Corporate information and statement of IFRS compliance [abstract]

Use of judgements, estimates and assumptions

Material accounting policy information: use of judgements, estimates and assumptions

Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp

management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of

contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and

assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text

below, and should be read in conjunction with the information provided in the Notes on financial statements.

The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for

the investments in Rosneft and Aker BP; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the

estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; pensions and other post-

employment benefits; and taxation. Judgements and estimates, not all of which are significant, made in assessing the impact of the current

economic and geopolitical environment, and climate change and the transition to a lower carbon economy on the consolidated financial

statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying

amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text.

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’s assets and liabilities discussed below and on similar assets and

liabilities that may be recognized in the future. The group’s 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’s 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’s 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°C above pre-industrial levels and

pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels.

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

As noted above, the group’s 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’s 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’s 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’s 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 £65/tCO2e in 2026

gradually increasing to £243/tCO2e in 2050.

However, as bp’s 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’s 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’s

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’s 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 – 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’s 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’s business activities over that period. The

significant majority of refining assets, recognized on the group’s 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’s 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.

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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’s 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’s 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’s defined benefit pension plans. See significant estimate: pensions and other post-employment benefits and Note 24 for

further information.

Business combinations and goodwill

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at

their fair values at the acquisition date.

Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling

interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and

liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's

proportionate share in the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated

to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial

recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January

2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments.

Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net

fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and

associates.

Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately

recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.

Segmental reporting

The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the chief executive

officer, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.

The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires

that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision

maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories

sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for

the group is not a recognized measure under IFRS.

During the first quarter 2025, the Archaea Energy business was moved from the customers & products segment to the gas & low carbon energy

segment. The change in segmentation is consistent with a change in the way that resources are allocated, and performance is assessed by the

chief operating decision maker, who for bp is the group chief executive.

Comparative information for 2024 has been restated where material to reflect the changes in reportable segments. For further information see

Note 5.

The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that

the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker

for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before

interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and

lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.

Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and

segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on

consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are

based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of customers &

products.

All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-employment benefit plans are allocated to

Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the

business in which the employees work.

Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country

of domicile.

Non-current assets held for sale

Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.

Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale

transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal

group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets.

Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the

date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to

the plan will be made or that the plan will be withdrawn.

Property, plant and equipment and intangible assets are not depreciated or amortized, and equity accounting of associates and joint ventures is

ceased once classified as held for sale.

Exploration, appraisal, and development expenditure

Exploration and appraisal expenditure

Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are

initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include

employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of

hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely

to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is,

the efforts are not successful, then the costs are expensed.

Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following

the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an

intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is

transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are

expensed.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within

one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover

potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline)

would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful

completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly

planned.

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.

Impairment of property, plant and equipment, intangible assets, and goodwill

Impairment of property, plant and equipment, intangible assets, goodwill, and equity-accounted entities

The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances

indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose

rather than retain assets, changes in the group’s assumptions about discount rates, commodity prices, low plant utilization, evidence of physical

damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure

or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount.

Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that

are largely independent of the cash inflows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of

disposal and its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected

disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount,

the CGU is considered impaired and is written down to its recoverable amount.

The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the

determination of value in use. They contain forecasts for oil and natural gas production, power generation, refinery throughputs, sales volumes for

various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions

allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the

group operates. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas

prices, power prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take

account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and

variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group to the extent that they are

not already reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current

market assessments of the time value of money.

Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does

not reflect the effects of factors that may be specific to the group and not applicable to entities in general. Fair value may be determined by

reference to agreed or expected sales proceeds, recent market transactions for similar assets or using discounted cash flow analyses. Where

discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market

participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.

An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer

exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed

only if there has been a change in the estimates used to determine the asset’s or CGU's recoverable amount since the last impairment loss was

recognized. If that is the case, the carrying amount of the asset or CGU is increased to the lower of its recoverable amount and the carrying amount

that would have been determined, net of depreciation, had no impairment loss been recognized for the asset or CGU in prior years. Impairment

reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s or CGU's

revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the

group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the

group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of

CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not

reversed in a subsequent period.

