2Q26 BP PLC SEA

BP PLC

04 August 2026

Stronger earnings; setting priorities to accelerate delivery

Financial summary		Second		First		Second			First			First
		quarter		quarter		quarter			half			half
$ million		2026		2026		2025			2026			2025
Profit for the period attributable to bp shareholders		3,911		3,842		1,629			7,753			2,316
Inventory holding (gains) losses*, net of tax		717		(3,180	)	407			(2,463	)		289
Replacement cost (RC) profit*		4,628		662		2,036			5,290			2,605
Net adverse impact of adjusting items*, net of tax		1,104		2,536		317			3,640			1,129
Underlying RC profit*		5,732		3,198		2,353			8,930			3,734
Operating cash flow		10,858		2,860		6,271			13,718			9,105
Capital expenditure		(3,086	)	(3,290	)	(3,361	)		(6,376	)		(6,984	)
Divestment and other proceeds(a)		609		248		1,356			857			1,684
Net debt*(b)		22,251		25,309		26,043			22,251			26,043
Underlying operating expenditure*		5,333		5,369		5,457			10,702			10,761
Announced dividend per ordinary share (cents per share)		8.660		8.320		8.320			16.980			16.320
Underlying RC profit per ordinary share* (cents)		36.92		20.67		15.03			57.62			23.76
Underlying RC profit per ADS* (dollars)		2.22		1.24		0.90			3.46			1.43

•       Stronger financial performance: 2Q 2026 underlying RC profit $5.7 billion, $2.5 billion higher than the prior quarter reflecting the strength of bp's integrated operational model; operating cash flow $10.9 billion after taking into account a $1.0 billion adjusted working capital* build_(C).

•       Operating performance: 2Q 2026 upstream plant reliability 92.4% (1Q 2026 95.7%); reported production 2.2mmboe/d (1Q 2026 2.3mmboe/d); refining availability 94.7% (1Q 2026 96.3%); refining throughput 1,467mb/d (1Q 2026 1,527mb/d)

•       Strategic progress on portfolio and balance sheet: Reached an agreement to sell Austrian retail business; agreed terms to bring partners into Kirkuk; completed the sale of Gelsenkirchen refinery, launched processes to market our North Sea business and Archaea Energy; the total of net debt, hybrid bonds and securities, leases and Gulf of America settlement liabilities reduced by $6.9 billion.

•       Shareholder returns: 2Q 2026 dividend per ordinary share of 8.66 cents, 4% increase.

BP p.l.c. Group results

Second quarter and first half 2026

1.  Strengthening the balance sheet. This quarter we reduced the total of net debt, hybrids, leases and Gulf of America settlement liabilities by more than 11% compared to last quarter. That is still not enough - we need to do more. Financial resilience gives us greater flexibility to invest to grow through the cycle and reward our shareholders.

2.  Simplifying the portfolio based on value, not sentiment nor history. We have to focus on the assets with the strongest potential to deliver competitive returns and long-term value - just as we have done with our decisions on the North Sea and Archaea.

3.  Investing with greater discipline to ensure every dollar of capital competes. Our decision to sell Bay du Nord and free up the capital shows that discipline in action. We must keep challenging ourselves, using our balanced investment criteria to make decisions rooted in profitability, cash generation and market realities. I am very clear on this, we need to compete in the weight class we are in.

4.  Driving operational excellence. We need to run our assets safely, reliably and with greater cost efficiency. We have made progress on reducing structural costs, but we have not improved enough where it matters most: the bottom line. We need to move faster, and we have both the opportunity and the technology to do this. Operational excellence is also about working safely with people, communities and the environment; it helps us work to deliver energy that is secure, affordable and lower-carbon, where it makes business sense - and it is how we will make bp more competitive.

5.  Hardwiring high-performance and accountability into bp. We must make better, faster decisions, reduce complexity and sharpen accountability. Last month, we moved to an Upstream and Downstream organization, supported by our world-class trading business. This integrated model is a competitive advantage and an important first step._(d)

(a) Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.

(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 29.

(d) Reportable segments for external financial reporting will remain unchanged until 31 December 2026 as the financial reporting aspects of the new segment model will take time to implement.

