed as a decrease in net revenue (and vice versa) rather than reflecting how carbon prices or other carbon emissions costs may ultimately be incorporated by the market. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors plus the diverse characteristics of the group's upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of upstream oil and gas properties. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $0.2\u00a0billion higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been approximately $0.5\u00a0billion lower. |
Management considers discount rate, renewable natural gas prices, and the level of capital expenditure and its consequential impact on production volumes to be the key sources of estimation uncertainty in determining the recoverable amount of the group\u2019s renewable natural gas assets owned by Archaea Energy. A change in revenue from renewable natural gas assets could arise either due to changes in renewable natural gas prices, changes in renewable natural gas production, principally as a result of changes in capital invested, or a combination of both. Management tested the impact of changes in net revenue cash flows on its value-in-use impairment testing. It is estimated that a reduction in revenue across all Archaea Energy assets of 10% would have resulted in an additional impairment charge of $0.5\u00a0billion. It is estimated that an increase in revenue of 10% would have resulted in a reduction to the impairment charge of $0.8\u00a0billion. These sensitivity analyses do not, however, represent management\u2019s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. It is estimated that an increase to the discount rate of 1% would have resulted in an additional impairment charge to Archaea Energy assets of $0.3\u00a0billion. It is estimated that a decrease in the discount rate of 1% would have resulted in a reduction to the impairment charge of $0.4\u00a0billion. |
Management considers discount rates and refining margins to be the key sources of estimation uncertainty in determining the recoverable amount of refinery assets. The sensitivity analysis below, in addition to covering the key sources of estimation uncertainty, also indicates how the energy transition and/or reduced demand for refined products may further impact forecast cash inflows to a greater extent than currently anticipated in the group\u2019s value-in-use estimates for refinery CGUs. Management tested the impact of a $1 per barrel decrease in each refinery\u2019s future margin assumption in all years of the value-in-use estimate. A reduction of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp\u2019s currently held refining property, plant and equipment in the range of $1-2\u00a0billion. This sensitivity analysis does not, however, represent management\u2019s best estimate of any impairment charges that might be recognized as it does not fully incorporate consequential changes that may arise, such as changes in costs and business plans and crude or product slates. The above sensitivity analysis therefore does not reflect a linear relationship between margins and value that can be extrapolated. The interdependency of these inputs and factors plus the varying configurations of the group's refineries limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the margin assumptions. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of refinery assets. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $0.5 billion higher. If the discount rate was one percentage point lower there would have been no impact on the net impairment loss recognized in 2025. |
Goodwill |
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of $10.3 billion on its balance sheet (2024 $14.9 billion), principally relating to the Atlantic Richfield, Devon Energy, Reliance transactions and its transition businesses. Of this, $7.1\u00a0billion relates to goodwill in the oil production & operations segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $7.2\u00a0billion), for which oil and gas price and production assumptions are key sources of estimation uncertainty. A further $0.9\u00a0billion relates to the transition businesses in the gas & low carbon energy segment (2024 $2.9\u00a0billion), for which project development revenues and margins, terminal value growth rate and discount rate are key sources of estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in Note 14. |
Significant judgement: supplier financing arrangements |
The group\u2019s trade payables include some supplier financing arrangements that utilize letter of credit facilities, promissory notes and reverse factoring. Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information. |
Significant estimate and judgement: derivative financial instruments | |
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market- corroborated data. This primarily applies to the group\u2019s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular, contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement and are accounted for on an accruals basis, rather than as a derivative. Under IFRS, bp fair values the derivative financial instruments used to risk-manage the LNG contracts themselves, resulting in a measurement mismatch. For more information, including the carrying amounts of level 3 derivatives, see Note 30 . | 0 |
Significant judgements and estimates: provisions |
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and, where still recognized, the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. This typically requires assessment of the local legal requirements and the financial standing of the owner. If the standing deteriorates significantly, for example, bankruptcy of the owner, a provision may be required. The group has $0.6\u00a0billion of decommissioning provisions recognized as at 31 December 2025 (2024 $0.7\u00a0billion) for assets previously sold to third parties where the sale transferred the decommissioning obligation to the new owner. See Note 33 for further information. Decommissioning provisions associated with refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates. Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates. See Note 33 for further information. The group performs periodic reviews of its refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision. Portfolio strength and flexibility are such that the point of cessation of manufacturing at the group\u2019s operating refineries is not yet expected within a determinate time period, as existing property plant and equipment is expected to be renewed or replaced. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2025 was 4.5% (2024 4.5%), which was based on long-dated US government bonds interpolated to reflect the expected weighted average time to decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 16 years (2024 17 years) and 7 years (2024 7 years) respectively. Costs at future prices are typically determined by applying an inflation rate of 1.5% (2024 1.5%) to decommissioning costs and 2% (2024 2%) for all other provisions. A lower rate is typically applied to decommissioning as certain costs are expected to remain fixed at current or past prices. The estimated phasing of undiscounted cash flows in real terms for upstream decommissioning is approximately $5.7\u00a0billion (2024 $5.5\u00a0billion) within the next 10 years, $6.0\u00a0billion (2024 $6.2\u00a0billion) in 10 to 20 years and the remainder of approximately $7.0\u00a0billion (2024 $6.7\u00a0billion ) after 20 years. The timing and amount of decommissioning cash flows are inherently uncertain and therefore the phasing is management\u2019s current best estimate but may not be what will ultimately occur. Further information about the group\u2019s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0 percentage point increase in the nominal discount rate applied could decrease the group\u2019s provision balances by approximately $1.4\u00a0billion (2024 $1.5\u00a0billion). The pre-tax impact on the group income statement would be a credit of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion). This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. The discounting impact on the group's decommissioning provisions for oil and gas properties in the oil productions & operations and gas & low carbon energy segments of a two-year change in the timing of expected future decommissioning expenditures is approximately $0.7\u00a0billion (2024 $0.3\u00a0billion). Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year and therefore the timing of upstream decommissioning expenditure is not a key source of estimation uncertainty. If all expected future decommissioning expenditures were 10% higher, then these decommissioning provisions would increase by approximately $1.2 billion (2024 $1.2\u00a0billion) and a pre-tax charge of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion) would be recognized. A one percentage point increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the decommissioning provision by approximately $1.8\u00a0billion (2024 $1.7\u00a0billion) with a pre-tax charge of approximately $0.4\u00a0billion (2024 $0.5\u00a0billion). As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. |
Significant estimate: pensions and other post-employment benefits |
Accounting for defined benefit pensions and other post-employment benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pensions and other post-employment benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet and pension and other post-employment benefit expense for the following year. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-employment benefit obligations within the next financial year. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24. |
Significant judgement and estimate: taxation |
The value of deferred tax assets and liabilities is an area involving inherent uncertainty and estimation and balances are therefore subject to risk of material change as a result of underlying assumptions and judgements used, in particular the forecast of future profitability used to determine the recoverability of deferred tax, for example future oil and gas prices, see \u2018Significant judgement and estimates - Recoverability of asset carrying values\u2019. It is impracticable to disclose the extent of the possible effects of profitability assumptions on the group\u2019s deferred tax assets. It is reasonably possible that to the extent that actual outcomes differ from management\u2019s estimates, material income tax charges or credits, and material changes in current and deferred tax assets or liabilities, may arise within the next financial year and in future periods. Judgement is required when determining whether a particular tax is an income tax or another type of tax (for example, a production tax). The attributes of the tax, including whether it is calculated on profits or another measure such as production or revenues, the extent of deductibility of costs and the interaction with existing income taxes, are considered in determining the classification of the tax. Accounting for deferred tax is applied to income taxes as described above but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. This judgement is considered significant only in relation to the group\u2019s taxes payable under the fiscal terms of bp\u2019s onshore concession in Abu Dhabi. These are principally reported as income taxes rather than as production taxes. For more information see Note 9 and Note 33. |
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy |
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group\u2019s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future. The group\u2019s assumptions for investment appraisal form part of an investment decision-making framework for currently unsanctioned future capital expenditure on property, plant and equipment, and intangibles including exploration and appraisal assets, that is designed to support the effective and resilient implementation of bp\u2019s strategy. The price assumptions used for investment appraisal include oil and gas price assumptions, which are producer prices and are therefore net of any future carbon prices that the purchaser may be required to pay, and an assumption of a single carbon emissions cost imposed on the producer in respect of operational greenhouse gas (GHG) emissions (carbon dioxide and methane) in order to incentivize engineering solutions to mitigate GHG emissions on projects. The group's oil and gas price assumptions for value-in-use impairment testing are aligned with those investment appraisal assumptions. The assumptions for future carbon emissions costs in value-in-use impairment testing differ from the investment appraisal assumptions and are described below. Management has also not identified any off-balance sheet commodity purchase obligations to be onerous contracts as result of the transition to a lower carbon economy at 31 December 2025. |
Impairment of property, plant and equipment and goodwill |
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment and goodwill in the oil and gas industry. Management\u2019s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised during 2025. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced in the short-term reflecting greater crude supply. Medium to long term prices steadily decline to a higher price of $60 per barrel in 2050 continuing to reflect the assumption that the energy system decarbonises but at a slower rate. The price assumptions for Henry Hub gas price have been reduced in the short term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand rebalance before remaining steady at $4.50 per mmBtu up to 2050. The revised assumptions for Brent oil and Henry Hub gas sit within the range of external scenarios considered by management and are in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2\u00b0C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5\u00b0C above pre-industrial levels. |
As noted above, the group\u2019s investment appraisal process includes a carbon emissions price series for the investment economics which is applied to bp's anticipated share of bp's forecast of the investment assets' scope 1 and 2 GHG emissions where they exceed defined thresholds, and is assumed to apply whether or not bp is the asset operator. However, for value-in-use impairment testing on bp's existing cash generating units (CGUs), consistent with all other relevant cash flows estimated, bp is required to reflect management's best estimate of any expected applicable carbon emission costs payable by bp, including where bp is not the operator, in the future for each jurisdiction in which the group has interests. This requires management\u2019s best estimate of how future changes to relevant carbon emission cost policies and/or legislation are likely to affect the future cash flows of the group\u2019s applicable CGUs, whether currently enacted or not. Future potential carbon pricing and/or costs of carbon emissions allowances are included in the value-in-use calculations to the extent management has sufficient information to make such an estimate. Currently this results in limited application of carbon price assumptions in value-in-use impairment tests given that carbon pricing legislation in most impacted jurisdictions where the group has interests is not in place and there is not sufficient information available as to the relevant policy makers' future intentions regarding carbon pricing to support an estimate. A key input into the determination of impairment is the assumption, aligned with bp\u2019s aim to reach net zero greenhouse gas emissions by 2050 or sooner, that the current recognized portfolio of oil and gas properties and refining assets will have an immaterial carrying value by 2050. |
Where we consider that the outcome of a value-in-use impairment test could be significantly affected by a carbon price in place in any jurisdiction, this is incorporated into the value-in use impairment testing cash flows. The most significant instances where a carbon price has been incorporated in the 2025 value-in-use impairment tests is for the UK North Sea. The assumptions for UK North Sea were \u00a365 /tCO2 e in 2026 gradually increasing to \u00a3243 /tCO2e in 2050. However, as bp\u2019s forecast future prices are producer prices, the group considers it reasonable to assume that if, in addition to the costs already in place, further scope 1 and 2 emission costs were partially to be borne directly by oil and gas producers including bp in future and the prevalence of such costs were to become widespread, the gross oil and gas prices realized by producers would be correspondingly higher over the long term, resulting in no expected overall materially negative impacts on the group\u2019s net cash flows. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions and carbon costs. Production assumptions within upstream property, plant and equipment and goodwill value-in-use impairment tests reflect management\u2019s current best estimate of future production of the existing upstream portfolio. See significant judgements and estimates: recoverability of asset carrying values and Note 14 for sensitivity analyses in relation to reasonably possible changes in production for upstream oil and gas properties and goodwill respectively. For the customers & products segment, though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery\u2019s useful life. Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future. |
Exploration and appraisal intangible assets |
The energy transition may affect the future development or viability of exploration prospects. The recoverability of the group's exploration and appraisal intangible assets was considered during 2025. No significant write-offs were identified. These assets will continue to be assessed as the energy transition progresses. See significant judgement: exploration and appraisal intangible assets and Note 8 for further information. |
Property, plant and equipment \u2013 depreciation and expected useful lives |
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, a significant majority of bp\u2019s existing upstream oil and natural gas properties are likely to have immaterial carrying values within the next 12 years and, as outlined in bp's strategy, oil and natural gas production will remain an important part of bp\u2019s business activities over that period. The significant majority of refining assets, recognized on the group\u2019s balance sheet at 31 December 2025 that are subject to depreciation, will be depreciated within the next 11 years; demand for refined products is expected to remain sufficient to support the remaining useful lives of existing assets. Therefore, management does not expect the useful lives of bp\u2019s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects as well as renewal and/or replacement of aged assets and therefore the useful lives of future capital expenditure may be different. See material accounting policy: property, plant and equipment for more information. |
Provisions: decommissioning |