The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired,

after recognizing its share of any losses of the equity-accounted entity itself. If any such objective evidence of impairment exists, the carrying

amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the

carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.

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.

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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’s 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 million) 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’s 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’s 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’s 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°C above pre-

industrial levels and pursuing efforts to limit the temperature increase to 1.5°C 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’s reserves and resources that support the carrying value of the group’s 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’s 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

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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’s 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’s 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’s

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’s 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’s 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°C 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’s 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’s World Energy Outlook Net Zero Emissions by 2050 (NZE) scenario) considered by IEA to

be consistent with limiting global average temperature to 1.5°C above pre-industrial levels.

These sensitivity analyses do not, however, represent management’s 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 billion higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been

approximately $0.5 billion lower.

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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’s 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 billion. It is estimated that an

increase in revenue of 10% would have resulted in a reduction to the impairment charge of $0.8 billion.

These sensitivity analyses do not, however, represent management’s 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 billion. 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 billion.

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’s value-in-use estimates for refinery CGUs.

Management tested the impact of a $1 per barrel decrease in each refinery’s 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’s currently held refining property, plant

and equipment in the range of $1-2 billion.

This sensitivity analysis does not, however, represent management’s 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 billion relates to goodwill in the oil production & operations

segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $7.2 billion), for which oil and gas price and production

assumptions are key sources of estimation uncertainty. A further $0.9 billion relates to the transition businesses in the gas & low carbon energy

segment (2024 $2.9 billion), 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.

Leases

Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as

leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the

use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any

substitution rights held by the lessor over the asset are not considered substantive.

Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for

as leases. See material accounting policy information: intangible assets.

A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease

term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. For the

majority of the leases in the group, there is not sufficient information available to readily determine the rate implicit in the lease, and therefore the

incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee

legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an

extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise.

The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate,

payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are

presented as financing cash flows and payments of interest are presented as operating cash flows.

Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value

calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized

cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or

development expenditure.

The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the

lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is

depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where

capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting

policy for impairment of property, plant and equipment, intangible assets and goodwill.

Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-

alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the

calculation of the lease liability and right-of-use asset.

If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease

expense is recognized in the income statement on a straight-line basis.

If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes

to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset

adjusted by an equivalent amount.

Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a

corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that

increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.

The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group

has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole

signatory to the lease agreement. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the

group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-

operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over

the right-of-use asset, otherwise no balances are recognized.

Financial liabilities

Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial

liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their

classification, as follows:

Financial liabilities measured at fair value through profit or loss

Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are

carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as

effective hedging instruments, are included in this category.

Derivatives designated as hedging instruments in an effective hedge

Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and

losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.

Financial liabilities measured at amortized cost

All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and

borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.

After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost

is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase,

settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.

This category of financial liabilities includes trade and other payables and finance debt.

Significant judgement: supplier financing arrangements

The group’s 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.

Financial guarantees

The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred if certain associates, joint

ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a

loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s

estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.

Derivative financial instruments and hedging activities

The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and

commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a

derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as

liabilities when the fair value is negative.

Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of

contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the

group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair

value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.

If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation

methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’.

This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contractual cash

flows can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement.

Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement.

For the purpose of hedge accounting, hedges are classified as:

•Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.

•Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized

asset or liability or a highly probable forecast transaction.

Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for

undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk

being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in

offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of

hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

Fair value hedges

The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk

being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies

fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.

Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated

adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over

the hedged item's remaining period to maturity.

Cash flow hedges

The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion

is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged

transaction affects profit or loss.

Where the hedged item is a highly probable forecast transaction that results in the recognition of a non-financial asset or liability, such as a

forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive

income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the

amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss

or when accounting under the equity method is discontinued. Where the hedged item is recognized directly in profit or loss, the amounts

recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as

appropriate.

Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the

hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts

previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or

loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to

occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.

Costs of hedging

The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of

hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to

the hedged item.

For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis

over the term of the hedging relationship.

