UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

for the month of August 2025

Commission File Number 1-06262

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 of Form 20-F or Form 40-F:

Form 20-F x  Form 40-F ¨

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-277842, 333-277842-01 AND 333-277842-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-102583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103923) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-119934) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200796) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-253287), THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-254578) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-270440) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-273587) OF BP p.l.c. AND THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-280100) OF BP p.l.c. AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

1

BP p.l.c. and subsidiaries

Form 6-K for the period ended 30 June 2025(a)

		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2025(b)	3-15, 27-33, 35-40
2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2025	16-26
3.	Principal risks and uncertainties	34
4.	Legal proceedings	35
5	Cautionary statement	41
6.	Capitalization and Indebtedness	42
7.	Signatures	43

(a)In this Form 6-K, references to the half year 2025 and half year 2024 refer to the six-month periods ended 30 June 2025 and 30 June 2024 respectively. References to the second quarter 2025 and second quarter 2024 refer to the three-month periods ended 30 June 2025 and 30 June 2024 respectively.

(b)This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in bp’s Annual Report on Form 20-F for the year ended 31 December 2024.

2

Group results second quarter and first half 2025

Delivering our plan

Financial summary	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2025	2025	2024	2025	2024
Profit (loss) for the period	1,929	982	70	2,911	2,479
Less: Non-controlling interests	300	295	199	595	345
Profit (loss) for the period attributable to bp shareholders	1,629	687	(129)	2,316	2,134
Inventory holding (gains) losses*, before tax	554	(159)	136	395	(715)
Taxation charge (credit) on inventory holding gains and losses	(147)	41	(23)	(106)	171
Replacement cost (RC) profit (loss)*	2,036	569	(16)	2,605	1,590
Net (favourable) adverse impact of adjusting items*, before tax	717	412	3,053	1,129	4,279
Taxation charge (credit) on adjusting items	(400)	400	(281)	—	(390)
Underlying RC profit*	2,353	1,381	2,756	3,734	5,479

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Sales and other operating revenues	46,627	47,299	93,532	96,179
Operating cash flow*	6,271	8,100	9,105	13,109
Capital expenditure*	(3,361)	(3,691)	(6,984)	(7,969)
Divestment and other proceeds(a)	1,356	760	1,684	1,173
Net cash issue (repurchase) of shares	(1,063)	(1,751)	(2,910)	(3,501)
Finance debt	60,346	54,986	60,346	54,986
Net debt*(b)	26,043	22,614	26,043	22,614
Adjusted EBITDA*	9,972	9,639	18,673	19,945
Announced dividend per ordinary share (cents per share)	8.320	8.000	16.320	15.270
Profit (loss) per ordinary share (cents)	10.41	(0.78)	14.73	12.85
Profit (loss) per ADS (dollars)	0.62	(0.05)	0.88	0.77
Underlying RC profit per ordinary share* (cents)	15.03	16.61	23.76	32.86
Underlying RC profit per ADS* (dollars)	0.90	1.00	1.43	1.97

(a)Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. See page 5 for more information on other proceeds.

(b)See Note 9 for more information.

RC profit (loss), underlying RC profit, net debt, adjusted EBITDA, 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 35.

