3Q26 BP PLC Part 1 of 1

•       Earnings improve, supported by the macro environment. 3Q 2026 underlying RC profit $8.5 billion, $2.7 billion higher than the prior quarter. Operating cash flow $14.8 billion, including adjusted working capital* release_(c) of $0.5 billion

•       Improved operational performance. 3Q 2026 upstream plant reliability 95.3% (2Q 2026 92.4%); reported production 2.2mmboe/d (2Q 2026 2.2mmboe/d); refining availability 96.5% (2Q 2026 94.7%); refining throughput 1,396mb/d (2Q 2026 1,467mb/d) reflects the divestment of Gelsenkirchen refinery.

•       Strengthening the balance sheet. Strong cash generation combined with decision to allocate excess cash to strengthen the balance sheet enabled an $8.4 billion reduction in net debt to $13.9 billion.

•       Strategy and outlook update on 15 December. We will set out the next phase of our plans to build a simpler, stronger and more valuable bp.

 

BP p.l.c. Group results

(a) Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. See page 4 for more information.

(b) See Note 9 for more information.

(c) Change in working capital adjusted for inventory holding gains, fair value accounting effects relating to subsidiaries and other adjusting items. See page 27.

 

RC profit, underlying RC profit, net debt, underlying RC profit per ordinary share, underlying RC profit per ADS and adjusted working capital are non-IFRS measures. Inventory holding (gains) losses and adjusting items are non-IFRS adjustments.

 

•    Underlying RC profit* for the quarter was $8.5 billion, compared with $5.7 billion for the previous quarter. Compared with the second quarter 2026, the underlying result mainly reflects significantly higher realized refining margins and significantly higher gas and marketing trading result. The underlying effective tax rate (ETR)* in the quarter was 28%, compared with 34% for the previous quarter, which reflects changes in the geographical mix of profits.

•    Reported profit for the quarter was $4.7 billion, compared with $3.9 billion for the second quarter 2026. The reported result for the third quarter is adjusted for inventory holding gains* of $1.6 billion (net of tax) and a net adverse impact of adjusting items* of $5.4 billion (net of tax) to derive the underlying RC profit. Adjusting items include adverse pre-tax fair value accounting effects* of $0.5 billion and post-tax net impairments of $4.0 billion (see page 26 for more information on adjusting items).

•    Operating cash flow for the quarter, after a $0.5 billion working capital* release (after adjusting for inventory holding gains, fair value accounting effects and other adjusting items), was $14.8 billion, around $4.0 billion higher than the previous quarter, reflecting higher underlying earnings, partly offset by $0.9 billion higher income taxes paid.

•    Net debt* was $13.9 billion at the end of the third quarter compared with $22.3 billion at the end of the second quarter 2026. This reduction reflects stronger cash generation during the quarter, partly offset by $1.0 billion perpetual hybrid securities redemption.

•    Gas & low carbon energy: The RC profit before interest and tax for the third quarter 2026 was $0.2 billion, compared with $1.6 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $3.0 billion, the underlying RC profit before interest and tax* for the third quarter was $3.2 billion, compared with $2.1 billion in the second quarter 2026. This reflects higher realizations which include the impact of changes in non-Henry Hub natural gas marker prices. The gas marketing and trading result was significantly higher than the second quarter 2026.

•    Oil production & operations: The RC profit before interest and tax for the third quarter 2026 was $3.4 billion, compared with $3.4 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.1 billion, the underlying RC profit before interest and tax for the third quarter was $3.5 billion, compared with $3.6 billion for the second quarter 2026. This reflects lower liquids realizations partly offset by lower exploration write-offs.

•    Customers & products: The RC profit before interest and tax for the third quarter 2026 was $4.8 billion, compared with $5.1 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $2.2 billion, the underlying RC profit before interest and tax (underlying result) for the third quarter was $6.9 billion, compared with $5.0 billion in the second quarter 2026. The customers third quarter underlying result was lower by $0.5 billion, reflecting weaker fuels margins and a lower result in Castrol and midstream, partly offset by higher volumes due to seasonal effects and lower underlying operating expenditure*. The products third quarter underlying result was higher by $2.5 billion. In refining, the result reflects significantly higher realized refining margins, stronger commercial optimization, lower turnaround and maintenance activity, and the absence of the impact of the prior-quarter third party event at Whiting, partially offset by lower earnings following the Gelsenkirchen divestment. The oil trading result was slightly higher compared with the second quarter.

