BP posts steady Q3 2025 with $7.8B OCF and dividend 8.320c

Rhea-AI Filing Summary

BP p.l.c. reported Q3 2025 results showing solid operations and cash generation. Underlying replacement cost (RC) profit was $2.2 billion, near last quarter’s level, while operating cash flow rose to $7.8 billion on a working capital release. Reported profit attributable to shareholders was $1.2 billion.

Upstream reliability was 96.8% and refining availability reached 96.6%, supporting stronger earnings in customers & products. Net debt ended the quarter at $26.1 billion, broadly flat quarter-on-quarter after redeeming $1.2 billion of hybrid bonds. Capital expenditure was $3.4 billion in the quarter and $10.4 billion year-to-date; full-year capex remains guided at around $14.5 billion.

BP announced a dividend of 8.320 cents per ordinary share and plans to execute a $0.75 billion share buyback before Q4 results. Management now expects 2025 divestment and other proceeds to be above $4 billion. Strategic updates included six major upstream project start-ups in 2025, FID on the Tiber-Guadalupe Gulf of America hub, and progress on portfolio simplification. A partial arbitration award favored BP in an LNG contract dispute; damages will be addressed in a future phase.

Insights

Energy sector analyst

Stable quarter: strong cash flow, steady leverage, active returns.

BP delivered Q3 underlying RC profit of $2.2B with operating cash flow of $7.8B. Segment detail shows downstream strength as refining availability hit 96.6%, while upstream reliability at 96.8% supported modest production gains quarter-on-quarter.

Leverage remained contained: net debt was $26.1B, essentially flat after redeeming $1.2B hybrid bonds. Capital discipline continues with capex at $3.4B in Q3 and full-year guidance around $14.5B. Shareholder returns combine an 8.320-cent dividend and a planned $0.75B buyback.

Key items to track include execution on >$4B of 2025 divestment and progress on the Tiber-Guadalupe hub FID. Subsequent filings may clarify the timing and magnitude of potential arbitration-related recoveries.

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

04 November, 2025

BP p.l.c.

(Translation of registrant's name into English)

1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual

reports under cover Form 20-F or Form 40-F.

Form 20-F |X| Form 40-F

--------------- ----------------

Indicate by check mark whether the registrant by furnishing the information

contained in this Form is also thereby furnishing the information to the

Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of

1934.

Yes No |X|

--------------- --------------

Exhibit 1.1 3Q25 SEA Part 1 of 1 dated 04 November 2025

Exhibit 1.1

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FOR IMMEDIATE RELEASE
London 4 November 2025
BP p.l.c. Group results
Third quarter and nine months 2025

“For a printer friendly version of this announcement please click on the link below to open a PDF version of the announcement”

http://www.rns-pdf.londonstockexchange.com/rns/0057G_1-2025-11-3.pdf

Strong operations and strategic progress

Financial summary		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit (loss) for the period attributable to bp shareholders		1,161	1,629	206		3,477	2,340
Inventory holding (gains) losses*, net of tax		62	407	906		351	362
Replacement cost (RC) profit (loss)*		1,223	2,036	1,112		3,828	2,702
Net (favourable) adverse impact of adjusting items*, net of tax		987	317	1,155		2,116	5,044
Underlying RC profit*		2,210	2,353	2,267		5,944	7,746
Operating cash flow*		7,786	6,271	6,761		16,891	19,870
Capital expenditure*		(3,381)	(3,361)	(4,542)		(10,365)	(12,511)
Divestment and other proceeds(a)		28	1,356	290		1,712	1,463
Net issue (repurchase) of shares		(750)	(1,063)	(2,001)		(3,660)	(5,502)
Net debt*(b)		26,054	26,043	24,268		26,054	24,268
Adjusted EBITDA*		9,981	9,972	9,654		28,654	29,599
Underlying operating expenditure*		5,487	5,457	5,590		16,248	16,542
Announced dividend per ordinary share (cents per share)		8.320	8.320	8.000		24.640	23.270
Underlying RC profit per ordinary share* (cents)		14.24	15.03	13.89		37.98	46.79
Underlying RC profit per ADS* (dollars)		0.85	0.90	0.83		2.28	2.81

Highlights

●

Good earnings and cash generation: 3Q25 operating cash flow $7.8bn; stronger underlying earnings across the operating segments supporting 3Q25 underlying RC profit $2.2bn.

●

Significant progress in upstream*: 3Q25 upstream plant reliability* 96.8% supporting underlying production* +3% quarter-on-quarter; six major projects* started up in 2025, FID taken on Tiber-Guadalupe in the Gulf of America; 12 exploration discoveries year-to-date.

●

Improved reliability and profitability in downstream*: 3Q25 refining availability* increased to 96.6%; around half of Customers & products' share of the group's 2027 structural cost reduction* target now delivered.

●

Continued progress on divestments; disciplined capital allocation: Now expect divestment and other proceeds received in 2025 to be above $4 billion. Full year capital expenditure guidance continues to be around $14.5bn with organic capital expenditure* remaining on track to be below $14bn; net debt broadly flat versus prior quarter despite redemption of $1.2bn hybrid bonds.

"We’ve delivered another quarter of good performance across the business with operations continuing to run well. All six of the major oil and gas projects planned for 2025 are online, including four ahead of schedule. We’ve sanctioned our seventh operated production hub in the Gulf of America and have had further exploration success. We delivered record 3Q underlying earnings in customers and refining captured a better margin environment. Meanwhile, we expect full year divestment proceeds to be higher - underpinned by around $5 billion of completed or announced disposal agreements.

We continue to make good progress to cut costs, strengthen our balance sheet and increase cash flow and returns. We are looking to accelerate delivery of our plans, including undertaking a thorough review of our portfolio to drive simplification and targeting further improvements in cost performance and efficiency. There is much more to do but we are moving at pace, and demonstrating that bp can and will do better for our investors."

Murray Auchincloss

Chief executive officer

(a)

Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. See page 3 for more information on other proceeds.

(b)

See Note 9 for more information.

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

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 31.

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	Highlights
	3Q25 underlying replacement cost (RC) profit* $2.2 billion
	●	Underlying RC profit for the quarter of $2.2 billion, compared with $2.4 billion for the previous quarter, reflects higher profitability in the operating segments offset by a higher underlying effective tax rate (ETR)* in the quarter of 39% which includes changes in the geographical mix of profits. Higher quarter-on-quarter underlying RC profit before interest and tax was driven by significantly lower level of refinery turnaround activity, stronger realized refining margins, and higher production, partly offset by a weak oil trading result, seasonal effects of environmental compliance costs, lower realizations and higher other businesses & corporate underlying charge.
	●	Reported profit for the quarter was $1.2 billion, compared with $1.6 billion for the second quarter 2025. The reported result for the third quarter is adjusted for inventory holding losses* of $0.1 billion (net of tax) and a net adverse impact of adjusting items* of $1.0 billion (net of tax) to derive the underlying RC profit. Adjusting items include net impairments and losses on sale of businesses and fixed assets of $0.8 billion (see page 25 for more information on adjusting items).
	Segment results
	●	Gas & low carbon energy: The RC profit before interest and tax for the third quarter 2025 was $1.1 billion, compared with $1.0 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.4 billion, the underlying RC profit before interest and tax* for the third quarter was $1.5 billion, compared with $1.5 billion in the second quarter 2025. The third quarter underlying result before interest and tax reflects a lower depreciation, depletion and amortization charge and higher production, partly offset by lower realizations. The gas marketing and trading result was average.
	●	Oil production & operations: The RC profit before interest and tax for the third quarter 2025 was $2.1 billion, compared with $1.9 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.2 billion, the underlying RC profit before interest and tax for the third quarter was $2.3 billion, compared with $2.3 billion in the second quarter 2025. The third quarter underlying result before interest and tax reflects higher production, primarily in bpx energy, partly offset by higher exploration write-offs.
	●	Customers & products: The RC profit before interest and tax for the third quarter 2025 was $1.6 billion, compared with $1.0 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 (underlying result) for the third quarter was $1.7 billion, compared with $1.5 billion in the second quarter 2025. The customers third quarter underlying result was higher by $0.1 billion, reflecting seasonally higher volumes, stronger integrated performance across fuels and midstream, and lower underlying operating expenditure*. The products third quarter underlying result was higher by $0.1 billion, reflecting stronger realized refining margins and a significantly lower level of turnaround activity, partly offset by seasonal effects of environmental compliance costs and the impact of unplanned Whiting outage due to exceptional weather conditions. The oil trading contribution was weak.
	Operating cash flow* $7.8 billion and net debt* $26.1 billion
	●	Operating cash flow of $7.8 billion was around $1.5 billion higher than the previous quarter, reflecting a $0.9 billion working capital* release (after adjusting inventory holding losses, fair value accounting effects and other adjusting items) this quarter compared to a $1.4 billion build in the previous quarter, partly offset by $0.9 billion higher income taxes paid. Net debt was broadly flat at $26.1 billion in the third quarter as higher operating cash flow was partly offset by the redemption of $1.2 billion perpetual hybrid bonds.
	Financial frame
	●	bp is committed to maintaining a strong balance sheet and maintaining 'A' grade credit range through the cycle. We have a target of $14-18 billion of net debt by the end of 2027(a).
	●	Our policy is to maintain a resilient dividend. Subject to board approval, we expect an increase in the dividend per ordinary share of at least 4% per year(b). For the third quarter, bp has announced a dividend per ordinary share of 8.320 cents.
	●	Share buybacks are a mechanism to return excess cash. When added to the resilient dividend, we expect total shareholder distributions of 30-40% of operating cash flow, over time. Related to the third quarter results, bp intends to execute a $0.75 billion share buyback prior to reporting the fourth quarter results. The $0.75 billion share buyback programme announced with the second quarter results was completed on 31 October 2025.
	●	bp will continue to invest with discipline, driven by value and focused on delivering returns. We continue to expect capital expenditure to be around $14.5 billion in 2025. The capital frame of around $13-15 billion for 2026 and 2027 remains unchanged.

