3Q26 BP PLC Part 1 of 1

Summary by AI ^BETAClose X

BP PLC reported strong third quarter and nine-month results for 2026, with underlying replacement cost profit reaching $8.5 billion for the quarter and $17.4 billion for the nine months, significantly up from the prior year. Operating cash flow was robust at $14.8 billion for the third quarter, contributing to an $8.4 billion reduction in net debt to $13.9 billion. The company also announced an interim dividend of 8.660 cents per ordinary share, payable in December. Strategic progress includes advancements in portfolio simplification and operational improvements, with an outlook update planned for December to detail the next phase of their strategy.

Disclaimer*

BP PLC

30 October 2026

FOR IMMEDIATE RELEASE
London 30 October 2026
BP p.l.c. Group results
Third quarter and nine months 2026

Cash generation accelerates balance sheet strengthening

Financial summary	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Profit for the period attributable to bp shareholders	4,696		3,911		1,161		12,449		3,477
Inventory holding (gains) losses*, net of tax	(1,598	)	717		62		(4,061	)	351
Replacement cost (RC) profit*	3,098		4,628		1,223		8,388		3,828
Net adverse impact of adjusting items*, net of tax	5,360		1,104		987		9,000		2,116
Underlying RC profit*	8,458		5,732		2,210		17,388		5,944
Operating cash flow	14,829		10,858		7,786		28,547		16,891
Capital expenditure	(3,036	)	(3,086	)	(3,381	)	(9,412	)	(10,365	)
Divestment and other proceeds_(a)	(21	)	609		28		836		1,712
Net debt*_(b)	13,870		22,251		26,054		13,870		26,054
Underlying operating expenditure*	5,264		5,333		5,487		15,966		16,248
Announced dividend per ordinary share (cents per share)	8.660		8.660		8.320		25.640		24.640
Underlying RC profit per ordinary share* (cents)	54.37		36.92		14.24		112.06		37.98
Underlying RC profit per ADS* (dollars)	3.26		2.22		0.85		6.72		2.28

Key headlines

• 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.

Meg O'Neill, Chief executive officer

"These are dynamic times with volatility and disruption to trade flows continuing to define energy markets.

The industry as a whole has been showing remarkable adaptability. Refineries have been running close to capacity to make up for shortfalls, shipping has been taking different and longer routes, and releases from strategic and commercial reserves are helping to bridge supply gaps.

I'm proud of the contribution bp is making to keep energy flowing. As a global integrated oil and gas company, our connectivity from the reservoir to the fuel pump is a significant source of strength and resilience, particularly given our ability to connect supply with demand.

We maintained upstream production at around 2.2 million barrels per day, upstream plant reliability and refining availability both improved compared to the previous quarter, and our trading performance was also higher.

This has generated a strong set of results, supported by the higher-price, higher-margin environment and some good progress on performance improvement across the business. Our underlying replacement cost profit for the quarter was $8.5 billion and operating cash flow was $14.8 billion, contributing to a reduction of $8.4 billion in net debt.

We have now delivered our net debt and structural cost reductions targets and have line of sight on the remaining two of the four primary financial targets we set ourselves for 2027.

Last week we announced an important step as we agreed with the State of Louisiana to accelerate the delivery of our Deepwater Horizon settlement commitments. Our intent is now to prioritize the use of excess cashflow to address our remaining Deepwater Horizon liabilities in full.

Deepwater Horizon was a tragedy. Eleven men lost their lives, and communities and the environment across the Gulf Coast were impacted. We will never forget - it changed bp. Its legacy guides us in how we operate today, with safety at the heart of everything we do.

And as we move forward, we will continue working with urgency to turn one good set of results into strong performance quarter after quarter. We have much more to do on the five priorities set out at mid-year to deliver a step change in performance and realize the full potential of this company.

Performance improvement priorities

Strengthening the balance sheet: The combined sum of bp's net debt, hybrids, lease liabilities and Gulf of America settlement liabilities is down by $9.3 billion compared with the second quarter of the year. This is good progress, but we are still too leveraged and further strengthening of the balance sheet remains our number one job. Our goal is a strong balance sheet that, through the cycle, supports the dividend and disciplined investment in service of delivering value to shareholders.

BP p.l.c. Group results

Third quarter and nine months 2026

Simplifying the portfolio and investing with discipline: We are moving at speed to simplify bp's portfolio to assets that best fit our integrated model and deliver the most competitive cash and returns. In the quarter we agreed the sale of our Austrian mobility and convenience business, completed the sale of the Gelsenkirchen refinery, and announced plans to market our North Sea and Archaea businesses. Still to come is the expected imminent closure of the Castrol divestment, unlocking $6 billion to further strengthen the balance sheet.

We have also de-risked exploration and production prospects in Brazil, the Gulf of America and Iraq by bringing in partners. In Venezuela we signed agreements for offshore gas production close to our LNG facilities in Trinidad. We are being rigorous about where we put capital and focusing on the most competitive opportunities. But this quarter we recognized $4.0 billion of impairments linked largely to transition businesses; we know we need to be better stewards of our shareholders' capital.

Driving operational excellence: The culture of ownership the bpx energy team has built in the US over the past three years is showing up in better execution, higher productivity and stronger returns. And in refining this quarter, availability and utilization improved and unit operating costs were down, unlocking greater value from our assets. This improvement needs to be sustained quarter on quarter and replicated across the company.

Hardwiring high performance and accountability: Senior leaders came together last month to hold up the mirror on past performance, challenge ways of working, and make new commitments on clearer accountabilities and better, faster data-based decision-making. We are giving our people clarity on the work they own, what they are expected to deliver and how success will be measured - supported by a much simpler governance and organizational structure that includes the return to upstream and downstream businesses.

Simpler, stronger, more valuable bp

Our goal is to be a resilient business that delivers strong performance in all price environments and grows long-term value for our shareholders. In December we will set out our longer-term plans and capital frame, alongside metrics and targets against which our performance can be judged as we continue to build a simpler, stronger, more valuable bp.

(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.

Definitions are provided in the Glossary on page 31. Non-IFRS measures are marked with an asterisk.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

3Q 2026 financial results summary

• 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.

Segment results

• 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.

Financial results

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.

Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
RC profit (loss) before interest and tax
gas & low carbon energy	208		1,564		1,097		2,826		3,502
oil production & operations	3,405		3,397		2,119		8,457		6,823
customers & products	4,796		5,100		1,610		12,348		2,685
other businesses & corporate	(765	)	(250	)	(277	)	(1,870	)	346
Consolidation adjustment - UPII*	-		-		(19	)	21		24
RC profit before interest and tax	7,644		9,811		4,530		21,782		13,380
Finance costs and net finance expense relating to pensions and other post-employment benefits	(1,071	)	(1,120	)	(1,212	)	(3,312	)	(3,654	)
Taxation on a RC basis	(3,034	)	(3,644	)	(1,747	)	(8,852	)	(4,955	)
Non-controlling interests	(441	)	(419	)	(348	)	(1,230	)	(943	)
RC profit attributable to bp shareholders*	3,098		4,628		1,223		8,388		3,828
Inventory holding gains (losses)*	2,040		(870	)	(82	)	5,329		(477	)
Taxation (charge) credit on inventory holding gains and losses	(442	)	153		20		(1,268	)	126
Profit for the period attributable to bp shareholders	4,696		3,911		1,161		12,449		3,477

Analysis of underlying RC profit (loss) before interest and tax

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Underlying RC profit (loss) before interest and tax
gas & low carbon energy	3,183		2,122		1,519		6,641		3,978
oil production & operations	3,534		3,581		2,299		9,096		7,456
customers & products	6,948		4,954		1,716		15,105		3,926
other businesses & corporate	(222	)	(345	)	(189	)	(839	)	(344	)
Consolidation adjustment - UPII	-		-		(19	)	21		24
Underlying RC profit before interest and tax	13,443		10,312		5,326		30,024		15,040
Finance costs on an underlying RC basis_(a) and net finance expense relating to pensions and other post-employment benefits	(1,020	)	(1,053	)	(1,129	)	(3,120	)	(3,306	)
Taxation on an underlying RC basis	(3,524	)	(3,108	)	(1,639	)	(8,286	)	(4,847	)
Non-controlling interests	(441	)	(419	)	(348	)	(1,230	)	(943	)
Underlying RC profit attributable to bp shareholders*	8,458		5,732		2,210		17,388		5,944

(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).

Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 7-13 for the segments.

Operating Metrics

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
Tier 1 and tier 2 process safety events_(a)	8	20	8	35	23
upstream production_(b) (mboe/d)	2,220	2,201	2,362	2,253	2,301
upstream unit production costs_(c) ($/boe)	6.54	6.62	6.19	6.51	6.44
bp-operated upstream plant reliability	95.3%	92.4%	96.8%	94.5%	96.3%
Refinery throughputs (mb/d)	1,396	1,467	1,516	1,463	1,433
bp-operated refining availability_(b)	96.5%	94.7%	96.6%	95.8%	96.4%

(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.

Outlook & Guidance

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.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

gas & low carbon energy

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%.

gas & low carbon energy (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Profit before interest and tax	208		1,564		1,097		2,826		3,502
Inventory holding (gains) losses*	-		-		-		-		-
RC profit before interest and tax	208		1,564		1,097		2,826		3,502
Net (favourable) adverse impact of adjusting items	2,975		558		422		3,815		476
Underlying RC profit before interest and tax	3,183		2,122		1,519		6,641		3,978
Taxation on an underlying RC basis	(906	)	(706	)	(529	)	(2,085	)	(1,509	)
Underlying RC profit before interest	2,277		1,416		990		4,556		2,469

	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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
Production (net of royalties)_(a)
Liquids (mb/d)	80	88	87	85	85
Natural gas (mmcf/d)	4,085	3,928	4,167	4,045	4,054
Total hydrocarbons (mboe/d)	784	765	806	783	784

Average realizations_(b)
Liquids ($/bbl)	85.05	94.09	64.57	82.43	66.31
Natural gas ($/mcf)	8.65	8.03	6.41	7.66	6.71
Total hydrocarbons ($/boe)	53.92	52.82	40.30	48.90	42.06

(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.

oil production & operations

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.

oil production & operations (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Profit before interest and tax	3,407		3,396		2,116		8,465		6,825
Inventory holding (gains) losses*	(2	)	1		3		(8	)	(2	)
RC profit before interest and tax	3,405		3,397		2,119		8,457		6,823
Net (favourable) adverse impact of adjusting items	129		184		180		639		633
Underlying RC profit before interest and tax	3,534		3,581		2,299		9,096		7,456
Taxation on an underlying RC basis	(1,378	)	(1,659	)	(1,054	)	(3,891	)	(3,491	)
Underlying RC profit before interest	2,156		1,922		1,245		5,205		3,965

	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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
Production (net of royalties)_(a)
Liquids (mb/d)	1,008	997	1,121	1,043	1,107
Natural gas (mmcf/d)	2,482	2,543	2,525	2,478	2,374
Total hydrocarbons (mboe/d)	1,436	1,436	1,556	1,470	1,517

Average realizations_(b)
Liquids ($/bbl)	76.42	84.10	59.58	73.23	62.17
Natural gas ($/mcf)	2.83	2.16	3.32	2.84	3.87
Total hydrocarbons ($/boe)	57.59	62.18	47.89	56.05	50.99

(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.

customers & products

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.

customers & products (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Profit before interest and tax	6,834		4,231		1,531		17,669		2,206
Inventory holding (gains) losses*	(2,038	)	869		79		(5,321	)	479
RC profit before interest and tax	4,796		5,100		1,610		12,348		2,685
Net (favourable) adverse impact of adjusting items	2,152		(146	)	106		2,757		1,241
Underlying RC profit before interest and tax	6,948		4,954		1,716		15,105		3,926
Of which:_(a)
customers - convenience & mobility	1,223		1,771		1,167		4,003		2,887
Castrol - included in customers	285		429		261		1,060		744
products - refining & trading	5,725		3,183		549		11,102		1,039
Taxation on an underlying RC basis	(1,415	)	(1,034	)	(360	)	(3,095	)	(687	)
Underlying RC profit before interest	5,533		3,920		1,356		12,010		3,239

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

	Third		Second		Third	Nine	Nine
	quarter		quarter		quarter	months	months
$ million	2026		2026		2025	2026	2025
Adjusted EBITDA*_(b)
customers - convenience & mobility	1,796		2,340		1,786	5,677	4,715
Castrol - included in customers	285		429		309	1,060	888
products - refining & trading	6,153		3,616		975	12,395	2,301
	7,949		5,956		2,761	18,072	7,016

Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,001		1,002		1,045	2,967	3,090

Capital expenditure
customers - convenience & mobility	322		309		386	998	1,358
Castrol - included in customers	(4	)	(3	)	37	8	110
products - refining & trading	161		229		384	680	1,152
Total capital expenditure	483		538		770	1,678	2,510

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
Marketing sales of refined products (mb/d)	2026	2026	2025	2026	2025
US	1,248	1,189	1,273	1,203	1,240
Europe	968	986	1,046	959	1,000
Rest of World	454	449	456	454	463
	2,670	2,624	2,775	2,616	2,703
Trading/supply sales of refined products	488	539	557	501	492
Total sales volume of refined products	3,158	3,163	3,332	3,117	3,195

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

46.7

29.6

15.8

31.2

12.0

Refinery throughputs (mb/d)
US	720	626	683	676	643
Europe	676	841	833	787	790
Total refinery throughputs	1,396	1,467	1,516	1,463	1,433

bp-operated refining availability (%)	96.5	94.7	96.6	95.8	96.4

other businesses & corporate

Other businesses & corporate comprises technology, bp ventures, shipping, our corporate activities & functions and any residual costs of the Gulf of America oil spill.

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.

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Profit (loss) before interest and tax	(765	)	(250	)	(277	)	(1,870	)	346
Inventory holding (gains) losses*	-		-		-		-		-
RC profit (loss) before interest and tax	(765	)	(250	)	(277	)	(1,870	)	346
Net (favourable) adverse impact of adjusting items_(a)	543		(95	)	88		1,031		(690	)
Underlying RC profit (loss) before interest and tax	(222	)	(345	)	(189	)	(839	)	(344	)
Taxation on an underlying RC basis	(16	)	91		106		199		248
Underlying RC profit (loss) before interest	(238	)	(254	)	(83	)	(640	)	(96	)

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

Financial statements

Group income statement

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025

Sales and other operating revenues (Note 5)	68,399		69,105		48,420		189,759		141,952
Earnings from joint ventures - after interest and tax	598		438		176		1,359		744
Earnings from associates - after interest and tax	413		145		275		911		679
Interest and other income	455		411		397		1,204		1,157
Gains on sale of businesses and fixed assets	19		15		(18	)	136		275
Total revenues and other income	69,884		70,114		49,250		193,369		144,807
Purchases	38,354		41,149		28,031		105,753		82,626
Production and manufacturing expenses	7,641		8,954		6,620		25,132		18,887
Production and similar taxes	542		629		431		1,600		1,292
Depreciation, depletion and amortization (Note 6)	4,353		4,149		4,472		12,912		13,296
Net impairment and losses on sale of businesses and fixed assets (Note 3)	4,364		1,100		753		6,053		2,413
Exploration expense	52		582		224		678		466
Distribution and administration expenses	4,894		4,610		4,271		14,130		12,924
Profit (loss) before interest and taxation	9,684		8,941		4,448		27,111		12,903
Finance costs	1,120		1,175		1,267		3,470		3,817
Net finance (income) expense relating to pensions and other post-employment benefits	(49	)	(55	)	(55	)	(158	)	(163	)
Profit (loss) before taxation	8,613		7,821		3,236		23,799		9,249
Taxation	3,476		3,491		1,727		10,120		4,829
Profit (loss) for the period	5,137		4,330		1,509		13,679		4,420
Attributable to
bp shareholders	4,696		3,911		1,161		12,449		3,477
Non-controlling interests	441		419		348		1,230		943
	5,137		4,330		1,509		13,679		4,420

Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic	30.19		24.77		7.48		79.81		22.22
Diluted	29.89		24.54		7.38		78.79		21.77
Per ADS (dollars)
Basic	1.81		1.49		0.45		4.79		1.33
Diluted	1.79		1.47		0.44		4.73		1.31