In addition to the highlights on page 3:

•       Profit attributable to bp shareholders in the third quarter and nine months was $4.7 billion and $12.4 billion respectively, compared with $1.2 billion and $3.5 billion in the same periods of 2025.

-     After adjusting profit attributable to bp shareholders for inventory holding gains* and net impact of adjusting items*, underlying replacement cost (RC) profit* for the third quarter and nine months was $8.5 billion and $17.4 billion respectively, compared with $2.2 billion and $5.9 billion for the same periods of 2025. The underlying RC profit for the third quarter and nine months compared with the same periods in 2025 mainly reflects significantly higher realized refining margins and higher realizations. The oil trading contribution and the gas marketing and trading result for the third quarter and nine months were significantly higher compared with the same periods in 2025. See pages 7, 9 and 11 for more information.

-     Adjusting items in the third quarter and nine months had a net adverse pre-tax impact of $5.9 billion and $8.4 billion respectively, compared with a net adverse pre-tax impact of $0.9 billion and $2.0 billion in the same periods of 2025.

-      Adjusting items for the third quarter and nine months include an adverse pre-tax impact of fair value accounting effects* of $0.5 billion and $0.7 billion respectively, compared with a favourable pre-tax impact of $0.2 billion and $1.7 billion in the same periods of 2025. In both the gas & low carbon energy and customers & products segments, fair value accounting effects represent the difference in treatment between management's internal performance measure and IFRS. In customers & products, the significant third quarter 2026 movement reflects changes in market prices affecting the valuation of positions subject to fair value accounting. In other businesses & corporate, the movements are driven by foreign exchange and interest rates with a significant favourable impact in the nine months 2025.

-      Adjusting items for third quarter and nine months also include an adverse pre-tax impairment impact of $4.1 billion and $5.3 billion respectively, compared with net impairment charges of $0.4 billion and $1.9 billion for the same periods in 2025. The 2026 charges are primarily attributable to transition businesses in the gas & low carbon energy segment.

•       The effective tax rate (ETR) on the profit before taxation for the third quarter and nine months was 40% and 43% respectively, compared with 53% and 52% for the same periods in 2025. Excluding inventory holding gains or losses and adjusting items, the underlying ETR* for the third quarter and nine months was 28% and 31% respectively, compared with 39% and 41% for the same periods in 2025. The lower underlying ETR for the third quarter and nine months reflects changes in the geographical mix of profits, particularly due to the higher results in products. Underlying ETR is a non-IFRS measure.

•       Operating cash flow for the third quarter and nine months was $14.8 billion and $28.5 billion respectively, compared with $7.8 billion and $16.9 billion for the same periods in 2025. The increases reflect the higher underlying earnings in the periods.

•       Capital expenditure in the third quarter and nine months was $3.0 billion and $9.4 billion respectively, compared with $3.4 billion and $10.4 billion in the same periods of 2025 reflecting our decisions around capital spend.

•       Total divestment and other proceeds for the third quarter and nine months were an outflow of $21 million and an inflow of $0.8 billion respectively, compared with inflows of $28 million and $1.7 billion for the same periods in 2025. There were no other proceeds in the third quarter 2026 and the third quarter 2025. Other proceeds for the nine months 2025 were $1.0 billion from the sale of a non-controlling interest in the subsidiary that holds our 12% share in the Trans-Anatolian natural gas pipeline (TANAP).

•       At the end of the third quarter, net debt* was $13.9 billion, compared with $22.3 billion at the end of the second quarter 2026 and $26.1 billion at the end of the third quarter 2025.

(a) A non-IFRS measure. Finance costs on an underlying RC basis is defined as finance costs as stated in the group income statement excluding finance costs classified as adjusting items* (see footnote (e) on page 26).

(a) Reported process safety events are investigated throughout the year and as a result there may be changes in previously reported events. See page 35 for more information.

(b) See Operational updates on pages 7, 9 and 11. Because of rounding, upstream production may not agree exactly with the sum of gas & low carbon energy and oil production & operations.