(a)

Potential proceeds from any transactions related to the Castrol strategic review and announcement to bring a strategic partner into Lightsource bp will be allocated to reduce net debt.

(b)

Subject to board discretion each quarter taking into account factors including current forecasts, the cumulative level of and outlook for cash flow, share count reduction from buybacks and maintaining ‘A’ range credit metrics.

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

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Financial results

In addition to the highlights on page 2:

●

Profit attributable to bp shareholders in the third quarter and nine months was $1.2 billion and $3.5 billion respectively, compared with a profit of $0.2 billion and $2.3 billion in the same periods of 2024.

-

After adjusting profit attributable to bp shareholders for inventory holding losses* and net impact of adjusting items*, underlying replacement cost (RC) profit* for the third quarter and nine months was $2.2 billion and $5.9 billion respectively, compared with $2.3 billion and $7.7 billion for the same periods of 2024. The underlying RC profit for the third quarter compared with the same period in 2024 mainly reflects higher realized refining margins and lower realizations. The underlying RC profit for the nine months compared with the same period in 2024 mainly reflects lower realizations and a lower gas marketing and trading result, partly offset by stronger performance in customers & products.

-

Adjusting items in the third quarter and nine months had a net adverse pre-tax impact of $0.9 billion and $2.0 billion respectively, compared with a net adverse pre-tax impact of $1.6 billion and $5.9 billion in the same periods of 2024.

-

Adjusting items for the third quarter and nine months include a favourable pre-tax impact of fair value accounting effects*, relative to management's internal measure of performance, of $0.2 billion and $1.7 billion respectively, compared with a favourable pre-tax impact of $0.4 billion and an adverse pre-tax impact of $0.9 billion in the same periods of 2024. This is primarily due to a decline in the LNG forward price over the 2025 periods compared with an increase in the comparative periods of 2024. In addition there is no significant impact of the fair value accounting effects relating to the hybrid bonds in the third quarter 2025 compared with a favourable impact in the third quarter 2024 and a significantly higher favourable impact of these in the nine months 2025 compared with 2024.

-

Adjusting items for the third quarter and nine months of 2025 include an adverse pre-tax impact of asset impairments of $0.4 billion and $1.9 billion respectively, compared with an adverse pre-tax impact of $1.7 billion and $3.7 billion in the same periods of 2024.

●

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was 53% and 51% respectively, compared with 51% and 59% for the same periods in 2024. Excluding adjusting items, the underlying ETR* for the third quarter and nine months was 39% and 41%, compared with 42% and 40% for the same periods in 2024. The lower underlying ETR for the third quarter reflects changes in the geographical mix of profits. ETR on RC profit or loss and underlying ETR are non-IFRS measures.

●

Operating cash flow* for the third quarter and nine months was $7.8 billion and $16.9 billion respectively, compared with $6.8 billion and $19.9 billion for the same periods in 2024. The change in the operating cash flows reflects the lower tax paid and the lower underlying replacement cost profit before tax for both periods compared with 2024, and differing impact of working capital* movements in the nine months 2025 compared with 2024.

●

Capital expenditure* in the third quarter and nine months was $3.4 billion and $10.4 billion respectively, compared with $4.5 billion and $12.5 billion in the same periods of 2024 reflecting the lower capital frame in place for 2025.

●

Total divestment and other proceeds for the third quarter and nine months were $28.0 million and $1.7 billion respectively, compared with $0.3 billion and $1.5 billion for the same periods in 2024. 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). Other proceeds for the nine months 2024 were $0.5 billion from the sale of a 49% interest in a controlled affiliate holding certain midstream assets offshore US.

●

At the end of the third quarter, net debt* was $26.1 billion, compared with $26.0 billion at the end of the second quarter 2025 and $24.3 billion at the end of the third quarter 2024. The year on year increase largely reflects lower operating cash flow over the period and acquired net debt, partially offset by the issuance of perpetual hybrid bonds.

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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		2025	2025	2024		2025	2024
RC profit (loss) before interest and tax
gas & low carbon energy		1,097	1,047	1,007		3,502	1,728
oil production & operations		2,119	1,916	1,891		6,823	8,218
customers & products		1,610	972	23		2,685	878
other businesses & corporate		(277)	645	653		346	173
Consolidation adjustment – UPII*		(19)	30	65		24	24
RC profit before interest and tax		4,530	4,610	3,639		13,380	11,021
Finance costs and net finance expense relating to pensions and other post-employment benefits		(1,212)	(1,173)	(1,059)		(3,654)	(3,269)
Taxation on a RC basis		(1,747)	(1,101)	(1,304)		(4,955)	(4,541)
Non-controlling interests		(348)	(300)	(164)		(943)	(509)
RC profit attributable to bp shareholders*		1,223	2,036	1,112		3,828	2,702
Inventory holding gains (losses)*		(82)	(554)	(1,182)		(477)	(467)
Taxation (charge) credit on inventory holding gains and losses		20	147	276		126	105
Profit for the period attributable to bp shareholders		1,161	1,629	206		3,477	2,340

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

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Underlying RC profit (loss) before interest and tax
gas & low carbon energy		1,519	1,462	1,756		3,978	4,816
oil production & operations		2,299	2,262	2,794		7,456	9,013
customers & products		1,716	1,533	381		3,926	2,819
other businesses & corporate		(189)	(38)	231		(344)	(81)
Consolidation adjustment – UPII		(19)	30	65		24	24
Underlying RC profit before interest and tax		5,326	5,249	5,227		15,040	16,591
Finance costs on an underlying RC basis(a) and net finance expense relating to pensions and other post-employment benefits		(1,129)	(1,095)	(1,001)		(3,306)	(2,914)
Taxation on an underlying RC basis		(1,639)	(1,501)	(1,795)		(4,847)	(5,422)
Non-controlling interests		(348)	(300)	(164)		(943)	(509)
Underlying RC profit attributable to bp shareholders*		2,210	2,353	2,267		5,944	7,746

(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 25).

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 6-12 for the segments.

Operating Metrics

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
		2025	2025	2024		2025	2024
Tier 1 and tier 2 process safety events*		7	5	11		22	32
upstream* production(a) (mboe/d)		2,362	2,300	2,378		2,301	2,378
upstream unit production costs*(b) ($/boe)		6.19	6.81	6.40		6.44	6.25
bp-operated upstream plant reliability*		96.8%	96.8%	95.0%		96.3%	95.3%
bp-operated refining availability*(a)		96.6%	96.4%	95.6%		96.4%	94.1%

(a)

See Operational updates on pages 6, 8 and 10. Because of rounding, upstream production may not agree exactly with the sum of gas & low carbon energy and oil production & operations.

(b)

The increase in the nine months 2025, compared with the nine months 2024 mainly reflects portfolio mix.

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Outlook & Guidance

4Q 2025 guidance

●

Looking ahead, bp expects fourth quarter 2025 reported upstream* production to be broadly flat compared with the third quarter 2025. Within this, bp expects reported production from oil production & operations to be slightly higher and production from gas & low carbon energy to be lower.

●

In its customers business, bp expects seasonally lower volumes compared to the third quarter and fuels margins to remain sensitive to movements in the cost of supply.

●

In products, bp expects, compared to the third quarter, similar level of refinery turnaround activity.

2025 guidance

In addition to the guidance on page 2:

●

bp now expects reported upstream* production to be slightly lower and underlying upstream production* to be broadly flat compared with 2024. Within this, bp expects underlying production from oil production & operations to be higher and production from gas & low carbon energy to be lower.

●

In its customers business, bp continues to expect growth in its customers businesses including a full year contribution from bp bioenergy. Earnings growth is expected to be supported by structural cost reduction*. bp continues to expect fuels margins to remain sensitive to the cost of supply.

●

In products, bp continues to expect stronger underlying performance underpinned by the absence of the plant-wide power outage at Whiting refinery, and improvement plans across the portfolio. bp continues to expect similar levels of refinery turnaround activity, with phasing of turnaround activity in 2025 heavily weighted towards the first half, with the highest impact in the second quarter.

●

bp now expects other businesses & corporate underlying annual charge to be around $0.5-0.75 billion for 2025, subject to foreign exchange impacts. The charge may vary from quarter to quarter.