RC profit (loss), 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 $5.7 billion, compared with $3.2 billion for the previous quarter. Compared with the first quarter 2026, the underlying result mainly reflects higher liquids and gas realizations including the impact of price lags, stronger realized refining margins and stronger customers result, partly offset by higher exploration write-offs. The underlying effective tax rate (ETR)* in the quarter was 34%, compared with 32% for the previous quarter, which reflects changes in the geographical mix of profits.

•    Reported profit for the quarter was $3.9 billion, compared with $3.8 billion for the first quarter 2026. The reported result for the second quarter is adjusted for inventory holding losses* of $0.7 billion (net of tax) and a net adverse impact of adjusting items* of $1.1 billion (net of tax) to derive the underlying RC profit. Adjusting items include favourable pre-tax fair value accounting effects* of $1.0 billion and post-tax net impairments of $0.8 billion (see page 28 for more information on adjusting items).

•    Operating cash flow for the quarter, after a $1.0 billion working capital* build (after adjusting for inventory holding losses, fair value accounting effects and other adjusting items), was $10.9 billion, around $8.0 billion higher than the previous quarter, reflecting higher earnings and a lower working capital build.

•    Net debt* was $22.3 billion at the end of the second quarter compared with $25.3 billion at the end of the first quarter 2026. This reduction reflects strong cash generation during the quarter, after the $2.9 billion (€2.5 billion) perpetual hybrid bond redemption and the payment for $1.1 billion Gulf of America settlement liabilities.

•    Gas & low carbon energy: The RC profit before interest and tax for the second quarter 2026 was $1.6 billion, compared with $1.1 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.6 billion, the underlying RC profit before interest and tax* for the second quarter was $2.1 billion, compared with $1.3 billion in the first quarter 2026. This primarily reflects higher realizations including the impact of price lags and the changes in non-Henry Hub natural gas marker prices. The gas marketing and trading result was broadly flat compared with the first quarter 2026.

•    Oil production & operations: The RC profit before interest and tax for the second quarter 2026 was $3.4 billion, compared with $1.7 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.2 billion, the underlying RC profit before interest and tax for the second quarter was $3.6 billion, compared with $2.0 billion for the first quarter 2026. This reflects higher liquid realizations including the impact of price lags, production mix benefit, and higher income from equity-accounted entities partially offset by higher exploration write-offs mainly due to sale of Bay du Nord in Canada and lower production due to seasonal maintenance in the Gulf of America.

•    Customers & products: The RC profit before interest and tax for the second quarter 2026 was $5.1 billion, compared with $2.5 billion for the previous quarter. After adjusting RC profit before interest and tax for a net favourable impact of adjusting items of $0.1 billion, the underlying RC profit before interest and tax (underlying result) for the second quarter was $5.0 billion, compared with $3.2 billion in the first quarter 2026. The customers second quarter underlying result was higher by $0.8 billion, reflecting seasonally higher volumes, higher fuels margins, a stronger Castrol performance and a slightly higher midstream contribution, partly offset by lower contribution from bioenergy. The products second quarter underlying result was higher by $1.0 billion. In refining, the result reflects significantly stronger realized refining margins, partly offset by higher planned turnaround and maintenance activity, as well as the impacts of the third-party event at Whiting in April. The oil trading result was slightly higher compared with the first quarter.

In addition to the highlights on page 3:

•       Profit attributable to bp shareholders in the second quarter and half year was $3.9 billion and $7.8 billion respectively, compared with $1.6 billion and $2.3 billion in the same periods of 2025.

-     After adjusting profit attributable to bp shareholders for inventory holding losses or gains* and net impact of adjusting items*, underlying replacement cost (RC) profit* for the second quarter and half year was $5.7 billion and $8.9 billion respectively, compared with $2.4 billion and $3.7 billion for the same periods of 2025. The underlying RC profit for the second quarter and half year compared with the same periods in 2025 mainly reflects a significant higher realized refining margins and higher liquid realizations. The oil trading contribution for the second quarter and first half was significantly higher compared with the same periods in 2025. See pages 7, 9 and 11 for more information.

-     Adjusting items in the second quarter and half year had a net adverse pre-tax impact of $0.6 billion and $2.6 billion respectively, compared with a net adverse pre-tax impact of $0.7 billion and $1.1 billion in the same periods of 2025.