(c) The increase in the nine months 2026, compared with the nine months 2025 mainly reflects portfolio mix.

 

4Q 2026 guidance

•       Looking ahead, bp expects fourth quarter 2026 reported upstream production to be 2,090 to 2,230mboe/d. This includes the impact of continued disruption in the Middle East, activity phasing in bpx energy, seasonally lower gas demand and around 20mboe/d for a weather event in the Gulf of America, partly offset by the recovery from outages. The heightened volatility in the oil and gas prices could also impact PSA contracts.

•       In its customers business, compared to the third quarter, bp expects a significantly lower result with seasonally lower volumes, a lower midstream result and lower Castrol earnings, subject to the anticipated completion of the divestment. Fuels margins and midstream performance are expected to remain sensitive to market conditions.

•       In products, bp expects throughput of 1,160-1,210mb/d, reflecting the absence of Gelsenkirchen for the full quarter following its divestment on 31 July and higher maintenance activity. Refining margins are expected to remain elevated and sensitive to the cost of supply and market conditions.

•       bp expects income taxes paid in the fourth quarter to be around $0.8 billion higher than the third quarter 2026 mainly due to the impact of higher profits on instalment payments.

 

2026 guidance

•       bp now expects reported upstream production to be 2,210 to 2,250mboe/d, compared with the 2025, 2,312mboe/d. This includes the impact of disruption in the Middle East, the divestment of the Culzean gas field in the UK North Sea and bp's reduced equity interest in Latin America.

•       In its customers business, bp expects to make continued progress growing cash flows, supported by lower underlying operating expenditure* driven by structural cost reductions*. These benefits will be partly offset by the earnings impact of completed and announced divestments. Reported earnings will benefit from lower depreciation as a result of the assets held for sale accounting treatment of Castrol following the planned divestment. Fuel margins are expected to remain sensitive to conditions and developments in the Middle East and any resulting policy responses.

•       In products, bp expects throughput of 1,390 to 1,400mb/d, reflecting the completion of the Gelsenkirchen divestment and a significantly lower level of planned turnaround activity. Refining margins are expected to remain sensitive to the cost of supply and market conditions.

•       bp continues to expect other businesses & corporate underlying annual charge to be around $1.0 billion for 2026. The charge may vary quarter to quarter.

•       bp continues to expect the depreciation, depletion and amortization to be $17.0-17.5 billion.

•       bp now expects the underlying ETR* for 2026 to be between 31% and 34%, which reflects the underlying ETR for the nine months of 31%. It is sensitive to a range of factors, including the volatility of the price environment and its impact on the geographical mix of the group's profits and losses.

•       bp continues to expect capital expenditure to be $13.5-14.0 billion.

•       bp now expects divestment and other proceeds to be around $8 billion in 2026, including approximately $6 billion from the announced Castrol divestment.

•       bp continues to expect Gulf of America settlement payments for the year to be around $1.6 billion pre-tax including $0.4 billion pre-tax paid during the first quarter and $1.1 billion pre-tax paid during the second quarter. The timing of the payment of the recently announced $350 million settlement with the US state of Louisiana is still to be determined.

 

 

 

 

Financial results

•    The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $208 million and $2,826 million respectively, compared with $1,097 million and $3,502 million for the same periods in 2025. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $2,975 million and $3,815 million respectively, compared with an adverse impact of net adjusting items of $422 million and $476 million for the same periods in 2025.

-      Adjusting items include an impairment charge of $3,365 million and a net impairment charge of $3,890 million for the third quarter and nine months in 2026, primarily related to the group's transition businesses, compared with net charges of $135 million and $881 million for the same periods in 2025.

-      Adjusting items also include the impacts of fair value accounting effects*, relative to management's internal measure of performance, which are a favourable impact of $644 million and $576 million for the third quarter and nine months in 2026, and a favourable impact of $131 million and $817 million for the same periods in 2025. See page 26 for more information on adjusting items.

•    After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $3,183 million and $6,641 million respectively, compared with $1,519 million and $3,978 million for the same periods in 2025.

•    The underlying RC profit before interest and tax for the third quarter compared with the same period in 2025, primarily reflects higher realizations. The gas marketing and trading result was significantly higher.