●

bp continues to expect the depreciation, depletion and amortization to be slightly higher compared with 2024.

●

bp continues to expect the underlying ETR* for 2025 to be around 40% but it is sensitive to a range of factors, including the volatility of the price environment and its impact on the geographical mix of the group’s profits and losses.

●

bp now expects divestment and other proceeds to be above $4 billion in 2025.

●

bp continues to expect Gulf of America settlement payments for the year to be around $1.2 billion pre-tax including $1.1 billion pre-tax paid during the second quarter.

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

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gas & low carbon energy*

Financial results

●

The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,097 million and $3,502 million respectively, compared with $1,007 million and $1,728 million for the same periods in 2024. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $422 million and $476 million respectively, compared with an adverse impact of net adjusting items of $749 million and $3,088 million for the same periods in 2024. Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are a favourable impact of $131 million and $817 million for the third quarter and nine months in 2025 and an adverse impact of $275 million and $1,173 million for the same periods in 2024. See page 25 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 $1,519 million and $3,978 million respectively, compared with $1,756 million and $4,816 million for the same periods in 2024.

●

The underlying RC profit before interest and tax for the third quarter, compared with the same period in 2024, reflects lower production and lower realizations. The gas marketing and trading result was average.

●

The underlying RC profit for the nine months, compared with the same period in 2024, reflects lower production, a lower gas marketing and trading result, and a higher depreciation, depletion and amortization charge, partly offset by lower exploration write-offs and the absence of the foreign exchange loss in Egypt in the first quarter of 2024.

Operational update

●

Reported production for the quarter was 806mboe/d, 9.5% lower than the same period in 2024, reflecting the divestments in Egypt and Trinidad in the fourth quarter of 2024. Underlying production* was 0.2% lower due to base decline offset by major project* start-ups in the year.

●

Reported production for the nine months was 784mboe/d, 13.0% lower than the same period in 2024, reflecting the divestments in Egypt and Trinidad in the fourth quarter of 2024. Underlying production was 2.8% lower, mainly due to base decline partly offset by major project start-ups in the year.

Strategic progress

gas

●

In August, a consortium of bp (16.09%), its Tangguh partners (23.91%), operator EnQuest (40%), and Agra (20%) secured the right to explore the Gaea and Gaea II cover onshore and offshore gas blocks near our Tangguh LNG facility with the signing of government-backed contracts.

●

In September bp announced the signing of a memorandum of understanding (MoU) to evaluate opportunities for a five-well programme at water depths ranging from 300 to 1,500 metres in the Mediterranean Sea, offshore Egypt. Drilling operations are expected to start in 2026, with possible tie-back options following evaluation of the drilling campaign and resource potential.

●

In September BOTAS and bp signed a three year liquefied natural gas (LNG) purchase agreement to supply 1.6 billion cubic meters (bcm) of LNG annually into Türkiye, totalling 4.8bcm over the contract period.

low carbon energy

●

In August JERA Nex bp and EnBW were granted development consent for the 1.5GW Morgan offshore wind project in the Irish Sea from the UK Secretary of State for Energy Security and Net Zero. Morgan is one of three proposed offshore wind projects in the UK, alongside Mona and Morven. Morgan’s sister project in the Irish Sea, Mona, received development consent in July. Following deal completion, bp's interests in the projects moved to JERA Nex bp – bp's 50:50 offshore wind joint venture with JERA.

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gas & low carbon energy (continued)

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit before interest and tax		1,097	1,047	1,007		3,502	1,728
Inventory holding (gains) losses*		—	—	—		—	—
RC profit before interest and tax		1,097	1,047	1,007		3,502	1,728
Net (favourable) adverse impact of adjusting items		422	415	749		476	3,088
Underlying RC profit before interest and tax		1,519	1,462	1,756		3,978	4,816
Taxation on an underlying RC basis		(529)	(509)	(545)		(1,509)	(1,432)
Underlying RC profit before interest		990	953	1,211		2,469	3,384

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,223	1,407	1,180		3,796	3,682
Exploration write-offs
Exploration write-offs		29	1	1		30	232
Adjusted EBITDA*
Total adjusted EBITDA		2,771	2,870	2,937		7,804	8,730
Capital expenditure*
gas(a)		727	688	1,248		2,189	3,018
low carbon energy		101	102	908		332	1,703
Total capital expenditure(a)		828	790	2,156		2,521	4,721

(a)

Comparative periods in 2024 have been restated to reflect the move of our Archaea business from the customers & products segment to the gas & low carbon energy segment.

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
		2025	2025	2024		2025	2024
Production (net of royalties)(b)
Liquids* (mb/d)		87	85	92		85	97
Natural gas (mmcf/d)		4,167	4,043	4,627		4,054	4,661
Total hydrocarbons* (mboe/d)		806	782	890		784	901
Average realizations*(c)
Liquids ($/bbl)		64.57	64.15	74.80		66.31	77.23
Natural gas ($/mcf)		6.41	6.50	5.80		6.71	5.57
Total hydrocarbons ($/boe)		40.30	40.84	37.91		42.06	37.13

(b)

Includes bp’s share of production of equity-accounted entities in the gas & low carbon energy segment.

(c)

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

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oil production & operations

Financial results

●

The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $2,119 million and $6,823 million respectively, compared with $1,891 million and $8,218 million for the same periods in 2024. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $180 million and $633 million respectively, compared with an adverse impact of net adjusting items of $903 million and $795 million for the same periods in 2024. See page 25 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 $2,299 million and $7,456 million respectively, compared with $2,794 million and $9,013 million for the same periods in 2024.

●

The underlying RC profit before interest and tax for the third quarter and nine months, compared with the same periods in 2024, primarily reflects lower realizations and a higher depreciation, depletion and amortization charge, partly offset by higher production and lower exploration write-offs.

Operational update

●

Reported production for the quarter was 1,556mboe/d, 4.6% higher than the same period in 2024. Underlying production* for the quarter was 3.5% higher, mainly reflecting higher production in bpx energy.

●

Reported production for the nine months was 1,517mboe/d, 2.7% higher than the same period in 2024. Underlying production was 1.9% higher, mainly reflecting higher production in bpx energy.

Strategic progress

●

Following the announcement in August regarding an exploration discovery in the Bumerangue block, offshore Brazil, initial laboratory and pressure gradient analysis has confirmed the presence of a ~1,000 metre gross hydrocarbon column including a ~100 metre gross oil column and a ~900 metre gross liquid rich gas-condensate column. Given the presence of liquids across the entire hydrocarbon column, the high-quality rock properties observed and our extensive technology and deepwater developments experience, bp believes that the carbon dioxide in the reservoir can be managed. bp is continuing laboratory testing and other analysis in addition to planning appraisal activities.

●

In August Aker BP announced successful completion of the Omega Alfa exploration campaign in the Norwegian North Sea, resulting in a significant oil discovery that adds substantial new resources to the Yggdrasil area. The recoverable volume is estimated at 96–134 million barrels of oil equivalent. The drilling campaign included the three longest well branches ever drilled on the Norwegian continental shelf. First oil from Yggdrasil is expected in 2027.

●

In September bp announced it has reached a final investment decision (FID) on the Tiber-Guadalupe project in the Gulf of America. The 100% bp-owned Tiber-Guadalupe will be bp’s seventh operated oil and gas production hub in the Gulf of America, featuring a new floating production platform with the capacity to produce 80,000 barrels of crude oil per day. The project includes six wells in the Tiber field and a two-well tieback from the Guadalupe field. Production is expected to start in 2030.

●

In October Rhino Resources, operator of the Petroleum Exploration Licence 85 in the Orange Basin offshore Namibia, partnering with Azule Energy (bp's 50% joint venture), announced a discovery at the Volans 1-X well. The well found 26 metres of net pay in rich-gas condensate bearing reservoirs with excellent quality petrophysical properties and a high condensate to gas ratio. This discovery builds on the announcement in April of a discovery in the Capricornus 1-X exploration well in the same licence block.

●

In October bp's contract with Iraq’s North Oil Company and North Gas Company became effective, after agreeing an initial baseline production rate of 328,000 barrels per day. Under the contract bp will rehabilitate and expand production at the Baba and Avana domes of the Kirkuk field, as well as the Jambour, Bai Hassan, and Khabbaz fields.

●

In October bp announced it had safely started up production from the Murlach field in the UK North Sea. The two-well subsea tieback is expected to add a peak net production of around 15,000 barrels of oil equivalent per day. Murlach is bp’s sixth major project* start-up in 2025, in line with its strategy to grow the upstream business.

●

In October bp agreed to sell its 32% non-operated working interest in the Culzean development in the central North Sea to Serica Energy. The sale is subject to a pre-emption period which runs for 30 days, with each of the Culzean field partners (TotalEnergies, 49.99%, and NEO NEXT, 18.01%) having the option to acquire bp’s stake on the same terms as those agreed by Serica.

●

In November bp announced that it had reached agreement to divest non-controlling interests in Permian and Eagle Ford midstream assets to investor Sixth Street for $1.5 billion. The transaction is structured in two phases: approximately $1 billion paid upon signing with the balance expected by the end of the year, subject to regulatory approvals.