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp\u2019s existing upstream oil and gas properties are expected to start decommissioning within the next two decades. Currently, the expected timing of decommissioning expenditures for the upstream oil and gas assets in the group\u2019s portfolio has not materially been brought forward. Management does not expect a reasonably possible change of two years in the expected timing of all decommissioning to have a material effect on the upstream decommissioning provisions, assuming cost assumptions remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management does not expect manufacturing to cease at refineries within a determinate period of time, as existing property, plant and equipment is expected to be renewed or replaced. Management will continue to review facts and circumstances, including where cessation of manufacturing decisions have been made, to assess if decommissioning provisions need to be recognized. Decommissioning provisions relating to refineries at 31 December 2025 are not material. See significant judgements and estimates: provisions for further information. |
Judgements and estimates made in assessing the impact of the geopolitical and economic environment |
In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the current geopolitical and economic environment. |
Oil and gas price assumptions |
Oil and gas price assumptions applied in value-in-use impairment testing have been updated (as noted above) including for inflation and have been rebased in real 2024 terms. See significant judgements and estimates: recoverability of asset carrying values for further information. |
Discount rate assumptions |
The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact on the nominal discount rate applied to provisions was determined not to be significant and so the rate remained unchanged from 2024. The post-tax impairment discount rate remained consistent with 2024 as did the risk premium applied to the majority of countries classified as higher-risk. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information. |
Pensions and other post-employment benefits |
Volatility in financial markets impact assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group\u2019s defined benefit pension plans. See significant estimate: pensions and other post-employment benefits and Note 24 for further information. |
Significant judgement: investment in Aker BP |
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Aker BP, a Norwegian oil and gas company, is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Aker BP's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Aker BP's oil and natural gas reserves would be reported. Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those decisions. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. bp owned 15.9% of the voting shares at 31 December 2025. bp\u2019s senior vice president North Sea, Doris Reiter, was appointed a member of the Aker BP board during 2024. bp\u2019s other nominated director, group chief financial officer, Kate Thomson, has been a member of the Aker BP board since formation of that company in 2016. She is also a member of the Aker BP board\u2019s Audit and Risk Committee. bp also holds the voting rights at general meetings of shareholders conferred by its stake in Aker BP. bp's management considers, therefore, that the group continues to have significant influence at 31 December 2025. |
Significant judgements and estimate: investment in Rosneft |
Since the first quarter 2022, bp accounts for its interest in Rosneft and its other businesses with Rosneft within Russia, as financial assets measured at fair value within \u2018Other investments\u2019. bp is not able to sell its Rosneft shares on the Moscow Stock Exchange and is unable to ascribe probabilities to possible outcomes of any exit process. It is considered by management that any measure of fair value, other than nil, would be subject to such high measurement uncertainty, considering the sanctions and restrictions implemented by Russia on Russian assets held by foreign investors, that no estimate would provide useful information even if it were accompanied by a description of the estimate made in producing it and an explanation of the uncertainties that affect the estimate. Accordingly, it is not currently possible to estimate any carrying value other than zero when determining the measurement of the interest in Rosneft and the other businesses with Rosneft within Russia as at 31 December 2025. Events or outcomes within the next financial year, that are different to those outlined above, could materially change the fair value of the investment. Russia has imposed restrictions on the payments of dividends to certain foreign shareholders, including those based in the UK, requiring such dividends to be paid in roubles into restricted bank accounts and a requirement for approval of the Russian government for transfers from any such bank accounts out of Russia. Given the restrictions applicable to such accounts, management has made the significant judgement that the criteria for recognizing any dividend income from Rosneft and its other businesses with Rosneft within Russia, for the years to 31 December 2023, 31 December 2024 and 31 December 2025 have not been met. |
Significant judgement: exploration and appraisal intangible assets |
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed. The carrying amount of capitalized costs are included in Note 8. |
15\u00a0to\u00a025\u00a0years | |
20\u00a0to\u00a050\u00a0years | |
20\u00a0to\u00a030 years | |
10 to 50 years | |
15 years | |
3 to 10 years | |
5 to 15 years |
Significant judgements and estimates: recoverability of asset carrying values |
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, carbon pricing (where applicable), production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, power and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15. The estimates for assumptions made in impairment tests in 2025 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment including as a result of the energy transition or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. |
Discount rates |
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use a post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and, in 2025, the post-tax discount rate was 8% (2024 8% ) other than for renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of 1% to 3% was reflected in the post-tax discount rate (2024 1% to 3%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from 9% to 18% (2024 9% to 20%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. For renewable power assets tested on a value-in-use basis, primarily the CGUs for which goodwill was allocated following the Lightsource bp acquisition, a WACC-based post- tax discount rate of 7% was used. For renewable power assets tested on a fair-value basis, primarily offshore wind assets (including those in equity accounted entities), a post-tax cost of equity-based discount rate range of 8.75% to 9.5% (2024 8.75% to 9.5%) was used. |
Oil and natural gas properties |
For oil and natural gas properties in the oil production & operations and gas & low carbon energy segments, expected future cash flows are estimated using management\u2019s best estimate of future oil and natural gas prices, production and reserves and certain resources volumes. Forecast cash flows include the impact of all approved emission reduction projects. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. In 2025, the group identified oil and gas properties in these segments with carrying amounts totalling $20,341 million (2024 $17,853\u00a0million) where the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year, see Sensitivity analyses, below. The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above. |
Oil and natural gas prices |
The price assumptions used for value-in-use impairment testing are based on those used for investment appraisal. bp\u2019s carbon emissions cost assumptions and their interrelationship with oil and gas prices are described in 'Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy' on page 160. The investment appraisal price assumptions were recommended by the senior vice president economic & energy insights after considering a range of external price sets, and supply and demand profiles associated with various energy transition scenarios. They were reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the scenarios considered include those where those goals are met as well as those where they are not met. During the year, bp's price assumptions applied in value-in-use impairment testing were revised. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced to $70 per barrel. Medium to long term prices steadily decline to a higher price of $60 per barrel by 2050 continuing to reflect the assumption that the energy system decarbonizes but at a slower rate. The price assumptions for the Henry Hub price have been reduced in the near term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand remain steady at $4.50 per mmBtu up to 2050. These price assumptions are derived from the central case investment appraisal assumptions. A summary of the group\u2019s revised price assumptions for Brent oil and Henry Hub gas, applied in 2025 and 2024, in real 2024 terms, is provided below. The assumptions represent management\u2019s best estimate of future prices at the balance sheet date, which sit within the range of external scenarios considered as appropriate for the purpose. They are considered by bp to be in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2\u00b0C above pre- industrial levels and pursuing efforts to limit the temperature increase to 1.5\u00b0C above pre-industrial levels. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2.0% - 3.0% (2024 2.0%-2.5%) is applied to determine the price assumptions in nominal terms. |
The majority of bp\u2019s reserves and resources that support the carrying value of the group\u2019s existing oil and gas properties are expected to be produced over the next 12 years. |
The recoverability of deferred tax assets is also affected by the group\u2019s oil and natural gas price assumptions as these could impact the estimate of future taxable profits. See Note 9 for further information. |
2025 price assumptions | 2026 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | 70 | 70 | 67 | 60 | |
Henry Hub gas ($/mmBtu) | 3.80 | 4.10 | 4.50 | 4.50 |
2024 price assumptions | 2025 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | 71 | 71 | 64 | 50 | |
Henry Hub gas ($/mmBtu) | 4.07 | 4.04 | 4.04 | 4.04 |
Global oil production increased by 3mmb/d (3%) in 2025, with non-OPEC+ countries contributing nearly 60% of the growth. Global oil demand grew by only 0.8% in 2025, almost entirely accounted for by non-OECD countries, following sharp fall in oil demand from Brazil, India and China. The global supply/demand imbalance of around 2.2mmb/d weighed on prices, with Dated Brent down by nearly $12 per barrel. While geopolitical risk (e.g., tariffs, sanctions) may support prices in the short-term, bp's long-term assumption for oil prices is lower than the 2025 average as oil demand is likely to fall such that the price levels needed to encourage sufficient investment to meet global oil demand will also be lower. The US Henry Hub (HH) spot price averaged $3.5 per mmBtu in 2025, up from $2.2 per mmBtu in 2024 and the highest level since 2022, driven by increased LNG export demand and a colder-than-normal start to the year. Higher gas prices supported a recovery in drilling activity in non- associated (dry) shale plays which, combined with well productivity gains, increasing gas-to-oil ratios in the Permian, and increased pipeline connectivity, meant that US dry gas production grew by 4% year on year and reached record high levels.The level of US gas prices in 2025 was below bp\u2019s long term price assumption based on the judgment of the price level required to incentivize new production. |
Oil and natural gas reserves |
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group\u2019s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group\u2019s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable. |
Sensitivity analyses |
Management considers discount rates, oil and natural gas prices and production to be the key sources of estimation uncertainty in determining the recoverable amount of upstream oil and gas assets. The sensitivity analyses below, in addition to covering the key sources of estimation uncertainty, also indicate how the energy transition, potential future carbon emissions costs for operational GHG emissions and/or reduced demand for oil and gas may further impact forecast revenue cash inflows to a greater extent than currently anticipated in the group\u2019s value-in-use estimates for oil and gas CGUs, if carbon emissions costs were to be implemented as a deduction against revenue cash flows. The analyses therefore represent a net revenue sensitivity. A change in net revenue from upstream oil and gas properties can arise either due to changes in oil and natural gas prices, carbon emissions costs/carbon prices, changes in oil and natural gas production, or a combination of these. Management tested the impact of changes in net revenue cash flows in value-in-use impairment testing under the following sensitivity analyses: an increase in net revenues of 8% in all years up to 2040, and 25% in all remaining years to 2050; and a decrease in net revenues of 20% in all years up to 2030, 35% in all subsequent years to 2040 and 50% in all remaining years to 2050. Net revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp\u2019s currently held upstream oil and gas properties in the range of $20-21 billion which is approximately 34% of the associated net book value of property, plant and equipment as at 31 December 2025. If this net revenue reduction was due to reductions in prices in isolation, it reflects an indicative decrease in the carrying amount of using price assumptions for Brent oil trending broadly towards the bottom of the range of prices associated with the 'family' of scenarios in our Transition Scenario Catalogue considered, by source data providers, to be consistent with limiting global average temperature to 1.5\u00b0C above pre-industrial levels. This Catalogue of scenarios is also used in bp's TCFD resilience scenario analysis. Net revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp\u2019s currently held upstream oil and gas properties in the range of $1-2 billion which is approximately 2-3% of the associated net book value of property, plant and equipment as at 31 December 2025. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments and represents approximately 15% of the total impairment reversal capacity available at 31 December 2025. If this net revenue increase was due to increases in prices in isolation, it reflects an indicative increase in the carrying amount of using price assumptions for Brent oil trending broadly aligned with the top end until the mid-2040s, and then towards the mean average at 2050, of the range of prices associated with the Transition Scenario Catalogue of scenarios (which included the IEA\u2019s World Energy Outlook Net Zero Emissions by 2050 (NZE) scenario) considered by IEA to be consistent with limiting global average temperature to 1.5\u00b0C above pre-industrial levels. |
These sensitivity analyses do not, however, represent management\u2019s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The analyses also assume the impact of increases in carbon price on operational GHG emissions are fully absorbed as a decrease in net revenue (and vice versa) rather than reflecting how carbon prices or other carbon emissions costs may ultimately be incorporated by the market. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors plus the diverse characteristics of the group's upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of upstream oil and gas properties. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $0.2\u00a0billion higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been approximately $0.5\u00a0billion lower. |
Management considers discount rate, renewable natural gas prices, and the level of capital expenditure and its consequential impact on production volumes to be the key sources of estimation uncertainty in determining the recoverable amount of the group\u2019s renewable natural gas assets owned by Archaea Energy. A change in revenue from renewable natural gas assets could arise either due to changes in renewable natural gas prices, changes in renewable natural gas production, principally as a result of changes in capital invested, or a combination of both. Management tested the impact of changes in net revenue cash flows on its value-in-use impairment testing. It is estimated that a reduction in revenue across all Archaea Energy assets of 10% would have resulted in an additional impairment charge of $0.5\u00a0billion. It is estimated that an increase in revenue of 10% would have resulted in a reduction to the impairment charge of $0.8\u00a0billion. These sensitivity analyses do not, however, represent management\u2019s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. It is estimated that an increase to the discount rate of 1% would have resulted in an additional impairment charge to Archaea Energy assets of $0.3\u00a0billion. It is estimated that a decrease in the discount rate of 1% would have resulted in a reduction to the impairment charge of $0.4\u00a0billion. |
Management considers discount rates and refining margins to be the key sources of estimation uncertainty in determining the recoverable amount of refinery assets. The sensitivity analysis below, in addition to covering the key sources of estimation uncertainty, also indicates how the energy transition and/or reduced demand for refined products may further impact forecast cash inflows to a greater extent than currently anticipated in the group\u2019s value-in-use estimates for refinery CGUs. Management tested the impact of a $1 per barrel decrease in each refinery\u2019s future margin assumption in all years of the value-in-use estimate. A reduction of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp\u2019s currently held refining property, plant and equipment in the range of $1-2\u00a0billion. This sensitivity analysis does not, however, represent management\u2019s best estimate of any impairment charges that might be recognized as it does not fully incorporate consequential changes that may arise, such as changes in costs and business plans and crude or product slates. The above sensitivity analysis therefore does not reflect a linear relationship between margins and value that can be extrapolated. The interdependency of these inputs and factors plus the varying configurations of the group's refineries limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the margin assumptions. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of refinery assets. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $0.5 billion higher. If the discount rate was one percentage point lower there would have been no impact on the net impairment loss recognized in 2025. |