Condensed group statement of comprehensive income

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025

Profit (loss) for the period	5,137		4,330		1,509		13,679		4,420
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences_(a)	(320	)	65		(276	)	(446	)	1,866
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets_(b)	345		2		22		347		22
Cash flow hedges and costs of hedging	37		(8	)	134		188		184
Share of items relating to equity-accounted entities, net of tax	45		(1	)	(5	)	51		(1	)
Income tax relating to items that may be reclassified	(12	)	(15	)	(3	)	(41	)	(18	)
	95		43		(128	)	99		2,053
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset	378		(364	)	(447	)	133		(330	)
Remeasurements of equity investments	-		3		-		2		1
Cash flow hedges that will subsequently be transferred to the balance sheet	1		-		(1	)	4		3
Income tax relating to items that will not be reclassified	(101	)	91		126		(47	)	83
	278		(270	)	(322	)	92		(243	)
Other comprehensive income	373		(227	)	(450	)	191		1,810
Total comprehensive income	5,510		4,103		1,059		13,870		6,230
Attributable to
bp shareholders	5,075		3,700		726		12,691		5,165
Non-controlling interests	435		403		333		1,179		1,065
	5,510		4,103		1,059		13,870		6,230

(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.

Condensed group statement of changes in equity

	bp shareholders'		Non-controlling interests				Total
$ million	equity		Hybrid bonds		Other interest		equity
At 1 January 2026	53,052		15,955		4,993		74,000

Total comprehensive income	12,691		532		647		13,870
Dividends	(3,921	)	-		(662	)	(4,583	)
Cash flow hedges transferred to the balance sheet, net of tax	(1	)	-		-		(1	)
Repurchase of ordinary share capital	(114	)	-		-		(114	)
Share-based payments, net of tax	722		-		-		722
Redemption of perpetual hybrid bonds, net of tax_(a)	(65	)	(3,816	)	-		(3,881	)
Payments on perpetual hybrid bonds	-		(568	)	-		(568	)
Transactions involving non-controlling interests, net of tax	(191	)	-		339		148
At 30 September 2026	62,173		12,103		5,317		79,593

	bp shareholders'		Non-controlling interests				Total
$ million	equity		Hybrid bonds		Other interest		equity
At 1 January 2025	59,246		16,649		2,423		78,318

Total comprehensive income	5,165		607		458		6,230
Dividends	(3,805	)	-		(386	)	(4,191	)
Cash flow hedges transferred to the balance sheet, net of tax	(5	)	-		-		(5	)
Repurchase of ordinary share capital	(3,261	)	-		-		(3,261	)
Share-based payments, net of tax	908		-		-		908
Share of equity-accounted entities' changes in equity, net of tax	1		-		-		1
Issue of perpetual hybrid bonds	-		500		-		500
Redemption of perpetual hybrid bonds, net of tax	-		(1,200	)	-		(1,200	)
Payments on perpetual hybrid bonds	(9	)	(618	)	-		(627	)
Transactions involving non-controlling interests, net of tax	4		-		968		972
At 30 September 2025	58,244		15,938		3,463		77,645

(a) In the nine months 2026, BP Capital Markets p.l.c. exercised its option to redeem €2.5 billion of hybrid bonds. During the third quarter 2026, a group subsidiary redeemed perpetual subordinated hybrid securities of $1.0 billion which had previously been specifically earmarked to fund BP Alternative Energy Investments Ltd., including the funding of Lightsource bp.

Group balance sheet

	30 September	31 December
$ million	2026	2025
Non-current assets
Property, plant and equipment	95,257	98,633
Goodwill	9,233	10,300
Intangible assets	8,143	8,197
Investments in joint ventures	11,399	13,400
Investments in associates	7,317	7,325
Other investments	661	857
Fixed assets	132,010	138,712
Loans	1,663	1,991
Trade and other receivables	2,490	2,376
Derivative financial instruments	21,641	20,957
Prepayments	637	608
Deferred tax assets	2,499	4,325
Defined benefit pension plan surpluses	7,309	7,771
	168,249	176,740
Current assets
Loans	375	457
Inventories	30,965	22,499
Trade and other receivables	39,765	26,014
Derivative financial instruments	9,518	5,180
Prepayments	2,067	3,422
Current tax receivable	715	1,153
Other investments	60	158
Cash and cash equivalents	42,993	36,556
	126,458	95,439
Assets classified as held for sale (Note 2)	9,014	6,347
	135,472	101,786
Total assets	303,721	278,526
Current liabilities
Trade and other payables	69,070	56,843
Derivative financial instruments	9,792	4,413
Accruals	5,870	5,572
Lease liabilities	3,013	2,832
Finance debt	5,975	3,356
Current tax payable	3,436	1,262
Provisions	4,772	4,709
	101,928	78,987
Liabilities directly associated with assets classified as held for sale (Note 2)	3,128	1,594
	105,056	80,581
Non-current liabilities
Other payables	7,089	7,975
Derivative financial instruments	21,678	19,667
Accruals	1,924	1,834
Lease liabilities	11,237	11,739
Finance debt	49,391	54,602
Deferred tax liabilities	8,172	7,642
Provisions	15,732	15,670
Defined benefit pension plan and other post-employment benefit plan deficits	3,849	4,816
	119,072	123,945
Total liabilities	224,128	204,526
Net assets	79,593	74,000
Equity
bp shareholders' equity	62,173	53,052
Non-controlling interests	17,420	20,948
Total equity	79,593	74,000

Condensed group cash flow statement

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Operating activities
Profit (loss) before taxation	8,613		7,821		3,236		23,799		9,249
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,369		4,675		4,655		13,456		13,614
Net impairment and (gain) loss on sale of businesses and fixed assets	4,345		1,085		771		5,917		2,138
Earnings from equity-accounted entities, less dividends received	(351	)	51		192		(667	)	32
Net charge for interest and other finance expense, less net interest paid	371		151		470		557		743
Share-based payments	181		201		264		700		880
Net operating charge for pensions and other post-employment benefits, less contributions and benefit payments for unfunded plans	299		(18	)	(96	)	252		(143	)
Net charge for provisions, less payments	(2,123	)	948		(60	)	1,182		1,710
Movements in inventories and other current and non-current assets and liabilities	1,428		(2,675	)	494		(11,789	)	(6,605	)
Income taxes paid	(2,303	)	(1,381	)	(2,140	)	(4,860	)	(4,727	)
Net cash provided by operating activities	14,829		10,858		7,786		28,547		16,891
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(2,964	)	(3,087	)	(3,171	)	(9,293	)	(9,758	)
Acquisitions, net of cash acquired	(3	)	9		(52	)	(8	)	(293	)
Investment in joint ventures	(64	)	(8	)	(128	)	(94	)	(245	)
Investment in associates	(5	)	-		(30	)	(17	)	(69	)
Total cash capital expenditure	(3,036	)	(3,086	)	(3,381	)	(9,412	)	(10,365	)
Proceeds from disposal of fixed assets	50		425		30		634		644
Proceeds from disposal of businesses, net of cash disposed	(71	)	184		(2	)	215		110
Proceeds from loan repayments	72		31		48		135		110
Cash provided from investing activities	51		640		76		984		864
Net cash used in investing activities	(2,985	)	(2,446	)	(3,305	)	(8,428	)	(9,501	)
Financing activities
Net issue (repurchase) of shares (Note 7)	-		-		(750	)	(562	)	(3,660	)
Lease liability payments	(769	)	(761	)	(816	)	(2,294	)	(2,327	)
Proceeds from long-term financing	11		1,170		1,028		1,248		2,237
Repayments of long-term financing	(2,366	)	(21	)	(1,250	)	(3,232	)	(3,464	)
Net increase (decrease) in short-term debt	(97	)	(2,726	)	104		289		18
Issue of perpetual hybrid bonds	-		-		-		-		500
Redemption of perpetual hybrid bonds_(a)	(1,000	)	(2,855	)	(1,200	)	(3,855	)	(1,200	)
Payments relating to perpetual hybrid bonds	(178	)	(293	)	(284	)	(708	)	(888	)
Payments relating to transactions involving non-controlling interests (Other interest)	(9	)	-		(2	)	(22	)	(2	)
Receipts relating to transactions involving non-controlling interests (Other interest)	-		1		8		1		973
Dividends paid - bp shareholders	(1,345	)	(1,302	)	(1,288	)	(3,925	)	(3,783	)
- non-controlling interests	(287	)	(206	)	(155	)	(668	)	(356	)
Net cash provided by (used in) financing activities	(6,040	)	(6,993	)	(4,605	)	(13,728	)	(11,952	)
Currency translation differences relating to cash and cash equivalents	54		49		(51	)	(6	)	248
Increase (decrease) in cash and cash equivalents	5,858		1,468		(175	)	6,385		(4,314	)
Cash and cash equivalents at beginning of period(b)	37,185		35,717		35,130		36,658		39,269
Cash and cash equivalents at end of period(c)	43,043		37,185		34,955		43,043		34,955

(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.