Top of page 9

oil production & operations (continued)

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit before interest and tax		2,116	1,914	1,889		6,825	8,216
Inventory holding (gains) losses*		3	2	2		(2)	2
RC profit before interest and tax		2,119	1,916	1,891		6,823	8,218
Net (favourable) adverse impact of adjusting items		180	346	903		633	795
Underlying RC profit before interest and tax		2,299	2,262	2,794		7,456	9,013
Taxation on an underlying RC basis		(1,054)	(1,062)	(1,259)		(3,491)	(3,939)
Underlying RC profit before interest		1,245	1,200	1,535		3,965	5,074

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,961	1,933	1,708		5,681	5,063
Exploration write-offs
Exploration write-offs		154	81	309		288	411
Adjusted EBITDA*
Total adjusted EBITDA		4,414	4,276	4,811		13,425	14,487
Capital expenditure*
Total capital expenditure		1,722	1,706	1,410		5,124	4,720

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
		2025	2025	2024		2025	2024
Production (net of royalties)(a)
Liquids* (mb/d)		1,121	1,115	1,084		1,107	1,075
Natural gas (mmcf/d)		2,525	2,338	2,348		2,374	2,335
Total hydrocarbons* (mboe/d)		1,556	1,518	1,488		1,517	1,477
Average realizations*(b)
Liquids ($/bbl)		59.58	59.74	70.22		62.17	71.26
Natural gas ($/mcf)		3.32	3.66	2.25		3.87	2.32
Total hydrocarbons ($/boe)		47.89	49.03	53.65		50.99	54.51

(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.

Top of page 10

customers & products

Financial results

●

The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,610 million and $2,685 million respectively, compared with $23 million and $878 million for the same periods in 2024. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $106 million and $1,241 million respectively, compared with an adverse impact of net adjusting items of $358 million and $1,941 million for the same periods in 2024. See page 25 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 $1,716 million and $3,926 million respectively, compared with $381 million and $2,819 million for the same periods in 2024.

●

The customers & products underlying result for the third quarter was significantly higher than the same period in 2024, primarily reflecting higher realized refining margins. The result for the nine months was significantly higher than the same period in 2024, reflecting stronger performance both in customers and products.

●

customers – the customers underlying result for the third quarter and nine months was higher compared with the same periods in 2024. The underlying result benefited from stronger integrated performance across fuels and midstream, lower underlying operating expenditure* supported by structural cost reductions*, and reflects a more than 20% increase in Castrol's earnings.

●

products – the products underlying result for the third quarter was significantly higher compared with the same period in 2024. In refining, the third quarter benefited from significantly higher realized margins and lower turnaround activity, as well as lower underlying operating expenditure. The refining result for the nine months was higher compared with the same period in 2024, primarily driven by the absence of the first quarter 2024 plant-wide power outage at the Whiting refinery and lower underlying operating expenditure, partly offset by lower realized margins and higher turnaround activity. The oil trading contribution for the third quarter and nine months was higher compared with the same periods in 2024.

Operational update

●

bp-operated refining availability* for the third quarter and nine months was 96.6% and 96.4%, compared with 95.6% and 94.1% for the same periods in 2024. The nine months was higher reflecting strong performance and notably the absence of the Whiting refinery power outage.

Strategic progress

●

Consistent with our strategy to focus downstream and prioritize high-return investments, bp took the decision to stop further work on development of a standalone biofuels production (HEFA) facility at our Rotterdam refinery in the Netherlands.

●

Castrol has announced a strategic investment in Electronic Cooling Solutions to expand into full-service thermal management for next-generation AI and high-performance computing systems.

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit (loss) before interest and tax		1,531	420	(1,157)		2,206	413
Inventory holding (gains) losses*		79	552	1,180		479	465
RC profit (loss) before interest and tax		1,610	972	23		2,685	878
Net (favourable) adverse impact of adjusting items		106	561	358		1,241	1,941
Underlying RC profit before interest and tax		1,716	1,533	381		3,926	2,819
Of which:(a)
customers – convenience & mobility		1,167	1,056	897		2,887	2,057
Castrol – included in customers		261	245	216		744	611
products – refining & trading		549	477	(516)		1,039	762
Taxation on an underlying RC basis		(360)	(251)	(67)		(687)	(525)
Underlying RC profit before interest		1,356	1,282	314		3,239	2,294

(a)

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

Top of page 11

customers & products (continued)

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Adjusted EBITDA*(b)
customers – convenience & mobility		1,786	1,698	1,410		4,715	3,545
Castrol – included in customers		309	295	261		888	740
products – refining & trading		975	895	(66)		2,301	2,120
		2,761	2,593	1,344		7,016	5,665
Depreciation, depletion and amortization
Total depreciation, depletion and amortization		1,045	1,060	963		3,090	2,846
Capital expenditure*
customers – convenience & mobility		386	387	455		1,358	1,518
Castrol – included in customers		37	36	50		110	167
products – refining & trading(c)		384	410	416		1,152	1,256
Total capital expenditure(c)		770	797	871		2,510	2,774

(b)

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

(c)

Comparative periods in 2024 have been restated to reflect the move of our Archaea business from the customers & products segment to the gas & low carbon energy segment.

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
Marketing sales of refined products (mb/d)		2025	2025	2024		2025	2024
US		1,273	1,248	1,240		1,240	1,197
Europe		1,046	1,006	1,130		1,000	1,049
Rest of World		456	466	457		463	463
		2,775	2,720	2,827		2,703	2,709
Trading/supply sales of refined products		557	478	354		492	364
Total sales volume of refined products		3,332	3,198	3,181		3,195	3,073

bp average refining indicator margin* (RIM) ($/bbl) 15.8 11.9 8.7 12.0 11.9

Refinery throughputs (mb/d)
US		683	573	671		643	622
Europe		833	715	769		790	774
Total refinery throughputs		1,516	1,288	1,440		1,433	1,396
bp-operated refining availability* (%)		96.6	96.4	95.6		96.4	94.1

Top of page 12

other businesses & corporate

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

Financial results

●

The replacement cost (RC) loss or profit before interest and tax for the third quarter and nine months was a loss of $277 million and a profit of $346 million respectively, compared with a profit of $653 million and $173 million for the same periods in 2024. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $88 million and a favourable impact of net adjusting items of $690 million respectively, compared with a favourable impact of net adjusting items of $422 million and $254 million for the same periods in 2024. Adjusting items include adverse impacts of fair value accounting effects* of $13 million for the third quarter and favourable impacts of fair value accounting effects of $1,096 million for the nine months in 2025, and a favourable impact of $494 million and $272 million for the same periods in 2024. See page 25 for more information on adjusting items.

●

After adjusting RC loss or profit before interest and tax for adjusting items, the underlying RC loss before interest and tax* for the third quarter and nine months was $189 million and $344 million respectively, compared with a profit of $231 million and a loss of $81 million for the same periods in 2024.

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit (loss) before interest and tax		(277)	645	653		346	173
Inventory holding (gains) losses*		—	—	—		—	—
RC profit (loss) before interest and tax		(277)	645	653		346	173
Net (favourable) adverse impact of adjusting items(a)		88	(683)	(422)		(690)	(254)
Underlying RC profit (loss) before interest and tax		(189)	(38)	231		(344)	(81)
Taxation on an underlying RC basis		106	109	(64)		248	38
Underlying RC profit (loss) before interest		(83)	71	167		(96)	(43)

(a)

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

Top of page 13

Financial statements

Group income statement

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Sales and other operating revenues (Note 5)		48,420	46,627	47,254		141,952	143,433
Earnings from joint ventures – after interest and tax		176	241	406		744	834
Earnings from associates – after interest and tax		275	155	280		679	844
Interest and other income		397	375	438		1,157	1,233
Gains on sale of businesses and fixed assets		(18)	279	(48)		275	197
Total revenues and other income		49,250	47,677	48,330		144,807	146,541
Purchases		28,031	26,875	30,139		82,626	86,677
Production and manufacturing expenses		6,620	6,153	5,004		18,887	18,543
Production and similar taxes		431	414	469		1,292	1,397
Depreciation, depletion and amortization (Note 6)		4,472	4,641	4,117		13,296	12,365
Net impairment and losses on sale of businesses and fixed assets (Note 3)		753	1,157	1,842		2,413	3,888
Exploration expense		224	139	372		466	798
Distribution and administration expenses		4,271	4,242	3,930		12,924	12,319
Profit (loss) before interest and taxation		4,448	4,056	2,457		12,903	10,554
Finance costs		1,267	1,229	1,101		3,817	3,392
Net finance (income) expense relating to pensions and other post-employment benefits		(55)	(56)	(42)		(163)	(123)
Profit (loss) before taxation		3,236	2,883	1,398		9,249	7,285
Taxation		1,727	954	1,028		4,829	4,436
Profit (loss) for the period		1,509	1,929	370		4,420	2,849
Attributable to
bp shareholders		1,161	1,629	206		3,477	2,340
Non-controlling interests		348	300	164		943	509
		1,509	1,929	370		4,420	2,849
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic		7.48	10.41	1.26		22.22	14.19
Diluted		7.38	10.27	1.23		21.77	13.83
Per ADS (dollars)
Basic		0.45	0.62	0.08		1.33	0.85
Diluted		0.44	0.62	0.07		1.31	0.83