Goodwill |
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of $10.3 billion on its balance sheet (2024 $14.9 billion), principally relating to the Atlantic Richfield, Devon Energy, Reliance transactions and its transition businesses. Of this, $7.1\u00a0billion relates to goodwill in the oil production & operations segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $7.2\u00a0billion), for which oil and gas price and production assumptions are key sources of estimation uncertainty. A further $0.9\u00a0billion relates to the transition businesses in the gas & low carbon energy segment (2024 $2.9\u00a0billion), for which project development revenues and margins, terminal value growth rate and discount rate are key sources of estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in Note 14. |
Significant judgement: supplier financing arrangements |
The group\u2019s trade payables include some supplier financing arrangements that utilize letter of credit facilities, promissory notes and reverse factoring. Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information. |
Significant judgement: supplier financing arrangements |
The group\u2019s trade payables include some supplier financing arrangements that utilize letter of credit facilities, promissory notes and reverse factoring. Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information. |
Significant estimate and judgement: derivative financial instruments | |
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market- corroborated data. This primarily applies to the group\u2019s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular, contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement and are accounted for on an accruals basis, rather than as a derivative. Under IFRS, bp fair values the derivative financial instruments used to risk-manage the LNG contracts themselves, resulting in a measurement mismatch. For more information, including the carrying amounts of level 3 derivatives, see Note 30 . | 0 |
Significant judgements and estimates: provisions |
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and, where still recognized, the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. This typically requires assessment of the local legal requirements and the financial standing of the owner. If the standing deteriorates significantly, for example, bankruptcy of the owner, a provision may be required. The group has $0.6\u00a0billion of decommissioning provisions recognized as at 31 December 2025 (2024 $0.7\u00a0billion) for assets previously sold to third parties where the sale transferred the decommissioning obligation to the new owner. See Note 33 for further information. Decommissioning provisions associated with refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates. Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates. See Note 33 for further information. The group performs periodic reviews of its refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision. Portfolio strength and flexibility are such that the point of cessation of manufacturing at the group\u2019s operating refineries is not yet expected within a determinate time period, as existing property plant and equipment is expected to be renewed or replaced. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2025 was 4.5% (2024 4.5%), which was based on long-dated US government bonds interpolated to reflect the expected weighted average time to decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 16 years (2024 17 years) and 7 years (2024 7 years) respectively. Costs at future prices are typically determined by applying an inflation rate of 1.5% (2024 1.5%) to decommissioning costs and 2% (2024 2%) for all other provisions. A lower rate is typically applied to decommissioning as certain costs are expected to remain fixed at current or past prices. The estimated phasing of undiscounted cash flows in real terms for upstream decommissioning is approximately $5.7\u00a0billion (2024 $5.5\u00a0billion) within the next 10 years, $6.0\u00a0billion (2024 $6.2\u00a0billion) in 10 to 20 years and the remainder of approximately $7.0\u00a0billion (2024 $6.7\u00a0billion ) after 20 years. The timing and amount of decommissioning cash flows are inherently uncertain and therefore the phasing is management\u2019s current best estimate but may not be what will ultimately occur. Further information about the group\u2019s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0 percentage point increase in the nominal discount rate applied could decrease the group\u2019s provision balances by approximately $1.4\u00a0billion (2024 $1.5\u00a0billion). The pre-tax impact on the group income statement would be a credit of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion). This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. The discounting impact on the group's decommissioning provisions for oil and gas properties in the oil productions & operations and gas & low carbon energy segments of a two-year change in the timing of expected future decommissioning expenditures is approximately $0.7\u00a0billion (2024 $0.3\u00a0billion). Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year and therefore the timing of upstream decommissioning expenditure is not a key source of estimation uncertainty. If all expected future decommissioning expenditures were 10% higher, then these decommissioning provisions would increase by approximately $1.2 billion (2024 $1.2\u00a0billion) and a pre-tax charge of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion) would be recognized. A one percentage point increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the decommissioning provision by approximately $1.8\u00a0billion (2024 $1.7\u00a0billion) with a pre-tax charge of approximately $0.4\u00a0billion (2024 $0.5\u00a0billion). As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. |
Significant judgements and estimates: provisions |
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and, where still recognized, the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. This typically requires assessment of the local legal requirements and the financial standing of the owner. If the standing deteriorates significantly, for example, bankruptcy of the owner, a provision may be required. The group has $0.6\u00a0billion of decommissioning provisions recognized as at 31 December 2025 (2024 $0.7\u00a0billion) for assets previously sold to third parties where the sale transferred the decommissioning obligation to the new owner. See Note 33 for further information. Decommissioning provisions associated with refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates. Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates. See Note 33 for further information. The group performs periodic reviews of its refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision. Portfolio strength and flexibility are such that the point of cessation of manufacturing at the group\u2019s operating refineries is not yet expected within a determinate time period, as existing property plant and equipment is expected to be renewed or replaced. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2025 was 4.5% (2024 4.5%), which was based on long-dated US government bonds interpolated to reflect the expected weighted average time to decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 16 years (2024 17 years) and 7 years (2024 7 years) respectively. Costs at future prices are typically determined by applying an inflation rate of 1.5% (2024 1.5%) to decommissioning costs and 2% (2024 2%) for all other provisions. A lower rate is typically applied to decommissioning as certain costs are expected to remain fixed at current or past prices. The estimated phasing of undiscounted cash flows in real terms for upstream decommissioning is approximately $5.7\u00a0billion (2024 $5.5\u00a0billion) within the next 10 years, $6.0\u00a0billion (2024 $6.2\u00a0billion) in 10 to 20 years and the remainder of approximately $7.0\u00a0billion (2024 $6.7\u00a0billion ) after 20 years. The timing and amount of decommissioning cash flows are inherently uncertain and therefore the phasing is management\u2019s current best estimate but may not be what will ultimately occur. Further information about the group\u2019s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0 percentage point increase in the nominal discount rate applied could decrease the group\u2019s provision balances by approximately $1.4\u00a0billion (2024 $1.5\u00a0billion). The pre-tax impact on the group income statement would be a credit of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion). This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. The discounting impact on the group's decommissioning provisions for oil and gas properties in the oil productions & operations and gas & low carbon energy segments of a two-year change in the timing of expected future decommissioning expenditures is approximately $0.7\u00a0billion (2024 $0.3\u00a0billion). Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year and therefore the timing of upstream decommissioning expenditure is not a key source of estimation uncertainty. If all expected future decommissioning expenditures were 10% higher, then these decommissioning provisions would increase by approximately $1.2 billion (2024 $1.2\u00a0billion) and a pre-tax charge of approximately $0.3\u00a0billion (2024 $0.4\u00a0billion) would be recognized. A one percentage point increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the decommissioning provision by approximately $1.8\u00a0billion (2024 $1.7\u00a0billion) with a pre-tax charge of approximately $0.4\u00a0billion (2024 $0.5\u00a0billion). As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. |
Significant estimate: pensions and other post-employment benefits |
Accounting for defined benefit pensions and other post-employment benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pensions and other post-employment benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet and pension and other post-employment benefit expense for the following year. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-employment benefit obligations within the next financial year. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24. |
Significant judgement and estimate: taxation |
The value of deferred tax assets and liabilities is an area involving inherent uncertainty and estimation and balances are therefore subject to risk of material change as a result of underlying assumptions and judgements used, in particular the forecast of future profitability used to determine the recoverability of deferred tax, for example future oil and gas prices, see \u2018Significant judgement and estimates - Recoverability of asset carrying values\u2019. It is impracticable to disclose the extent of the possible effects of profitability assumptions on the group\u2019s deferred tax assets. It is reasonably possible that to the extent that actual outcomes differ from management\u2019s estimates, material income tax charges or credits, and material changes in current and deferred tax assets or liabilities, may arise within the next financial year and in future periods. Judgement is required when determining whether a particular tax is an income tax or another type of tax (for example, a production tax). The attributes of the tax, including whether it is calculated on profits or another measure such as production or revenues, the extent of deductibility of costs and the interaction with existing income taxes, are considered in determining the classification of the tax. Accounting for deferred tax is applied to income taxes as described above but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. This judgement is considered significant only in relation to the group\u2019s taxes payable under the fiscal terms of bp\u2019s onshore concession in Abu Dhabi. These are principally reported as income taxes rather than as production taxes. For more information see Note 9 and Note 33. |
$ million | |||
2025 | 2024 | ||
Property, plant and equipment | 2,542 | 1,981 | |
Goodwill | 2,817 | \u2014 | |
Intangible assets | 165 | 333 | |
Investments in associates | 20 | \u2014 | |
Investments in joint ventures | 18 | 1,182 | |
Other investments | 65 | \u2014 | |
Inventories | 11 | \u2014 | |
Cash | 68 | 65 | |
Trade and other receivables | 292 | 520 | |
Deferred tax assets | 349 | \u2014 | |
Assets classified as held for sale | 6,347 | 4,081 | |
Trade and other payables | (87) | (264) | |
Lease liabilities | (109) | (58) | |
Finance debt | (1,143) | (720) | |
Provisions | (75) | (63) | |
Deferred tax liabilities | (11) | \u2014 | |
Defined benefit pension plan and other post-employment benefit plan deficits | (169) | \u2014 | |
Liabilities directly associated with assets classified as held for sale | (1,594) | (1,105) |
$ million | ||||
2025 | 2024 | 2023 | ||
Gains on sale of businesses and fixed assets | ||||
gas & low carbon energy | 258 | 297 | 19 | |
oil production & operations | 407 | 144 | 297 | |
customers & products | 317 | 190 | 44 | |
other businesses & corporate | 5 | 47 | 9 | |
987 | 678 | 369 | ||
$ million | ||||
2025 | 2024 | 2023 | ||
Losses on sale of businesses and fixed assets, and closures | ||||
gas & low carbon energy | 410 | 303 | 9 | |
oil production & operations | 110 | 19 | 5 | |
customers & products | 118 | 1,457 | 143 | |
other businesses & corporate | 4 | 27 | (1) | |
642 | 1,806 | 156 | ||
Impairment losses | ||||
gas & low carbon energy a | 4,146 | 3,310 | 2,213 | |
oil production & operations | 454 | 1,155 | 1,840 | |
customers & products a | 926 | 1,144 | 1,614 | |
other businesses & corporate | 3 | 24 | 80 | |
5,529 | 5,633 | 5,747 | ||
Impairment reversals | ||||
gas & low carbon energy | (108) | (44) | (1) | |
oil production & operations | (12) | (384) | (26) | |
customers & products | (14) | (1) | \u2014 | |
other businesses & corporate | \u2014 | (15) | (19) | |
(134) | (444) | (46) | ||
Impairment and losses on sale of businesses and fixed assets, and closures | 6,037 | 6,995 | 5,857 |
$ million | $ million | |||||||||
gas & low carbon energy | oil production & operations | |||||||||
2025 | 2024 | 2025 | 2024 | |||||||
Total | Upstream gas businesses | Transition businesses | Total a | |||||||
Goodwilla | 2,260 | 925 | 3,185 | 2,228 | 2,938 | 5,166 | 4,870 | 4,925 | ||
Excess of recoverable amount over carrying amount | 2,917 | \u2014 | 2,917 | 2,026 | n/a | 2,026 | 13,748 | 12,432 |
$ million | |||||||
2025 | |||||||
By business | gas & low carbon energy | oil production & operations | customers & products | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | 40,333 | 24,527 | 148,783 | 2,232 | (26,540) | 189,335 | |
Less: sales and other operating revenues between segments | (1,832) | (22,876) | (43) | (1,789) | 26,540 | \u2014 | |
Third party sales and other operating revenues | 38,501 | 1,651 | 148,740 | 443 | \u2014 | 189,335 | |
Earnings from joint ventures and associates \u2013 after interest and tax | (501) | 690 | 430 | (1) | \u2014 | 618 | |
Segment results | |||||||
Replacement cost profit (loss) before interest and taxation | 1,330 | 8,558 | 4,100 | (40) | 45 | 13,993 | |
Inventory holding gains (losses)a | \u2014 | 2 | (1,353) | \u2014 | \u2014 | (1,351) | |
Profit (loss) before interest and taxation | 1,330 | 8,560 | 2,747 | (40) | 45 | 12,642 | |
Finance costs | (5,106) | ||||||
Net finance income relating to pensions and other post- employment benefits | 210 | ||||||
Profit before taxation | 7,746 | ||||||
Other income statement items | |||||||
Depreciation, depletion and amortization | |||||||
US | 235 | 4,992 | 1,994 | 89 | \u2014 | 7,310 | |
Non-US | 4,734 | 2,727 | 2,151 | 900 | \u2014 | 10,512 | |
Charges for provisions, net of write-back of unused provisions, including change in discount rate | 37 | 302 | 3,180 | 666 | \u2014 | 4,185 | |
Segment assets | |||||||
Investments in joint ventures and associates | 7,005 | 10,488 | 3,230 | 2 | \u2014 | 20,725 | |
Additions to non-current assets b | 7,188 | 9,782 | 4,617 | 885 | \u2014 | 22,472 |
$ million | |||||||
2024 | |||||||
By business | gas & low carbon energy a | oil production & operations | customers & products a | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | 32,628 | 25,637 | 155,401 | 2,290 | (26,771) | 189,185 | |
Less: sales and other operating revenues between segments | (1,585) | (23,237) | (317) | (1,632) | 26,771 | \u2014 | |
Third party sales and other operating revenues | 31,043 | 2,400 | 155,084 | 658 | \u2014 | 189,185 | |
504 | 1,100 | 393 | (4) | \u2014 | 1,993 | ||
Segment results | \u00a0 | \u00a0 | \u00a0 | \u00a0 | |||
Replacement cost profit (loss) before interest and taxation a | 3,052 | 10,789 | (1,043) | (988) | (25) | 11,785 | |
Inventory holding gains (losses)b | \u2014 | (9) | (479) | \u2014 | \u2014 | (488) | |
Profit (loss) before interest and taxation a | 3,052 | 10,780 | (1,522) | (988) | (25) | 11,297 | |
Finance costs | (4,683) | ||||||
\u00a0 | \u00a0 | \u00a0 | 168 | ||||
Profit before taxation | \u00a0 | \u00a0 | \u00a0 | 6,782 | |||
Other income statement items | \u00a0 | \u00a0 | \u00a0 | \u00a0 | |||
Depreciation, depletion and amortization | |||||||
US | 95 | 4,421 | 2,142 | 89 | \u2014 | 6,747 | |
Non-US | 4,740 | 2,376 | 1,815 | 944 | \u2014 | 9,875 | |
Charges for provisions, net of write-back of unused provisions, including change in discount rate | 38 | 92 | 2,602 | 231 | \u2014 | 2,963 | |
Segment assets | \u00a0 | \u00a0 | \u00a0 | \u00a0 | |||
Investments in joint ventures and associatesa | 6,111 | 10,730 | 3,183 | 8 | \u2014 | 20,032 | |
Additions to non-current assets a c | 12,098 | 7,296 | 6,700 | 1,045 | \u2014 | 27,139 |
$ million | |||||||
2023 | |||||||
By business | gas & low carbon energy a | oil production & operations | customers & products a | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | 50,297 | 24,904 | 160,215 | 2,657 | (27,943) | 210,130 | |
Less: sales and other operating revenues between segments | (1,808) | (23,708) | (367) | (2,060) | 27,943 | \u2014 | |
Third party sales and other operating revenues | 48,489 | 1,196 | 159,848 | 597 | \u2014 | 210,130 | |
(677) | 1,164 | 427 | (16) | \u2014 | 898 | ||
Segment results | |||||||
Replacement cost profit (loss) before interest and taxation | 14,080 | 11,191 | 4,230 | (903) | (14) | 28,584 | |
Inventory holding gains (losses)b | 1 | \u2014 | (1,237) | \u2014 | \u2014 | (1,236) | |
Profit (loss) before interest and taxation | 14,081 | 11,191 | 2,993 | (903) | (14) | 27,348 | |
Finance costs | (3,840) | ||||||
241 | |||||||
Profit before taxation | 23,749 | ||||||
Other income statement items | \u00a0 | \u00a0 | \u00a0 | \u00a0 | |||
Depreciation, depletion and amortization | |||||||
US | 96 | 3,554 | 1,883 | 85 | \u2014 | 5,618 | |
Non-US | 5,584 | 2,138 | 1,665 | 923 | \u2014 | 10,310 | |