Notes

Note 1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.

The results for the interim periods presented herein are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2025 included in bp Annual Report and Form 20-F 2025.

bp prepares its consolidated financial statements included within bp Annual Report and Form 20-F on the basis of United Kingdom adopted international accounting standards and IFRS® Accounting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU), and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the UK and EU differ in certain respects from IFRS as issued by the IASB. The differences have no impact on the group's consolidated financial statements for the periods presented. The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing bp Annual Report and Form 20-F 2026, which are the same as those used in preparing bp Annual Report and Form 20-F 2025.

New standards and amendments to IFRS

On 1 January 2026, bp adopted the amendments to IFRS 9 'Financial Instruments' relating to the settlement of liabilities through electronic payment systems using the modified retrospective approach. The impact to the interim financial information upon transition was a $34 million increase to cash and cash equivalents.

Significant accounting judgements and estimates

bp's significant accounting judgements and estimates were disclosed in bp Annual Report and Form 20-F 2025. These have been subsequently considered at the end of this quarter to determine if any changes were required to those judgements and estimates.

Considerations in respect of ongoing geopolitical instability in the Middle East and impact on the economic environment

The impact of ongoing geopolitical instability in the Middle East and the associated economic developments have been considered for the basis of preparation for the interim financial information. Such factors include the economic effect of price volatility, supply disruptions in the region, operability of producing assets and discount rates.

Impairment testing assumptions

As a result of ongoing geopolitical instability in the Middle East and the related economic impact, the group's value-in-use impairment testing price assumptions for Brent oil and Henry Hub gas were revised during the third quarter from those disclosed in the bp Annual Report and Form 20-F 2025, and also revised since the second quarter 2026. The group has updated its estimate of Brent oil prices to $87/bbl (previously $70/bbl) and Henry Hub gas prices to $3.18/mmBtu (previously $3.80/mmBtu) in real 2024 terms on an average basis for the full year 2026. With reference to the Brent price, this estimate assumes ongoing supply disruptions resulting from geopolitical instability in the Middle East into 2027. With regard to the Henry Hub gas price assumption, the price decrease is based on an expectation of strong production growth for the remainder of 2026 and into 2027 in the US domestic market. No material impairment or reversal of impairment arose in the third quarter 2026 interim period as a result of the changes to these commodity price assumptions. The post-tax discount rate used for value-in-use impairment testing of assets other than certain low carbon energy assets was maintained at 8% (31 December 2025 8%).

Segmentation

Reportable segments for external financial reporting will remain Oil production & operations, Gas & low carbon energy and Customers & products until 31 December 2026, as the financial reporting aspects of the new segment model announced on 9 June 2026 will take time to implement. Until the new reporting segments take effect from the financial year beginning 1 January 2027, decisions about resource allocation and performance assessment of segments will continue to be made on the existing segmental internal reporting regularly reviewed by the chief operating decision maker.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2026 is $9,014 million, with associated liabilities of $3,128 million.

Gas & low carbon energy

On 24 October 2024, bp completed the acquisition of the remaining 50.03% of Lightsource bp. The acquisition included certain assets for which sales processes were in progress at the acquisition date. The sales of these assets are expected to complete in 2026. The carrying amount of assets classified as held for sale at 30 September 2026 is $856 million, with associated liabilities of $587 million.

Oil production & operations

On 17 July 2026 bp and ConocoPhillips agreed terms for ConocoPhillips to acquire a 42% interest in BP Energy Company of Kirkuk Limited (BP ECKL). On 28 July 2026 bp and Türkiye Petrolleri Anonim Ortaklığı (TPAO) agreed terms for TPAO to acquire a 15% interest in BP ECKL. The three parties intend to form a joint venture, and bp expects to equity account for its retained 43% interest after completion. The sales of these interests are expected to be completed during the fourth quarter of 2026. The carrying amount of assets classified as held for sale at 30 September 2026 is $485 million, with associated liabilities of $248 million.

Customers & products

On 18 March 2026, bp agreed with the Klesch Group to divest its 100% interest in the Gelsenkirchen refinery and associated assets. The transaction completed on 31 July 2026. The related assets and liabilities, of the business, previously classified as held for sale, were derecognised on that date. A loss on sale of businesses of $249 million has been recognized including $345 million of cumulative foreign exchange losses recycled to the group income statement from reserves.

On 24 December 2025, bp announced an agreement with Stonepeak to divest a 65% shareholding in the Castrol business with bp retaining a 35% interest through a holding in a newly incorporated entity. The carrying amount of assets classified as held for sale at 30 September 2026 is $7,673 million including $2,707 million of goodwill that arose on the acquisition of Castrol in 2000, with associated liabilities of $2,293 million. See also Note 10.

Note 3. Impairment and losses on sale of businesses and fixed assets

Net impairment charges and losses on sale of businesses and fixed assets for the third quarter and nine months were $4,364 million and $6,053 million respectively, compared with net charges of $753 million and $2,413 million for the same periods in 2025 and include net impairment charges for the third quarter and nine months of $4,067 million and $5,315 million respectively, compared with net impairment charges of $370 million and $1,931 million for the same periods in 2025.

Gas & low carbon energy

Third quarter and nine months 2026 impairments includes a net impairment charge of $3,365 million and $3,890 million respectively, primarily related to the group's transition businesses, including Lightsource bp and offshore wind, compared with net charges of $135 million and $881 million for the same periods in 2025 in the gas & low carbon energy segment.

Oil production & operations

Third quarter and nine months 2026 impairments includes a charge of $73 million and $328 million respectively, compared with a reversal of $7 million and a net charge of $329 million for the same periods in 2025 in the oil production & operations segment.

Customers & products

Third quarter and nine months 2026 impairments includes an impairment charge of $629 million and $854 million respectively, compared with net charges of $242 million and $719 million for the same periods in 2025 in the customers & products segment.

Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
gas & low carbon energy	208		1,564		1,097		2,826		3,502
oil production & operations	3,405		3,397		2,119		8,457		6,823
customers & products	4,796		5,100		1,610		12,348		2,685
other businesses & corporate	(765	)	(250	)	(277	)	(1,870	)	346
	7,644		9,811		4,549		21,761		13,356
Consolidation adjustment - UPII*	-		-		(19	)	21		24
RC profit (loss) before interest and tax	7,644		9,811		4,530		21,782		13,380
Inventory holding gains (losses)*
gas & low carbon energy	-		-		-		-		-
oil production & operations	2		(1	)	(3	)	8		2
customers & products	2,038		(869	)	(79	)	5,321		(479	)
Profit (loss) before interest and tax	9,684		8,941		4,448		27,111		12,903
Finance costs	1,120		1,175		1,267		3,470		3,817
Net finance expense/(income) relating to pensions and other post-employment benefits	(49	)	(55	)	(55	)	(158	)	(163	)
Profit (loss) before taxation	8,613		7,821		3,236		23,799		9,249

RC profit (loss) before interest and tax*
US	3,718		3,727		632		8,966		3,582
Non-US	3,926		6,084		3,898		12,816		9,798
	7,644		9,811		4,530		21,782		13,380

Note 5. Sales and other operating revenues

	Third	Second		Third	Nine	Nine
	quarter	quarter		quarter	months	months
$ million	2026	2026		2025	2026	2025
By segment
gas & low carbon energy	14,905	11,675		9,655	36,027	29,605
oil production & operations	7,251	7,813		6,232	21,016	18,787
customers & products	53,322	57,159		38,697	153,442	112,309
other businesses & corporate	735	739		627	2,035	1,650
	76,213	77,386		55,211	212,520	162,351