Top of page 14

Condensed group statement of comprehensive income

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit (loss) for the period		1,509	1,929	370		4,420	2,849
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences(a)		(276)	1,323	838		1,866	248
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets		22	—	—		22	—
Cash flow hedges and costs of hedging		134	235	(111)		184	(326)
Share of items relating to equity-accounted entities, net of tax		(5)	3	(41)		(1)	(39)
Income tax relating to items that may be reclassified		(3)	(57)	91		(18)	127
		(128)	1,504	777		2,053	10
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset		(447)	(214)	(51)		(330)	(357)
Remeasurements of equity investments		—	2	(8)		1	(38)
Cash flow hedges that will subsequently be transferred to the balance sheet		(1)	2	10		3	7
Income tax relating to items that will not be reclassified(b)		126	52	12		83	745
		(322)	(158)	(37)		(243)	357
Other comprehensive income		(450)	1,346	740		1,810	367
Total comprehensive income		1,059	3,275	1,110		6,230	3,216
Attributable to
bp shareholders		726	2,883	922		5,165	2,705
Non-controlling interests		333	392	188		1,065	511
		1,059	3,275	1,110		6,230	3,216

(a)

Second quarter and nine months 2025 are principally affected by movements in the Pound Sterling against the US dollar.

(b)

Nine months 2024 includes a $658-million credit in respect of the reduction in the deferred tax liability on defined benefit pension plan surpluses following the reduction in the rate of the authorized surplus payments tax charge in the UK from 35% to 25%.

Top of page 15

Condensed group statement of changes in equity

		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(a)		—	500	—	500
Redemption of perpetual hybrid bonds, net of tax(b)		—	(1,200)	—	(1,200)
Payments on perpetual hybrid bonds		(9)	(618)	—	(627)
Transactions involving non-controlling interests, net of tax(c)		4	—	968	972
At 30 September 2025		58,244	15,938	3,463	77,645
		bp shareholders’	Non-controlling interests		Total
$ million		equity	Hybrid bonds	Other interest	equity
At 1 January 2024		70,283	13,566	1,644	85,493
Total comprehensive income		2,705	470	41	3,216
Dividends		(3,739)	—	(282)	(4,021)
Cash flow hedges transferred to the balance sheet, net of tax		(8)	—	—	(8)
Repurchase of ordinary share capital		(5,554)	—	—	(5,554)
Share-based payments, net of tax		903	—	—	903
Issue of perpetual hybrid bonds		(4)	1,300	—	1,296
Redemption of perpetual hybrid bonds, net of tax		9	(1,300)	—	(1,291)
Payments on perpetual hybrid bonds		—	(520)	—	(520)
Transactions involving non-controlling interests, net of tax		231	—	201	432
At 30 September 2024		64,826	13,516	1,604	79,946

(a)

During the nine months 2025 a group subsidiary issued perpetual subordinated hybrid securities of $0.5 billion, the proceeds of which were specifically earmarked to fund BP Alternative Energy Investments Ltd including the funding of Lightsource bp. This transaction resulted in a reduction of net debt and gearing.

(b)

In the third quarter 2025, BP Capital Markets p.l.c. exercised its option to redeem $1.2 billion of hybrid bonds.

(c)

In the nine months 2025, a group subsidiary that holds a 12% stake in the Trans-Anatolian Natural Gas Pipeline (TANAP), issued $1.0 billion of equity instruments with preferred distributions. The group retains control over the ability to defer these distributions which are not guaranteed, and investors cannot redeem their shares except under specific conditions that are within the group's control.

Top of page 16

Group balance sheet

		30 September	31 December
$ million		2025	2024
Non-current assets
Property, plant and equipment		100,363	100,238
Goodwill		15,114	14,888
Intangible assets		9,007	9,646
Investments in joint ventures		12,392	12,291
Investments in associates		9,910	7,741
Other investments		1,166	1,292
Fixed assets		147,952	146,096
Loans		2,172	1,961
Trade and other receivables		2,372	1,815
Derivative financial instruments		18,207	16,114
Prepayments		545	548
Deferred tax assets		5,702	5,403
Defined benefit pension plan surpluses		7,651	7,457
		184,601	179,394
Current assets
Loans		444	223
Inventories		24,154	23,232
Trade and other receivables		26,169	27,127
Derivative financial instruments		4,525	5,112
Prepayments		1,714	2,594
Current tax receivable		973	1,096
Other investments		139	165
Cash and cash equivalents		34,909	39,204
		93,027	98,753
Assets classified as held for sale (Note 2)		2,831	4,081
		95,858	102,834
Total assets		280,459	282,228
Current liabilities
Trade and other payables		54,625	58,411
Derivative financial instruments		3,694	4,347
Accruals		5,290	6,071
Lease liabilities		2,761	2,660
Finance debt		6,091	4,474
Current tax payable		1,562	1,573
Provisions		5,003	3,600
		79,026	81,136
Liabilities directly associated with assets classified as held for sale (Note 2)		1,334	1,105
		80,360	82,241
Non-current liabilities
Other payables		8,086	9,409
Derivative financial instruments		17,415	18,532
Accruals		1,693	1,326
Lease liabilities		11,868	9,340
Finance debt		54,097	55,073
Deferred tax liabilities		8,432	8,428
Provisions		15,810	14,688
Defined benefit pension plan and other post-employment benefit plan deficits		5,053	4,873
		122,454	121,669
Total liabilities		202,814	203,910
Net assets		77,645	78,318
Equity
bp shareholders’ equity		58,244	59,246
Non-controlling interests		19,401	19,072
Total equity		77,645	78,318

Top of page 17

Condensed group cash flow statement

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Operating activities
Profit (loss) before taxation		3,236	2,883	1,398		9,249	7,285
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		4,655	4,723	4,427		13,614	13,008
Net impairment and (gain) loss on sale of businesses and fixed assets		771	878	1,890		2,138	3,691
Earnings from equity-accounted entities, less dividends received		192	40	(196)		32	(273)
Net charge for interest and other finance expense, less net interest paid		470	126	324		743	1,040
Share-based payments		264	215	278		880	946
Net operating charge for pensions and other post-employment benefits, less contributions and benefit payments for unfunded plans		(96)	(36)	(52)		(143)	(118)
Net charge for provisions, less payments		(60)	666	(48)		1,710	33
Movements in inventories and other current and non-current assets and liabilities		494	(2,030)	1,798		(6,605)	1,223
Income taxes paid		(2,140)	(1,194)	(3,058)		(4,727)	(6,965)
Net cash provided by operating activities		7,786	6,271	6,761		16,891	19,870
Investing activities
Expenditure on property, plant and equipment, intangible and other assets		(3,171)	(3,236)	(4,223)		(9,758)	(11,404)
Acquisitions, net of cash acquired		(52)	(39)	(218)		(293)	(440)
Investment in joint ventures		(128)	(59)	(76)		(245)	(524)
Investment in associates		(30)	(27)	(25)		(69)	(143)
Total cash capital expenditure		(3,381)	(3,361)	(4,542)		(10,365)	(12,511)
Proceeds from disposal of fixed assets		30	322	16		644	117
Proceeds from disposal of businesses, net of cash disposed		(2)	76	274		110	840
Proceeds from loan repayments		48	31	19		110	59
Cash provided from investing activities		76	429	309		864	1,016
Net cash used in investing activities		(3,305)	(2,932)	(4,233)		(9,501)	(11,495)
Financing activities
Net issue (repurchase) of shares (Note 7)		(750)	(1,063)	(2,001)		(3,660)	(5,502)
Lease liability payments		(816)	(784)	(703)		(2,327)	(2,076)
Proceeds from long-term financing		1,028	1,155	2,401		2,237	7,396
Repayments of long-term financing		(1,250)	(848)	(956)		(3,464)	(2,253)
Net increase (decrease) in short-term debt		104	39	(73)		18	(8)
Issue of perpetual hybrid bonds(a)		—	—	—		500	1,296
Redemption of perpetual hybrid bonds(a)		(1,200)	—	—		(1,200)	(1,288)
Payments relating to perpetual hybrid bonds		(284)	(332)	(271)		(888)	(798)
Payments relating to transactions involving non-controlling interests (Other interest)		(2)	—	—		(2)	—
Receipts relating to transactions involving non-controlling interests (Other interest)		8	965	(7)		973	517
Dividends paid - bp shareholders		(1,288)	(1,238)	(1,297)		(3,783)	(3,720)
- non-controlling interests		(155)	(127)	(96)		(356)	(282)
Net cash provided by (used in) financing activities		(4,605)	(2,233)	(3,003)		(11,952)	(6,718)
Currency translation differences relating to cash and cash equivalents		(51)	193	179		248	(92)
Increase (decrease) in cash and cash equivalents		(175)	1,299	(296)		(4,314)	1,565
Cash and cash equivalents at beginning of period		35,130	33,831	34,891		39,269	33,030
Cash and cash equivalents at end of period(b)		34,955	35,130	34,595		34,955	34,595

(a)

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

(b)

Third quarter and nine months 2025 includes $46 million (second quarter 2025 $63 million) of cash and cash equivalents classified as assets held for sale in the group balance sheet.