139 | 35 | 2,007 | 152 | \u2014 | 2,333 | ||
Segment assets | |||||||
Investments in joint ventures and associatesa | 5,404 | 10,721 | 4,096 | 28 | \u2014 | 20,249 | |
Additions to non-current assets a c | 5,451 | 7,384 | 8,791 | 1,075 | \u2014 | 22,701 |
$ million | ||||
2025 | ||||
By geographical area | US | Non-US | Total | |
Revenues | \u00a0 | \u00a0 | \u00a0 | |
Third party sales and other operating revenues a | 56,703 | 132,632 | 189,335 | |
Other income statement items | ||||
Production and similar taxes | 175 | 1,523 | 1,698 | |
Non-current assets | ||||
Non-current assets b c | 61,269 | 77,194 | 138,463 |
$ million | ||||
2024 | ||||
By geographical area | US | Non-US | Total | |
Revenues | ||||
Third party sales and other operating revenues a | 58,804 | 130,381 | 189,185 | |
Other income statement items | ||||
Production and similar taxes | 149 | 1,650 | 1,799 | |
Non-current assets | ||||
Non-current assets b c | 63,415 | 81,937 | 145,352 |
$ million | ||||
2023 | ||||
By geographical area | US | Non-US | Total | |
Revenues | ||||
Third party sales and other operating revenues a | 60,577 | 149,553 | 210,130 | |
Other income statement items | ||||
Production and similar taxes | 136 | 1,643 | 1,779 | |
Non-current assets | ||||
Non-current assets b c | 64,238 | 83,816 | 148,054 |
$\u00a0million | ||||
2025 | 2024 | 2023 | ||
Crude oil | 2,063 | 2,219 | 2,413 | |
Oil products | 114,207 | 121,019 | 128,969 | |
Natural gas, LNG and NGLs | 27,477 | 24,464 | 29,541 | |
Non-oil products and other revenues from contracts with customers | 15,132 | 13,362 | 10,298 | |
Revenue from contracts with customers | 158,879 | 161,064 | 171,221 | |
Other operating revenues a | 30,456 | 28,121 | 38,909 | |
Total sales and other operating revenues | 189,335 | 189,185 | 210,130 |
$ million | ||||
2025 | 2024 | 2023 | ||
Interest and other income | ||||
Interest income from | ||||
Financial assets measured at amortized cost | 1,203 | 1,308 | 1,034 | |
Financial assets measured at fair value through profit or loss | 129 | 181 | 215 | |
Other incomea | 277 | 1,284 | 386 | |
1,609 | 2,773 | 1,635 | ||
Currency exchange losses charged to the income statement b | (295) | 541 | 74 | |
Expenditure on research and development | 274 | 301 | 298 | |
Costs relating to the Gulf of America oil spill (pre-interest and tax) c | 31 | 51 | 57 | |
Finance costs | ||||
Interest expense on lease liabilities | 704 | 468 | 363 | |
Interest expense on other liabilities measured at amortized costd | 3,419 | 3,483 | 3,115 | |
Capitalized at 4.69% ( 2024 4.94% and 2023 4.88%) e | (142) | (382) | (514) | |
Finance debt risk management activities f | (22) | 104 | (35) | |
Unwinding of discount on provisions | 675 | 617 | 504 | |
Unwinding of discount on other payables measured at amortized cost | 472 | 393 | 407 | |
5,106 | 4,683 | 3,840 |
$ million | ||||
2025 | 2024 | 2023 | ||
Exploration and evaluation costs | ||||
Exploration expenditure written off | 343 | 767 | 746 | |
Other exploration costs | 227 | 207 | 251 | |
Exploration expense for the year | 570 | 974 | 997 | |
Impairment losses | 26 | 6 | 20 | |
Intangible assets \u2013 exploration and appraisal expenditurea | 3,963 | 4,438 | 4,328 | |
Liabilities | 33 | 76 | 109 | |
Net assets | 3,930 | 4,362 | 4,219 | |
Cash used in operating activities | 227 | 207 | 251 | |
Cash used in investing activities | 1,169 | 1,513 | 1,039 |
$ million | ||||
2025 | 2024 | 2023 | ||
Current tax | ||||
Charge for the year a | 6,501 | 7,187 | 9,048 | |
Adjustment in respect of prior years | (188) | 234 | (373) | |
6,313 | 7,421 | 8,675 | ||
Deferred tax | ||||
Origination and reversal of temporary differences in the current yearb | (537) | (1,851) | (238) | |
Adjustment in respect of prior years c | 675 | (17) | (568) | |
138 | (1,868) | (806) | ||
Tax charge on profit | 6,451 | 5,553 | 7,869 |
$ million | ||||
2025 | 2024 | 2023 | ||
Profit (loss) before taxation | 7,746 | 6,782 | 23,749 | |
Tax charge (credit) on profit or loss | 6,451 | 5,553 | 7,869 | |
Effective tax rate | 83% | 82% | 33% | |
Tax rate computed at the weighted average statutory rate a | 55 | 66 | 34 | |
Increase (decrease) resulting from | ||||
Tax reported in equity-accounted entities | (5) | (7) | (2) | |
Adjustments in respect of prior years | 6 | 3 | (4) | |
Deferred tax not recognized | 5 | 5 | 2 | |
Disposal impacts | \u2014 | 5 | \u2014 | |
Foreign exchange | (4) | 5 | \u2014 | |
Items not deductible for tax purposes b | 11 | 5 | 2 | |
Tax rate change effect of UK Energy Profits Levy c | 7 | 1 | \u2014 | |
Impact of Germany tax rate change | 3 | \u2014 | \u2014 | |
Other d | 5 | (1) | 1 | |
Effective tax rate | 83 | 82 | 33 |
$ million | |||
Analysis of movements during the year in the net deferred tax liability | 2025 | 2024 | |
At 1 January | 3,025 | 5,349 | |
Exchange adjustments | (63) | 57 | |
Charge (credit) for the year in the income statement | 138 | (1,868) | |
Charge (credit) for the year in other comprehensive income | (33) | (807) | |
Charge (credit) for the year in equity | (33) | 167 | |
Acquisitions and disposals | 283 | 127 | |
At 31 December | 3,317 | 3,025 |
$ million | ||||||
Income statement | Balance sheet | |||||
2025 | 2024 | 2023 | 2025 | 2024 | ||
Deferred tax liability | ||||||
Depreciation | (897) | (1,337) | (1,552) | 15,474 | 16,333 | |
Pension plan surpluses | (3) | 62 | 133 | 1,860 | 1,789 | |
Derivative financial instruments | 37 | 40 | 12 | 106 | 58 | |
Other taxable temporary differences a | 37 | (352) | 10 | 824 | 663 | |
(826) | (1,587) | (1,397) | 18,264 | 18,843 | ||
Deferred tax asset | ||||||
Depreciation | 993 | (229) | (166) | (1,544) | (2,373) | |
Lease liabilities | (395) | (209) | (176) | (2,375) | (1,952) | |
Pension plan and other post-employment benefit plan deficits | 48 | 28 | (60) | (552) | (623) | |
Decommissioning, environmental and other provisions | (314) | 425 | 563 | (5,981) | (5,623) | |
Derivative financial instruments | (48) | (9) | (14) | (277) | (268) | |
Tax credits | (111) | (43) | (67) | (1,047) | (937) | |
Loss carry forward | 580 | 194 | 296 | (1,852) | (2,285) | |
Other deductible temporary differences b | 211 | (438) | 215 | (1,319) | (1,757) | |
964 | (281) | 591 | (14,947) | (15,818) | ||
Net deferred tax charge (credit) and net deferred tax liability | 138 | (1,868) | (806) | 3,317 | 3,025 | |
Of which \u2013 deferred tax liabilities | 7,642 | 8,428 | ||||
\u2013 deferred tax assets | 4,325 | 5,403 |
$ billion | |||
At 31\u00a0December | 2025 | 2024 | |
Unused US state tax lossesa | 2.9 | 2.3 | |
Unused tax losses \u2013 other jurisdictions b | 9.4 | 7.3 | |
Unused tax credits | 36.7 | 33.3 | |
of which \u2013 arising in the UK c | 33.2 | 29.1 | |
\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0\u00a0 \u2013 arising in the US d | 3.5 | 4.2 | |
Deductible temporary differencese | 28.3 | 23.4 | |
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities | 0.7 | 0.7 |
$ million | ||||
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge | 2025 | 2024 | 2023 | |
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets | 101 | 87 | 360 | |
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets | 11 | 14 | 3 | |
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets | 156 | 280 | 332 | |
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset | 725 | 111 | 54 |
Pence per share | Cents per share | $ million | ||||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Dividends announced and paid in\u00a0cash | ||||||||||
Preference shares | 1 | 1 | 1 | |||||||
Ordinary shares | ||||||||||
March | 6.1761 | 5.6922 | 5.5507 | 8.000 | 7.270 | 6.610 | 1,257 | 1,218 | 1,183 | |
June | 5.8993 | 5.6825 | 5.3089 | 8.000 | 7.270 | 6.610 | 1,237 | 1,204 | 1,152 | |
September | 6.1942 | 6.0498 | 5.7320 | 8.320 | 8.000 | 7.270 | 1,288 | 1,297 | 1,249 | |
December | 6.2394 | 6.2959 | 5.7367 | 8.320 | 8.000 | 7.270 | 1,276 | 1,283 | 1,224 | |
24.5090 | 23.7204 | 22.3283 | 32.640 | 30.540 | 27.760 | 5,059 | 5,003 | 4,809 | ||
Dividend announced, paid in March 2026 | 8.320 | 1,280 |
Cents per share | ||||
Per ordinary share | 2025 | 2024 | 2023 | |
Basic earnings per share | 0.35 | 2.38 | 87.78 | |
Diluted earnings per share | 0.34 | 2.32 | 85.85 | |
Dollars\u00a0per\u00a0share | ||||
Per American Depositary Share (ADS) a | 2025 | 2024 | 2023 | |
Basic earnings per share | 0.02 | 0.14 | 5.27 | |
Diluted earnings per share | 0.02 | 0.14 | 5.15 |
$ million | ||||
2025 | 2024 | 2023 | ||
Profit (loss) attributable to bp shareholders | 55 | 381 | 15,239 | |
Less: dividend requirements on preference shares | 1 | 1 | 1 | |
Less: (gain) loss on redemption of perpetual hybrid bondsa | \u2014 | (10) | \u2014 | |
Profit (loss) for the year attributable to bp ordinary shareholders | 54 | 390 | 15,238 | |
Shares thousand | ||||
2025 | 2024 | 2023 | ||
Basic weighted average number of ordinary shares b | 15,586,782 | 16,385,535 | 17,360,288 | |
326,218 | 431,129 | 389,790 | ||
15,913,000 | 16,816,664 | 17,750,078 | ||
Shares thousand | ||||
2025 | 2024 | 2023 | ||
Basic weighted average number of ordinary shares \u2013 ADS equivalent | 2,597,797 | 2,730,922 | 2,893,381 | |
54,369 | 71,855 | 64,965 | ||
2,652,166 | 2,802,777 | 2,958,346 |
Share options | 2025 | 2024 | |||
Number of options a b thousand | Weighted average exercise price $ | Number of options a b thousand | Weighted average exercise price $ | ||
Outstanding | 382,873 | 4.21 | 533,895 | 4.15 | |
Exercisable | 345,112 | 4.23 | 2,931 | 3.38 | |
Dilutive effect | 80,562 | n/a | 140,971 | n/a |
Share plans | 2025 | 2024 | |
Number of shares a | Number of shares a | ||
Vesting | thousand | thousand | |
Within one year | 155,555 | 271,216 | |
1 to 2 years | 116,997 | 134,342 | |
2 to 3 years | 105,074 | 102,525 | |
3 to 4 years | 366 | 956 | |
Over 4 years | 43 | 118 | |
378,035 | 509,157 | ||
Dilutive effect | 161,105 | 269,796 |
$ million | |||||||||
Land and land improvements | Buildings | Oil and gas properties a | Plant, machinery and equipment | Fittings, fixtures and office equipment | Transportation | Oil depots, storage tanks and service stations | Total | ||
Cost - owned PP&E | |||||||||
At 1 January 2025 | 4,060 | 1,167 | 184,304 | 48,731 | 2,315 | 2,687 | 12,417 | 255,681 | |
Exchange adjustments | 299 | 47 | \u2014 | 1,403 | 78 | 19 | 1,011 | 2,857 | |
Additions | 23 | 131 | 9,896 | 2,667 | 89 | 125 | 784 | 13,715 | |
Acquisitions | \u2014 | 18 | \u2014 | 68 | \u2014 | \u2014 | 3 | 89 | |
Transfers from intangible assets | \u2014 | \u2014 | 3,593 | \u2014 | \u2014 | \u2014 | \u2014 | 3,593 | |
Reclassified as assets held for sale | (72) | (69) | (923) | (1,755) | (137) | (3) | (314) | (3,273) | |
Deletions and disposals | (299) | (4) | (2,074) | (1,047) | (176) | (38) | (693) | (4,331) | |
At 31 December 2025 | 4,011 | 1,290 | 194,796 | 50,067 | 2,169 | 2,790 | 13,208 | 268,331 | |
Depreciation - owned PP&E | |||||||||
At 1 January 2025 | 876 | 520 | 128,091 | 26,929 | 1,716 | 1,933 | 6,561 | 166,626 | |
Exchange adjustments | 60 | 17 | \u2014 | 961 | 50 | 8 | 629 | 1,725 | |
Charge for the year | 47 | 60 | 11,458 | 1,741 | 138 | 102 | 771 | 14,317 | |
Impairment losses | 11 | 5 | 568 | 1,224 | \u2014 | 11 | 42 | 1,861 | |
Impairment reversals | (10) | \u2014 | (9) | (3) | \u2014 | (4) | (2) | (28) | |
Transfers from intangible assets | \u2014 | \u2014 | 2,285 | \u2014 | \u2014 | \u2014 | \u2014 | 2,285 | |
Reclassified as assets held for sale | (9) | (41) | (423) | (967) | (102) | (2) | (187) | (1,731) | |
Deletions and disposals | (28) | (4) | (1,843) | (795) | (167) | (36) | (472) | (3,345) | |
At 31 December 2025 | 947 | 557 | 140,127 | 29,090 | 1,635 | 2,012 | 7,342 | 181,710 | |
3,064 | 733 | 54,669 | 20,977 | 534 | 778 | 5,866 | 86,621 | ||
Right-of-use assets - net book amount at 31 December 2025b | \u2014 | 1,894 | 748 | 1,863 | \u2014 | 2,311 | 5,196 | 12,012 | |
Total PP&E - net book amount at 31 December 2025 | 3,064 | 2,627 | 55,417 | 22,840 | 534 | 3,089 | 11,062 | 98,633 | |
Cost - owned PP&E | |||||||||
At 1 January 2024 | 3,924 | 992 | 185,346 | 47,384 | 2,290 | 2,958 | 12,224 | 255,118 | |
Exchange adjustments | (213) | (35) | \u2014 | (864) | (43) | (23) | (637) | (1,815) | |
Additions | 352 | 222 | 7,899 | 3,039 | 138 | 144 | 1,042 | 12,836 | |
Acquisitions | 60 | 148 | \u2014 | 1,235 | 57 | 80 | 70 | 1,650 | |
Transfers from intangible assets | \u2014 | \u2014 | 391 | \u2014 | \u2014 | \u2014 | \u2014 | 391 | |
Reclassified as assets held for sale | (25) | (41) | (3,210) | (747) | (1) | \u2014 | \u2014 | (4,024) | |
Deletions and disposals | (38) | (119) | (6,122) | (1,316) | (126) | (472) | (282) | (8,475) | |
At 31 December 2024 | 4,060 | 1,167 | 184,304 | 48,731 | 2,315 | 2,687 | 12,417 | 255,681 | |
Depreciation - owned PP&E | |||||||||
At 1 January 2024 | 838 | 553 | 123,442 | 25,671 | 1,684 | 2,292 | 6,363 | 160,843 | |
Exchange adjustments | (52) | (9) | \u2014 | (536) | (24) | (9) | (388) | (1,018) | |
Charge for the year | 58 | 43 | 10,626 | 1,553 | 157 | 91 | 731 | 13,259 | |
Impairment losses | 70 | \u2014 | 2,418 | 1,260 | 1 | 9 | 82 | 3,840 | |
Impairment reversals | \u2014 | \u2014 | (420) | (4) | \u2014 | (3) | \u2014 | (427) | |
Reclassified as assets held for sale | (6) | (4) | (2,168) | (367) | (1) | \u2014 | \u2014 | (2,546) | |
Deletions and disposals | (32) | (63) | (5,807) | (648) | (101) | (447) | (227) | (7,325) | |
At 31 December 2024 | 876 | 520 | 128,091 | 26,929 | 1,716 | 1,933 | 6,561 | 166,626 | |
3,184 | 647 | 56,213 | 21,802 | 599 | 754 | 5,856 | 89,055 | ||
Right-of-use assets - net book amount at 31 December 2024b | \u2014 | 1,613 | 41 | 1,431 | 10 | 2,589 | 5,499 | 11,183 | |
3,184 | 2,260 | 56,254 | 23,233 | 609 | 3,343 | 11,355 | 100,238 | ||
Assets under construction included above | |||||||||
At 31 December 2025 | 11,653 | ||||||||
At 31 December 2024 | 10,722 | ||||||||
Depreciation charge for the year on right-of-use assets | |||||||||
2025 | 342 | 55 | 728 | 3 | 1,026 | 874 | 3,028 | ||
2024 | 215 | 30 | 640 | 3 | 1,109 | 882 | 2,878 |
$ million | |||
2025 | 2024 | ||
Cost | |||
At 1\u00a0January | 15,530 | 13,176 | |
Exchange adjustments | 397 | (179) | |
Acquisitions and other additions | (89) | 2,734 | |
Reclassified as assets held for sale | (2,756) | (79) | |
Deletions and disposals | (133) | (122) | |
At 31\u00a0December | 12,949 | 15,530 | |
Impairment losses | |||
At 1\u00a0January | 642 | 704 | |
Exchange adjustments | 30 | (2) | |
Impairment losses for the year | 2,009 | \u2014 | |
Deletions and disposals | (32) | (60) | |
At 31\u00a0December | 2,649 | 642 | |
Net book amount at 31\u00a0December | 10,300 | 14,888 | |
Net book amount at 1\u00a0January | 14,888 | 12,472 |
$ million | |||
Goodwill at 31 December | 2025 | 2024 | |
gas & low carbon energy a | 3,185 | 5,166 | |
oil production & operations | 4,870 | 4,925 | |
customers & products a | 2,245 | 4,797 | |
other businesses & corporate | \u2014 | \u2014 | |
10,300 | 14,888 |
$ million | $ million | |||||||||
gas & low carbon energy | oil production & operations | |||||||||
2025 | 2024 | 2025 | 2024 | |||||||
Total | Upstream gas businesses | Transition businesses | Total a | |||||||
Goodwilla | 2,260 | 925 | 3,185 | 2,228 | 2,938 | 5,166 | 4,870 | 4,925 | ||
Excess of recoverable amount over carrying amount | 2,917 | \u2014 | 2,917 | 2,026 | n/a | 2,026 | 13,748 | 12,432 |
$ million | |||||||||||
2025 | 2024 | ||||||||||
Castrol | US Fuels | European Fuels | Other | Total | Castrol | US Fuels | European Fuels | Other | Total a | ||
Goodwilla | \u2014 | 844 | 823 | 578 | 2,245 | 2,615 | 828 | 801 | 553 | 4,797 |
$ million | |||||||||
2025 | 2024 | ||||||||
Exploration and appraisal expenditure a | Biogas rights agreements | Other intangibles | Total | Exploration and appraisal expenditure a | Biogas rights agreements | Other intangibles | Total | ||
Cost | |||||||||
At 1\u00a0January | 13,053 | 2,990 | 7,550 | 23,593 | 13,075 | 2,989 | 7,117 | 23,181 | |
Exchange adjustments | \u2014 | \u2014 | 350 | 350 | \u2014 | \u2014 | (171) | (171) | |
Acquisitionsb | \u2014 | \u2014 | 28 | 28 | \u2014 | \u2014 | 351 | 351 | |
Additions | 1,213 | 1 | 544 | 1,758 | 1,539 | 193 | 904 | 2,636 | |
Transfers to property, plant and equipment | (3,593) | \u2014 | \u2014 | (3,593) | (391) | \u2014 | \u2014 | (391) | |
Reclassified as assets held for sale | \u2014 | \u2014 | (667) | (667) | (1) | \u2014 | (385) | (386) | |
Deletions and disposals | (3,057) | (8) | (311) | (3,376) | (1,169) | (192) | (266) | (1,627) | |
At 31\u00a0December | 7,616 | 2,983 | 7,494 | 18,093 | 13,053 | 2,990 | 7,550 | 23,593 | |
Amortization | |||||||||
At 1\u00a0January | 8,615 | 557 | 4,775 | 13,947 | 8,747 | 105 | 4,338 | 13,190 | |
Exchange adjustments | \u2014 | \u2014 | 215 | 215 | \u2014 | \u2014 | (97) | (97) | |
Exploration expenditure written off | 343 | \u2014 | \u2014 | 343 | 767 | \u2014 | \u2014 | 767 | |
Charge for the year | \u2014 | 93 | 736 | 829 | \u2014 | 114 | 717 | 831 | |
Impairment losses | 26 | 710 | 41 | 777 | 6 | 344 | 108 | 458 | |
Impairment reversals | \u2014 | (84) | \u2014 | (84) | (2) | \u2014 | \u2014 | (2) | |
Transfers to property, plant and equipment | (2,285) | \u2014 | \u2014 | (2,285) | \u2014 | \u2014 | \u2014 | \u2014 | |
Reclassified as assets held for sale | \u2014 | \u2014 | (502) | (502) | \u2014 | \u2014 | (53) | (53) | |
Deletions and disposals | (3,046) | (7) | (291) | (3,344) | (903) | (6) | (238) | (1,147) | |
At 31\u00a0December | 3,653 | 1,269 | 4,974 | 9,896 | 8,615 | 557 | 4,775 | 13,947 | |
Net book amount at 31\u00a0December | 3,963 | 1,714 | 2,520 | 8,197 | 4,438 | 2,433 | 2,775 | 9,646 | |
Net book amount at 1\u00a0January | 4,438 | 2,433 | 2,775 | 9,646 | 4,328 | 2,884 | 2,779 | 9,991 |
$ million | ||||||
Income statement | Balance sheet | |||||
Earnings from joint ventures - after interest and tax | Investments in joint ventures | |||||
2025 | 2024 | 2023 | 2025 | 2024 | ||
Azule Energy | 406 | 504 | 700 | 5,080 | 5,109 | |
Other joint ventures | (706) | 405 | (633) | 8,320 | 7,182 | |
(300) | 909 | 67 | 13,400 | 12,291 |
$ million | ||||
Gross amount | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenues | 4,426 | 5,410 | 5,164 | |
Profit (loss) before interest and taxation | 1,266 | 1,896 | 2,146 | |
Finance costs | 304 | 512 | 400 | |
Profit (loss) before taxation a | 962 | 1,384 | 1,746 | |
Taxation | 150 | 376 | 346 | |
Profit (loss) for the year | 812 | 1,008 | 1,400 | |
Other comprehensive income | \u2014 | \u2014 | \u2014 | |
Total comprehensive income | 812 | 1,008 | 1,400 | |
Non-current assets | 22,564 | 20,584 | ||
Current assets b | 4,010 | 3,384 | ||
Total assets | 26,574 | 23,968 | ||
Current liabilities c | 5,056 | 3,576 | ||
Non-current liabilities d | 11,358 | 10,174 | ||
Total liabilities | 16,414 | 13,750 | ||
Net assets | 10,160 | 10,218 | ||
Less: non-controlling interests | \u2014 | \u2014 | ||
10,160 | 10,218 |
$ million | ||||||||||
bp share | ||||||||||
2025 | 2024 | 2023 | ||||||||
Azule Energy | Other | Total | Azule Energy | Other | Total | Azule Energy | Other | Total | ||
Sales and other operating revenues | 2,213 | 10,030 | 12,243 | 2,705 | 12,164 | 14,869 | 2,582 | 13,705 | 16,287 | |