Less: sales and other operating revenues between segments
gas & low carbon energy	369	808		310	1,524	1,378
oil production & operations	6,777	7,289		5,908	19,666	17,544
customers & products	254	(293	)	70	436	57
other businesses & corporate	414	477		503	1,135	1,420
	7,814	8,281		6,791	22,761	20,399

External sales and other operating revenues
gas & low carbon energy	14,536	10,867		9,345	34,503	28,227
oil production & operations	474	524		324	1,350	1,243
customers & products	53,068	57,452		38,627	153,006	112,252
other businesses & corporate	321	262		124	900	230
Total sales and other operating revenues	68,399	69,105		48,420	189,759	141,952

By geographical area
US	23,504	25,125		18,968	68,105	56,947
Non-US	56,360	57,019		37,877	155,956	109,811
	79,864	82,144		56,845	224,061	166,758
Less: sales and other operating revenues between areas	11,465	13,039		8,425	34,302	24,806
	68,399	69,105		48,420	189,759	141,952

Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	347	402		635	1,082	1,471
Oil products	42,425	43,549		30,274	115,825	86,008
Natural gas, LNG and NGLs	10,681	8,523		7,192	25,841	20,504
Non-oil products and other revenues from contracts with customers	3,880	3,721		3,528	11,296	10,858
Revenue from contracts with customers	57,333	56,195		41,629	154,044	118,841
Other operating revenues_(a)	11,066	12,910		6,791	35,715	23,111
Total sales and other operating revenues	68,399	69,105		48,420	189,759	141,952

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

Note 6. Depreciation, depletion and amortization

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2026	2026	2025	2026	2025
Total depreciation, depletion and amortization by segment
gas & low carbon energy	1,228	1,139	1,223	3,553	3,796
oil production & operations	1,861	1,754	1,961	5,624	5,681
customers & products	1,001	1,002	1,045	2,967	3,090
other businesses & corporate	263	254	243	768	729
	4,353	4,149	4,472	12,912	13,296
Total depreciation, depletion and amortization by geographical area
US	1,794	1,721	1,898	5,394	5,531
Non-US	2,559	2,428	2,574	7,518	7,765
	4,353	4,149	4,472	12,912	13,296

Note 7. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2026	2026	2025	2026	2025
Results for the period
Profit (loss) for the period attributable to bp shareholders	4,696	3,911	1,161	12,449	3,477
Less: preference dividend	-	1	-	1	1
Less: (gain) loss on redemption of perpetual hybrid bonds_(a)	-	65	-	65	-
Profit (loss) attributable to bp ordinary shareholders	4,696	3,845	1,161	12,383	3,476

Number of shares (thousand)_(b)
Basic weighted average number of shares outstanding	15,555,241	15,522,233	15,518,940	15,516,394	15,646,554
ADS equivalent_(c)	2,592,540	2,587,038	2,586,490	2,586,065	2,607,759

Weighted average number of shares outstanding used to calculate diluted earnings per share	15,710,351	15,667,335	15,735,029	15,716,209	15,968,108
ADS equivalent_(c)	2,618,391	2,611,222	2,622,504	2,619,368	2,661,351

Shares in issue at period-end	15,563,419	15,546,713	15,487,180	15,563,419	15,487,180
ADS equivalent_(c)	2,593,903	2,591,118	2,581,196	2,593,903	2,581,196

(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.

Note 8. Dividends

Dividends payable

bp today announced an interim dividend of 8.660 cents per ordinary share which is expected to be paid on 18 December 2026 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 13 November 2026. The ex-dividend date will be 12 November 2026 for ordinary shareholders and 13 November 2026 for ADS holders. The corresponding amount in sterling is due to be announced on 8 December 2026, calculated based on the average of the market exchange rates over three dealing days between 2 December 2026 and 4 December 2026. Holders of ADSs are expected to receive $0.5196 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2026 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
Dividends paid per ordinary share
cents	8.660	8.320	8.320	25.300	24.320
pence	6.406	6.184	6.194	18.816	18.270
Dividends paid per ADS (cents)	51.96	49.92	49.92	151.80	145.92

Note 9. Net debt*

	30 September		30 June		30 September
$ million	2026		2026		2025
Finance debt_(a)	55,366		58,337		60,188
Fair value (asset) liability of hedges related to finance debt_(b)	1,497		1,082		775
	56,863		59,419		60,963
Less: cash and cash equivalents	42,993		37,168		34,909
Net debt_(c)	13,870		22,251		26,054
Total equity	79,593		76,420		77,645
Gearing*	14.8	%	22.6	%	25.1	%

(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.

As part of actively managing its debt portfolio, in the third quarter and nine months 2026, the group bought back $1.0 billion of finance debt consisting entirely of US dollar bonds. These transactions have no significant impact on net debt or gearing.

Note 10. Update on bp's sale of a 65% shareholding in the Castrol business

On 24 December 2025, bp announced an agreement with Stonepeak to divest a 65% shareholding in the Castrol business with bp retaining a 35% interest through a holding in a newly incorporated entity.

The sale is expected to complete imminently. The related assets and liabilities of the business, previously classified as held for sale, will be derecognised as of that date. Proceeds from the sale of the business, net of cash disposed, are estimated to be $6 billion. The shares to be held by Stonepeak after the transaction closes are subject to preferred distributions, the effect of which is that bp does not expect to recognize income or dividends from the investment in the short to medium term.

Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 29 October 2026, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in bp Annual Report and Form 20-F 2026. bp Annual Report and Form 20-F 2025 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

Additional information

Capital expenditure

Capital expenditure is a measure that provides useful information to understand how bp's management allocates resources including the investment of funds in projects which expand the group's activities through acquisition.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2026	2026	2025	2026	2025
Capital expenditure
Organic capital expenditure*	3,036	3,086	3,328	9,398	10,089
Inorganic capital expenditure*	-	-	53	14	276
	3,036	3,086	3,381	9,412	10,365

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2026	2026	2025	2026	2025
Capital expenditure by segment
gas & low carbon energy	916	776	828	2,387	2,521
oil production & operations	1,612	1,733	1,722	5,236	5,124
customers & products	483	538	770	1,678	2,510
other businesses & corporate	25	39	61	111	210
	3,036	3,086	3,381	9,412	10,365
Capital expenditure by geographical area
US	1,385	1,423	1,591	4,410	4,600
Non-US	1,651	1,663	1,790	5,002	5,765
	3,036	3,086	3,381	9,412	10,365

Adjusting items*

Adjusting items are items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors to better understand and evaluate the group's reported financial performance. Adjusting items are used as a reconciling adjustment to derive underlying RC profit or loss and related underlying measures which are non-IFRS measures.