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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 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 2024 included in bp Annual Report and Form 20-F 2024.

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 2025 which are the same as those used in preparing bp Annual Report and Form 20-F 2024.

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

UK Energy Profits Levy

In October 2024, the UK government announced changes (effective from 1 November 2024) to the Energy Profits Levy including a 3% increase in the rate taking the headline rate of tax on North Sea profits to 78%, an extension to the period of application of the Levy to 31 March 2030 and the removal of the Levy’s main investment allowance. The changes to the rate and to the investment allowance were substantively enacted in 2024. The extension of the Levy to 31 March 2030 was substantively enacted in the first quarter 2025, resulting in a non-cash deferred charge of $539 million.

Germany tax legislation

On 11 July 2025, the German federal government substantively enacted a number of changes to its tax legislation, including a 5% reduction in the corporate income tax rate by 2032. The reduction in the tax rate will be phased in by means of a 1% reduction each year between 2028 and 2032 and has resulted in a non-cash deferred tax charge of $233 million in the third quarter 2025.

Change in segmentation

During the first quarter of 2025, our Archaea business has moved from the customers & products segment to the gas & low carbon energy segment. The change in segmentation is consistent with a change in the way that resources are allocated, and performance is assessed by the chief operating decision maker, who for bp is the group chief executive.

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

Significant accounting judgements and estimates

bp's significant accounting judgements and estimates were disclosed in bp Annual Report and Form 20-F 2024. These have been subsequently considered at the end of this quarter to determine if any changes were required to those judgements and estimates. No significant changes were identified.

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Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2025 is $2,831 million, with associated liabilities of $1,334 million.

Gas & low carbon energy

On 18 July 2025, bp announced that it plans to sell its US onshore wind energy business, bp Wind Energy to LS Power. bp Wind Energy has interests in ten operating onshore wind energy assets across seven US states. The transaction is expected to complete by the end of 2025, subject to regulatory approval. The carrying amount of assets classified as held for sale at 30 September 2025 is $570 million, with associated liabilities of $39 million.

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. Completion of the sale of a significant majority of these assets is expected to complete by the end of 2025, whilst sale of the remaining assets is now expected to complete within the first half of 2026. The carrying amount of assets classified as held for sale at 30 September 2025 is $1,868 million, with associated liabilities of $1,200 million.

On 1 August 2025, bp and JERA Co., Inc. completed formation of a new offshore wind joint venture - JERA Nex bp. bp contributed its development projects in the UK, Germany and US into the joint venture. The related assets and liabilities of those projects, previously classified as held for sale, were derecognised on that date.

Customers & products

On 9 July 2025, bp announced the sale of its Netherlands mobility & convenience and bp pulse businesses to Catom BV. The transaction includes bp’s Dutch retail sites, EV charging hubs and the associated fleet business. Completion of the disposal is expected by the end of 2025 subject to regulatory approvals. The carrying amount of assets classified as held for sale at 30 September 2025 is $393 million, with associated liabilities of $95 million.

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 $753 million and $2,413 million respectively, compared with net charges of $1,842 million and $3,888 million for the same periods in 2024 and include net impairment charges for the third quarter and nine months of $370 million and $1,931 million respectively, compared with net impairment charges of $1,730 million and $3,675 million for the same periods in 2024. 

Gas & low carbon energy

Third quarter and nine months 2025 impairments includes a net impairment charge of $135 million and $881 million respectively, compared with net charges of $734 million and $1,859 million for the same periods in 2024 in the gas & low carbon energy segment.

Oil production & operations

Third quarter and nine months 2025 impairments includes a reversal of $7 million and a net impairment charge of $329 million respectively, compared with net charges of $767 million and $900 million for the same periods in 2024 in the oil production & operations segment.

Customers & products

Third quarter and nine months 2025 impairments includes a net impairment charge of $242 million and $719 million respectively, compared with net charges of $223 million and $914 million for the same periods in 2024 in the customers & products segment.

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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		2025	2025	2024		2025	2024
gas & low carbon energy		1,097	1,047	1,007		3,502	1,728
oil production & operations		2,119	1,916	1,891		6,823	8,218
customers & products		1,610	972	23		2,685	878
other businesses & corporate		(277)	645	653		346	173
		4,549	4,580	3,574		13,356	10,997
Consolidation adjustment – UPII*		(19)	30	65		24	24
RC profit (loss) before interest and tax		4,530	4,610	3,639		13,380	11,021
Inventory holding gains (losses)*
gas & low carbon energy		—	—	—		—	—
oil production & operations		(3)	(2)	(2)		2	(2)
customers & products		(79)	(552)	(1,180)		(479)	(465)
Profit (loss) before interest and tax		4,448	4,056	2,457		12,903	10,554
Finance costs		1,267	1,229	1,101		3,817	3,392
Net finance expense/(income) relating to pensions and other post-employment benefits		(55)	(56)	(42)		(163)	(123)
Profit (loss) before taxation		3,236	2,883	1,398		9,249	7,285
RC profit (loss) before interest and tax*
US		632	1,417	1,122		3,582	4,277
Non-US		3,898	3,193	2,517		9,798	6,744
		4,530	4,610	3,639		13,380	11,021

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Note 5. Sales and other operating revenues

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
By segment
gas & low carbon energy		9,655	9,172	8,526		29,605	23,010
oil production & operations		6,232	6,053	6,468		18,787	19,559
customers & products		38,697	37,449	38,437		112,309	119,432
other businesses & corporate		627	539	614		1,650	1,746
		55,211	53,213	54,045		162,351	163,747
Less: sales and other operating revenues between segments
gas & low carbon energy		310	337	385		1,378	1,026
oil production & operations		5,908	5,818	5,860		17,544	17,755
customers & products		70	(55)	(138)		57	180
other businesses & corporate		503	486	684		1,420	1,353
		6,791	6,586	6,791		20,399	20,314
External sales and other operating revenues
gas & low carbon energy		9,345	8,835	8,141		28,227	21,984
oil production & operations		324	235	608		1,243	1,804
customers & products		38,627	37,504	38,575		112,252	119,252
other businesses & corporate		124	53	(70)		230	393
Total sales and other operating revenues		48,420	46,627	47,254		141,952	143,433
By geographical area
US		18,968	18,890	19,388		56,947	59,586
Non-US		37,877	36,233	36,712		109,811	112,752
		56,845	55,123	56,100		166,758	172,338
Less: sales and other operating revenues between areas		8,425	8,496	8,846		24,806	28,905
		48,420	46,627	47,254		141,952	143,433
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil		635	421	618		1,471	1,704
Oil products		30,274	28,572	30,997		86,008	93,385
Natural gas, LNG and NGLs		7,192	6,049	6,458		20,504	17,196
Non-oil products and other revenues from contracts with customers		3,528	3,697	3,213		10,858	9,249
Revenue from contracts with customers		41,629	38,739	41,286		118,841	121,534
Other operating revenues(a)		6,791	7,888	5,968		23,111	21,899
Total sales and other operating revenues		48,420	46,627	47,254		141,952	143,433

(a)

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

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Note 6. Depreciation, depletion and amortization

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Total depreciation, depletion and amortization by segment
gas & low carbon energy		1,223	1,407	1,180		3,796	3,682
oil production & operations		1,961	1,933	1,708		5,681	5,063
customers & products		1,045	1,060	963		3,090	2,846
other businesses & corporate		243	241	266		729	774
		4,472	4,641	4,117		13,296	12,365
Total depreciation, depletion and amortization by geographical area
US		1,898	1,897	1,735		5,531	5,008
Non-US		2,574	2,744	2,382		7,765	7,357
		4,472	4,641	4,117		13,296	12,365

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. Against the authority granted at bp's 2025 annual general meeting, 138 million ordinary shares repurchased were settled during the third quarter 2025 for a total cost of $750 million. All of these shares were held as treasury shares. A further 91 million ordinary shares were repurchased between the end of the reporting period and the date when the financial statements are authorised for issue for a total cost of $522 million. This amount has been accrued at 30 September 2025. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of 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		2025	2025	2024		2025	2024
Results for the period
Profit (loss) for the period attributable to bp shareholders		1,161	1,629	206		3,477	2,340
Less: preference dividend		—	1	—		1	1
Less: (gain) loss on redemption of perpetual hybrid bonds		—	—	—		—	(10)
Profit (loss) attributable to bp ordinary shareholders		1,161	1,628	206		3,476	2,349
Number of shares (thousand)(a)
Basic weighted average number of shares outstanding		15,518,940	15,645,561	16,321,349		15,646,554	16,553,408
ADS equivalent(b)		2,586,490	2,607,593	2,720,224		2,607,759	2,758,901
Weighted average number of shares outstanding used to calculate diluted earnings per share		15,735,029	15,854,588	16,709,108		15,968,108	16,980,519
ADS equivalent(b)		2,622,504	2,642,431	2,784,851		2,661,351	2,830,086
Shares in issue at period-end		15,487,180	15,596,112	16,155,806		15,487,180	16,155,806
ADS equivalent(b)		2,581,196	2,599,352	2,692,634		2,581,196	2,692,634

(a)

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

(b)

One ADS is equivalent to six ordinary shares.