Profit (loss) before interest and taxation | 633 | (61) | 572 | 948 | (74) | 874 | 1,073 | 8 | 1,081 | |
Finance costs | 152 | 398 | 550 | 256 | 249 | 505 | 200 | 421 | 621 | |
Profit (loss) before taxation | 481 | (459) | 22 | 692 | (323) | 369 | 873 | (413) | 460 | |
Taxation | 75 | 247 | 322 | 188 | (729) | (541) | 173 | 219 | 392 | |
Non-controlling interest | \u2014 | \u2014 | \u2014 | \u2014 | 1 | 1 | \u2014 | 1 | 1 | |
Profit (loss) for the year | 406 | (706) | (300) | 504 | 405 | 909 | 700 | (633) | 67 | |
Other comprehensive income | \u2014 | \u2014 | \u2014 | \u2014 | (3) | (3) | \u2014 | 45 | 45 | |
Total comprehensive income | 406 | (706) | (300) | 504 | 402 | 906 | 700 | (588) | 112 | |
Non-current assets | 11,282 | 18,162 | 29,444 | 10,292 | 13,871 | 24,163 | ||||
Current assets | 2,005 | 3,960 | 5,965 | 1,692 | 4,363 | 6,055 | ||||
Total assets | 13,287 | 22,122 | 35,409 | 11,984 | 18,234 | 30,218 | ||||
Current liabilities | 2,528 | 3,398 | 5,926 | 1,788 | 2,914 | 4,702 | ||||
Non-current liabilities | 5,679 | 7,244 | 12,923 | 5,087 | 5,057 | 10,144 | ||||
Total liabilities | 8,207 | 10,642 | 18,849 | 6,875 | 7,971 | 14,846 | ||||
Net assets | 5,080 | 11,480 | 16,560 | 5,109 | 10,263 | 15,372 | ||||
Less: non-controlling interests | \u2014 | (90) | (90) | \u2014 | (11) | (11) | ||||
5,080 | 11,390 | 16,470 | 5,109 | 10,252 | 15,361 | |||||
Group investment in joint ventures | ||||||||||
Group share of net assets (as above) | 5,080 | 11,390 | 16,470 | 5,109 | 10,252 | 15,361 | ||||
Cumulative impairment charge | \u2014 | (3,066) | (3,066) | \u2014 | (3,066) | (3,066) | ||||
Loans made by group companies to joint ventures | \u2014 | (4) | (4) | \u2014 | (4) | (4) | ||||
5,080 | 8,320 | 13,400 | 5,109 | 7,182 | 12,291 |
$ million | |||||||
Sales to joint ventures | 2025 | 2024 | 2023 | ||||
Product | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | |
LNG, crude oil and oil products, natural gas | 2,470 | 469 | 3,653 | 507 | 3,585 | 501 | |
Purchases from joint ventures | 2025 | 2024 | 2023 | ||||
Product | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | |
2,230 | 426 | 2,952 | 468 | 3,328 | 427 |
Subsidiaries | % | Country of incorporation | Principal activities | ||
International | |||||
BP Corporate Holdings Limited | 100 | England & Wales | Investment holding | ||
BP Exploration Operating Company Limited | 100 | England & Wales | Exploration and production | ||
*BP Gamma Holdings Limited | 100 | England & Wales | Investment holding | ||
*BP Global Investments Limited | 100 | England & Wales | Investment holding | ||
*BP International Limited | 100 | England & Wales | Integrated oil operations | ||
BP Oil International Limited | 100 | England & Wales | Integrated oil operations | ||
*Castrol Group Holdings Limited | 100 | Scotland | Investment holding | ||
Azerbaijan | |||||
BP Exploration (Caspian Sea) Limited | 100 | England & Wales | Exploration and production | ||
BP Exploration (Azerbaijan) Limited | 100 | England & Wales | Exploration and production | ||
Germany | |||||
BP Europa SE | 100 | Germany | Refining and marketing | ||
Trinidad\u00a0and Tobago | |||||
BP Trinidad and Tobago LLC | 70 | US | Exploration and production | ||
UK | |||||
BP Capital Markets p.l.c. | 100 | England & Wales | Finance | ||
Lightsource BP Renewable Energy Investments Limited | 100 | England & Wales | Onshore renewables | ||
US | |||||
*BP Holdings North America Limited | 100 | England & Wales | Investment holding | ||
Atlantic Richfield Company | 100 | US | Exploration and production, refining and marketing | ||
BP America Inc. | 100 | US | |||
BP America Production Company | 100 | US | |||
BP Company North America Inc. | 100 | US | |||
BP Corporation North America Inc. | 100 | US | |||
BP Products North America Inc. | 100 | US | |||
The Standard Oil Company | 100 | US | |||
Archaea Energy Inc. | 100 | US | Bioenergy | ||
BP Capital Markets America Inc. | 100 | US | Finance | ||
Joint arrangements | % | Country of incorporation | Principal activities | ||
Angola | |||||
Azule Energy Holdings Limited | 50 | England & Wales | Exploration and production |
$ million | ||||
bp share | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenues | 13,374 | 12,859 | 11,396 | |
Profit before interest and taxation | 1,940 | 2,389 | 2,279 | |
Finance costs | 32 | 41 | 41 | |
Profit (loss) before taxation | 1,908 | 2,348 | 2,238 | |
Taxation | 990 | 1,264 | 1,407 | |
Profit (loss) for the year | 918 | 1,084 | 831 | |
Other comprehensive income | (4) | (9) | (237) | |
Total comprehensive income | 914 | 1,075 | 594 | |
Non-current assets | 12,089 | 11,395 | ||
Current assets | 3,915 | 4,230 | ||
Total assets | 16,004 | 15,625 | ||
Current liabilities | 2,997 | 3,009 | ||
Non-current liabilities | 5,714 | 4,886 | ||
Total liabilities | 8,711 | 7,895 | ||
Net assets | 7,293 | 7,730 | ||
Group investment in associates | ||||
Group share of net assets (as\u00a0above) | 7,293 | 7,730 | ||
Loans made by group companies to associates | 32 | 11 | ||
7,325 | 7,741 |
$ million | |||||||
Sales to associates | 2025 | 2024 | 2023 | ||||
Product | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | |
LNG, crude oil and oil products, natural gas | 1,034 | 348 | 844 | 148 | 1,009 | 368 | |
$ million | |||||||
Purchases from associates | 2025 | 2024 | 2023 | ||||
Product | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | |
Crude oil and oil products, natural gas, transportation tariff | 6,708 | 2,052 | 7,034 | 2,223 | 5,473 | 2,607 |
Subsidiaries | % | Country of incorporation | Principal activities | ||
International | |||||
BP Corporate Holdings Limited | 100 | England & Wales | Investment holding | ||
BP Exploration Operating Company Limited | 100 | England & Wales | Exploration and production | ||
*BP Gamma Holdings Limited | 100 | England & Wales | Investment holding | ||
*BP Global Investments Limited | 100 | England & Wales | Investment holding | ||
*BP International Limited | 100 | England & Wales | Integrated oil operations | ||
BP Oil International Limited | 100 | England & Wales | Integrated oil operations | ||
*Castrol Group Holdings Limited | 100 | Scotland | Investment holding | ||
Azerbaijan | |||||
BP Exploration (Caspian Sea) Limited | 100 | England & Wales | Exploration and production | ||
BP Exploration (Azerbaijan) Limited | 100 | England & Wales | Exploration and production | ||
Germany | |||||
BP Europa SE | 100 | Germany | Refining and marketing | ||
Trinidad\u00a0and Tobago | |||||
BP Trinidad and Tobago LLC | 70 | US | Exploration and production | ||
UK | |||||
BP Capital Markets p.l.c. | 100 | England & Wales | Finance | ||
Lightsource BP Renewable Energy Investments Limited | 100 | England & Wales | Onshore renewables | ||
US | |||||
*BP Holdings North America Limited | 100 | England & Wales | Investment holding | ||
Atlantic Richfield Company | 100 | US | Exploration and production, refining and marketing | ||
BP America Inc. | 100 | US | |||
BP America Production Company | 100 | US | |||
BP Company North America Inc. | 100 | US | |||
BP Corporation North America Inc. | 100 | US | |||
BP Products North America Inc. | 100 | US | |||
The Standard Oil Company | 100 | US | |||
Archaea Energy Inc. | 100 | US | Bioenergy | ||
BP Capital Markets America Inc. | 100 | US | Finance | ||
Joint arrangements | % | Country of incorporation | Principal activities | ||
Angola | |||||
Azule Energy Holdings Limited | 50 | England & Wales | Exploration and production |
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Equity investments a | \u2014 | 816 | \u2014 | 1,095 | |
Contingent consideration | 60 | 25 | 55 | 136 | |
Other | 98 | 16 | 110 | 61 | |
158 | 857 | 165 | 1,292 |
$ million | |||
2025 | 2024 | ||
Crude oil | 2,789 | 3,007 | |
Natural gas | 697 | 548 | |
Emissions allowances | 843 | 549 | |
Refined petroleum and petrochemical products | 5,803 | 6,627 | |
10,132 | 10,731 | ||
Trading inventories | 8,665 | 8,977 | |
Supplies | 2,105 | 1,946 | |
Biological assets | 112 | 178 | |
Solar projects | 1,485 | 1,400 | |
22,499 | 23,232 | ||
Cost of inventories expensed in the income statement | 110,640 | 113,941 |
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Financial assets | |||||
Trade receivables | 21,107 | 6 | 21,659 | 502 | |
Amounts receivable from joint ventures and associates | 817 | \u2014 | 655 | \u2014 | |
Other receivables | 2,882 | 1,755 | 3,524 | 808 | |
24,806 | 1,761 | 25,838 | 1,310 | ||
Non-financial assets | |||||
Sales taxes and production taxes | 1,032 | 509 | 1,165 | 356 | |
Other receivables | 176 | 106 | 124 | 149 | |
1,208 | 615 | 1,289 | 505 | ||
26,014 | 2,376 | 27,127 | 1,815 |
$ million | |||||||
2025 | 2024 | 2023 | |||||
Trade and other receivables | Fixed asset investments | Trade and other receivables | Fixed asset investments | Trade and other receivables | Fixed asset investments | ||
At 1 January | 995 | 3,298 | 1,424 | 3,183 | 636 | 3,050 | |
Charged to costs and expenses | 23 | 179 | (90) | 140 | 866 | 176 | |
Charged to other accounts a | 10 | \u2014 | (7) | \u2014 | 1 | (1) | |
Deductions | (90) | (62) | (332) | (25) | (79) | (42) | |
At 31 December | 938 | 3,415 | 995 | 3,298 | 1,424 | 3,183 |
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Financial liabilities | |||||
Trade payables | 37,082 | \u2014 | 38,636 | \u2014 | |
Amounts payable to joint ventures and associates | 2,477 | 1 | 2,690 | 1 | |
Payables for capital expenditure and acquisitions | 3,054 | 85 | 3,670 | 309 | |
Payables related to the Gulf of America oil spill | 1,520 | 5,735 | 1,126 | 6,830 | |
Other payables | 7,771 | 457 | 7,358 | 678 | |
51,904 | 6,278 | 53,480 | 7,818 | ||
Non-financial liabilities | |||||
Sales taxes, customs duties, production taxes and social security | 2,001 | 55 | 2,121 | 54 | |
Other payables | 2,938 | 1,642 | 2,810 | 1,537 | |
4,939 | 1,697 | 4,931 | 1,591 | ||
56,843 | 7,975 | 58,411 | 9,409 |
$ million | |||||||
Decommissioning | Environmental | Litigation and claims | Emissions | Other c | Total | ||
At 1 January 2025 | 11,758 | 1,518 | 701 | 2,330 | 1,981 | 18,288 | |
Exchange adjustments | 159 | 15 | 6 | 99 | 144 | 423 | |
Acquisitions | \u2014 | \u2014 | 26 | \u2014 | 3 | 29 | |
New and increase in existing provisions a | 528 | 325 | 362 | 3,052 | 1,329 | 5,596 | |
Write-back of unused provisions a | (2) | (73) | (20) | (83) | (707) | (885) | |
Unwinding of discountb | 530 | 63 | 20 | \u2014 | 62 | 675 | |
Utilization | (17) | (297) | (188) | (1,834) | (522) | (2,858) | |
Reclassified to other payables | (540) | (2) | (108) | \u2014 | (2) | (652) | |
(21) | (31) | (2) | \u2014 | (21) | (75) | ||
Deletions | (142) | (18) | (1) | \u2014 | (1) | (162) | |
At 31 December 2025 | 12,253 | 1,500 | 796 | 3,564 | 2,266 | 20,379 | |
Of which \u2013 current | 824 | 319 | 100 | 2,709 | 757 | 4,709 | |
\u2013 non-current | 11,429 | 1,181 | 696 | 855 | 1,509 | 15,670 |
% | ||||||||||
Financial assumptions used to determine benefit obligation | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Discount rate for plan liabilities | 5.6 | 5.5 | 4.8 | 5.4 | 5.6 | 5.0 | 4.2 | 3.5 | 3.6 | |
Rate of increase for pensions in payment | 2.7 | 2.9 | 2.8 | \u2014 | \u2014 | \u2014 | 1.8 | 1.8 | 2.1 | |
Rate of increase in deferred pensions | 2.7 | 2.9 | 2.8 | \u2014 | \u2014 | \u2014 | 0.6 | 0.6 | 0.7 | |
Inflation for plan liabilities | 2.9 | 3.1 | 3.0 | 2.0 | 2.0 | 2.0 | 2.0 | 2.0 | 2.4 | |
% | ||||||||||
Financial assumptions used to determine benefit expense | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Discount rate for plan service cost a | N/A | N/A | 5.7 | 5.0 | 5.2 | 3.7 | 3.7 | 4.3 | ||
Discount rate for plan other finance expense | 5.5 | 4.8 | 5.0 | 5.6 | 5.0 | 5.2 | 3.5 | 3.6 | 4.2 | |
Inflation for plan service cost a | N/A | N/A | N/A | 2.0 | 2.0 | 2.0 | 2.0 | 2.4 | 2.1 |
Years | ||||||||||
Mortality assumptions | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Life expectancy at age 60 for a male currently aged 60 | 27.1 | 27.0 | 27.4 | 25.2 | 25.1 | 25.0 | 26.4 | 26.2 | 26.1 | |
Life expectancy at age 60 for a male currently aged 40 | 28.9 | 28.9 | 29.2 | 26.9 | 26.8 | 26.7 | 28.9 | 28.6 | 28.6 | |
Life expectancy at age 60 for a female currently aged 60 | 28.9 | 29.0 | 29.2 | 28.2 | 28.1 | 28.1 | 29.5 | 29.5 | 29.3 | |
Life expectancy at age 60 for a female currently aged 40 | 30.4 | 30.5 | 30.6 | 29.7 | 29.6 | 29.6 | 31.7 | 31.7 | 31.6 |
UK | US | ||
Asset category | % | % | |
Total equity (including private equity) | 8 | 19 | |
Bonds/cash (including LDI) | 85 | 81 | |
Property/real estate | 7 | \u2014 |
$ million | ||||||
UKa | USb | Eurozone | Other | Total | ||
Fair value of pension plan assets | ||||||
At 31 December 2025 | ||||||
Listed equities \u2013 developed markets | 725 | 137 | 84 | 181 | 1,127 | |
\u2013 emerging markets | 29 | 17 | 10 | 70 | 126 | |
Private equity c | 1,871 | 910 | \u2014 | \u2014 | 2,781 | |
Government issued nominal bonds d | 3,761 | 1,369 | 901 | 214 | 6,245 | |
Government issued index-linked bonds d | 10,805 | \u2014 | 85 | 8 | 10,898 | |
Corporate bondsd | 5,383 | 2,790 | 70 | 236 | 8,479 | |
Propertye | 2,487 | \u2014 | 6 | 13 | 2,506 | |
Cash | 574 | 83 | 912 | 106 | 1,675 | |
Other f | 3,232 | 46 | (58) | 11 | 3,231 | |
Debt (repurchase agreements) used to fund liability driven investments | (4,278) | \u2014 | \u2014 | \u2014 | (4,278) | |
24,589 | 5,352 | 2,010 | 839 | 32,790 | ||
At 31 December 2024 | ||||||
Listed equities \u2013 developed markets | 963 | 113 | 341 | 230 | 1,647 | |
\u2013 emerging markets | 32 | 13 | 55 | 75 | 175 | |
Private equity c | 1,916 | 950 | \u2014 | 2 | 2,868 | |
Government issued nominal bonds d | 5,027 | 1,317 | 690 | 223 | 7,257 | |
Government issued index-linked bonds d | 11,105 | \u2014 | 78 | 7 | 11,190 | |
Corporate bondsd | 6,088 | 2,763 | 605 | 261 | 9,717 | |
Propertye | 2,344 | \u2014 | 84 | 19 | 2,447 | |
Cash | 416 | 67 | 100 | 78 | 661 | |
Other f | 1,039 | 36 | 54 | 14 | 1,143 | |
Debt (repurchase agreements) used to fund liability driven investments | (5,664) | \u2014 | \u2014 | \u2014 | (5,664) | |
23,266 | 5,259 | 2,007 | 909 | 31,441 | ||
At 31 December 2023 | ||||||
Listed equities \u2013 developed markets | 862 | 97 | 333 | 232 | 1,524 | |
\u2013 emerging markets | 28 | 12 | 51 | 66 | 157 | |
Private equity c | 2,022 | 1,014 | \u2014 | 2 | 3,038 | |
Government issued nominal bonds d | 6,285 | 1,457 | 746 | 285 | 8,773 | |
Government issued index-linked bonds d | 13,177 | \u2014 | 88 | \u2014 | 13,265 | |
Corporate bondsd | 6,144 | 2,802 | 605 | 166 | 9,717 | |
Propertye | 2,437 | \u2014 | 92 | 17 | 2,546 | |
Cash | 453 | 59 | 82 | 85 | 679 | |
Other f | 1,123 | 33 | 55 | 391 | 1,602 | |
Debt (repurchase agreements) used to fund liability driven investments | (6,485) | \u2014 | \u2014 | \u2014 | (6,485) | |
26,046 | 5,474 | 2,052 | 1,244 | 34,816 |
$ million | ||||||
2025 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service cost a | 47 | 157 | 56 | 25 | 285 | |
Past service cost b | \u2014 | \u2014 | (39) | \u2014 | (39) | |
Settlement b | \u2014 | \u2014 | 11 | \u2014 | 11 | |
Operating charge (credit) relating to defined benefit plans | 47 | 157 | 28 | 25 | 257 | |
Payments to defined contribution plans | 180 | 179 | 7 | 35 | 401 | |
Total operating charge (credit) | 227 | 336 | 35 | 60 | 658 | |
Interest income on plan assetsa | (1,322) | (286) | (78) | (38) | (1,724) | |
Interest on plan liabilities | 976 | 300 | 190 | 48 | 1,514 | |
Other finance (income) expense | (346) | 14 | 112 | 10 | (210) | |
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | (613) | 120 | (225) | (1) | (719) | |
Change in financial assumptions underlying the present value of the plan liabilities | 453 | (242) | 436 | 8 | 655 | |
Change in demographic assumptions underlying the present value of the plan\u00a0liabilities | (26) | \u2014 | \u2014 | (1) | (27) | |
Experience gains and losses arising on the plan liabilities | 15 | (40) | (102) | (3) | (130) | |
Remeasurements recognized in other comprehensive income | (171) | (162) | 109 | 3 | (221) | |
Movements in benefit obligation during the year | ||||||
Benefit obligation at 1\u00a0January | 17,324 | 5,524 | 5,002 | 1,007 | 28,857 | |
Exchange adjustments | 1,301 | \u2014 | 646 | 50 | 1,997 | |
Operating charge relating to defined benefit plans | 47 | 157 | 28 | 25 | 257 | |
Interest cost | 976 | 300 | 190 | 48 | 1,514 | |
Contributions by plan participants | 8 | \u2014 | 2 | 5 | 15 | |
Benefit payments (funded plans) c | (1,160) | (313) | (95) | (64) | (1,632) | |
Benefit payments (unfunded plans) c | (10) | (145) | (246) | (11) | (412) | |
Reclassified as assets held for sale | (24) | \u2014 | (161) | (77) | (262) | |
Disposals | \u2014 | \u2014 | (1) | \u2014 | (1) | |
Remeasurements | (442) | 282 | (334) | (4) | (498) | |
Benefit obligation at 31 December a d e | 18,020 | 5,805 | 5,031 | 979 | 29,835 | |
Movements in fair value of plan assets during the year | ||||||
Fair value of plan assets at 1\u00a0January | 23,266 | 5,259 | 2,007 | 909 | 31,441 | |
Exchange adjustments | 1,757 | \u2014 | 257 | 43 | 2,057 | |
Interest income on plan assetsa e | 1,322 | 286 | 78 | 38 | 1,724 | |
Contributions by plan participants | 8 | \u2014 | 2 | 5 | 15 | |
Contributions by and refunds to employers (funded plans) | 9 | \u2014 | 16 | (28) | (3) | |
Benefit payments (funded plans) c | (1,160) | (313) | (95) | (64) | (1,632) | |
Reclassified as assets held for sale | \u2014 | \u2014 | (30) | (63) | (93) | |
Remeasurements f | (613) | 120 | (225) | (1) | (719) | |
Fair value of plan assets at 31 December g | 24,589 | 5,352 | 2,010 | 839 | 32,790 | |
Surplus (deficit) at 31\u00a0December | 6,569 | (453) | (3,021) | (140) | 2,955 | |
Represented by | ||||||
Asset recognized | 6,697 | 921 | 93 | 60 | 7,771 | |
Liability recognized | (128) | (1,374) | (3,114) | (200) | (4,816) | |
6,569 | (453) | (3,021) | (140) | 2,955 | ||
The surplus (deficit) may be analysed between funded and unfunded plans as\u00a0follows | ||||||
Funded | 6,696 | 921 | 84 | 29 | 7,730 | |
Unfunded | (127) | (1,374) | (3,105) | (169) | (4,775) | |
6,569 | (453) | (3,021) | (140) | 2,955 | ||
Funded | (17,893) | (4,431) | (1,926) | (810) | (25,060) | |
Unfunded | (127) | (1,374) | (3,105) | (169) | (4,775) | |
(18,020) | (5,805) | (5,031) | (979) | (29,835) |
$ million | ||||||
2024 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service cost a | 48 | 160 | 62 | 23 | 293 | |
Past service cost b | \u2014 | \u2014 | (1) | \u2014 | (1) | |
Settlement b | (1) | \u2014 | \u2014 | \u2014 | (1) | |
Operating charge (credit) relating to defined benefit plans | 47 | 160 | 61 | 23 | 291 | |
Payments to defined contribution plans | 161 | 192 | 8 | 35 | 396 | |
Total operating charge (credit) | 208 | 352 | 69 | 58 | 687 | |
Interest income on plan assetsa | (1,218) | (267) | (70) | (49) | (1,604) | |
Interest on plan liabilities | 909 | 283 | 184 | 60 | 1,436 | |
Other finance (income) expense | (309) | 16 | 114 | 11 | (168) | |
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | (2,388) | (239) | 65 | 83 | (2,479) | |