3

Highlights(a)
2Q25 profit $1.6 billion; underlying replacement cost (RC) profit* $2.4 billion
•	Profit for the quarter attributable to bp shareholders was $1.6 billion, compared with $0.7 billion for the first quarter 2025 and a loss of $0.1 billion for the second quarter 2024. The result for the second quarter 2025 is adjusted for inventory holding losses* of $0.6 billion (pre-tax) and a net adverse impact of adjusting items* of $0.7 billion (pre-tax) to derive the underlying RC profit. Adjusting items include pre-tax net impairments of $1.1 billion and favourable fair value accounting effects* of $0.6 billion. See page 28 for more information on adjusting items.
•	Underlying RC profit for the quarter was $2.4 billion, compared with $1.4 billion for the previous quarter and $2.8 billion for the second quarter 2024. Compared with the first quarter 2025, the underlying result reflects an average gas marketing and trading result, stronger realized refining margins, stronger customers result, a strong oil trading result, partly offset by lower liquids and gas realizations and significantly higher level of refinery turnaround activity.
Segment results
•	Gas & low carbon energy: The RC profit before interest and tax for the second quarter 2025 was $1.0 billion, compared with $1.4 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 second quarter was $1.5 billion, compared with $1.0 billion in the first quarter 2025. The second quarter underlying result before interest and tax reflects an average gas marketing and trading result compared with a weak result in the first quarter, and higher volumes, partly offset by lower realizations and a higher depreciation, depletion and amortization charge.
•	Oil production & operations: The RC profit before interest and tax for the second quarter 2025 was $1.9 billion, compared with $2.8 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.3 billion, the underlying RC profit before interest and tax for the second quarter was $2.3 billion, compared with $2.9 billion in the first quarter 2025. The second quarter underlying result before interest and tax reflects lower realizations and a higher depreciation, depletion and amortization charge partly offset by higher production.
•	Customers & products: The RC profit before interest and tax for the second quarter 2025 was $1.0 billion, compared with $0.1 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.6 billion, the underlying RC profit before interest and tax (underlying result) for the second quarter was $1.5 billion, compared with $0.7 billion in the first quarter 2025. The customers second quarter underlying result was higher by $0.4 billion, reflecting seasonally higher volumes and stronger fuels margins. The products second quarter underlying result was higher by $0.5 billion, reflecting stronger realized refining margins and a strong oil trading contribution, partly offset by a significantly higher level of refinery turnaround activity.
Operating cash flow* $6.3 billion, finance debt $60.3 billion and net debt* $26.0 billion
•	Operating cash flow of $6.3 billion, which includes the $1.1 billion settlement payment for the Gulf of America (see page 29), was around $3.4 billion higher than the previous quarter. Operating cash flow in the second quarter 2024 was $8.1 billion. Finance debt at the end of the second quarter 2025 was $60.3 billion, compared with $59.5 billion at the end of the fourth quarter 2024. Net debt reduced to $26.0 billion in the second quarter as cash inflows from higher operating cash flow and divestment and other proceeds exceeded cash outflows during the period. Net debt at the end of the fourth quarter 2024 was $23.0 billion.
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(b).
•	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(c). For the second quarter, bp has announced a dividend per ordinary share of 8.32 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 second quarter results, bp intends to execute a $0.75 billion share buyback prior to reporting the third quarter results. The $0.75 billion share buyback programme announced with the first quarter results was completed on 1 August 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.
Accelerating strategy
•	In service of accelerating its strategy, bp intends to conduct a thorough review of its portfolio of businesses and initiate a further cost review.

(a)This report discusses certain material changes in bp’s results of operations with respect to the quarter ended 30 June 2025 as compared to the quarter ended 31 March 2025. Financial information for the quarter ended 31 March 2025 can be in found in our Current Report on Form 6-K filed with the SEC on 29 April 2025.

(b)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.

(c)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 41.

4

Financial results

In addition to the highlights on page 4:

•Profit attributable to bp shareholders in the second quarter and half year was $1.6 billion and $2.3 billion respectively, compared with a loss of $0.1 billion and a profit of $2.1 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 second quarter and half year was $2.4 billion and $3.7 billion respectively, compared with $2.8 billion and $5.5 billion for the same periods of 2024. The underlying RC profit for the second quarter compared with the same period in 2024 mainly reflects lower liquids realizations, offset by a stronger customers result and oil trading contribution. The gas marketing and trading result was average. The underlying RC profit for the half year compared with the same period in 2024 mainly reflects lower refining margins, lower liquids realizations and a lower gas marketing and trading result, partly offset by the absence of the Whiting refinery outage and a stronger customers result. Underlying operating expenditure* for the half year, compared with the same period in 2024, was slightly lower, with structural cost reductions* offset by growth and inflation.