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Note 8. Dividends

Dividends payable

bp today announced an interim dividend of 8.320 cents per ordinary share which is expected to be paid on 19 December 2025 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 14 November 2025. The ex-dividend date will be 13 November 2025 for ordinary shareholders and 14 November 2025 for ADS holders. The corresponding amount in sterling is due to be announced on 9 December 2025, calculated based on the average of the market exchange rates over three dealing days between 3 December 2025 and 5 December 2025. Holders of ADSs are expected to receive $0.4992 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2025 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
		2025	2025	2024		2025	2024
Dividends paid per ordinary share
cents		8.320	8.000	8.000		24.320	22.540
pence		6.194	5.899	6.050		18.270	17.425
Dividends paid per ADS (cents)		49.92	48.00	48.00		145.92	135.24

Note 9. Net debt

Net debt*		30 September	30 June	30 September
$ million		2025	2025	2024
Finance debt(a)		60,188	60,346	57,470
Fair value (asset) liability of hedges related to finance debt(b)		775	764	1,393
		60,963	61,110	58,863
Less: cash and cash equivalents		34,909	35,067	34,595
Net debt(c)		26,054	26,043	24,268
Total equity		77,645	79,780	79,946
Gearing*		25.1%	24.6%	23.3%

(a)

The fair value of finance debt at 30 September 2025 was $57,113 million (30 June 2025 $57,135 million, 30 September 2024 $54,324 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 $94 million at 30 September 2025 (second quarter 2025 liability of $96 million and third quarter 2024 liability of $123 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.

Note 10. Events after the reporting period

On 8 October 2025, the International Chamber of Commerce International Court of Arbitration issued a partial final award in bp's favour against Venture Global (“VG”). The arbitration tribunal found that VG had breached its obligations to declare Commercial Operations Date of its Calcasieu Project in a timely manner and act as a "Reasonable and Prudent Operator" pursuant to the long-term LNG Sale and Purchase Agreement (“SPA”) with bp. Throughout the breach, VG sold LNG cargos on the spot market rather than to bp as required under the SPA.

The next phase of the arbitration proceedings is a damages hearing, most likely to occur in 2026. Due to the uncertainty of the final amount to be received, management has not recognised a receivable in the quarter.

Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 3 November 2025, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in bp Annual Report and Form 20-F 2025. bp Annual Report and Form 20-F 2024 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.

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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		2025	2025	2024		2025	2024
Capital expenditure
Organic capital expenditure*		3,328	3,321	4,341		10,089	11,906
Inorganic capital expenditure*		53	40	201		276	605
		3,381	3,361	4,542		10,365	12,511

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Capital expenditure by segment
gas & low carbon energy(a)		828	790	2,156		2,521	4,721
oil production & operations		1,722	1,706	1,410		5,124	4,720
customers & products(a)		770	797	871		2,510	2,774
other businesses & corporate		61	68	105		210	296
		3,381	3,361	4,542		10,365	12,511
Capital expenditure by geographical area
US		1,591	1,576	1,389		4,600	4,801
Non-US		1,790	1,785	3,153		5,765	7,710
		3,381	3,361	4,542		10,365	12,511

(a)

Comparative periods in 2024 have been restated to reflect the move of our Archaea business from the customers & products segment to the gas & low carbon energy segment.

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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		2025	2025	2024		2025	2024
gas & low carbon energy
Gains on sale of businesses and fixed assets		—	69	19		68	29
Net impairment and losses on sale of businesses and fixed assets(a)		(489)	(439)	(772)		(1,294)	(1,898)
Environmental and related provisions		—	—	—		—	—
Restructuring, integration and rationalization costs		8	3	(24)		(3)	(24)
Fair value accounting effects(b)(c)		131	18	(275)		817	(1,173)
Other		(72)	(66)	303		(64)	(22)
		(422)	(415)	(749)		(476)	(3,088)
oil production & operations
Gains on sale of businesses and fixed assets		(29)	196	(82)		176	109
Net impairment and losses on sale of businesses and fixed assets(a)		10	(330)	(770)		(335)	(919)
Environmental and related provisions		(145)	(55)	(53)		(231)	65
Restructuring, integration and rationalization costs		9	(46)	(1)		(78)	(1)
Fair value accounting effects		—	—	—		—	—
Other		(25)	(111)	3		(165)	(49)
		(180)	(346)	(903)		(633)	(795)
customers & products
Gains on sale of businesses and fixed assets		10	16	12		29	21
Net impairment and losses on sale of businesses and fixed assets(a)		(274)	(389)	(295)		(777)	(1,069)
Environmental and related provisions		(1)	(1)	(4)		(2)	3
Restructuring, integration and rationalization costs		(17)	(86)	(39)		(194)	(38)
Fair value accounting effects(c)		42	(201)	157		(241)	38
Other(d)		134	100	(189)		(56)	(896)
		(106)	(561)	(358)		(1,241)	(1,941)
other businesses & corporate
Gains on sale of businesses and fixed assets		2	—	3		2	35
Net impairment and losses on sale of businesses and fixed assets		—	—	(6)		(5)	9
Environmental and related provisions		(48)	(18)	(8)		(138)	11
Restructuring, integration and rationalization costs		(8)	(39)	(50)		(245)	(38)
Fair value accounting effects(c)		(13)	740	494		1,096	272
Gulf of America oil spill		(9)	(9)	(20)		(27)	(39)
Other		(12)	9	9		7	4
		(88)	683	422		690	254
Total before interest and taxation		(796)	(639)	(1,588)		(1,660)	(5,570)
Finance costs(e)		(83)	(78)	(58)		(348)	(355)
Total before taxation		(879)	(717)	(1,646)		(2,008)	(5,925)
Taxation on adjusting items(f)		125	400	535		664	1,229
Taxation – tax rate change effect(g)		(233)	—	(44)		(772)	(348)
Total after taxation for period		(987)	(317)	(1,155)		(2,116)	(5,044)

(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 3, 6 and 32.

(d)

Nine months 2024 includes the initial recognition of onerous contract provisions related to Gelsenkirchen refinery. The unwind of these provisions in the subsequent quarters are reported as an adjusting item as the contractual obligations are settled.

(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.

(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)

Third quarter 2025 and nine months 2025 include the deferred tax impact of a change in the tax rate in Germany, see Note 1 for further information. Nine months 2025 and nine months 2024 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.

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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		2025	2025	2024
Net debt*		26,054	26,043	24,268
Lease liabilities		14,629	14,636	11,018
Net partner (receivable) payable for leases entered into on behalf of joint operations		(1,082)	(1,030)	(98)
Net debt including leases		39,601	39,649	35,188
Total equity		77,645	79,780	79,946
Gearing including leases*		33.8%	33.2%	30.6%

Gulf of America oil spill

		30 September	31 December
$ million		2025	2024
Gulf of America oil spill payables and provisions		(7,172)	(7,958)
Of which - current		(1,512)	(1,127)
Deferred tax asset		1,097	1,205

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 2024 - 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		2025	2025	2024		2025	2024
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement(a)		494	(2,030)	1,798		(6,605)	1,223
Adjusted for inventory holding gains (losses) (Note 4)		(82)	(554)	(1,182)		(477)	(467)
Adjusted for fair value accounting effects relating to subsidiaries		177	554	319		1,690	(1,026)
Other adjusting items(b)		322	646	451		1,569	(201)
Working capital release (build) after adjusting for net inventory holding gains (losses), fair value accounting effects and other adjusting items		911	(1,384)	1,386		(3,823)	(471)

(a)

The movement in working capital includes outflows relating to the Gulf of America oil spill on a pre-tax basis of $5 million and $1,136 million in the third quarter and nine months 2025 (second quarter 2025 $1,129 million, third quarter 2024 $4 million, nine months 2024 $1,140 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.

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Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*

Adjusted EBITDA is a non-IFRS measure closely tracked by bp's management to evaluate the underlying trends in bp’s operating performance on a comparable basis, period on period.

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
$ million		2025	2025	2024		2025	2024
Profit for the period		1,509	1,929	370		4,420	2,849
Finance costs		1,267	1,229	1,101		3,817	3,392
Net finance (income) expense relating to pensions and other post-employment benefits		(55)	(56)	(42)		(163)	(123)
Taxation		1,727	954	1,028		4,829	4,436
Profit before interest and tax		4,448	4,056	2,457		12,903	10,554
Inventory holding (gains) losses*, before tax		82	554	1,182		477	467
RC profit before interest and tax		4,530	4,610	3,639		13,380	11,021
Net (favourable) adverse impact of adjusting items*, before interest and tax		796	639	1,588		1,660	5,570
Underlying RC profit before interest and tax		5,326	5,249	5,227		15,040	16,591
Add back:
Depreciation, depletion and amortization		4,472	4,641	4,117		13,296	12,365
Exploration expenditure written off		183	82	310		318	643
Adjusted EBITDA		9,981	9,972	9,654		28,654	29,599

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Underlying operating expenditure* reconciliation

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).