Change in financial assumptions underlying the present value of the plan liabilities | 1,496 | 403 | 103 | (48) | 1,954 | |
Change in demographic assumptions underlying the present value of the plan liabilities | 194 | (8) | 1 | 2 | 189 | |
Experience gains and losses arising on the plan liabilities | 15 | (34) | 2 | (7) | (24) | |
Remeasurements recognized in other comprehensive income | (683) | 122 | 171 | 30 | (360) | |
Movements in benefit obligation during the year | ||||||
Benefit obligation at 1\u00a0January | 19,579 | 5,837 | 5,537 | 1,371 | 32,324 | |
Exchange adjustments | (352) | \u2014 | (355) | (66) | (773) | |
Operating charge relating to defined benefit plans | 47 | 160 | 61 | 23 | 291 | |
Interest cost | 909 | 283 | 184 | 60 | 1,436 | |
Contributions by plan participants | 7 | \u2014 | 2 | 7 | 16 | |
Benefit payments (funded plans) c | (1,153) | (243) | (89) | (427) | (1,912) | |
Benefit payments (unfunded plans) c | (8) | (152) | (232) | (12) | (404) | |
Disposals | \u2014 | \u2014 | \u2014 | (2) | (2) | |
Remeasurements | (1,705) | (361) | (106) | 53 | (2,119) | |
Benefit obligation at 31 December a d | 17,324 | 5,524 | 5,002 | 1,007 | 28,857 | |
Movements in fair value of plan assets during the year | ||||||
Fair value of plan assets at 1\u00a0January | 26,046 | 5,474 | 2,052 | 1,244 | 34,816 | |
Exchange adjustments | (473) | \u2014 | (139) | (61) | (673) | |
Interest income on plan assetsa e | 1,218 | 267 | 70 | 49 | 1,604 | |
Contributions by plan participants | 7 | \u2014 | 2 | 7 | 16 | |
Contributions by employers (funded plans) | 9 | \u2014 | 46 | 14 | 69 | |
Benefit payments (funded plans) c | (1,153) | (243) | (89) | (427) | (1,912) | |
Remeasurements e | (2,388) | (239) | 65 | 83 | (2,479) | |
Fair value of plan assets at 31\u00a0December f | 23,266 | 5,259 | 2,007 | 909 | 31,441 | |
Surplus (deficit) at 31\u00a0December | 5,942 | (265) | (2,995) | (98) | 2,584 | |
Represented by | ||||||
Asset recognized | 6,083 | 1,009 | 273 | 92 | 7,457 | |
Liability recognized | (141) | (1,274) | (3,268) | (190) | (4,873) | |
5,942 | (265) | (2,995) | (98) | 2,584 | ||
The surplus (deficit) may be analysed between funded and unfunded plans as\u00a0follows | ||||||
Funded | 6,083 | 1,009 | 261 | 48 | 7,401 | |
Unfunded | (141) | (1,274) | (3,256) | (146) | (4,817) | |
5,942 | (265) | (2,995) | (98) | 2,584 | ||
Funded | (17,183) | (4,250) | (1,746) | (861) | (24,040) | |
Unfunded | (141) | (1,274) | (3,256) | (146) | (4,817) | |
(17,324) | (5,524) | (5,002) | (1,007) | (28,857) |
$ million | ||||||
2023 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service cost a | 44 | 156 | 47 | 21 | 268 | |
Past service cost b | 4 | \u2014 | 5 | (2) | 7 | |
Settlement b | \u2014 | \u2014 | \u2014 | 3 | 3 | |
Operating charge (credit) relating to defined benefit plans | 48 | 156 | 52 | 22 | 278 | |
Payments to defined contribution plans | 132 | 158 | 7 | 36 | 333 | |
Total operating charge (credit) | 180 | 314 | 59 | 58 | 611 | |
Interest income on plan assetsa | (1,259) | (274) | (78) | (56) | (1,667) | |
Interest on plan liabilities | 869 | 297 | 194 | 66 | 1,426 | |
Other finance (income) expense | (390) | 23 | 116 | 10 | (241) | |
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | (677) | 45 | 82 | 28 | (522) | |
Change in financial assumptions underlying the present value of the plan liabilities | (649) | 28 | (508) | (24) | (1,153) | |
Change in demographic assumptions underlying the present value of the plan liabilities | (230) | (5) | 8 | \u2014 | (227) | |
Experience gains and losses arising on the plan liabilities | (320) | 45 | (84) | (1) | (360) | |
Remeasurements recognized in other comprehensive income | (1,876) | 113 | (502) | 3 | (2,262) |
$ million | |||||||
One percentage point | |||||||
UK | US | Eurozone | |||||
Increase | Decrease | Increase | Decrease | Increase | Decrease | ||
Discount rate a | |||||||
Effect on expense in 2026 | (186) | 168 | (44) | 46 | (2) | (5) | |
Effect on obligation at 31 December 2025 | (1,803) | 2,185 | (465) | 614 | (497) | 604 | |
Inflation rate b | |||||||
Effect on expense in 2026 | 90 | (82) | 8 | (6) | 22 | (20) | |
Effect on obligation at 31 December 2025 | 1,613 | (1,464) | 39 | (33) | 480 | (414) |
$ million | ||||
One year increase | ||||
UK | US | Eurozone | ||
Longevity | ||||
Effect on expense in 2026 | 33 | 4 | 9 | |
Effect on obligation at 31 December 2025 | 593 | 60 | 189 |
$ million | ||||||
Estimated future benefit payments | UK | US | Eurozone | Other | Total | |
2026 | 1,190 | 467 | 324 | 61 | 2,042 | |
2027 | 1,212 | 463 | 325 | 55 | 2,055 | |
2028 | 1,219 | 458 | 320 | 56 | 2,053 | |
2029 | 1,233 | 467 | 319 | 55 | 2,074 | |
2030 | 1,234 | 473 | 312 | 54 | 2,073 | |
2031 - 2035 | 6,214 | 2,383 | 1,431 | 285 | 10,313 | |
Years | ||||||
Weighted average duration | 11.1 | 9.2 | 12.5 | 12.6 |
$\u00a0million | ||||
2025 | 2024 | 2023 | ||
Total for all directors | ||||
Emoluments | 11 | 8 | 8 | |
Amounts received under incentive schemes a | 3 | 5 | 6 | |
Total | 14 | 13 | 14 |
$\u00a0million | ||||
2025 | 2024 | 2023 | ||
Total for all senior management and non-executive directors | ||||
Short-term employee benefits | 34 | 22 | 31 | |
Pensions and other post-employment benefits | \u2014 | \u2014 | \u2014 | |
Share-based payments a | 28 | 26 | 12 | |
Termination benefits | \u2014 | 3 | \u2014 | |
Total | 62 | 51 | 43 |
$ million | ||||
Employee costs | 2025 | 2024 | 2023 | |
Wages and salaries a | 9,295 | 8,601 | 7,835 | |
Social security costs | 1,166 | 1,032 | 943 | |
Share-based payments b | 847 | 1,088 | 1,131 | |
Pension and other post-employment benefit costs | 448 | 519 | 370 | |
11,756 | 11,240 | 10,279 |
2025 | 2024 | 2023 | ||||||||
Average number of employeesc | US | Non-US | Total | US | Non-US | Total | US | Non-US | Total | |
gas & low carbon energy | 1,000 | 5,200 | 6,200 | 900 | 4,400 | 5,300 | 900 | 3,700 | 4,600 | |
oil production & operations | 3,300 | 6,000 | 9,300 | 3,300 | 5,700 | 9,000 | 3,100 | 5,500 | 8,600 | |
customers & products d e | 27,100 | 43,700 | 70,800 | 27,500 | 38,000 | 65,500 | 19,500 | 36,300 | 55,800 | |
other businesses and corporate | 1,200 | 10,700 | 11,900 | 1,400 | 9,800 | 11,200 | 1,400 | 9,000 | 10,400 | |
32,600 | 65,600 | 98,200 | 33,100 | 57,900 | 91,000 | 24,900 | 54,500 | 79,400 |
$ million | |||
2025 | 2024 | ||
Cash | 17,158 | 16,414 | |
Triparty repos and term bank deposits | 12,691 | 14,453 | |
Other cash equivalents | 6,707 | 8,337 | |
36,556 | 39,204 |
$ million | |||||||
2025 | 2024 | ||||||
Current | Non-current | Total | Current | Non-current | Total | ||
Borrowings | 3,356 | 54,602 | 57,958 | 4,474 | 55,073 | 59,547 |
Fixed rate debt | Floating rate debt | Total | |||||
Weighted average interest rate % | Weighted average time for which rate is fixed Years | Amount $\u00a0million | Weighted average interest rate % | Amount $\u00a0million | Amount $\u00a0million | ||
2025 | |||||||
US dollar | 5 | 8 | 41,018 | 4 | 16,486 | 57,504 | |
Other currencies | 6 | 4 | 246 | 6 | 208 | 454 | |
41,264 | 16,694 | 57,958 | |||||
2024 | |||||||
US dollar | 4 | 8 | 41,145 | 5 | 17,847 | 58,992 | |
Other currencies | 6 | 3 | 396 | 6 | 159 | 555 | |
41,541 | 18,006 | 59,547 |
$ million | |||||
2025 | 2024 | ||||
Fair value | Carrying amount | Fair value | Carrying amount | ||
Short-term borrowings | 353 | 353 | 681 | 681 | |
Long-term borrowings | 54,582 | 57,605 | 54,285 | 58,866 | |
Total finance debt | 54,935 | 57,958 | 54,966 | 59,547 |
$ million | |||
At 31 December | 2025 | 2024 | |
Finance debt | 57,958 | 59,547 | |
Less: fair value asset (liability) of hedges related to finance debta | (780) | (2,654) | |
58,738 | 62,201 | ||
Less: cash and cash equivalents | 36,556 | 39,204 | |
Net debt | 22,182 | 22,997 | |
Total equity | 74,000 | 78,318 | |
Gearing | 23.1% | 22.7% |
$ million | ||||||
Finance debt | Currency swaps a | Lease liabilities | Partner payable for leases entered into on behalf of joint operations | Total liabilities arising from financing activities | ||
At 1 January 2025 | 59,547 | 4,113 | 12,000 | 37 | 75,697 | |
Exchange adjustments | 127 | \u2014 | 399 | 2 | 528 | |
Net financing cash flow | (3,290) | (22) | (3,091) | (2) | (6,405) | |
Fair value (gains) losses | 1,664 | (3,044) | \u2014 | \u2014 | (1,380) | |
New and remeasured leases/joint operations payables | \u2014 | \u2014 | 5,449 | (4) | 5,445 | |
Other movements | (90) | \u2014 | (186) | (2) | (278) | |
At 31 December 2025 | 57,958 | 1,047 | 14,571 | 31 | 73,607 | |
At 1 January 2024 | 51,954 | 2,978 | 11,121 | 30 | 66,083 | |
Exchange adjustments | (39) | \u2014 | (272) | (1) | (312) | |
Net financing cash flow | 4,761 | (27) | (2,833) | (14) | 1,887 | |
Fair value (gains) losses | (840) | 1,162 | \u2014 | \u2014 | 322 | |
New and remeasured leases/joint operations payables | \u2014 | \u2014 | 3,441 | 24 | 3,465 | |
Other movementsb | 3,711 | \u2014 | 543 | (2) | 4,252 | |
At 31 December 2024 | 59,547 | 4,113 | 12,000 | 37 | 75,697 |
$ million | |||
2025 | 2024 | ||
Undiscounted lease liability cash flows due: | |||
Within 1 year | 3,596 | 3,237 | |
1 to 2 years | 2,906 | 2,418 | |
2 to 3 years | 2,222 | 1,798 | |
3 to 4 years | 1,620 | 1,394 | |
4 to 5 years | 1,481 | 1,099 | |
5 to 10 years | 4,076 | 3,039 | |
Over 10 years | 3,435 | 1,283 | |
19,336 | 14,268 | ||
Impact of discounting | (4,765) | (2,268) | |
Lease liabilities at 31 December | 14,571 | 12,000 | |
Of which \u2013 current | 2,832 | 2,660 | |
\u2013 non-current | 11,739 | 9,340 |
$ million | |||
2025 | 2024 | ||
Total cash outflow for amounts included in lease liabilities | 3,727 | 3,283 | |
Expense for variable payments not included in the lease liability a | 61 | 45 | |
Short-term lease expense a | 286 | 499 | |
Additions to right-of-use assets in the period | 4,349 | 3,781 | |
Gain (loss) on sale and leaseback transactions | 1 | \u2014 |
$ million | |||||||
At 31 December 2025 | Note | Measured at amortized cost | Mandatorily measured at fair value through profit or loss | Derivative hedging instruments | Total\u00a0carrying amount | ||
Financial assets | |||||||
Other investments | 18 | \u2014 | 1,015 | \u2014 | 1,015 | ||
Loans | 1,991 | 457 | \u2014 | 2,448 | |||
Trade and other receivables | 20 | 26,567 | \u2014 | \u2014 | 26,567 | ||
Derivative financial instruments | 30 | \u2014 | 25,892 | 245 | 26,137 | ||
Cash and cash equivalents | 25 | 31,777 | 4,779 | \u2014 | 36,556 | ||
Financial liabilities | |||||||
Trade and other payables | 22 | (58,182) | \u2014 | \u2014 | (58,182) | ||
Derivative financial instruments | 30 | \u2014 | (23,056) | (1,024) | (24,080) | ||
Accruals | (7,406) | \u2014 | \u2014 | (7,406) | |||
Lease liabilities | 28 | (14,571) | \u2014 | \u2014 | (14,571) | ||
Finance debt | 26 | (57,958) | \u2014 | \u2014 | (57,958) | ||
(77,782) | 9,087 | (779) | (69,474) |
$ million | |||||||
At 31 December 2024 | Note | Measured at amortized cost | Mandatorily measured at fair value through profit or loss | Derivative hedging instruments | Total\u00a0carrying amount | ||
Financial assets | |||||||
Other investments | 18 | 26 | 1,431 | \u2014 | 1,457 | ||
Loans | 1,807 | 377 | \u2014 | 2,184 | |||
Trade and other receivables | 20 | 27,148 | \u2014 | \u2014 | 27,148 | ||
Derivative financial instruments | 30 | \u2014 | 21,226 | \u2014 | 21,226 | ||
Cash and cash equivalents | 25 | 32,547 | 6,657 | \u2014 | 39,204 | ||
Financial liabilities | |||||||
Trade and other payables | 22 | (61,298) | \u2014 | \u2014 | (61,298) | ||
Derivative financial instruments | 30 | \u2014 | (20,224) | (2,655) | (22,879) | ||
Accruals | (7,397) | \u2014 | \u2014 | (7,397) | |||
Lease liabilities | 28 | (12,000) | \u2014 | \u2014 | (12,000) | ||
Finance debt | 26 | (59,547) | \u2014 | \u2014 | (59,547) | ||
(78,714) | 9,467 | (2,655) | (71,902) |
% | |||
As at 31\u00a0December | 2025 | 2024 | |
AAA to AA- | 14% | 12% | |
A+ to A- | 52% | 50% | |
BBB+ to BBB- | 13% | 16% | |
BB+ to BB- | 11% | 10% | |
B+ to B- | 6% | 8% | |
CCC+ and below | 4% | 4% |
$ million | |||||||
Gross amounts of recognized financial assets (liabilities) | Amounts set off | Net\u00a0amounts presented\u00a0on the balance sheet | Related amounts not set off in the balance sheet | Net\u00a0amount | |||
At 31 December 2025 | Master netting arrangements | Cash collateral (received) pledged | |||||
Derivative assets | 28,414 | (2,277) | 26,137 | (7,491) | (544) | 18,102 | |
Derivative liabilities | (26,357) | 2,277 | (24,080) | 7,491 | 101 | (16,488) | |
Trade and other receivables | 14,055 | (6,385) | 7,670 | (1,555) | (170) | 5,945 | |
Trade and other payables | (17,308) | 6,385 | (10,923) | 1,555 | 8 | (9,360) | |
At 31 December 2024 | |||||||
Derivative assets | 23,779 | (2,553) | 21,226 | (5,624) | (362) | 15,240 | |
Derivative liabilities | (25,432) | 2,553 | (22,879) | 5,624 | 294 | (16,961) | |
Trade and other receivables | 17,832 | (9,445) | 8,387 | (1,532) | (206) | 6,649 | |
Trade and other payables | (20,289) | 9,445 | (10,844) | 1,532 | 12 | (9,300) |
2025 | 2024 | ||||||
Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | ||
Carrying amount of liabilities ($ million) | |||||||
Presented within trade and other payables | 5,596 | 1,356 | 1,018 | 7,431 | 1,778 | 390 | |
of which suppliers have received payment from the financial institution | 5,247 | 1,356 | 1,018 | 7,016 | 1,778 | 390 | |
Range of payment due dates (days) | |||||||
Liabilities that are part of the arrangement | 6 to 60 | 30 to 60 | 30 to 60 | 8 to 57 | 30 to 60 | 30 to 60 | |
Trade payables that are not part of the arrangement | 8 to 60 | 6 to 60 | 7 to 60 | 6 to 60 | 6 to 60 | 6 to 60 |
$\u00a0million | |||||||||
2025 | 2024 | ||||||||
Trade\u00a0and other payables a | Accruals | Finance debtb | Interest on finance debt | Trade and other payables a | Accruals | Finance debtb | Interest on finance debt | ||
Within one year | 51,907 | 5,572 | 3,312 | 2,227 | 53,663 | 6,071 | 4,402 | 2,490 | |
1 to 2 years | 1,331 | 319 | 6,628 | 1,995 | 1,670 | 260 | 4,716 | 2,217 | |
2 to 3 years | 1,203 | 181 | 6,007 | 1,717 | 1,177 | 150 | 6,449 | 1,947 | |
3 to 4 years | 1,190 | 161 | 4,235 | 1,480 | 1,139 | 130 | 5,649 | 1,678 | |
4 to 5 years | 1,186 | 172 | 3,680 | 1,312 | 1,138 | 125 | 3,928 | 1,447 | |
5 to 10 years | 2,413 | 496 | 15,775 | 4,136 | 3,889 | 375 | 17,301 | 4,877 | |
Over 10 years | 126 | 505 | 13,292 | 5,347 | 157 | 286 | 13,947 | 6,198 | |
59,356 | 7,406 | 52,929 | 18,214 | 62,833 | 7,397 | 56,392 | 20,854 |
$\u00a0million | |||||||
2025 | 2024 | ||||||
Cash outflows for derivative financial instruments at 31 December | Derivative assets | Derivative liabilities | Total | Derivative assets | Derivative liabilities | Total | |
Within one year | 1,812 | 3,324 | 5,136 | \u2014 | 1,718 | 1,718 | |
1 to 2 years | 2,009 | 1,068 | 3,077 | \u2014 | 5,136 | 5,136 | |
2 to 3 years | 1,085 | 658 | 1,743 | \u2014 | 3,077 | 3,077 | |
3 to 4 years | \u2014 | 3,696 | 3,696 | \u2014 | 1,743 | 1,743 | |
4 to 5 years | 1,330 | 225 | 1,555 | \u2014 | 3,696 | 3,696 | |
5 to 10 years | 3,071 | 4,443 | 7,514 | \u2014 | 8,307 | 8,307 | |
Over 10 years | 498 | 1,465 | 1,963 | \u2014 | 2,486 | 2,486 | |
\u00a0 | 9,805 | 14,879 | 24,684 | \u2014 | 26,163 | 26,163 |
% | |||
As at 31\u00a0December | 2025 | 2024 | |
AAA to AA- | 14% | 12% | |
A+ to A- | 52% | 50% | |
BBB+ to BBB- | 13% | 16% | |
BB+ to BB- | 11% | 10% | |
B+ to B- | 6% | 8% | |
CCC+ and below | 4% | 4% |
$ million | |||||||
Gross amounts of recognized financial assets (liabilities) | Amounts set off | Net\u00a0amounts presented\u00a0on the balance sheet | Related amounts not set off in the balance sheet | Net\u00a0amount | |||
At 31 December 2025 | Master netting arrangements | Cash collateral (received) pledged | |||||
Derivative assets | 28,414 | (2,277) | 26,137 | (7,491) | (544) | 18,102 | |
Derivative liabilities | (26,357) | 2,277 | (24,080) | 7,491 | 101 | (16,488) | |
Trade and other receivables | 14,055 | (6,385) | 7,670 | (1,555) | (170) | 5,945 | |
Trade and other payables | (17,308) | 6,385 | (10,923) | 1,555 | 8 | (9,360) | |
At 31 December 2024 | |||||||
Derivative assets | 23,779 | (2,553) | 21,226 | (5,624) | (362) | 15,240 | |
Derivative liabilities | (25,432) | 2,553 | (22,879) | 5,624 | 294 | (16,961) | |
Trade and other receivables | 17,832 | (9,445) | 8,387 | (1,532) | (206) | 6,649 | |
Trade and other payables | (20,289) | 9,445 | (10,844) | 1,532 | 12 | (9,300) |
2025 | 2024 | ||||||
Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | ||
Carrying amount of liabilities ($ million) | |||||||
Presented within trade and other payables | 5,596 | 1,356 | 1,018 | 7,431 | 1,778 | 390 | |
of which suppliers have received payment from the financial institution | 5,247 | 1,356 | 1,018 | 7,016 | 1,778 | 390 | |
Range of payment due dates (days) | |||||||
Liabilities that are part of the arrangement | 6 to 60 | 30 to 60 | 30 to 60 | 8 to 57 | 30 to 60 | 30 to 60 | |
Trade payables that are not part of the arrangement | 8 to 60 | 6 to 60 | 7 to 60 | 6 to 60 | 6 to 60 | 6 to 60 |
$\u00a0million | |||||||||
2025 | 2024 | ||||||||
Trade\u00a0and other payables a | Accruals | Finance debtb | Interest on finance debt | Trade and other payables a | Accruals | Finance debtb | Interest on finance debt | ||
Within one year | 51,907 | 5,572 | 3,312 | 2,227 | 53,663 | 6,071 | 4,402 | 2,490 | |
1 to 2 years | 1,331 | 319 | 6,628 | 1,995 | 1,670 | 260 | 4,716 | 2,217 | |
2 to 3 years | 1,203 | 181 | 6,007 | 1,717 | 1,177 | 150 | 6,449 | 1,947 | |
3 to 4 years | 1,190 | 161 | 4,235 | 1,480 | 1,139 | 130 | 5,649 | 1,678 | |
4 to 5 years | 1,186 | 172 | 3,680 | 1,312 | 1,138 | 125 | 3,928 | 1,447 | |
5 to 10 years | 2,413 | 496 | 15,775 | 4,136 | 3,889 | 375 | 17,301 | 4,877 | |
Over 10 years | 126 | 505 | 13,292 | 5,347 | 157 | 286 | 13,947 | 6,198 | |
59,356 | 7,406 | 52,929 | 18,214 | 62,833 | 7,397 | 56,392 | 20,854 |
$\u00a0million | |||||||
2025 | 2024 | ||||||
Cash outflows for derivative financial instruments at 31 December | Derivative assets | Derivative liabilities | Total | Derivative assets | Derivative liabilities | Total | |
Within one year | 1,812 | 3,324 | 5,136 | \u2014 | 1,718 | 1,718 | |
1 to 2 years | 2,009 | 1,068 | 3,077 | \u2014 | 5,136 | 5,136 | |
2 to 3 years | 1,085 | 658 | 1,743 | \u2014 | 3,077 | 3,077 | |
3 to 4 years | \u2014 | 3,696 | 3,696 | \u2014 | 1,743 | 1,743 | |
4 to 5 years | 1,330 | 225 | 1,555 | \u2014 | 3,696 | 3,696 | |
5 to 10 years | 3,071 | 4,443 | 7,514 | \u2014 | 8,307 | 8,307 | |
Over 10 years | 498 | 1,465 | 1,963 | \u2014 | 2,486 | 2,486 | |
\u00a0 | 9,805 | 14,879 | 24,684 | \u2014 | 26,163 | 26,163 |
% | |||
As at 31\u00a0December | 2025 | 2024 | |
AAA to AA- | 14% | 12% | |
A+ to A- | 52% | 50% | |
BBB+ to BBB- | 13% | 16% | |
BB+ to BB- | 11% | 10% | |
B+ to B- | 6% | 8% | |
CCC+ and below | 4% | 4% |
$ million | |||||||
Gross amounts of recognized financial assets (liabilities) | Amounts set off | Net\u00a0amounts presented\u00a0on the balance sheet | Related amounts not set off in the balance sheet | Net\u00a0amount | |||
At 31 December 2025 | Master netting arrangements | Cash collateral (received) pledged | |||||
Derivative assets | 28,414 | (2,277) | 26,137 | (7,491) | (544) | 18,102 | |