–Adjusting items in the second quarter and half year had a net adverse pre-tax impact of $0.7 billion and $1.1 billion respectively, compared with a net adverse pre-tax impact of $3.1 billion and $4.3 billion in the same periods of 2024.

–Adjusting items for the second quarter and half year include a favourable pre-tax impact of fair value accounting effects*, relative to management's internal measure of performance, of $0.6 billion and $1.5 billion respectively, compared with an adverse pre-tax impact of $1.0 billion and $1.2 billion in the same periods of 2024. This is primarily due to little movement in the LNG forward price in the second quarter 2025 compared with an increase in the second quarter 2024 and a decline in the price in the first half of 2025 compared to an increase in the comparative period of 2024. In addition there has been a favourable impact of the fair value accounting effects relating to the hybrid bonds in the 2025 periods compared to adverse impacts in the 2024 comparative periods.

–Adjusting items for the second quarter and half year of 2025 include an adverse pre-tax impact of asset impairments of $1.1 billion and $1.6 billion respectively, compared with an adverse pre-tax impact of $1.3 billion and $1.9 billion in the same periods of 2024.

•The effective tax rate (ETR) on the profit or loss before taxation for the second quarter and half year was 33% and 52% respectively, compared with 94% and 58% for the same periods in 2024. The ETR on RC profit or loss* for the second quarter and half year was 32% and 50% respectively, compared with 87% and 63% for the same periods in 2024. Excluding adjusting items, the underlying ETR* for the second quarter and half year was 36% and 43%, compared with 33% and 38% for the same periods in 2024. The higher underlying ETR for the second quarter and half year reflects the absence of the impact of the reassessment of the recognition of deferred tax assets. The higher underlying ETR for the half year also 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 second quarter and half year was $6.3 billion and $9.1 billion respectively, compared with $8.1 billion and $13.1 billion for the same periods in 2024.

•Capital expenditure* in the second quarter and half year was $3.4 billion and $7.0 billion respectively, compared with $3.7 billion and $8.0 billion in the same periods of 2024 reflecting the lower capital frame in place for 2025.

•Total divestment and other proceeds for the second quarter and half year were $1.4 billion and $1.7 billion respectively, compared with $0.8 billion and $1.2 billion for the same periods in 2024. Other proceeds for the second quarter and half year 2025 were $1.0 billion from the sale of a non-controlling interest in the subsidiary that holds our 12% share in the Trans-Anatolian natural gas pipeline (TANAP). Other proceeds for the second quarter and half year 2024 were $0.5 billion from the sale of a 49% interest in a controlled affiliate holding certain midstream assets offshore US.

•Finance debt at the end of the second quarter was $60.3 billion, compared with $59.5 billion at the end of the fourth quarter 2024. At the end of the second quarter, net debt* was $26.0 billion, compared with $23.0 billion at the end of the fourth quarter 2024.

5

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

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
RC profit (loss) before interest and tax
gas & low carbon energy	1,047	(315)	2,405	721
oil production & operations	1,916	3,267	4,704	6,327
customers & products	972	(133)	1,075	855
other businesses & corporate	645	(180)	623	(480)
Consolidation adjustment – UPII*	30	(73)	43	(41)
	4,610	2,566	8,850	7,382
Finance costs and net finance expense relating to pensions and other post-employment benefits	(1,173)	(1,176)	(2,442)	(2,210)
Taxation on a RC basis	(1,101)	(1,207)	(3,208)	(3,237)
Non-controlling interests	(300)	(199)	(595)	(345)
RC profit (loss) attributable to bp shareholders*	2,036	(16)	2,605	1,590
Inventory holding gains (losses)*	(554)	(136)	(395)	715
Taxation (charge) credit on inventory holding gains and losses	147	23	106	(171)
Profit (loss) for the period attributable to bp shareholders	1,629	(129)	2,316	2,134