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
gas & low carbon energy
Gains on sale of businesses and fixed assets	11		7		-		19		68
Net impairment and losses on sale of businesses and fixed assets_(a)	(3,366	)	(687	)	(489	)	(4,109	)	(1,294	)
Environmental and related provisions	-		-		-		-		-
Restructuring, integration and rationalization costs	(20	)	(9	)	8		(42	)	(3	)
Fair value accounting effects_(b)(c)	644		205		131		576		817
Other	(244	)	(74	)	(72	)	(259	)	(64	)
	(2,975	)	(558	)	(422	)	(3,815	)	(476	)
oil production & operations
Gains on sale of businesses and fixed assets	23		5		(29	)	95		176
Net impairment and losses on sale of businesses and fixed assets	(71	)	(108	)	10		(334	)	(335	)
Environmental and related provisions	(44	)	(42	)	(145	)	(256	)	(231	)
Restructuring, integration and rationalization costs	(89	)	(9	)	9		(164	)	(78	)
Fair value accounting effects	-		-		-		-		-
Other	52		(30	)	(25	)	20		(165	)
	(129	)	(184	)	(180	)	(639	)	(633	)
customers & products
Gains on sale of businesses and fixed assets	(18	)	4		10		19		29
Net impairment and losses on sale of businesses and fixed assets_(a)	(927	)	(306	)	(274	)	(1,367	)	(777	)
Environmental and related provisions	-		-		(1	)	(3	)	(2	)
Restructuring, integration and rationalization costs	(92	)	(40	)	(17	)	(192	)	(194	)
Fair value accounting effects_(c)	(1,093	)	641		42		(1,045	)	(241	)
Other	(22	)	(153	)	134		(169	)	(56	)
	(2,152	)	146		(106	)	(2,757	)	(1,241	)
other businesses & corporate
Gains on sale of businesses and fixed assets	2		-		2		3		2
Net impairment and losses on sale of businesses and fixed assets	-		1		-		(243	)	(5	)
Environmental and related provisions	(139	)	(21	)	(48	)	(160	)	(138	)
Restructuring, integration and rationalization costs	9		(5	)	(8	)	(106	)	(245	)
Fair value accounting effects_(c)	(92	)	114		(13	)	(196	)	1,096
Gulf of America oil spill	(3	)	-		(9	)	(7	)	(27	)
Other_(d)	(320	)	6		(12	)	(322	)	7
	(543	)	95		(88	)	(1,031	)	690
Total before interest and taxation	(5,799	)	(501	)	(796	)	(8,242	)	(1,660	)
Finance costs_(e)	(51	)	(67	)	(83	)	(192	)	(348	)
Total before taxation	(5,850	)	(568	)	(879	)	(8,434	)	(2,008	)
Taxation on adjusting items_(f)(g)	490		(439	)	125		(469	)	664
Taxation - tax rate change effect_(h)	-		(97	)	(233	)	(97	)	(772	)
Total after taxation for period	(5,360	)	(1,104	)	(987	)	(9,000	)	(2,116	)

(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.

Net debt including leases*

Gearing including leases and net debt including leases are non-IFRS measures that provide the impact of the group's lease portfolio on net debt and gearing.

Net debt including leases	30 September		30 June		30 September
$ million	2026		2026		2025
Net debt*	13,870		22,251		26,054
Lease liabilities	14,250		14,356		14,629
Net partner (receivable) payable for leases entered into on behalf of joint operations	(966	)	(1,040	)	(1,082	)
Net debt including leases	27,154		35,567		39,601
Total equity	79,593		76,420		77,645
Gearing including leases*	25.4	%	31.8	%	33.8	%

Gulf of America oil spill

	30 September		31 December
$ million	2026		2025
Gulf of America oil spill payables and provisions	(5,940	)	(7,256	)
Of which - current	(1,131	)	(1,522	)

Deferred tax asset	886		1,110

During the second quarter pre-tax payments of $1,129 million were made relating to the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Payables and provisions presented in the table above reflect the latest estimate for the remaining costs associated with the Gulf of America oil spill. Where amounts have been provided on an estimated basis, the amounts ultimately payable may differ from the amounts provided and the timing of payments is uncertain. Further information relating to the Gulf of America oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in bp Annual Report and Form 20-F 2025 - Financial statements - Notes 7, 22, 23, 29, and 33.

Working capital* reconciliation

Change in working capital adjusted for inventory holding gains/losses*, fair value accounting effects* relating to subsidiaries and other adjusting items is a non-IFRS measure. It represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been underlying replacement cost profit rather than profit for the period.

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2026		2026		2025		2026		2025
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement_(a)	1,428		(2,675	)	494		(11,789	)	(6,605	)
Adjusted for inventory holding gains (losses) (Note 4)	2,040		(870	)	(82	)	5,329		(477	)
Adjusted for fair value accounting effects relating to subsidiaries	(554	)	906		177		(749	)	1,690
Other adjusting items_(b)	(2,383	)	1,623		322		694		1,569
Working capital release (build) after adjusting for net inventory holding gains (losses), fair value accounting effects and other adjusting items	531		(1,016	)	911		(6,515	)	(3,823	)

(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.

Underlying operating expenditure* reconciliation

Management believes that underlying operating expenditure is a performance measure that provides investors with useful information regarding the company's financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects.

	Third	Second		Third		Nine		Nine
	quarter	quarter		quarter		months		months
$ million	2026	2026		2025		2026		2025
From group income statement
Production and manufacturing expenses	7,641	8,954		6,620		25,132		18,887
Distribution and administration expenses	4,894	4,610		4,271		14,130		12,924
	12,535	13,564		10,891		39,262		31,811
Less certain variable costs:
Transportation and shipping costs	3,244	3,772		2,579		10,099		7,659
Environmental costs	1,075	2,917		1,290		6,391		4,257
Marketing and distribution costs	868	724		358		2,359		1,206
Commission, storage and handling costs	399	423		410		1,221		1,181
Other variable costs and non-cash costs	385	253		654		1,141		1,386
Certain variable costs and non-cash costs	5,971	8,089		5,291		21,211		15,689

Adjusted operating expenditure*	6,564	5,475		5,600		18,051		16,122
Less certain adjusting items*:
Gulf of America oil spill	3	-		9		7		27
Environmental and related provisions	183	63		194		419		371
Restructuring, integration and rationalization costs	192	63		8		504		520
Fair value accounting effects - derivative instruments relating to the hybrid bonds	92	(114	)	13		196		(1,096	)
Other certain adjusting items_(a)	830	130		(111	)	959		52
Certain adjusting items	1,300	142		113		2,085		(126	)

Underlying operating expenditure	5,264	5,333		5,487		15,966		16,248


(Decrease) increase in underlying operating expenditure						(282	)
Of which:
Structural cost reduction*						(1,223	)
Increase/(decrease) in underlying operating expenditure due to inflation, exchange movements, portfolio changes and growth						941

Structural cost reduction at 30 September 2026 since 2023
Structural cost reduction in 2024 and 2025						(2,761	)
Structural cost reduction in the nine months 2026						(1,223	)
Cumulative structural cost reduction excluding the Gelsenkirchen refinery						(3,984	)

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

Reconciliation of customers & products RC profit before interest and tax to underlying RC profit before interest and tax* to adjusted EBITDA* by business

	Third		Second	Third		Nine		Nine
	quarter		quarter	quarter		months		months
$ million	2026		2026	2025		2026		2025
RC profit before interest and tax for customers & products	4,796		5,100	1,610		12,348		2,685
Less: Adjusting items* gains (charges)	(2,152	)	146	(106	)	(2,757	)	(1,241	)
Underlying RC profit before interest and tax for customers & products	6,948		4,954	1,716		15,105		3,926
By business:
customers - convenience & mobility	1,223		1,771	1,167		4,003		2,887
Castrol - included in customers	285		429	261		1,060		744
products - refining & trading	5,725		3,183	549		11,102		1,039

Add back: Depreciation, depletion and amortization	1,001		1,002	1,045		2,967		3,090
By business:
customers - convenience & mobility	573		569	619		1,674		1,828
Castrol - included in customers	-		-	48		-		144
products - refining & trading	428		433	426		1,293		1,262

Adjusted EBITDA for customers & products	7,949		5,956	2,761		18,072		7,016
By business:
customers - convenience & mobility	1,796		2,340	1,786		5,677		4,715
Castrol - included in customers	285		429	309		1,060		888
products - refining & trading	6,153		3,616	975		12,395		2,301

Realizations and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
Average realizations_(a)
Liquids_(b) ($/bbl)
US	67.31	76.03	54.02	64.60	56.32
Europe	102.74	97.49	69.15	94.59	69.81
Rest of World	88.04	95.39	67.20	84.26	70.36
bp average	77.20	85.14	60.02	74.11	62.55
Natural gas ($/mcf)
US	2.41	1.72	2.41	2.48	2.67
Europe	16.89	17.25	11.98	13.95	13.90
Rest of World	8.61	8.03	6.41	7.64	6.71
bp average	6.57	5.89	5.34	5.95	5.75
Total hydrocarbons ($/boe)
US	45.54	48.47	38.91	44.30	41.41
Europe	102.08	97.85	69.25	92.70	73.19
Rest of World	61.76	64.34	47.62	57.76	49.70
bp average	56.16	58.62	45.00	53.30	47.58
Average oil marker prices ($/bbl)
Brent	96.99	103.85	69.13	93.92	70.93
West Texas Intermediate	86.08	93.11	65.07	84.06	66.74
Western Canadian Select	66.45	72.86	52.52	65.47	54.66
Alaska North Slope	87.84	103.05	70.07	89.53	71.54
Average natural gas marker prices
Henry Hub gas price_(c) ($/mmBtu)	2.96	2.90	3.07	3.64	3.39
UK Gas - National Balancing Point (p/therm)	155.75	112.39	79.84	123.46	93.38

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

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

Exchange rates

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2026	2026	2025	2026	2025
$/£ average rate for the period	1.34	1.34	1.35	1.34	1.31
$/£ period-end rate	1.32	1.32	1.34	1.32	1.34

$/€ average rate for the period	1.15	1.16	1.17	1.16	1.12
$/€ period-end rate	1.13	1.14	1.17	1.13	1.17

$/AUD average rate for the period	0.71	0.71	0.65	0.70	0.64
$/AUD period-end rate	0.70	0.69	0.66	0.70	0.66

Legal proceedings

The following discussion sets out the material developments in the group's material legal proceedings following the publication of bp's second quarter and first half 2026 results.