-      Adjusting items for the second quarter and half year include a favourable pre-tax impact of fair value accounting effects* of $1.0 billion and an adverse pre-tax impact of $0.1 billion respectively, compared with a favourable pre-tax impact of $0.6 billion and $1.5 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 other businesses & corporate, there was a favourable impact of the fair value accounting effects relating to the hybrid bonds in the second quarter and an adverse impact in the half year, compared with a favourable impact in the same periods of 2025. These movements are driven by foreign exchange and interest rates.

•       The effective tax rate (ETR) on the profit before taxation for the second quarter and half year was 45% and 44% respectively, compared with 33% and 52% for the same periods in 2025. Excluding inventory holding gains or losses and adjusting items, the underlying ETR* for the second quarter and half year was 34% and 33% respectively, compared with 36% and 43% for the same periods in 2025. The lower underlying ETR for the second quarter and half year reflects changes in the geographical mix of profits. Underlying ETR is a non-IFRS measure.

•       Operating cash flow for the second quarter and half year was $10.9 billion and $13.7 billion respectively, compared with $6.3 billion and $9.1 billion for the same periods in 2025. The cash flow increases are driven by the higher underlying RC profit in the 2026 periods and the impact of the working capital* (after adjusting for inventory holding gains or losses, fair value accounting effects and other adjusting items) movements in the periods.

•       Capital expenditure in the second quarter and half year was $3.1 billion and $6.4 billion respectively, compared with $3.4 billion and $7.0 billion in the same periods of 2025.

•       Total divestment and other proceeds for the second quarter and half year were $0.6 billion and $0.9 billion respectively, compared with $1.4 billion and $1.7 billion for the same periods in 2025. Other proceeds for the second quarter and half year 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 second quarter, net debt* was $22.3 billion, compared with $25.3 billion at the end of the first quarter 2026 and $26.0 billion at the end of the second 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 (c) on page 28).

(a) 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.

(b) The decrease in the first half 2026, compared with the first half 2025 mainly reflects portfolio mix.

3Q 2026 guidance

•       Looking ahead, bp expects third quarter 2026 reported upstream production to be 2,100 to 2,250mboe/d, compared with the second quarter 2026, 2,201mboe/d. This includes the impact of continued disruption in the Middle East, bp's reduced equity interest in Latin America and an estimated impact of around 40mboe/d for potential seasonal weather events in the Gulf of America. The heightened volatility in the oil and gas prices could also impact PSA contracts.

•       In its customers business, compared to the second quarter, bp expects a significantly lower result, with broadly flat volumes and a lower midstream result, as well as lower earnings in Castrol due to the lagged impact of higher base oil costs. Both fuels margins and midstream performance are expected to remain sensitive to conditions and developments in the Middle East.

•       In products, bp expects throughput of 1,300 to 1,360mb/d, reflecting the completion of the Gelsenkirchen divestment and a lower level of planned turnaround 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 third quarter to be around $1 billion higher than the second quarter 2026 mainly due to timing effects, including the timing of instalment payments, which are typically higher in the third quarter each year.

•       bp intends to repay $1.0 billion of perpetual subordinated hybrid securities issued by a group subsidiary.

2026 guidance

•       bp now expects reported upstream production to be 2,180 to 2,270mboe/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 addition to an estimated impact of around 15mboe/d for potential seasonal weather events in the Gulf of America. Underlying upstream production is expected to be broadly flat compared with 2025 with production from oil production & operations to be broadly flat and production from gas & low carbon energy to be lower.

•       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 1,360 to 1,410mb/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 now expects the depreciation, depletion and amortization to be $17.0-17.5 billion.

•       bp now expects the underlying ETR* for 2026 to be 35-40%, which reflects the underlying ETR for the first half of 33%. 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 now expects capital expenditure to be $13.5-14.0 billion reflecting decision to delay asset farm downs and capture better value.

•       bp now expects divestment and other proceeds to be $8-9 billion in 2026, including approximately $6 billion from the announced Castrol transaction.

•       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.

Financial results

•    The replacement cost (RC) profit before interest and tax for the second quarter and half year was $1,564 million and $2,618 million respectively, compared with $1,047 million and $2,405 million for the same periods in 2025. The second quarter and half year are adjusted by an adverse impact of net adjusting items* of $558 million and $840 million respectively, compared with an adverse impact of net adjusting items of $415 million and $54 million for the same periods in 2025. Adjusting items include the impacts of fair value accounting effects*, relative to management's internal measure of performance, which are a favourable impact of $205 million and an adverse impact of $68 million for the second quarter and half year in 2026, and a favourable impact of $18 million and $686 million for the same periods in 2025. See page 28 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 second quarter and half year was $2,122 million and $3,458 million respectively, compared with $1,462 million and $2,459 million for the same periods in 2025.