•    The underlying RC profit before interest and tax for the nine months compared with the same period in 2025, reflects higher realizations, a lower depreciation, depletion and amortization charge and higher income from equity-accounted entities. The gas marketing and trading result was significantly higher.

Operational update

•    Reported production for the quarter was 784mboe/d, 2.6% lower than the same period in 2025. Underlying production was 1.8% lower primarily due to base decline in Egypt partly offset by ramp up of major projects.

•    Reported production for the nine months was 783mboe/d, 0.2% lower than the same period in 2025. Underlying production was 0.4% higher mainly due to ramp up of major projects partly offset by base decline.

Strategic progress

•    In August, bp agreed to acquire Woodside Energy's 70% interest in Block TTDAA 14, the Calypso gas project in Trinidad and Tobago, increasing bp's stake to 100% and assuming operatorship. The transaction is subject to regulatory approvals.

•    In August, bp and the government of the Bolivarian Republic of Venezuela signed agreements to advance offshore gas development, including the award of an exploration and production licence for Phase 2 of the Loran field in the Plataforma Deltana area. The licence has been granted with bp as operator and in partnership with XRG and UCC Oil and Gas Holding LLC, with each party holding an equal working interest share. Loran Phase 2 contains an estimated 4 trillion cubic feet of recoverable gas resources.

•    In August, bp agreed terms for the National Gas Company of Trinidad and Tobago Limited to acquire a 20% participating interest in Block 5(b), aligning interests across the Manakin-Cocuina cross-border gas development between Trinidad and Tobago and Venezuela, subject to regulatory approvals.

•    In September, bp entered into an agreement to sell a 5% interest in the Browse project in Western Australia to Osaka Gas Browse Pty Ltd, reducing bp's working interest to 34.33%. The transaction is subject to regulatory and partner approvals.

•    In September, bp completed the farm down in Indonesia, of a 50% participating interest in the bp operated Agung I and Agung II exploration blocks to INPEX, reducing bp's working interest to 50%.

		Third		Second		Third			Nine		Nine
		quarter		quarter		quarter			months		months
$ million		2026		2026		2025			2026		2025
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,228		1,139		1,223			3,553		3,796
Exploration write-offs
Exploration write-offs		18		48		29			66		30
Adjusted EBITDA*
Total adjusted EBITDA		4,429		3,309		2,771			10,260		7,804
Capital expenditure
gas		816		717		727			2,168		2,189
low carbon energy		100		59		101			219		332
Total capital expenditure		916		776		828			2,387		2,521

(a) Includes bp's share of production of equity-accounted entities in the gas & low carbon energy segment.

(b) Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

Financial results

•    The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $3,405 million and $8,457 million respectively, compared with $2,119 million and $6,823 million for the same periods in 2025. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $129 million and $639 million respectively, compared with an adverse impact of net adjusting items of $180 million and $633 million for the same periods in 2025. See page 26 for more information on adjusting items.

•    After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $3,534 million and $9,096 million respectively, compared with $2,299 million and $7,456 million for the same periods in 2025.

•    The underlying RC profit before interest and tax for the third quarter, compared with the same period in 2025, primarily reflects higher realizations partly offset by divestment of the Culzean gas field in the UK North Sea.

•    The underlying RC profit before interest and tax for the nine months, compared with the same period in 2025, reflects higher realizations, partly offset by higher exploration write-offs mainly due to the sale of Bay du Nord in Canada and the divestment of the Culzean gas field in the UK North Sea.

Operational update

•    Reported production for the quarter was 1,436mboe/d, 7.8% lower than the same period in 2025. Underlying production for the quarter was 1.1% lower mainly due to maintenance and base decline partly offset by higher production in bpx energy.

•    Reported production for the nine months was 1,470mboe/d, 3.1% lower than the same period in 2025. Underlying production for the nine months was 2.1% higher mainly due to higher production in bpx energy and ramp up of major projects partly offset by seasonal maintenance.

Strategic progress

•    In August, bp was the highest bidder on five blocks in the BBG-3 Gulf of America lease sale.

•    In August, Aker BP started production from the Skarv Satellite Project (bp interest in Aker BP 15.9%), which comprises the Alve Nord, Idun Nord and Ørn fields in the Norwegian Sea. The developments represent approximately 120 million barrels of oil equivalent of recoverable resources.