Offsetting of financial assets and liabilities

Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a

legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the

liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount

receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered

when assessing whether a current legally enforceable right to set off exists.

Employee benefits and Pensions and other post-retirement benefits

Employee benefits

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services

are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date

are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the

award vests. The material accounting policy information for pensions and other post-employment benefits are described below.

Pensions and other post-employment benefits

The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit

method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to

determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a

reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company

becomes committed to a change.

Net interest expense relating to pensions and other post-employment benefits, which is recognized in the income statement, represents the net

change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the

discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking

into account expected changes in the obligation or plan assets during the year.

Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts

included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not

subsequently reclassified to profit and loss.

The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present

value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which

the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid

price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or

reductions in future contributions to the plan.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

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.

Customs duties and sales taxes

Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are

recognized net of the amount of customs duties or sales tax except:

•Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are

recognized as part of the cost of acquisition of the asset.

•Receivables and payables are stated with the amount of customs duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.

Revenue and other income

Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a

promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and

other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its

performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not

significant.

When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that

performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is

allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.

Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized

based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after

delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently

adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price

adjustments, is disclosed as revenue from contracts with customers.

Sales and purchase of commodities accounted for under IFRS 15 are presented on a gross basis in Revenue from contracts with customers and

Purchases respectively. Physically settled derivatives which represent trading or optimization activities are presented net alongside financially

settled derivative contracts in Other operating revenues within Sales and other operating income. Certain physically settled sale and purchase

derivative contracts which are not part of trading and optimization activities are presented gross within Other operating revenues and Purchases

respectively. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues.

Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and

purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.

Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no

purchase or sale is recorded.

Sales and other transactions through which the group loses control of solar projects developed under Lightsource bp’s develop-to-sell business

model are accounted for as revenues from contracts with customers.

Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash

receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).

Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.

Updates to significant accounting policies

Updates to material accounting policy information

Impact of new International Financial Reporting Standards

There are no new or other amended standards or interpretations adopted from 1 January 2025 onwards, that have a significant impact on the

consolidated financial statements for 2025.

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

Not yet adopted

Amendments to IFRS 9 ' Financial Instruments' relating to the settlement of liabilities through electronic payment systems are effective for annual

periods beginning on or after 1 January 2026. bp will adopt the amendments in the financial reporting period commencing 1 January 2026 using the

modified retrospective approach. The amendments clarify the timing of derecognition of financial instruments and whilst they permit financial

liabilities to be derecognized before the settlement date if certain criteria are met, the group is not expected to make this election. Management

has considered the amendments and does not anticipate any material effect on the Group’s financial position or results. The expected impact on

transition is a $34 million increase to cash and cash equivalents.

IFRS 18 ‘Presentation and Disclosure in Financial Statements’ will supersede IAS 1 ‘Presentation of Financial Statements’ and is effective for annual

periods beginning on or after 1 January 2027. IFRS 18 (and consequential amendments made to IAS 7 ‘Statement of Cash Flows’, IAS 8 ‘Accounting

Policies: Changes in Accounting Estimates and Errors’, IAS 33 ‘Earnings per share’ and IFRS 7 ‘Financial Instruments: Disclosures’) introduces several

new requirements that are expected to impact the presentation and disclosure of the Group’s consolidated financial statements. These new

requirements include:

•Requirements to classify all income and expenses included in the statement of profit or loss into one of five categories and to present two new

mandatory subtotals.

•Requirement to use the operating profit subtotal as the starting point for the indirect method of reporting cash flows from operating activities in

the statement of cash flows.

•Specific classification requirements for interest paid/received and dividends received in the statement of cash flows such that interest and

dividend receipts are included as investing cash flows and interest paid as financing cash flows.

•Required disclosures about certain non-GAAP measures (‘management defined performance measures’) in a single note to the financial

statements

•Enhanced guidance on the aggregation of information across all the primary financial statements and the notes.

The group’s evaluation of the effect of adopting IFRS 18 is ongoing but it is currently anticipated that IFRS 18 will have a significant impact on the

presentation of the Group’s financial statements and related disclosures.