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

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Underlying RC profit (loss) before interest and tax
gas & low carbon energy	1,462	1,402	2,459	3,060
oil production & operations	2,262	3,094	5,157	6,219
customers & products	1,533	1,149	2,210	2,438
other businesses & corporate	(38)	(158)	(155)	(312)
Consolidation adjustment – UPII	30	(73)	43	(41)
	5,249	5,414	9,714	11,364
Finance costs on an underlying RC basis(a) and net finance expense relating to pensions and other post-employment benefits	(1,095)	(971)	(2,177)	(1,913)
Taxation on an underlying RC basis	(1,501)	(1,488)	(3,208)	(3,627)
Non-controlling interests	(300)	(199)	(595)	(345)
Underlying RC profit attributable to bp shareholders*	2,353	2,756	3,734	5,479

(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 28).

Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-15 for the segments.

Operating Metrics

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
Tier 1 and tier 2 process safety events*	5	7	15	21
upstream* production(a) (mboe/d)	2,300	2,379	2,270	2,379
upstream unit production costs*(b) ($/boe)	6.81	6.34	6.58	6.17
bp-operated upstream plant reliability*	96.8%	96.1%	96.1%	95.5%
bp-operated refining availability*(a)	96.4%	96.4%	96.3%	93.4%

(a)See Operational updates on pages 8, 11 and 13. 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 first half 2025, compared with the first half 2024 mainly reflects portfolio mix.

6

Outlook & Guidance

3Q 2025 guidance

•Looking ahead, bp expects third quarter 2025 reported upstream* production to be slightly lower compared with the second quarter 2025.

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

•In products, bp expects, compared to the second quarter, a significantly lower level of planned refinery turnaround activity, partly offset by seasonal effects of environmental compliance costs.

•bp expects income taxes paid in the third quarter to be around $1 billion higher than the second quarter 2025 mainly due to the timing of instalment payments, which are typically higher in the third quarter each year.

•On 4 August bp elected to redeem $1.2 billion of its perpetual hybrid bonds, representing the remaining amount callable from June 2025. The hybrid bonds will be redeemed on 1 September 2025 using proceeds from bp's November 2024 hybrid bond issuance.

2025 guidance

In addition to the guidance on page 4:

•bp continues to expect reported upstream* production to be lower and underlying upstream production* to be slightly lower compared with 2024. Within this, bp expects underlying production from oil production & operations to be broadly flat 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 $0.5-1.0 billion for 2025, subject to foreign exchange impacts. The charge may vary from quarter to quarter.

•bp now expects 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 continues to expect divestment and other proceeds to be around $3-4 billion in 2025, with the remaining proceeds weighted to the fourth quarter 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.

New refining rule of thumb

bp has retired the refining marker margin* (RMM) and replaced it with the bp refining indicator margin* (RIM), and updated the associated refining rule of thumb (RoT). The bp RIM RoT reflects the sensitivity of the group’s 2025 underlying replacement cost profit before interest and tax* to changes in bp’s RIM at normal operating conditions, and will not fully explain all quarter on quarter movements in Products.

The bp RIM reflects a broader set of crudes and products, and is more representative of bp's refining portfolio and realized refining margin per barrel. As a result, we believe this weekly disclosure will enhance the understanding of our realized margin delivery and refining profitability.

Refining RoT for +/- $1/bbl change	Impact on 2025 underlying RC profit before interest and tax
bp RIM (new)	$550m
bp RMM (retired)	$400m

As a consequence of this change, the refining price assumptions applicable to bp's CMU Cash Flow and ROACE Targets* have been updated by replacing the RMM price assumption with a RIM price assumption. The updated price assumptions are: at $70/bbl Brent, $4/mmBtu Henry Hub and $10.3/bbl refining indicator margin, all 2024 real. There is no change to the CMU Cash Flow and ROACE Targets or to the prices used for impairment testing as a consequence of this update. Price assumptions are not intended to reflect management's forecasts for future prices.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 41.