•    In September, bp agreed terms for Shell to acquire a 50% stake in the Tupinambá exploration block in the Santos Basin, offshore Brazil, in addition to a 30% stake in five leases containing the Conifer exploration prospect in the deepwater Gulf of America Paleogene. bp will retain the remaining 50% interest in Tupinambá and 70% in Conifer and continue as operator in both. The transaction remains subject to regulatory approvals.

•    In September, bp on behalf of the partnership, reached an agreement to transport and process third-party gas and condensate from the Absheron field in Azerbaijan. Gas will be transported through the South Caucasus Pipeline (SCP), while condensate will be processed at the bp-operated Shah Deniz 2 gas plant and transported through the Baku-Tbilisi-Ceyhan (BTC) pipeline.

 

		Third		Second		Third			Nine		Nine
		quarter		quarter		quarter			months		months
$ million		2026		2026		2025			2026		2025
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,861		1,754		1,961			5,624		5,681
Exploration write-offs
Exploration write-offs		(3	)	478		154			477		288
Adjusted EBITDA*
Total adjusted EBITDA		5,392		5,813		4,414			15,197		13,425
Capital expenditure
Total capital expenditure		1,612		1,733		1,722			5,236		5,124

(a) Includes bp's share of production of equity-accounted entities in the oil production & operations segment.

(b) Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

Financial results

•    The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $4,796 million and $12,348 million respectively, compared with $1,610 million and $2,685 million for the same periods in 2025. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $2,152 million and $2,757 million respectively, compared with an adverse impact of net adjusting items of $106 million and $1,241 million for the same periods in 2025. See page 26 for more information on adjusting items.

•    After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* (underlying result) for the third quarter and nine months was $6,948 million and $15,105 million respectively, compared with $1,716 million and $3,926 million for the same periods in 2025.

•    The customers & products underlying result for the third quarter and nine months was significantly higher compared with the same periods in 2025, reflecting a stronger performance across both sub-segments.

•    customers - the customers underlying result for the third quarter was slightly higher compared with the same period in 2025, reflecting a stronger midstream performance and lower underlying operating expenditure*, largely offset by lower fuels margins and a lower contribution from bioenergy. The customers underlying result for the nine months was significantly higher compared with the same period in 2025, driven by a stronger midstream performance, higher earnings in Castrol and a lower underlying operating expenditure and depreciation, partly offset by lower fuels volumes and margins, and a lower contribution from bioenergy.

•    products - the products underlying result for the third quarter and nine months was significantly higher compared with the same periods in 2025. In refining, the third quarter result benefited from significantly higher realized refining margins, stronger commercial optimization, and lower turnaround activity. In refining, the result for the nine months benefited from significantly higher realized refining margins, stronger commercial optimization and crude selection timing effect, and significantly lower turnaround activity, partly offset by production impacts from operational and maintenance events. The oil trading contribution for the third quarter and nine months was significantly higher compared with the same periods in 2025.

Operational update

•    bp-operated refining availability for the third quarter and nine months was 96.5% and 95.8% respectively, lower compared with 96.6% and 96.4% for the same periods in 2025.

Strategic progress

•    In New Zealand, bp committed to securing additional diesel and jet fuel storage capacity at Channel Infrastructure, strengthening fuel supply resilience and supporting future customer demand.

•    The Castrol divestment is expected imminently and remains on track to complete within agreed timelines.

(a) A reconciliation to RC profit before interest and tax by business is provided on page 29.

(a) A reconciliation to RC profit before interest and tax by business is provided on page 29.

bp average refining indicator margin (RIM) ($/bbl)

46.7

29.6

15.8

31.2

12.0

 

Financial results

•    The replacement cost (RC) loss before interest and tax for the third quarter and nine months was $765 million and $1,870 million respectively, compared with a loss of $277 million and a profit of $346 million for the same periods in 2025. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $543 million and $1,031 million respectively, compared with an adverse impact of net adjusting items of $88 million and a favourable impact of $690 million for the same periods in 2025. Adjusting items include an adverse impact of fair value accounting effects* of $92 million and $196 million for the third quarter and nine months, and an adverse impact of $13 million and a favourable impact of $1,096 million for the same periods in 2025. See page 26 for more information on adjusting items.