•    The underlying RC profit before interest and tax for the second quarter compared with the same period in 2025, reflects higher realizations and a lower depreciation charge partly offset by a slightly lower gas marketing and trading result. For the half year compared with the same period in 2025, it reflects higher realizations, a lower depreciation charge and a slightly higher gas marketing and trading result.

Operational update

•    Reported production for the quarter was 765mboe/d, 2.1% lower than the same period in 2025. Underlying production was 2.2% lower mainly due to base decline partly offset by ramp up of major projects.

•    Reported production for the half year was 782mboe/d, 1.1% higher than the same period in 2025. Underlying production was 1.6% higher mainly due to ramp up of major projects partly offset by base decline.

Strategic progress

•    bp continues to progress development of the Cocuina-Manakin gas field, on the maritime border between Venezuela and Trinidad and Tobago. In April 2026, bp also signed a memorandum of understanding with the Venezuelan Government regarding joint opportunities in the offshore Loran gas field and certain exploration areas

•    In May bp signed three production-sharing contracts in Indonesia, bringing bp's total participation in oil and gas blocks in the country to 11. This includes the Bintuni and Drawa exploration blocks and also participation in the INPEX-operated Barong block in East Java.

•    In May bp confirmed a gas discovery in the East Nile Delta region in Egypt. The discovery follows the drilling of the Nidoco N-2 exploration well, operated by Eni in partnership with bp and the Egyptian General Petroleum Corporation (EGPC).

•    In May bp signed a 10-year deal with Oil and Natural Gas Corporation (ONGC) where bp has been selected as the technical services provider for the western offshore fields in the Mumbai Offshore Basin in India.

•    In May bp signed a new long-term deal to supply the Korea Gas Corporation (KOGAS) with 0.7 million tonnes per annum of LNG for 10 years from 2028.

•    In June bp entered into an agreement to sell a 5% interest in the Browse project in Western Australia to GS Energy, with bp retaining 39.33% working interest.

•    In June bp, together with ADNOC and partners, has signed a concession agreement to develop the Bab Gas Cap project in Abu Dhabi. With this agreement, bp holds a 10% interest in the Bab Gas Cap concession, which is expected to produce up to 1.5 billion cubic feet per day of gas.

•    bp today is announcing that it is launching a process to market Archaea Energy for a potential sale.

•    These events build on the progress announced in our first-quarter results, which comprised the following:

		Second		First		Second			First		First
		quarter		quarter		quarter			half		half
$ million		2026		2026		2025			2026		2025
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,139		1,186		1,407			2,325		2,573
Exploration write-offs
Exploration write-offs		48		-		1			48		1
Adjusted EBITDA*
Total adjusted EBITDA		3,309		2,522		2,870			5,831		5,033
Capital expenditure
gas		717		635		688			1,352		1,462
low carbon energy		59		60		102			119		231
Total capital expenditure		776		695		790			1,471		1,693

(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 second quarter and half year was $3,397 million and $5,052 million respectively, compared with $1,916 million and $4,704 million for the same periods in 2025. The second quarter and half year are adjusted by an adverse impact of net adjusting items* of $184 million and $510 million respectively, compared with an adverse impact of net adjusting items of $346 million and $453 million for the same periods in 2025. See page 28 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 second quarter and half year was $3,581 million and $5,562 million respectively, compared with $2,262 million and $5,157 million for the same periods in 2025.

•    The underlying RC profit before interest and tax for the second quarter, compared with the same period in 2025, reflects higher liquid realizations and higher income from equity-accounted entities partly offset by higher exploration write-offs mainly due to sale of Bay du Nord in Canada, the divestment of the Culzean gas field in the UK North Sea, and lower production.

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

Operational update

•    Reported production for the quarter was 1,436mboe/d, 5.4% lower than the same period in 2025. Underlying production for the quarter was 1.8% higher mainly due to increased production in bpx Energy and ramp up of major projects partly offset by seasonal maintenance.

•    Reported production for the half year was 1,488mboe/d, 0.6% lower than the same period in 2025. Underlying production for the half year was 3.8% higher mainly due to increased production in bpx Energy and ramp up of major projects partly offset by seasonal maintenance.