For a full discussion of the group's material legal proceedings, see pages 236-237 of bp Annual Report and Form 20-F 2025.

Louisiana Costal restoration

bp has reached agreement to settle all remaining governmental land loss claims brought by the coastal Louisiana parishes and the State of Louisiana to which bp entities are named defendants. The terms of the agreement are confidential to the parties but are not expected to have a significant effect on the company's financial position or profitability.

bp entities remain as defendants in two private landowner cases which have been filed in Louisiana state courts seeking restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. These cases are not expected to have a significant effect on the company's financial position or profitability and in future reports bp will not report on these proceedings absent any material developments.

Glossary

Non-IFRS measures are provided for investors because they are closely tracked by management to evaluate bp's operating performance and to make financial, strategic and operating decisions. Non-IFRS measures are sometimes referred to as alternative performance measures.

Adjusted EBITDA is a non-IFRS measure presented for bp's operating segments and is defined as replacement cost (RC) profit before interest and tax, adjusting for net adjusting items* before interest and tax, and adding back depreciation, depletion and amortization and exploration write-offs (net of adjusting items). Adjusted EBITDA by business is a further analysis of adjusted EBITDA for the customers & products businesses. bp believes it is helpful to disclose adjusted EBITDA by operating segment and by business because it reflects how the segments measure underlying business delivery. The nearest equivalent measure on an IFRS basis for the segment is RC profit or loss before interest and tax, which is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS. A reconciliation to IFRS information is provided on page 29 for the customers & products businesses.

Adjusted operating expenditure is a non-IFRS measure and a subset of production and manufacturing expenses plus distribution and administration expenses. It represents the majority of the remaining expenses in these line items but excludes certain costs that are variable, primarily with volumes (such as freight costs). Other variable costs are included in purchases in the income statement. Management believes that adjusted operating expenditure is a performance measure that provides investors with useful information regarding the company's financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain adjusting items*, foreign exchange and commodity price effects. The nearest IFRS measures are production and manufacturing expenses and distributions and administration expenses. A reconciliation of production and manufacturing expenses plus distribution and administration expenses to adjusted operating expenditure is provided on page 28.

Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors to better understand and evaluate the group's reported financial performance. Adjusting items include gains and losses on the sale of businesses and fixed assets, impairments, environmental and related provisions and charges, restructuring, integration and rationalization costs, fair value accounting effects and costs relating to the Gulf of America oil spill and other items. Adjusting items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. Adjusting items are used as a reconciling adjustment to derive underlying RC profit or loss and related underlying measures which are non-IFRS measures. An analysis of adjusting items by segment and type is shown on page 26.

Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement. Capital expenditure for the operating segments, gas & low carbon energy businesses and customers & products businesses is presented on the same basis.

Consolidation adjustment - UPII is unrealized profit in inventory arising on inter-segment transactions.

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

Glossary (continued)

Fair value accounting effects are non-IFRS adjustments to our IFRS profit (loss). They reflect the difference between the way bp manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Fair value accounting effects are included within adjusting items. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below. Other than as noted below, the fair value accounting effects described are reported in both the gas & low carbon energy and customer & products segments.

bp uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.

bp enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp's gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.

IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.

bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.

The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates this difference for consolidated entities by comparing the IFRS result with management's internal measure of performance. We believe that disclosing management's estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.

These include:

• 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.

Furthermore, the fair values of derivative instruments used to risk manage certain other oil, gas, power and other contracts, are deferred to match with the underlying exposure. The commodity contracts for business requirements are accounted for on an accruals basis.

In addition, fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which are classified as equity instruments were recorded in the balance sheet at their issuance date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the other businesses & corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.

Glossary (continued)

Gas & low carbon energy segment comprises our gas and low carbon businesses. Our gas business includes regions with upstream activities that predominantly produce natural gas, gas trading and our Archaea Energy business. Our low carbon business includes solar, offshore wind, hydrogen and CCS, and power trading, and until December 2025 also included onshore wind. Power trading and marketing includes trading of both renewable and non-renewable power.

Gearing and gearing including leases are non-IFRS measures. See Net debt or net debt including leases below.

Hydrocarbons - Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Inorganic capital expenditure is a subset of capital expenditure on a cash basis and a non-IFRS measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. bp believes that this measure provides useful information as it allows investors to understand how bp's management invests funds in projects which expand the group's activities through acquisition. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis. Further information and a reconciliation to IFRS information is provided on page 25.

Inventory holding gains and losses are non-IFRS adjustments to our IFRS profit (loss) and represent:

• 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.

The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions that are price risk-managed. See Replacement cost (RC) profit or loss definition below.

Liquids - Liquids comprises crude oil, condensate and natural gas liquids. For the oil production & operations segment, it also includes bitumen.

Major projects have a bp net investment of at least $250 million, or are considered to be of strategic importance to bp or of a high degree of complexity.

Net debt and gearing are non-IFRS measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. 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. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 24.

We are unable to present reconciliations of forward-looking information for net debt or gearing to finance debt and total equity, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable IFRS forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in an IFRS estimate.

Net debt including leases and gearing including leases are non-IFRS measures. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group's lease portfolio on net debt and gearing. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt including leases is provided on page 27.

Glossary (continued)

Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement.

Organic capital expenditure is a non-IFRS measure. Organic capital expenditure comprises capital expenditure on a cash basis less inorganic capital expenditure. bp believes that this measure provides useful information as it allows investors to understand how bp's management invests funds in developing and maintaining the group's assets. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis and a reconciliation to IFRS information is provided on page 25.

We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest IFRS estimate.

Production-sharing agreement/contract (PSA/PSC) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the bp share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties. For the gas & low carbon energy and oil production & operations segments, realizations include transfers between businesses.

Refining availability represents Solomon Associates' operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all mechanical, process and regulatory downtime.

Refining indicator margin (RIM) is a simple indicator of the weighted average of bp's crude slate and product yield as deemed representative for each refinery. Actual margins realized by bp may vary due to a variety of factors, including the actual mix of a crude and product for a given quarter.

Replacement cost (RC) profit or loss / RC profit or loss attributable to bp shareholders reflects the replacement cost of inventories sold in the period and is calculated as profit or loss attributable to bp shareholders, adjusting for inventory holding gains and losses (net of tax). RC profit or loss for the group is not a recognized IFRS measure. bp believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp's management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to bp shareholders. A reconciliation to IFRS information is provided on page 1. RC profit or loss before interest and tax is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

Structural cost reduction is calculated as decreases in underlying operating expenditure* (as defined on page 35) 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.

bp believes this performance measure is useful in demonstrating how management drives cost discipline across the entire organization, simplifying our processes and portfolio and streamlining the way we work. The nearest IFRS measures are production and manufacturing expenses and distributions and administration expenses. A reconciliation of production and manufacturing expenses plus distribution and administration expenses to underlying operating expenditure is provided on page 28.

Glossary (continued)

Technical service contract (TSC) - Technical service contract is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, the oil and gas company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a profit margin which reflects incremental production added to the oilfield.

Tier 1 and tier 2 process safety events - Tier 1 events are losses of primary containment from a process of greatest consequence - causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp's operational HSSE reporting boundary. That boundary includes bp's own operated facilities and certain other locations or situations. Reported process safety events are investigated throughout the year and as a result there may be changes in previously reported events. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this represents a more up to date reflection of the safety environment.