7

gas & low carbon energy*

Financial results

•Sales and other operating revenues for the second quarter and half year were $9.2 billion and $20.0 billion respectively, compared with $5.8 billion and $14.5 billion for the corresponding periods in 2024. For the second quarter, revenues were higher mainly due to higher gas marketing and trading revenues partly offset by lower volumes and lower realizations. For the half year, revenues were higher mainly due to higher gas marketing and trading revenues and higher realizations, partly offset by lower volumes.

•The replacement cost (RC) profit before interest and tax for the second quarter and half year was $1,047 million and $2,405 million respectively, compared with a loss of $315 million and a profit of $721 million for the same periods in 2024. The second quarter and half year are adjusted by an adverse impact of net adjusting items* of $415 million and $54 million respectively, compared with an adverse impact of net adjusting items of $1,717 million and $2,339 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 $18 million and $686 million for the second quarter and half year in 2025 and an adverse impact of $1,011 million and $898 million for the same periods in 2024. See page 28 for more information on adjusting items.

•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the second quarter and half year was $1,462 million and $2,459 million respectively, compared with $1,402 million and $3,060 million for the same periods in 2024.

•The underlying RC profit before interest and tax for the second quarter compared with the same period in 2024, reflects higher-margin production offset by a higher depreciation, depletion and amortization charge and the divestments in Trinidad and Egypt in the fourth quarter of 2024. The gas marketing and trading result was average.

•The underlying RC profit for the half year, compared with the same period in 2024, reflects a lower gas marketing and trading result, the divestments in Trinidad and Egypt in the fourth quarter of 2024, and a higher depreciation, depletion and amortization charge, partly offset by higher-margin production and the absence of the foreign exchange loss in Egypt and exploration write-offs in the first half of 2024. Underlying operating expenditure for the half year, compared with the same period in 2024, was higher, with structural cost reductions more than offset by growth and inflation.

Operational update

•Reported production for the quarter was 782mboe/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 2.1% lower due to base decline, partly offset by major project startups.

•Reported production for the half year was 773mboe/d, 14.8% lower than the same period in 2024. Underlying production was 4.1% lower, mainly due to base decline partly offset by major project startups.

Strategic progress

gas

•In May bp announced the Mento development in Trinidad & Tobago has safely delivered its first gas. Mento is a 50:50 joint venture between EOG Resources Trinidad Ltd (EOG) and bp, with EOG as the operator.

•In May and June, bp signed sale and purchase agreements (SPA) for liquefied natural gas (LNG) with: Zhejiang, under which bp has agreed to supply of 1 million mt/year of LNG to Zhejiang Energy for a duration of 10 years; approximately 0.7 million mt/year of LNG to A2A from 2027 to 2044.

•In May bp made the final investment decision (FID) to invest in an infill wells programme at the offshore KG D6 gas block located offshore India.

•In June Gás Natural Açu (GNA) II, the largest gas fired power plant in Brazil has started commercial operations of its 1.7 gigawatts capacity plant. bp is the exclusive LNG supplier for GNA II and holds a 33.5% stake in the project alongside Siemens Energy (33.5%) and SPIC Brazil (33%).

•In June bp and its partners, announced the final investment decision (FID) for the new Shah Deniz Compression project, the next stage of development of the giant Shah Deniz gas field in the Azerbaijan sector of the Caspian Sea (bp operator 29.99%).

•In June bp, State Oil Company of the Azerbaijan Republic (SOCAR) and TPAO signed agreements enabling TPAO to join the production-sharing agreement* (PSA) for the Shafag-Asiman offshore block in the Azerbaijan sector of the Caspian Sea. The agreement provides for the drilling of a well into the Lower Surakhany reservoir and the extension of the term of the PSA. The deal is expected to be completed by the end of the third quarter of 2025.