•    After adjusting RC loss before interest and tax for adjusting items, the underlying RC loss before interest and tax* for the third quarter and nine months was $222 million and $839 million respectively, compared with a loss of $189 million and $344 million for the same periods in 2025.

 

 

(a) Includes fair value accounting effects relating to hybrid bonds. See page 32 for more information.

(a) Nine months 2025 is principally affected by movements in the Pound Sterling against the US dollar.

(b) Third quarter 2026 relates to the divestment of the Gelsenkirchen refinery.

(a) See Condensed group statement of changes in equity - footnote (a) for further information.

(b) Nine months 2026 includes the impact of initial adoption of amendments to IFRS 9 'Financial Instruments'. See note 1.

(c) Third quarter and nine months 2026 include $50 million (second quarter 2026 $17 million, third quarter and nine months 2025 $46 million) of cash and cash equivalents classified as assets held for sale in the group balance sheet.

 

 

(a) Principally relates to commodity derivative transactions including sales of bp own production in trading books.

(a) See Condensed group statement of changes in equity - footnote (a) for further information.

(b) Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.

(c) One ADS is equivalent to six ordinary shares.

 

Dividends payable

 

(a) The fair value of finance debt at 30 September 2026 was $50,344 million (30 June 2026 $54,869 million, 30 September 2025 $57,113 million).

(b) Derivative financial instruments entered into for the purpose of managing foreign currency exchange risk associated with net debt with a fair value liability position of $103 million at 30 September 2026 (second quarter 2026 liability of $105 million and third quarter 2025 liability of $94 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

(c) Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement.

 

(a) See Note 3 for further information.

(b) Under IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value accounting effect includes the change in value of LNG contracts that are being risk managed, and the underlying result reflects how bp risk-manages its LNG contracts.

(c) For further information, including the nature of fair value accounting effects reported in each segment, see pages 4, 7 and 32.

(d) Third quarter and nine months 2026 include a $313 million loss on settlement of a defined benefit pension plan in the Netherlands.

(e) Includes the unwinding of discounting effects relating to Gulf of America oil spill payables, the income statement impact of temporary valuation differences related to the group's interest rate and foreign currency exchange risk management associated with finance debt, and the unwinding of discounting effects relating to certain onerous contract provisions. Third quarter and nine months 2026 also include the income statement impact of the buyback of finance debt (see Note 9 for further information).

(f) Includes certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.

(g) Second quarter 2026 and nine months 2026 include the impact of the reassessment of the recognition of deferred tax assets.

(h) Second quarter 2026 and nine months 2025 include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at the opening balance sheet date. The EPL increases the headline rate of tax on taxable profits from bp's North Sea business to 78%. In the first quarter 2025 a two-year extension of the EPL to 31 March 2030 was substantively enacted. Third quarter 2025 and nine months 2025 include the deferred tax impact of a change in the tax rate in Germany.

(a) The movement in working capital includes outflows relating to the Gulf of America oil spill on a pre-tax basis of $7 million in the third quarter 2026 (second quarter 2026 $1,129 million, third quarter 2025 $5 million).

(b) Other adjusting items relate to the non-cash movement of US emissions obligations carried as a provision that will be settled by allowances held as inventory.

(a) Third quarter and nine months 2026 include a $313 million loss on settlement of a defined benefit pension plan in the Netherlands.

(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.

(b) Liquids comprises crude oil, condensate and natural gas liquids.

(c) Henry Hub First of Month Index.

Louisiana Costal restoration

 

•    Under management's internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period.

•    Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp's risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments used to risk manage the near-term portions of the LNG contracts are fair valued under IFRS. The fair value accounting effect, which is reported in the gas and low carbon energy segment, represents the change in value of LNG contracts that are being risk managed and which is reflected in the underlying result, but not in reported earnings. Management believes that this gives a better representation of performance in each period.

•    the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting of inventories other than for trading inventories, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed as inventory holding gains and losses represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation's production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach; and

•    an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade by grade basis, during the period. This is calculated from each operation's inventory management system on a monthly basis using the discrete monthly movement in market prices for these inventories.

Trade marks