Strategic progress

•    In May, bp as operator, confirmed a final investment decision (FID) on the Thunder Horse subsea pump. With plans to deliver first oil in 2028, the project is expected to add gross production of around 15,000 barrels of oil equivalent per day at peak.

•    In June bp confirmed the preliminary results of the Capricornus-1A appraisal well in Namibia's Orange Basin. This established an oil pay extension from the Capricornus discovery well. Petroleum Exploration License 85 (PEL85), where the well was drilled, is operated by Rhino Resources where Azule Energy has a 42.5% working interest. bp holds a 50% interest in Azule Energy.

•    In June bp, as operator, announced the commencement of non‑associated gas (NAG) production operations on the Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea. This marks the first commercial gas production operations on ACG, one of the world's largest oil-producing fields.

•    In June bp announced the FID for the Greater PAJ Project, a major offshore oil development located in Blocks 31 and 31/21 in Angola, adding expected gross production of around 95,000 barrels of oil equivalent per day at peak. This is operated by Azule Energy, a 50:50 joint venture between bp and Eni. Azule Energy has a 26.67% working interest in Block 31 and a 50% working interest in Block 31/21.

•    In June, following regulatory approval, bp completed the sale of a 10% shareholding in Pan American Energy Group S.L., reducing its shareholding from 50% to 40%.

•    It was announced that, effective 1 July 2026, operatorship of the Baku-Tbilisi-Ceyhan (BTC) oil export pipeline was transferred from bp to SOCAR Midstream Operations LLC (SMO), a wholly owned subsidiary of SOCAR.

•    In July bp agreed to sell its non-operated interest in the Bay du Nord project offshore Newfoundland and Labrador, Canada, to Equinor. Completion of the transaction is subject to third party approvals.

•    In July bp has agreed terms for ConocoPhillips to acquire a 42% interest in BP Energy Company of Kirkuk Limited (BP ECKL), supporting the redevelopment of several large-scale oil fields in the Kirkuk area of northern Iraq. bp has also agreed terms for Turkiye Petrolleri Anonim Ortakligi (TPAO) to acquire a further 15% interest in BP ECKL. Completion of the respective transactions are subject to third party approvals.

•    In July bp successfully started up the Atlantis Major Facility Expansion project in the Gulf of America, the eighth of its 10 major projects due online between 2025 and 2027, adding two new subsea water injection wells.

•    In July bp announced its intention to market its North Sea business for a potential sale.

•    These events build on the progress announced in our first-quarter results, which comprised the following:

		Second		First		Second			First		First
		quarter		quarter		quarter			half		half
$ million		2026		2026		2025			2026		2025
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,754		2,009		1,933			3,763		3,720
Exploration write-offs
Exploration write-offs		478		2		81			480		134
Adjusted EBITDA*
Total adjusted EBITDA		5,813		3,992		4,276			9,805		9,011
Capital expenditure
Total capital expenditure		1,733		1,891		1,706			3,624		3,402

(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 second quarter and half year was $5,100 million and $7,552 million respectively, compared with $972 million and $1,075 million for the same periods in 2025. The second quarter and half year are adjusted by a favourable impact of net adjusting items* of $146 million and an adverse impact of $605 million respectively, compared with an adverse impact of net adjusting items of $561 million and $1,135 million for the same periods in 2025. See page 28 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 second quarter and half year was $4,954 million and $8,157 million respectively, compared with $1,533 million and $2,210 million for the same periods in 2025.

•    The customers & products underlying result for the second quarter and for the half year 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 second quarter and half year was significantly higher compared with the same periods in 2025, reflecting stronger integrated performance across fuels and midstream and a stronger Castrol result, partly offset by a lower contribution from bioenergy and lower fuels volumes.

•    products - the products underlying result for the second quarter and half year was significantly higher compared with the same periods in 2025. In refining, the second quarter and first half result benefited from significantly higher realized refining margins and significantly lower turnaround activity, as well as crude selection timing effects. These benefits were partly offset by the impacts of the third party event at Whiting in April and other maintenance activities. The oil trading contribution for the second quarter and first half was significantly higher compared with the same periods in 2025.

Operational update

•    bp-operated refining availability for the second quarter and half year was 94.7% and 95.5% respectively, lower compared with 96.4% and 96.3% for the same periods in 2025.