Derivative liabilities | (26,357) | 2,277 | (24,080) | 7,491 | 101 | (16,488) | |
Trade and other receivables | 14,055 | (6,385) | 7,670 | (1,555) | (170) | 5,945 | |
Trade and other payables | (17,308) | 6,385 | (10,923) | 1,555 | 8 | (9,360) | |
At 31 December 2024 | |||||||
Derivative assets | 23,779 | (2,553) | 21,226 | (5,624) | (362) | 15,240 | |
Derivative liabilities | (25,432) | 2,553 | (22,879) | 5,624 | 294 | (16,961) | |
Trade and other receivables | 17,832 | (9,445) | 8,387 | (1,532) | (206) | 6,649 | |
Trade and other payables | (20,289) | 9,445 | (10,844) | 1,532 | 12 | (9,300) |
2025 | 2024 | ||||||
Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | ||
Carrying amount of liabilities ($ million) | |||||||
Presented within trade and other payables | 5,596 | 1,356 | 1,018 | 7,431 | 1,778 | 390 | |
of which suppliers have received payment from the financial institution | 5,247 | 1,356 | 1,018 | 7,016 | 1,778 | 390 | |
Range of payment due dates (days) | |||||||
Liabilities that are part of the arrangement | 6 to 60 | 30 to 60 | 30 to 60 | 8 to 57 | 30 to 60 | 30 to 60 | |
Trade payables that are not part of the arrangement | 8 to 60 | 6 to 60 | 7 to 60 | 6 to 60 | 6 to 60 | 6 to 60 |
$\u00a0million | |||||||||
2025 | 2024 | ||||||||
Trade\u00a0and other payables a | Accruals | Finance debtb | Interest on finance debt | Trade and other payables a | Accruals | Finance debtb | Interest on finance debt | ||
Within one year | 51,907 | 5,572 | 3,312 | 2,227 | 53,663 | 6,071 | 4,402 | 2,490 | |
1 to 2 years | 1,331 | 319 | 6,628 | 1,995 | 1,670 | 260 | 4,716 | 2,217 | |
2 to 3 years | 1,203 | 181 | 6,007 | 1,717 | 1,177 | 150 | 6,449 | 1,947 | |
3 to 4 years | 1,190 | 161 | 4,235 | 1,480 | 1,139 | 130 | 5,649 | 1,678 | |
4 to 5 years | 1,186 | 172 | 3,680 | 1,312 | 1,138 | 125 | 3,928 | 1,447 | |
5 to 10 years | 2,413 | 496 | 15,775 | 4,136 | 3,889 | 375 | 17,301 | 4,877 | |
Over 10 years | 126 | 505 | 13,292 | 5,347 | 157 | 286 | 13,947 | 6,198 | |
59,356 | 7,406 | 52,929 | 18,214 | 62,833 | 7,397 | 56,392 | 20,854 |
$\u00a0million | |||||||
2025 | 2024 | ||||||
Cash outflows for derivative financial instruments at 31 December | Derivative assets | Derivative liabilities | Total | Derivative assets | Derivative liabilities | Total | |
Within one year | 1,812 | 3,324 | 5,136 | \u2014 | 1,718 | 1,718 | |
1 to 2 years | 2,009 | 1,068 | 3,077 | \u2014 | 5,136 | 5,136 | |
2 to 3 years | 1,085 | 658 | 1,743 | \u2014 | 3,077 | 3,077 | |
3 to 4 years | \u2014 | 3,696 | 3,696 | \u2014 | 1,743 | 1,743 | |
4 to 5 years | 1,330 | 225 | 1,555 | \u2014 | 3,696 | 3,696 | |
5 to 10 years | 3,071 | 4,443 | 7,514 | \u2014 | 8,307 | 8,307 | |
Over 10 years | 498 | 1,465 | 1,963 | \u2014 | 2,486 | 2,486 | |
\u00a0 | 9,805 | 14,879 | 24,684 | \u2014 | 26,163 | 26,163 |
$ million | |||||
2025 | 2024 | ||||
Fair value asset | Fair value liability | Fair value asset | Fair value liability | ||
Derivatives held for trading | |||||
Currency derivatives | 549 | (720) | 343 | (1,738) | |
Oil price derivatives | 1,509 | (1,315) | 1,350 | (1,071) | |
Natural gas price derivatives | 14,974 | (13,781) | 11,533 | (10,506) | |
Power price derivatives | 8,605 | (7,046) | 7,905 | (6,893) | |
Other derivatives | 255 | (194) | 95 | (16) | |
25,892 | (23,056) | 21,226 | (20,224) | ||
Cash flow hedges | |||||
Currency forwards | \u2014 | \u2014 | \u2014 | \u2014 | |
\u2014 | \u2014 | \u2014 | \u2014 | ||
Fair value hedges | |||||
Currency swaps | 245 | (1,022) | \u2014 | (2,651) | |
Interest rate swaps | \u2014 | (2) | \u2014 | (4) | |
245 | (1,024) | \u2014 | (2,655) | ||
26,137 | (24,080) | 21,226 | (22,879) | ||
Of which \u2013 current | 5,180 | (4,413) | 5,112 | (4,347) | |
\u2013 non-current | 20,957 | (19,667) | 16,114 | (18,532) |
$ million | ||||||||
2025 | ||||||||
Less\u00a0than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | 130 | 90 | 32 | 26 | 63 | 208 | 549 | |
Oil price derivatives | 1,277 | 130 | 52 | 42 | 6 | 2 | 1,509 | |
Natural gas price derivatives | 2,116 | 1,057 | 857 | 747 | 662 | 9,535 | 14,974 | |
Power price derivatives | 1,653 | 1,211 | 790 | 531 | 408 | 4,012 | 8,605 | |
Other derivatives | 1 | 2 | 226 | 1 | \u2014 | 25 | 255 | |
5,177 | 2,490 | 1,957 | 1,347 | 1,139 | 13,782 | 25,892 | ||
$\u00a0million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | 197 | 19 | 10 | 7 | 7 | 103 | 343 | |
Oil price derivatives | 1,004 | 156 | 78 | 53 | 55 | 4 | 1,350 | |
Natural gas price derivatives | 2,337 | 923 | 628 | 556 | 503 | 6,586 | 11,533 | |
Power price derivatives | 1,571 | 990 | 627 | 426 | 396 | 3,895 | 7,905 | |
Other derivatives | 4 | 4 | \u2014 | 85 | \u2014 | 2 | 95 | |
5,113 | 2,092 | 1,343 | 1,127 | 961 | 10,590 | 21,226 |
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | (192) | (20) | (14) | (196) | (12) | (286) | (720) | |
Oil price derivatives | (1,155) | (138) | (15) | (6) | (1) | \u2014 | (1,315) | |
Natural gas price derivatives | (1,748) | (917) | (705) | (605) | (545) | (9,261) | (13,781) | |
Power price derivatives | (1,268) | (996) | (677) | (504) | (336) | (3,265) | (7,046) | |
Other derivatives | (18) | (7) | (169) | \u2014 | \u2014 | \u2014 | (194) | |
(4,381) | (2,078) | (1,580) | (1,311) | (894) | (12,812) | (23,056) | ||
$ million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | (111) | (529) | (172) | (4) | (562) | (360) | (1,738) | |
Oil price derivatives | (975) | (65) | (16) | (6) | (9) | \u2014 | (1,071) | |
Natural gas price derivatives | (2,075) | (836) | (515) | (409) | (363) | (6,308) | (10,506) | |
Power price derivatives | (1,062) | (779) | (569) | (401) | (471) | (3,611) | (6,893) | |
Other derivatives | (6) | (1) | \u2014 | (9) | \u2014 | \u2014 | (16) | |
(4,229) | (2,210) | (1,272) | (829) | (1,405) | (10,279) | (20,224) |
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | 131 | 17 | 6 | \u2014 | \u2014 | \u2014 | 154 | |
Level 2 | 4,813 | 1,541 | 940 | 296 | 198 | 156 | 7,944 | |
Level 3 | 1,585 | 1,339 | 1,199 | 1,105 | 983 | 13,860 | 20,071 | |
6,529 | 2,897 | 2,145 | 1,401 | 1,181 | 14,016 | 28,169 | ||
Less: netting by counterparty | (1,352) | (407) | (188) | (54) | (42) | (234) | (2,277) | |
5,177 | 2,490 | 1,957 | 1,347 | 1,139 | 13,782 | 25,892 | ||
Fair value of derivative liabilities | ||||||||
Level 1 | (131) | (18) | (5) | (1) | (1) | \u2014 | (156) | |
Level 2 | (4,337) | (1,284) | (700) | (395) | (59) | (235) | (7,010) | |
Level 3 | (1,265) | (1,183) | (1,063) | (969) | (876) | (12,811) | (18,167) | |
(5,733) | (2,485) | (1,768) | (1,365) | (936) | (13,046) | (25,333) | ||
Less: netting by counterparty | 1,352 | 407 | 188 | 54 | 42 | 234 | 2,277 | |
(4,381) | (2,078) | (1,580) | (1,311) | (894) | (12,812) | (23,056) | ||
Net fair value | 796 | 412 | 377 | 36 | 245 | 970 | 2,836 | |
$\u00a0million | ||||||||
2024 | ||||||||
Less\u00a0than 1\u00a0year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | 157 | 35 | 7 | 2 | \u2014 | \u2014 | 201 | |
Level 2 | 5,037 | 1,457 | 551 | 330 | 134 | 107 | 7,616 | |
Level 3 | 1,516 | 1,175 | 948 | 839 | 858 | 10,626 | 15,962 | |
6,710 | 2,667 | 1,506 | 1,171 | 992 | 10,733 | 23,779 | ||
Less: netting by counterparty | (1,597) | (575) | (163) | (44) | (31) | (143) | (2,553) | |
5,113 | 2,092 | 1,343 | 1,127 | 961 | 10,590 | 21,226 | ||
Fair value of derivative liabilities | ||||||||
Level 1 | (124) | (20) | (7) | (2) | \u2014 | \u2014 | (153) | |
Level 2 | (4,491) | (1,868) | (625) | (189) | (717) | (289) | (8,179) | |
Level 3 | (1,211) | (897) | (803) | (682) | (719) | (10,133) | (14,445) | |
(5,826) | (2,785) | (1,435) | (873) | (1,436) | (10,422) | (22,777) | ||
Less: netting by counterparty | 1,597 | 575 | 163 | 44 | 31 | 143 | 2,553 | |
(4,229) | (2,210) | (1,272) | (829) | (1,405) | (10,279) | (20,224) | ||
Net fair value | 884 | (118) | 71 | 298 | (444) | 311 | 1,002 |
$ million | |||||||
Oil price | Natural\u00a0gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2025 | 30 | 394 | (306) | 12 | 2 | 132 | |
Gains (losses) recognized in the income statement | 85 | 62 | 466 | 115 | 23 | 751 | |
Sales | \u2014 | \u2014 | 84 | \u2014 | \u2014 | 84 | |
Settlements | (50) | (113) | (113) | (18) | \u2014 | (294) | |
Transfers out of level 3 | (8) | (412) | (146) | \u2014 | 1 | (565) | |
Net fair value of contracts at 31 December 2025 | 57 | (69) | (15) | 109 | 26 | 108 | |
Deferred day-one gains (losses) | 1,796 | ||||||
Derivative asset (liability) | 1,904 | ||||||
$ million | |||||||
Oil price | Natural gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2024 | 107 | 599 | (120) | 219 | 2 | 807 | |
Gains (losses) recognized in the income statement | (26) | (90) | 129 | (193) | \u2014 | (180) | |
Purchases | \u2014 | \u2014 | 31 | \u2014 | \u2014 | 31 | |
Settlements | (38) | (100) | (377) | (14) | \u2014 | (529) | |
Transfers out of level 3 | (13) | (15) | 31 | \u2014 | \u2014 | 3 | |
Net fair value of contracts at 31 December 2024 | 30 | 394 | (306) | 12 | 2 | 132 | |
Deferred day-one gains (losses) | 1,385 | ||||||
Derivative asset (liability) | 1,517 |
$ million | ||||
Change in fair value of hedging instrument used to calculate ineffectiveness | Change in fair value of hedged item used to calculate ineffectiveness | Hedge ineffectiveness recognized in profit or (loss) | ||
At 31 December 2025 | ||||
Cash flow hedges | ||||
Foreign exchange risk | ||||
Highly probable forecast capital expenditure | \u2014 | \u2014 | \u2014 | |
Commodity price risk | ||||
Highly probable forecast sales | 287 | (287) | \u2014 | |
At 31 December 2024 | ||||
Cash flow hedges | ||||
Foreign exchange risk | ||||
Highly probable forecast capital expenditure | \u2014 | \u2014 | \u2014 | |
Commodity price risk | ||||
Highly probable forecast sales | 155 | (155) | \u2014 |
Carrying amount of hedging instrument | Nominal amounts of hedging instruments | ||||
Assets | Liabilities | ||||
At 31 December 2025 | $ million | $ million | $ million | mmBtu | |
Cash flow hedges | |||||
Foreign exchange risk | |||||
Highly probable forecast capital expenditure | \u2014 | \u2014 | 87 | ||
Commodity price risk | |||||
Highly probable forecast sales | \u2014 | \u2014 | (686) | ||
At 31 December 2024 | |||||
Cash flow hedges | |||||
Foreign exchange risk | |||||
Highly probable forecast capital expenditure | \u2014 | \u2014 | 95 | ||
Commodity price risk | |||||
Highly probable forecast sales | \u2014 | \u2014 | (209) |
Weighted average price/rate | |||||
2025 | 2024 | ||||
At 31 December | Forecast capital expenditure | Forecast sales | Forecast capital expenditure | Forecast sales | |
Sterling/US dollar | 1.35 | 1.25 | |||
Euro/US dollar | \u2014 | 1.04 | |||
Australian dollar/US dollar | 0.67 | \u2014 | |||
Henry Hub $/mmBtu | 4.01 | 3.38 |
$ million | ||||
Change in fair value of hedging instrument used to calculate ineffectiveness | Change in fair value of hedged item used to calculate ineffectiveness | Hedge ineffectiveness recognized in profit or (loss) | ||
At 31 December 2025 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | (2) | 2 | \u2014 | |
Interest rate and foreign currency risk on finance debt | (1,850) | 1,797 | 53 | |
At 31 December 2024 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | \u2014 | 1 | (1) | |
Interest rate and foreign currency risk on finance debt | 927 | (772) | (155) |
$ million | ||||
Carrying amount of hedging instrument | Nominal amounts of hedging instruments | |||
At 31 December 2025 | Assets | Liabilities | ||
Fair value hedges | ||||
Interest rate risk on finance debt | \u2014 | (2) | 149 | |
Interest rate and foreign currency risk on finance debt | 245 | (1,022) | 16,304 | |
At 31 December 2024 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | \u2014 | (4) | 132 | |
Interest rate and foreign currency risk on finance debt | \u2014 | (2,651) | 15,887 |
$ million | |||||||||
At 31 December 2025 | Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5-10 years | Over 10 years | Total | |
Fair value hedges | |||||||||
Interest rate risk on finance debt | 149 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 149 | |
2,045 | 1,525 | 1,843 | 1,166 | 1,095 | 7,099 | 1,531 | 16,304 | ||
At 31 December 2024 | |||||||||
Fair value hedges | |||||||||
Interest rate risk on finance debt | \u2014 | 132 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 132 | |
1,614 | 1,819 | 1,346 | 1,627 | 1,047 | 6,521 | 1,913 | 15,887 |
At 31 December | 2025 | 2024 | |||
Interest rate swaps | Cross-currency interest rate swaps | Interest rate swaps | Cross-currency interest rate swaps | ||
Interest rate | 4.84% | 5.64% | 5.45% | 6.34% | |
Sterling/US dollar | 1.28 | 1.28 | |||
Euro/US dollar | 1.13 | 1.13 | |||
Hong Kong dollar/US dollar | 0.13 | \u2014 | |||
Canadian dollar/US dollar | \u2014 | 0.78 | |||
Australian dollar/ US dollar | 0.67 | 0.67 | |||
Japanese Yen/ US dollar | 0.01 | 0.01 | |||
Swiss Franc/US dollar | 1.18 | 1.18 |
$ million | |||||
Accumulated fair value adjustment included in the carrying amount of hedged items | |||||
At 31 December 2025 | Liabilities | Assets | Liabilities | Discontinued hedges | |
Fair value hedges | |||||
Interest rate risk on finance debt | (149) | 1 | \u2014 | (85) | |
Interest rate and foreign currency risk on finance debt | (16,281) | 1,201 | (35) | 134 | |
At 31 December 2024 | |||||
Fair value hedges | |||||
Interest rate risk on finance debt | (156) | 3 | \u2014 | (160) | |
Interest rate and foreign currency risk on finance debt | (16,295) | 1,017 | \u2014 | 143 |
$ million | |||||
Cash flow hedge reserve | |||||
Highly probable forecast capital expenditure | Highly probable forecast sales | Interest rate and foreign currency risk on finance debt | Total | ||
At 1 January 2025 | 3 | (2) | (186) | (185) | |
Recognized in other comprehensive income | |||||
Cash flow hedges marked to market | 5 | 287 | \u2014 | 292 | |
\u2014 | (127) | \u2014 | (127) | ||
Costs of hedging marked to market | \u2014 | \u2014 | 27 | 27 | |
Costs of hedging reclassified to the income statement | \u2014 | \u2014 | 34 | 34 | |
5 | 160 | 61 | 226 | ||
Cash flow hedges transferred to the balance sheet | (6) | \u2014 | \u2014 | (6) | |
At 31 December 2025 | 2 | 158 | (125) | 35 | |
$ million | |||||
Cash flow hedge reserve | |||||
Highly probable forecast capital expenditure | Highly probable forecast sales | Interest rate and foreign currency risk on finance debt | Total | ||
At 1 January 2024 | 14 | 529 | (182) | 361 | |
Recognized in other comprehensive income | |||||
Cash flow hedges marked to market | (1) | 155 | \u2014 | 154 | |
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss | \u2014 | (686) | \u2014 | (686) | |
Costs of hedging marked to market | \u2014 | \u2014 | (2) | (2) | |
Costs of hedging reclassified to the income statement | \u2014 | \u2014 | (2) | (2) | |
(1) | (531) | (4) | (536) | ||
Cash flow hedges transferred to the balance sheet | (10) | \u2014 | \u2014 | (10) | |
At 31 December 2024 | 3 | (2) | (186) | (185) |
$ million | ||||||||
2025 | ||||||||
Less\u00a0than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | 130 | 90 | 32 | 26 | 63 | 208 | 549 | |
Oil price derivatives | 1,277 | 130 | 52 | 42 | 6 | 2 | 1,509 | |
Natural gas price derivatives | 2,116 | 1,057 | 857 | 747 | 662 | 9,535 | 14,974 | |
Power price derivatives | 1,653 | 1,211 | 790 | 531 | 408 | 4,012 | 8,605 | |
Other derivatives | 1 | 2 | 226 | 1 | \u2014 | 25 | 255 | |
5,177 | 2,490 | 1,957 | 1,347 | 1,139 | 13,782 | 25,892 | ||
$\u00a0million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | 197 | 19 | 10 | 7 | 7 | 103 | 343 | |
Oil price derivatives | 1,004 | 156 | 78 | 53 | 55 | 4 | 1,350 | |
Natural gas price derivatives | 2,337 | 923 | 628 | 556 | 503 | 6,586 | 11,533 | |
Power price derivatives | 1,571 | 990 | 627 | 426 | 396 | 3,895 | 7,905 | |
Other derivatives | 4 | 4 | \u2014 | 85 | \u2014 | 2 | 95 | |
5,113 | 2,092 | 1,343 | 1,127 | 961 | 10,590 | 21,226 |
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | (192) | (20) | (14) | (196) | (12) | (286) | (720) | |
Oil price derivatives | (1,155) | (138) | (15) | (6) | (1) | \u2014 | (1,315) | |
Natural gas price derivatives | (1,748) | (917) | (705) | (605) | (545) | (9,261) | (13,781) | |
Power price derivatives | (1,268) | (996) | (677) | (504) | (336) | (3,265) | (7,046) | |
Other derivatives | (18) | (7) | (169) | \u2014 | \u2014 | \u2014 | (194) | |
(4,381) | (2,078) | (1,580) | (1,311) | (894) | (12,812) | (23,056) | ||
$ million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Currency derivatives | (111) | (529) | (172) | (4) | (562) | (360) | (1,738) | |
Oil price derivatives | (975) | (65) | (16) | (6) | (9) | \u2014 | (1,071) | |
Natural gas price derivatives | (2,075) | (836) | (515) | (409) | (363) | (6,308) | (10,506) | |
Power price derivatives | (1,062) | (779) | (569) | (401) | (471) | (3,611) | (6,893) | |
Other derivatives | (6) | (1) | \u2014 | (9) | \u2014 | \u2014 | (16) | |
(4,229) | (2,210) | (1,272) | (829) | (1,405) | (10,279) | (20,224) |
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | 131 | 17 | 6 | \u2014 | \u2014 | \u2014 | 154 | |
Level 2 | 4,813 | 1,541 | 940 | 296 | 198 | 156 | 7,944 | |
Level 3 | 1,585 | 1,339 | 1,199 | 1,105 | 983 | 13,860 | 20,071 | |
6,529 | 2,897 | 2,145 | 1,401 | 1,181 | 14,016 | 28,169 | ||
Less: netting by counterparty | (1,352) | (407) | (188) | (54) | (42) | (234) | (2,277) | |
5,177 | 2,490 | 1,957 | 1,347 | 1,139 | 13,782 | 25,892 | ||
Fair value of derivative liabilities | ||||||||
Level 1 | (131) | (18) | (5) | (1) | (1) | \u2014 | (156) | |
Level 2 | (4,337) | (1,284) | (700) | (395) | (59) | (235) | (7,010) | |
Level 3 | (1,265) | (1,183) | (1,063) | (969) | (876) | (12,811) | (18,167) | |
(5,733) | (2,485) | (1,768) | (1,365) | (936) | (13,046) | (25,333) | ||
Less: netting by counterparty | 1,352 | 407 | 188 | 54 | 42 | 234 | 2,277 | |
(4,381) | (2,078) | (1,580) | (1,311) | (894) | (12,812) | (23,056) | ||
Net fair value | 796 | 412 | 377 | 36 | 245 | 970 | 2,836 | |
$\u00a0million | ||||||||
2024 | ||||||||
Less\u00a0than 1\u00a0year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5\u00a0years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | 157 | 35 | 7 | 2 | \u2014 | \u2014 | 201 | |
Level 2 | 5,037 | 1,457 | 551 | 330 | 134 | 107 | 7,616 | |
Level 3 | 1,516 | 1,175 | 948 | 839 | 858 | 10,626 | 15,962 | |
6,710 | 2,667 | 1,506 | 1,171 | 992 | 10,733 | 23,779 | ||
Less: netting by counterparty | (1,597) | (575) | (163) | (44) | (31) | (143) | (2,553) | |
5,113 | 2,092 | 1,343 | 1,127 | 961 | 10,590 | 21,226 | ||
Fair value of derivative liabilities | ||||||||
Level 1 | (124) | (20) | (7) | (2) | \u2014 | \u2014 | (153) | |
Level 2 | (4,491) | (1,868) | (625) | (189) | (717) | (289) | (8,179) | |
Level 3 | (1,211) | (897) | (803) | (682) | (719) | (10,133) | (14,445) | |
(5,826) | (2,785) | (1,435) | (873) | (1,436) | (10,422) | (22,777) | ||
Less: netting by counterparty | 1,597 | 575 | 163 | 44 | 31 | 143 | 2,553 | |
(4,229) | (2,210) | (1,272) | (829) | (1,405) | (10,279) | (20,224) | ||
Net fair value | 884 | (118) | 71 | 298 | (444) | 311 | 1,002 |
$ million | |||||||
Oil price | Natural\u00a0gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2025 | 30 | 394 | (306) | 12 | 2 | 132 | |