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		2025	2025	2024		2025	2024
From group income statement
Production and manufacturing expenses		6,620	6,153	5,004		18,887	18,543
Distribution and administration expenses		4,271	4,242	3,930		12,924	12,319
		10,891	10,395	8,934		31,811	30,862
Less certain variable costs:
Transportation and shipping costs		2,579	2,634	2,426		7,659	7,516
Environmental costs		1,290	1,630	1,210		4,257	3,078
Marketing and distribution costs		358	421	400		1,206	1,532
Commission, storage and handling costs		410	405	393		1,181	1,144
Other variable costs and non-cash costs		654	435	(602)		1,386	439
Certain variable costs and non-cash costs		5,291	5,525	3,827		15,689	13,709
Adjusted operating expenditure*		5,600	4,870	5,107		16,122	17,153
Less certain adjusting items*:
Gulf of America oil spill		9	9	20		27	39
Environmental and related provisions		194	74	65		371	(79)
Restructuring, integration and rationalization costs		8	168	114		520	101
Fair value accounting effects – derivative instruments relating to the hybrid bonds		13	(740)	(494)		(1,096)	(272)
Other certain adjusting items		(111)	(98)	(188)		52	822
Certain adjusting items		113	(587)	(483)		(126)	611
Underlying operating expenditure		5,487	5,457	5,590		16,248	16,542

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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		2025	2025	2024		2025	2024
RC profit (loss) before interest and tax for customers & products		1,610	972	23		2,685	878
Less: Adjusting items* gains (charges)		(106)	(561)	(358)		(1,241)	(1,941)
Underlying RC profit (loss) before interest and tax for customers & products		1,716	1,533	381		3,926	2,819
By business:
customers – convenience & mobility		1,167	1,056	897		2,887	2,057
Castrol – included in customers		261	245	216		744	611
products – refining & trading		549	477	(516)		1,039	762
Add back: Depreciation, depletion and amortization		1,045	1,060	963		3,090	2,846
By business:
customers – convenience & mobility		619	642	513		1,828	1,488
Castrol – included in customers		48	50	45		144	129
products – refining & trading		426	418	450		1,262	1,358
Adjusted EBITDA for customers & products		2,761	2,593	1,344		7,016	5,665
By business:
customers – convenience & mobility		1,786	1,698	1,410		4,715	3,545
Castrol – included in customers		309	295	261		888	740
products – refining & trading		975	895	(66)		2,301	2,120

Top of page 30

Realizations* and marker prices

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
		2025	2025	2024		2025	2024
Average realizations(a)
Liquids* ($/bbl)
US		54.02	53.39	63.31		56.32	63.83
Europe		69.15	64.62	75.45		69.81	80.44
Rest of World		67.20	69.69	80.79		70.36	81.39
bp average		60.02	60.16	70.68		62.55	71.89
Natural gas ($/mcf)
US		2.41	2.52	1.18		2.67	1.39
Europe		11.98	13.06	12.22		13.90	10.68
Rest of World		6.41	6.50	5.80		6.71	5.57
bp average		5.34	5.56	4.75		5.75	4.61
Total hydrocarbons* ($/boe)
US		38.91	39.51	42.18		41.41	42.65
Europe		69.25	68.02	74.03		73.19	74.73
Rest of World		47.62	48.44	47.57		49.70	47.22
bp average		45.00	45.84	46.81		47.58	46.91
Average oil marker prices ($/bbl)
Brent		69.13	67.88	80.34		70.93	82.79
West Texas Intermediate		65.07	63.81	75.28		66.74	77.71
Western Canadian Select		52.52	53.16	59.98		54.66	62.22
Alaska North Slope		70.07	68.82	78.95		71.54	82.24
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)		3.07	3.44	2.15		3.39	2.10
UK Gas – National Balancing Point (p/therm)		79.84	84.53	81.77		93.38	75.75

(a)

Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.

(b)

Henry Hub First of Month Index.

Exchange rates

		Third	Second	Third		Nine	Nine
		quarter	quarter	quarter		months	months
		2025	2025	2024		2025	2024
$/£ average rate for the period		1.35	1.34	1.30		1.31	1.28
$/£ period-end rate		1.34	1.37	1.34		1.34	1.34
$/€ average rate for the period		1.17	1.13	1.10		1.12	1.09
$/€ period-end rate		1.17	1.17	1.12		1.17	1.12
$/AUD average rate for the period		0.65	0.64	0.67		0.64	0.66
$/AUD period-end rate		0.66	0.65	0.69		0.66	0.69

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Legal proceedings

For a full discussion of the group’s material legal proceedings, see pages 218-219 of bp Annual Report and Form 20-F 2024.

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 EBITDA for the group is defined as profit or loss for the period, adjusting for finance costs and net finance (income) or expense relating to pensions and other post-employment benefits and taxation, inventory holding gains or losses before tax, net adjusting items before interest and tax, and adding back depreciation, depletion and amortization (pre-tax) and exploration expenditure written-off (net of adjusting items, pre-tax). The nearest equivalent measure on an IFRS basis for the group is profit or loss for the period. A reconciliation to IFRS information is provided on page 27 for the group.

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 25.

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.

downstream is the customers & products segment.

Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-IFRS measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Taxation on a 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. Information on RC profit or loss is provided below. bp believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. Taxation on a RC basis and ETR on RC profit or loss are non-IFRS measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

Top of page 32

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.

Top of page 33

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, integrated gas and power and gas trading. From the first quarter of 2025 it also includes our Archaea business which prior to that was reported in the customers & products segment. Our low carbon business includes solar, offshore and onshore wind, hydrogen and CCS and power trading. Power trading includes trading of both renewable and non-renewable power.

Gearing and net debt 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 23.

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.

Gearing including leases and net debt 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 26.

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 24.

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.

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Glossary (continued)

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.

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 24.

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.

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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 – 2025 underlying production, when compared with 2024, 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 25 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 6-12 for the segments.

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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

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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, results of operations, cost reduction, cash flows, and shareholder returns; plans and expectations regarding the amount and timing of dividends, share buybacks, and dividend reinvestment programs; plans and expectations regarding bp’s upstream production; plans and expectations regarding the amount, timing, quantum and nature of certain acquisitions, divestments and related payments and proceeds, including expectations regarding bp Wind Energy, Lightsource bp and other bp businesses and assets subject to disposal or divestment; plans and expectations regarding bp’s net debt, credit rating, investment strategy, capital expenditures, capital frame, underlying effective tax rate, and depreciation, depletion and amortization; expectations regarding bp’s customers business, including with respect to earnings growth, fuels margins and the impact of structural cost reduction; expectations regarding bp’s products, including underlying performance and refinery turnaround activity; expectations regarding bp’s other businesses & corporate underlying annual charge; expectations regarding Gulf of America settlement payments; plans and expectations regarding the Tiber-Guadalupe project as well as bp’s projects in the Mediterranean Sea, the Bumerangue block, the UK’s North Sea, and Aker BP’s project in the Yggdrasil area; plans and expectations regarding bp’s partnerships and other collaborations and agreements with BOTAS, Iraq’s North Oil Company and North Gas Company and others; expectations regarding bp’s tax liabilities and obligations; and expectations regarding the pending legal proceedings involving bp.

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; 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 “Principal risks and uncertainties” in bp’s Report on Form 6-K regarding results for the six-month period ended 30 June 2025 as filed with the US Securities and Exchange Commission (the “SEC”) as well as “Risk factors” in bp’s Annual Report and Form 20-F for fiscal year 2024 as filed with the SEC.

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.

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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 213800LH1BZH3D16G760

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BP p.l.c.

(Registrant)

Dated: 04 November 2025

/s/ Ben J. S. Mathews

------------------------

Ben J. S. Mathews

Company Secretary

FAQ

How did BP (BP) perform in Q3 2025?

Underlying RC profit was $2.2 billion, with operating cash flow of $7.8 billion and reported profit attributable to shareholders of $1.2 billion.

What is BP’s Q3 2025 dividend and buyback plan?

BP announced a dividend of 8.320 cents per ordinary share and intends to execute a $0.75 billion share buyback before reporting Q4 results.

What are BP’s leverage and cash metrics for Q3 2025?

Net debt was $26.1 billion at quarter-end, broadly flat, supported by $7.8 billion operating cash flow.

What guidance did BP provide for 2025 capex and divestments?

BP continues to expect full-year capex around $14.5 billion and now expects divestment and other proceeds to be above $4 billion.

How did BP’s segments perform in Q3 2025?

Customers & products improved with underlying RC profit before interest and tax of $1.7 billion; upstream reliability was 96.8%.

What legal development did BP disclose?

A partial arbitration award favored BP in an LNG contract dispute; damages will be addressed in a later hearing.

What is the announced timetable for BP’s Q3 2025 dividend?

The dividend is expected to be paid on 19 December 2025 to holders on the register on 14 November 2025.