Strategic progress

•    In July bp completed the sale of the Gelsenkirchen refinery and related businesses to Klesch Group, following the announcement in March that an agreement had been reached for the sale.

•    In July bp announced the sale of its Austria mobility & convenience and bp pulse businesses to volenergy AG. The sale is expected to complete by the end of 2026 subject to regulatory approvals.

•    bp signed a 25-year agreement to continue operating at Durban's Island View Terminal, securing long-term access to strategic infrastructure that strengthens our supply position in South Africa.

•    Working with government partners, bp secured a fast-tracked lease extension at the Bulwer Island facility at the Port of Brisbane enabling investment in additional fuel storage capacity to support Australia's fuel security.

•    These events build on the progress announced in our first-quarter results, which comprised the following:

◦       Air bp signed a multi‑year supply agreement with Airbus to provide jet fuel and sustainable aviation fuel (SAF), as well as aviation services in Germany and Spain.

◦       In January bp and Castrol commenced their Formula 1 partnership with Audi during the start of the season. This reflects the outcome of several years of bp and Castrol fuels and lubricants research and development to support compliance with the new 2026 Formula 1 regulations. The partnership showcases our strengths in technology and innovation and helps build brand equity.

(a) A reconciliation to RC profit before interest and tax by business is provided on page 31.

(a) A reconciliation to RC profit before interest and tax by business is provided on page 31.

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

29.6

16.9

11.9

23.3

10.0

Financial results

•    The replacement cost (RC) loss before interest and tax for the second quarter and half year was $250 million and $1,105 million respectively, compared with a profit of $645 million and $623 million for the same periods in 2025. The second quarter and half year are adjusted by a favourable impact of net adjusting items* of $95 million and an adverse impact of $488 million respectively, compared with a favourable impact of net adjusting items of $683 million and $778 million for the same periods in 2025. Adjusting items include a favourable impact of fair value accounting effects* of $114 million and an adverse impact of $104 million for the second quarter and half year, and a favourable impact of $740 million and $1,109 million for the same periods in 2025. See page 28 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 second quarter and half year was $345 million and $617 million respectively, compared with a loss of $38 million and $155 million for the same periods in 2025.

Strategic progress

•    In July bp reached an agreement to sell the majority of the direct investments held in bp Ventures, subject to regulatory and contractual approvals. Alongside this transaction bp intends to further simplify its portfolio by closing bp Ventures.

(a) Includes fair value accounting effects relating to hybrid bonds. See page 35 for more information.

Conclusion

Basis for Conclusion

Conclusion Relating to Going Concern

Responsibilities of the directors

Auditor's Responsibilities for the review of the financial information

Use of our report

(a) Second quarter and first half 2025 are principally affected by movements in the Pound Sterling against the US dollar.

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

(b) First quarter and first half 2026 include the impact of initial adoption of amendments to IFRS 9 'Financial Instruments'. See note 1.

(c) Second quarter and first half 2026 include $17 million (first quarter 2026 $24 million, second quarter and first half 2025 $63 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 June 2026 was $54,869 million (31 March 2026 $56,331 million, 30 June 2025 $57,135 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 $105 million at 30 June 2026 (first quarter 2026 liability of $101 million and second quarter 2025 liability of $96 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) 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.

(b) For further information, including the nature of fair value accounting effects reported in each segment, see pages 4, 7 and 35.

(c) 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.

(d) 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.

(e) Second quarter 2026 and first quarter 2026 include the impact of the reassessment of the recognition of deferred tax assets.

(f) Second quarter 2026 and first half 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.

(a) The movement in working capital includes outflows relating to the Gulf of America oil spill on a pre-tax basis of $1,129 million in the second quarter 2026 (first quarter 2026 $396 million, second quarter 2025 $1,129 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) 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.

•    Commodity prices and market environment - our financial performance is impacted by fluctuations in the prices of oil, natural gas, refined products, and emerging energy commodities due to factors such as volatile energy markets, exchange rates, or structural shifts in demand and supply, policy, or trade (such as carbon pricing or LNG flows).

•    Accessing and producing hydrocarbon resources - failure to adequately access, develop or sustain production of hydrocarbon resources may result in delivery delays, missed strategic targets and adversely impact our financial performance and undermine our reputation.

•    Major project delivery - failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance and long-term competitiveness.