Gains (losses) recognized in the income statement | 85 | 62 | 466 | 115 | 23 | 751 | |
Sales | \u2014 | \u2014 | 84 | \u2014 | \u2014 | 84 | |
Settlements | (50) | (113) | (113) | (18) | \u2014 | (294) | |
Transfers out of level 3 | (8) | (412) | (146) | \u2014 | 1 | (565) | |
Net fair value of contracts at 31 December 2025 | 57 | (69) | (15) | 109 | 26 | 108 | |
Deferred day-one gains (losses) | 1,796 | ||||||
Derivative asset (liability) | 1,904 | ||||||
$ million | |||||||
Oil price | Natural gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2024 | 107 | 599 | (120) | 219 | 2 | 807 | |
Gains (losses) recognized in the income statement | (26) | (90) | 129 | (193) | \u2014 | (180) | |
Purchases | \u2014 | \u2014 | 31 | \u2014 | \u2014 | 31 | |
Settlements | (38) | (100) | (377) | (14) | \u2014 | (529) | |
Transfers out of level 3 | (13) | (15) | 31 | \u2014 | \u2014 | 3 | |
Net fair value of contracts at 31 December 2024 | 30 | 394 | (306) | 12 | 2 | 132 | |
Deferred day-one gains (losses) | 1,385 | ||||||
Derivative asset (liability) | 1,517 |
2025 | 2024 | 2023 | |||||
Issued | Shares thousand | $ million | Shares thousand | $ million | Shares thousand | $ million | |
8% cumulative first preference shares of \u00a31 each a | 7,233 | 12 | 7,233 | 12 | 7,233 | 12 | |
9% cumulative second preference shares of \u00a31 each a | 5,473 | 9 | 5,473 | 9 | 5,473 | 9 | |
21 | 21 | 21 | |||||
Ordinary shares of 25 cents each | |||||||
At 1\u00a0January | 16,662,465 | 4,165 | 17,900,800 | 4,475 | 19,097,783 | 4,774 | |
Issue of new shares for employee share-based payment\u00a0plans | \u2014 | \u2014 | \u2014 | \u2014 | 66,000 | 17 | |
Repurchase of ordinary share capital | (835,649) | (209) | (1,238,335) | (310) | (1,262,983) | (316) | |
Repurchases transferred to treasury shares | 659,497 | 165 | \u2014 | \u2014 | \u2014 | \u2014 | |
At 31\u00a0December | 16,486,313 | 4,121 | 16,662,465 | 4,165 | 17,900,800 | 4,475 | |
4,142 | 4,186 | 4,496 |
2025 | 2024 | 2023 | |||||
Shares thousand | Nominal\u00a0value $ million | Shares thousand | Nominal\u00a0value $ million | Shares thousand | Nominal\u00a0value $\u00a0million | ||
At 1\u00a0January | 812,021 | 204 | 1,077,079 | 271 | 1,124,927 | 281 | |
Purchases for settlement of employee share plans | 660,765 | 165 | 8,302 | 2 | 24,688 | 6 | |
Issue of new shares for employee share-based payment\u00a0plans | \u2014 | \u2014 | \u2014 | \u2014 | 71,039 | 19 | |
Shares re-issued for employee share-based payment plans | (363,198) | (92) | (273,360) | (69) | (143,575) | (35) | |
At 31\u00a0December | 1,109,588 | 277 | 812,021 | 204 | 1,077,079 | 271 | |
Of which \u2013 shares held in treasury by bp | 857,433 | 214 | 481,474 | 121 | 726,339 | 183 | |
\u2013 shares held in ESOP trusts | 252,118 | 63 | 330,510 | 83 | 350,704 | 88 | |
\u2013 shares held by bp\u2019s US share plan administrator b | 37 | \u2014 | 37 | \u2014 | 36 | \u2014 |
Share capital | Share premium account | Capital redemption reserve | Merger reserve | Total share\u00a0capital and\u00a0capital reserves | ||
At 1 January 2025 | 4,186 | 14,031 | 2,806 | 27,206 | 48,229 | |
Profit (loss) for the year | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges and costs of hedging (including reclassifications) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Share of items relating to equity-accounted entities, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Remeasurements of equity investments | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges that will subsequently be transferred to the balance sheet | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Total comprehensive income | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Dividends | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges transferred to the balance sheet, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Repurchases of ordinary share capital | (44) | \u2014 | 44 | \u2014 | \u2014 | |
Share-based payments, net of taxb | \u2014 | 35 | \u2014 | \u2014 | 35 | |
Share of equity-accounted entities\u2019 changes in equity, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Issue of perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Redemption of perpetual hybrid bonds, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Payments on perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Transactions involving non-controlling interests, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
At 31 December 2025 | 4,142 | 14,066 | 2,850 | 27,206 | 48,264 | |
At 1 January 2024 | 4,496 | 13,815 | 2,496 | 27,206 | 48,013 | |
Profit (loss) for the year | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications)a | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges and costs of hedging (including reclassifications) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Share of items relating to equity-accounted entities, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Other | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Remeasurements of equity investments | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges that will subsequently be transferred to the balance sheet | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Total comprehensive income | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Dividends | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges transferred to the balance sheet, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Repurchases of ordinary share capital | (310) | \u2014 | 310 | \u2014 | \u2014 | |
Share-based payments, net of taxb | \u2014 | 216 | \u2014 | \u2014 | 216 | |
Issue of perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Redemption of perpetual hybrid bonds, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Payments on perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Transactions involving non-controlling interests, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
At 31 December 2024 | 4,186 | 14,031 | 2,806 | 27,206 | 48,229 |
$ million | ||||||||||
Treasury shares | Foreign currency translation reserve | Investments in equity instruments | Cash flow hedges | Costs of hedging | Total fair value reserves | Profit and loss account | bp shareholders\u2019 equity | Non-controlling interests | Total equity | |
Hybrid bonds | Other interest | |||||||||
(9,030) | (2,196) | (3) | (98) | (187) | (288) | 22,531 | 59,246 | 16,649 | 2,423 | 78,318 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 55 | 55 | 799 | 441 | 1,295 |
\u2014 | 1,804 | 1 | \u2014 | \u2014 | 1 | \u2014 | 1,805 | \u2014 | 115 | 1,920 |
\u2014 | \u2014 | \u2014 | 122 | 61 | 183 | \u2014 | 183 | \u2014 | \u2014 | 183 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (4) | (4) | \u2014 | \u2014 | (4) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (166) | (166) | \u2014 | \u2014 | (166) |
\u2014 | \u2014 | (6) | \u2014 | \u2014 | (6) | \u2014 | (6) | \u2014 | \u2014 | (6) |
\u2014 | \u2014 | \u2014 | 5 | \u2014 | 5 | \u2014 | 5 | \u2014 | \u2014 | 5 |
\u2014 | 1,804 | (5) | 127 | 61 | 183 | (115) | 1,872 | 799 | 556 | 3,227 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (5,087) | (5,087) | \u2014 | (524) | (5,611) |
\u2014 | \u2014 | \u2014 | (6) | \u2014 | (6) | \u2014 | (6) | \u2014 | \u2014 | (6) |
(3,558) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (454) | (4,012) | \u2014 | \u2014 | (4,012) |
3,917 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (2,840) | 1,112 | \u2014 | \u2014 | 1,112 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 1 | 1 | \u2014 | \u2014 | 1 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 500 | \u2014 | 500 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (1,200) | \u2014 | (1,200) |
\u2014 | (9) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (9) | (793) | \u2014 | (802) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (65) | (65) | \u2014 | 2,538 | 2,473 |
(8,671) | (401) | (8) | 23 | (126) | (111) | 13,971 | 53,052 | 15,955 | 4,993 | 74,000 |
(11,323) | (1,920) | 38 | 319 | (183) | 174 | 35,339 | 70,283 | 13,566 | 1,644 | 85,493 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 381 | 381 | 641 | 207 | 1,229 |
\u2014 | (276) | (1) | \u2014 | \u2014 | (1) | \u2014 | (277) | \u2014 | (87) | (364) |
\u2014 | \u2014 | \u2014 | (406) | (4) | (410) | \u2014 | (410) | \u2014 | \u2014 | (410) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (12) | (12) | \u2014 | \u2014 | (12) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (1) | (1) | \u2014 | \u2014 | (1) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 367 | 367 | \u2014 | \u2014 | 367 |
\u2014 | \u2014 | (40) | \u2014 | \u2014 | (40) | \u2014 | (40) | \u2014 | \u2014 | (40) |
\u2014 | \u2014 | \u2014 | (1) | \u2014 | (1) | \u2014 | (1) | \u2014 | \u2014 | (1) |
\u2014 | (276) | (41) | (407) | (4) | (452) | 735 | 7 | 641 | 120 | 768 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (5,018) | (5,018) | \u2014 | (375) | (5,393) |
\u2014 | \u2014 | \u2014 | (10) | \u2014 | (10) | \u2014 | (10) | \u2014 | \u2014 | (10) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (7,302) | (7,302) | \u2014 | \u2014 | (7,302) |
2,293 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (1,426) | 1,083 | \u2014 | \u2014 | 1,083 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (22) | (22) | 4,352 | \u2014 | 4,330 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 9 | 9 | (1,300) | \u2014 | (1,291) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (610) | \u2014 | (610) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 216 | 216 | \u2014 | 1,034 | 1,250 |
(9,030) | (2,196) | (3) | (98) | (187) | (288) | 22,531 | 59,246 | 16,649 | 2,423 | 78,318 |
Share capital | Share premium account | Capital redemption reserve | Merger reserve | Total share\u00a0capital and\u00a0capital reserves | ||
At 1 January 2023 | 4,795 | 13,692 | 2,180 | 27,206 | 47,873 | |
Profit (loss) for the year | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges and costs of hedging (including reclassifications) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Share of items relating to equity-accounted entities, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Remeasurements of equity investments | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges that will subsequently be transferred to the balance sheet | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Total comprehensive income | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Dividends | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Cash flow hedges transferred to the balance sheet, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Repurchases of ordinary share capital | (316) | \u2014 | 316 | \u2014 | \u2014 | |
Share-based payments, net of taxa | 17 | 123 | \u2014 | \u2014 | 140 | |
Share of equity-accounted entities\u2019 changes in equity, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Issue of perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Payments on perpetual hybrid bonds | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
Transactions involving non-controlling interests, net of tax | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | |
At 31 December 2023 | 4,496 | 13,815 | 2,496 | 27,206 | 48,013 |
$ million | ||||||||||
Treasury shares | Foreign currency translation reserve | Investments in equity instruments | Cash flow hedges | Costs of hedging | Total fair value reserves | Profit and loss account | bp shareholders\u2019 equity | Non-controlling interests | Total equity | |
Hybrid bonds | Other interest | |||||||||
(12,153) | (2,643) | \u2014 | (183) | (73) | (256) | 34,732 | 67,553 | 13,390 | 2,047 | 82,990 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 15,239 | 15,239 | 586 | 55 | 15,880 |
\u2014 | 728 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 728 | \u2014 | 26 | 754 |
\u2014 | \u2014 | \u2014 | 488 | (110) | 378 | \u2014 | 378 | \u2014 | \u2014 | 378 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (192) | (192) | \u2014 | \u2014 | (192) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (1,504) | (1,504) | \u2014 | \u2014 | (1,504) |
\u2014 | \u2014 | 38 | \u2014 | \u2014 | 38 | \u2014 | 38 | \u2014 | \u2014 | 38 |
\u2014 | \u2014 | \u2014 | 15 | \u2014 | 15 | \u2014 | 15 | \u2014 | \u2014 | 15 |
\u2014 | 728 | 38 | 503 | (110) | 431 | 13,543 | 14,702 | 586 | 81 | 15,369 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (4,831) | (4,831) | \u2014 | (403) | (5,234) |
\u2014 | \u2014 | \u2014 | (1) | \u2014 | (1) | \u2014 | (1) | \u2014 | \u2014 | (1) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (8,167) | (8,167) | \u2014 | \u2014 | (8,167) |
830 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (301) | 669 | \u2014 | \u2014 | 669 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 1 | 1 | \u2014 | \u2014 | 1 |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (1) | (1) | 176 | \u2014 | 175 |
\u2014 | (5) | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | (5) | (586) | \u2014 | (591) |
\u2014 | \u2014 | \u2014 | \u2014 | \u2014 | \u2014 | 363 | 363 | \u2014 | (81) | 282 |
(11,323) | (1,920) | 38 | 319 | (183) | 174 | 35,339 | 70,283 | 13,566 | 1,644 | 85,493 |
$ million | ||||
2025 | ||||
Pre-tax | Tax | Net\u00a0of\u00a0tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | 1,904 | 16 | 1,920 | |
Cash flow hedges (including reclassifications) | 160 | (38) | 122 | |
Costs of hedging (including reclassifications) | 61 | \u2014 | 61 | |
Share of items relating to equity-accounted entities, net of tax | (4) | \u2014 | (4) | |
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asset | (221) | 55 | (166) | |
Remeasurements of equity investments | (6) | \u2014 | (6) | |
Cash flow hedges that will subsequently be transferred to the balance sheet | 5 | \u2014 | 5 | |
Other comprehensive income | 1,899 | 33 | 1,932 | |
$ million | ||||
2024 | ||||
Pre-tax | Tax | Net of tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | (288) | (76) | (364) | |
Cash flow hedges (including reclassifications) | (531) | 125 | (406) | |
Costs of hedging (including reclassifications) | (4) | \u2014 | (4) | |
Share of items relating to equity-accounted entities, net of tax | (12) | \u2014 | (12) | |
Other | \u2014 | (1) | (1) | |
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asset a | (360) | 727 | 367 | |
Remeasurements of equity investments | (47) | 7 | (40) | |
Cash flow hedges that will subsequently be transferred to the balance sheet | (1) | \u2014 | (1) | |
Other comprehensive income | (1,243) | 782 | (461) | |
$ million | ||||
2023 | ||||
Pre-tax | Tax | Net of tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | 583 | 171 | 754 | |
Cash flow hedges (including reclassifications) | 637 | (149) | 488 | |
Costs of hedging (including reclassifications) | (78) | (32) | (110) | |
Share of items relating to equity-accounted entities, net of tax | (192) | \u2014 | (192) | |
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asset | (2,262) | 758 | (1,504) | |
Remeasurements of equity investments | 51 | (13) | 38 | |
Cash flow hedges that will subsequently be transferred to the balance sheet | 15 | \u2014 | 15 | |
Other comprehensive income | (1,246) | 735 | (511) |
2025 | 2024 | 2023 | |||||
Shares thousand | Nominal\u00a0value $ million | Shares thousand | Nominal\u00a0value $ million | Shares thousand | Nominal\u00a0value $\u00a0million | ||
At 1\u00a0January | 812,021 | 204 | 1,077,079 | 271 | 1,124,927 | 281 | |
Purchases for settlement of employee share plans | 660,765 | 165 | 8,302 | 2 | 24,688 | 6 | |
Issue of new shares for employee share-based payment\u00a0plans | \u2014 | \u2014 | \u2014 | \u2014 | 71,039 | 19 | |
Shares re-issued for employee share-based payment plans | (363,198) | (92) | (273,360) | (69) | (143,575) | (35) | |
At 31\u00a0December | 1,109,588 | 277 | 812,021 | 204 | 1,077,079 | 271 | |
Of which \u2013 shares held in treasury by bp | 857,433 | 214 | 481,474 | 121 | 726,339 | 183 | |
\u2013 shares held in ESOP trusts | 252,118 | 63 | 330,510 | 83 | 350,704 | 88 | |
\u2013 shares held by bp\u2019s US share plan administrator b | 37 | \u2014 | 37 | \u2014 | 36 | \u2014 |
$\u00a0million | ||||
2025 | 2024 | 2023 | ||
Total for all directors | ||||
Emoluments | 11 | 8 | 8 | |
Amounts received under incentive schemes a | 3 | 5 | 6 | |
Total | 14 | 13 | 14 |
$\u00a0million | ||||
2025 | 2024 | 2023 | ||
Total for all senior management and non-executive directors | ||||
Short-term employee benefits | 34 | 22 | 31 | |
Pensions and other post-employment benefits | \u2014 | \u2014 | \u2014 | |
Share-based payments a | 28 | 26 | 12 | |
Termination benefits | \u2014 | 3 | \u2014 | |
Total | 62 | 51 | 43 |
$ million | ||||
Fees | 2025 | 2024 | 2023 | |
The audit of the company annual accounts a | 42 | 40 | 38 | |
The audit of accounts of subsidiaries of the company | 17 | 17 | 15 | |
Total audit | 59 | 57 | 53 | |
Audit-related assurance servicesb | 5 | 4 | 4 | |
Total audit and audit-related assurance services | 64 | 61 | 57 | |
Non-audit and other assurance services | 9 | 4 | 3 | |
Services relating to bp pension plans | 1 | 1 | 1 | |
74 | 66 | 61 |
Subsidiaries | % | Country of incorporation | Principal activities | ||
International | |||||
BP Corporate Holdings Limited | 100 | England & Wales | Investment holding | ||
BP Exploration Operating Company Limited | 100 | England & Wales | Exploration and production | ||
*BP Gamma Holdings Limited | 100 | England & Wales | Investment holding | ||
*BP Global Investments Limited | 100 | England & Wales | Investment holding | ||
*BP International Limited | 100 | England & Wales | Integrated oil operations | ||
BP Oil International Limited | 100 | England & Wales | Integrated oil operations | ||
*Castrol Group Holdings Limited | 100 | Scotland | Investment holding | ||
Azerbaijan | |||||
BP Exploration (Caspian Sea) Limited | 100 | England & Wales | Exploration and production | ||
BP Exploration (Azerbaijan) Limited | 100 | England & Wales | Exploration and production | ||
Germany | |||||
BP Europa SE | 100 | Germany | Refining and marketing | ||
Trinidad\u00a0and Tobago | |||||
BP Trinidad and Tobago LLC | 70 | US | Exploration and production | ||
UK | |||||
BP Capital Markets p.l.c. | 100 | England & Wales | Finance | ||
Lightsource BP Renewable Energy Investments Limited | 100 | England & Wales | Onshore renewables | ||
US | |||||
*BP Holdings North America Limited | 100 | England & Wales | Investment holding | ||
Atlantic Richfield Company | 100 | US | Exploration and production, refining and marketing | ||
BP America Inc. | 100 | US | |||
BP America Production Company | 100 | US | |||
BP Company North America Inc. | 100 | US | |||
BP Corporation North America Inc. | 100 | US | |||
BP Products North America Inc. | 100 | US | |||
The Standard Oil Company | 100 | US | |||
Archaea Energy Inc. | 100 | US | Bioenergy | ||
BP Capital Markets America Inc. | 100 | US | Finance | ||
Joint arrangements | % | Country of incorporation | Principal activities | ||
Angola | |||||
Azule Energy Holdings Limited | 50 | England & Wales | Exploration and production |