Underlying effective tax rate (ETR) is a non-IFRS measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses and total taxation on adjusting items. Information on underlying RC profit or loss is provided below. Taxation on an underlying RC basis presented for the operating segments is calculated through an allocation of taxation on an underlying RC basis to each segment. bp believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp's operational performance on a comparable basis, period on period. Taxation on an underlying RC basis and underlying ETR are non-IFRS measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable IFRS forward-looking financial measure. These items include the taxation on inventory holding gains and losses and adjusting items, that are difficult to predict in advance in order to include in an IFRS estimate.

Underlying operating expenditure is a non-IFRS measure and a subset of production and manufacturing expenses plus distribution and administration expenses and excludes costs that are classified as adjusting items. It represents the majority of the remaining expenses in these line items but excludes certain costs that are variable, primarily with volumes (such as freight costs). Other variable costs are included in purchases in the income statement. Management believes that underlying operating expenditure is a performance measure that provides investors with useful information regarding the company's financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects. The nearest IFRS measures are production and manufacturing expenses and distribution and administration expenses. A reconciliation of production and manufacturing expenses plus distribution and administration expenses to underlying operating expenditure is provided on page 28.

Underlying production - 2026 underlying production, when compared with 2025, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract.

Underlying RC profit or loss / underlying RC profit or loss attributable to bp shareholders is a non-IFRS measure and is RC profit or loss* (as defined on page 34) after excluding net adjusting items and related taxation. See page 26 for additional information on the adjusting items that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the items and their financial impact.

Underlying RC profit or loss before interest and tax for the operating segments or customers & products businesses is calculated as RC profit or loss (as defined above) including profit or loss attributable to non-controlling interests before interest and tax for the operating segments and excluding net adjusting items for the respective operating segment or business.

bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp's operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp's operational performance on a comparable basis, period on period, by adjusting for the effects of these adjusting items. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments and businesses is RC profit or loss before interest and taxation. A reconciliation to IFRS information is provided on page 1 for the group and pages 7-13 for the segments.

Glossary (continued)

Underlying RC profit or loss per share / underlying RC profit or loss per ADS is a non-IFRS measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders, rather than profit or loss attributable to bp ordinary shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp's operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp ordinary shareholders.

upstream includes oil and natural gas field development and production within the gas & low carbon energy and oil production & operations segments.

upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity, excluding non-operated assets and bpx energy. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of America weather related downtime.

upstream unit production costs are calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp's share of equity-accounted entities.

Working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement.

Change in working capital adjusted for inventory holding gains/losses, fair value accounting effects relating to subsidiaries and other adjusting items is a non-IFRS measure. It is calculated by adjusting for inventory holding gains/losses reported in the period; fair value accounting effects relating to subsidiaries reported within adjusting items for the period; and other adjusting items relating to the non-cash movement of US emissions obligations carried as a provision that will be settled by allowances held as inventory. This represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been underlying replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities.

bp utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.

Trade marks

Trade marks of the bp group appear throughout this announcement. They include:

bp, Amoco, Aral, ampm, bp pulse, Castrol, PETRO, TA, and Thorntons

Cautionary statement

In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the 'PSLRA') and the general doctrine of cautionary statements, bp is providing the following cautionary statement:

The discussion in this announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as 'will', 'expects', 'is expected to', 'aims', 'should', 'may', 'objective', 'is likely to', 'intends', 'believes', 'anticipates', 'plans', 'we see', 'focus on' or similar expressions.

In particular, the following, among other statements, are all forward-looking in nature: plans, expectations and assumptions regarding oil and gas demand, supply, prices or volatility; expectations regarding production and volumes; expectations regarding turnaround and maintenance activity; plans and expectations regarding bp's balance sheet, financial performance, strategy, four primary and other financial and performance targets, results of operations, cost reduction, cash flows, shareholder returns, governance and organizational structure; plans and expectations regarding the amount and timing of dividends and dividend reinvestment programs; plans and expectations regarding bp's strategy and outlook update on 15 December 2026, including bp's longer-term plans, capital frame, performance metrics and targets, and plans to build a simpler, stronger and more valuable bp; plans and expectations regarding bp's upstream production, including the impact of conditions in the Middle East, bp's divestment of Culzean gas field and bp's reduced equity interest in Latin America; plans and expectations regarding the amount, effects, timing, quantum and nature of certain acquisitions, divestments and related payments and proceeds, including expectations regarding the Castrol business, the Austrian mobility & convenience business, Lightsource bp, the North Sea business, the Archaea business and other bp businesses and assets subject to disposal or divestment; plans and expectations regarding bp's partnerships and joint ventures as well as current and future projects, including BP Energy Company of Kirkuk Limited, Block TTDAA 14 (the Calypso gas project), agreements with the government of Venezuela relating to offshore gas development including Phase 2 of the Loran field, Block 5(b), the Browse project, bp's bid in the BBG-3 Gulf of America lease sale, the Skarv Satellite Project, the Tupinamba exploration block, the Conifer exploration prospect, the Absheron field and Channel Infrastructure; plans and expectations regarding bp's net debt, credit rating, hybrid capital, investment strategy, capital expenditures, capital frame, underlying effective tax rate, depreciation, depletion and amortization; plans and expectations regarding bp's customers business, including with respect to volumes, underlying operating expenditure, earnings growth, cash flows, midstream performance, fuels margins, the impact of base oil costs and conditions in the Middle East, structural cost reduction and the earnings impact of divestments; expectations regarding bp's products, including underlying performance, refining margins, maintenance activity, and refinery turnaround activity; expectations regarding bp's income taxes payable, including the impact of higher profits on instalment payments; expectations regarding bp's other businesses & corporate underlying annual charge; expectations regarding price assumptions used in accounting estimates; and plans and expectations regarding Gulf of America settlement payments, including bp's agreement to accelerate remaining payments to the State of Louisiana and bp's intention to prioritize excess cashflow to address other remaining settlement agreement liabilities in full.

By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp. Recent global developments have caused significant uncertainty and volatility in macroeconomic conditions and commodity markets. Each item of outlook and guidance set out in this announcement is based on bp's current expectations but actual outcomes and results may be impacted by these evolving macroeconomic and market conditions. Actual results or outcomes may differ materially from those expressed in such statements, depending on a variety of factors, including: the extent and duration of the impact of current market conditions including the volatility of oil prices, the effects of bp's plan to exit its shareholding in Rosneft and other investments in Russia, overall global economic and business conditions impacting bp's business and demand for bp's products as well as the specific factors identified in the discussions accompanying such forward-looking statements; changes in consumer preferences and societal expectations; the pace of development and adoption of alternative energy solutions; developments in policy, law, regulation, technology and markets, including societal and investor sentiment related to the issue of climate change; the receipt of relevant third party and/or regulatory approvals including ongoing approvals required for the continued developments of approved projects; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America and continued base oil and additive supply shortages; OPEC+ quota restrictions; PSA and TSC effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of America oil spill; the conditions and developments in the Middle East; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp's access to future credit resources; business disruption and crisis management; the impact on bp's reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; the possibility that international sanctions or other steps taken by governmental authorities or any other relevant persons may impact bp's ability to sell its interests in Rosneft, or the price for which bp could sell such interests; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and those factors discussed under "Risk factors" in bp's Annual Report and Form 20-F for fiscal year 2025 as filed with the US Securities and Exchange Commission.

Cautionary note to U.S. investors - This document contains references to non-proved reserves and production outlooks based on non-proved reserves that the SEC's rules prohibit us from including in our filings with the SEC. U.S. investors are urged to consider closely the disclosures in our Form 20-F, SEC File No. 1-06262. This form is available on our website at www.bp.com. You can also obtain this form from the SEC's website at www.sec.gov.

Contacts

	London	Houston

Press Office	Rita Brown	Paul Takahashi
	+44 (0) 7787 685821	+1 713 903 9729

Investor Relations	Craig Marshall	Graham Collins
bp.com/investors	+44 (0) 203 401 5592	+1 832 753 5116

BP p.l.c.'s LEI Code 213800LH1BZH3DI6G760

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