•    Geopolitical exposure - the diverse locations of our business activities and operations around the world expose us to a wide range of geopolitical developments (including sanctions, trade route restrictions, civil unrest, conflict, or government intervention).

•    Liquidity, capital access and financial resilience - external market conditions can impact our ability to maintain liquidity, credit strength, or access to capital markets which could impair our ability to operate, meet financial commitments, or deliver our strategy.

•    Partner and third-party risk - the performance, standards, or compliance of non-operated joint ventures, strategic partners, contractors, sub-contractors, or other third parties could expose bp to legal, operational, financial, or reputational harm.

•    Digital, cyber security and data risk - increasing reliance on digital infrastructure, growing AI adoption, and evolving cyber threats exposes bp and our third-party suppliers and contractors to data loss, infrastructure failures, or system compromise which could result in operational disruption, regulatory breaches, significant fines and reputational harm.

•    Climate change and the transition to a lower carbon economy - developments in policy, law, regulation, technology and markets, including societal and investor sentiment, related to the issue of climate change and the transition to a lower carbon economy could increase costs, reduce revenues, constrain our operations and affect our business plans and financial performance.

•    Competitiveness - failure to maintain a competitive strategy, underpinned by a strong portfolio of assets, cost performance, innovative technology, projects and long-term growth opportunities, could negatively impact our investors' confidence in our ability to grow long-term shareholder value and returns.

•    Talent, leadership and organizational capability - failure to retain, develop, and attract the talent, leadership, capabilities and behaviours required to deliver our strategy could weaken performance, culture, and long-term value creation.

•    Process safety, personal safety, and environmental risks - bp's operations and business activities are exposed to a wide range of safety, operational integrity, and environmental risks - particularly under growing complexity and delivery intensity - which could result in major incidents that harm people or the environment, disrupted operations, damage to bp's reputation, legal liability, undermine our financial standing or threaten our licence to operate.

•    Security - hostile acts such as terrorism, civil unrest, armed conflict, sabotage, activism, piracy, insider threats, workplace violence, cyber-enabled physical attacks, or threats to personnel security such as kidnapping or detention could harm our people, disrupt operations, compromise critical assets, or damage our reputation.

•    Product quality - failure to supply products to customers, meet technical specifications or regulatory standards could lead to harm, operational disruption, reputational damage, or legal and financial consequences.

•    Legal, regulatory and ethical compliance - ethical misconduct, non-compliance with law and regulation or changes in law and regulation could increase costs, constrain our operations and affect our strategy, business plans and financial performance. Incidents of ethical misconduct or non-compliance could also damage our reputation and result in litigation, regulatory action, penalties and potentially affect our licence to operate.

•    Financial and physical commodity trading activities - we undertake physical and financial trading across global commodity and financial markets. Risk associated with our trading activities could arise from a failure to maintain robust oversight, controls, and disciplined execution in our trading activities which could result in business disruption, financial loss, regulatory action, or reputational damage.

•    Integrity of financial and non-financial reporting - failure to maintain integrity in financial and non-financial reporting may result in material misstatement or regulatory breach, which could lead to regulatory action, legal liability and reputational damage.

•    Adjusted free cash flow is a non-IFRS measure and defined as operating cash flow excluding working capital (after adjusting for inventory holding gains/losses, fair value accounting effects and other adjusting items) less cash capital expenditure.

•    ROACE is a non-IFRS measure and is defined as underlying replacement cost profit after adding back non-controlling interest and interest expense net of tax, divided by the average of the beginning and ending balances of total equity plus finance debt excluding cash and cash equivalents and goodwill as presented on the group balance sheet over the periods. Interest expense before tax is finance costs as presented on the group income statement, excluding lease interest, the unwinding of the discount on provisions and other payables and other adjusting items reported in finance costs.

•    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.

Structural cost reduction is calculated as decreases in underlying operating expenditure* (as defined on page 38) as a result of operational efficiencies, divestments, workforce reductions and other cost saving measures that are expected to be sustainable compared with 2023 levels. The total change between periods in underlying operating expenditure will reflect both structural cost reductions and other changes in spend, including market factors, such as inflation and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations. Estimates of cumulative annual structural cost reduction may be revised depending on whether cost reductions realized in prior periods are determined to be sustainable compared with 2023 levels. Structural cost reductions are stewarded internally to support management's oversight of spending over time.

Trade marks