•In June Shafag (Jabrayil) Solar Ltd, bp’s joint venture with SOCAR Green and the Azerbaijan Business Development Fund, announced FID on the 240MWAC Shafag solar plant in the Jabrayil district of Azerbaijan. In parallel the investors in the Sangachal terminal sanctioned the linked Sangachal terminal electrificaton project.

•In July bp and Libya’s National Oil Corporation (NOC) signed a memorandum of understanding to explore redevelopment of the mature giant Sarir and Messla oilfields in Libya’s Sirte basin and assess the wider unconventional potential within the country.

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

bp announced: the Raven Infills project in the West Nile Delta (WND) had started production ahead of schedule (bp 82.75% operator, Harbour Energy 17.25%); the successful completion of the “El Fayoum-5” gas discovery well in the North Alexandria Offshore Concession in WND; it has agreed for Apollo-managed funds to purchase a 25% non-controlling stake in bp Pipelines TANAP Limited, the bp subsidiary that holds a 12% share in the TANAP pipeline, for consideration of approximately $1.0 billion; it achieved two major milestones in Trinidad & Tobago, sanctioning the Ginger gas development and exploration success at its Frangipani well; its Cypre development (located in Trinidad & Tobago) safely delivered its first gas; and it safely loaded the first cargo of LNG for export from its GTA Phase 1 project offshore Mauritania and Senegal.

8

gas & low carbon energy (continued)

low carbon energy

•In August bp and JERA Co., Inc. completed formation of a new joint venture (JV) called JERA Nex bp. The JV will aim to become one of the largest global offshore wind developers and operators (total 13GW potential net generating capacity).

•In June bp completed the sale of 100% of its interest in a parcel of land located at Astoria, in the City and State of New York, to the Power Authority of the State of New York.

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

•In July bp announced that it has agreed to sell its US onshore wind business, BP Wind Energy North America Inc., to LS Power, a leading development, investment and operating company focused on the North American power and energy infrastructure sector. Subject to regulatory approvals the deal is expected to complete by the end of 2025.

•In July bp informed its partners in the Australian Renewable Energy Hub in the Pilbara region of Western Australia that it intends to exit the project as operator and equity holder. bp will work with its partners to ensure a safe and efficient transition of operatorship.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2025	2025	2024	2025	2024
Profit (loss) before interest and tax	1,047	1,358	(315)	2,405	721
Inventory holding (gains) losses*	—	—	—	—	—
RC profit (loss) before interest and tax	1,047	1,358	(315)	2,405	721
Net (favourable) adverse impact of adjusting items	415	(361)	1,717	54	2,339
Underlying RC profit before interest and tax	1,462	997	1,402	2,459	3,060
Taxation on an underlying RC basis	(509)	(471)	(369)	(980)	(887)
Underlying RC profit before interest	953	526	1,033	1,479	2,173

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Sales and other operating revenues(a)
Sales and other operating revenues	9,172	5,809	19,950	14,484
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,407	1,209	2,573	2,502
Exploration write-offs
Exploration write-offs	1	28	1	231
Adjusted EBITDA*(b)
Total adjusted EBITDA	2,870	2,639	5,033	5,793
Capital expenditure*
gas(c)	688	1,016	1,462	1,770
low carbon energy	102	136	231	795
Total capital expenditure(c)	790	1,152	1,693	2,565

(a)Includes sales to other segments.

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

(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.

9

gas & low carbon energy (continued)

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
Production (net of royalties)(d)
Liquids* (mb/d)	85	98	84	100
Natural gas (mmcf/d)	4,043	4,648	3,997	4,678
Total hydrocarbons* (mboe/d)	782	899	773	907
Of which equity-accounted entities:
Liquids (mb/d)	5	2	5	2
Natural gas (mmcf/d)	170	—	169	—
Total hydrocarbons (mboe/d)	34	2	34	2
Average realizations*(e)
Liquids ($/bbl)	64.15	79.92	67.21	78.38
Natural gas ($/mcf)	6.50	5.47	6.86	5.46
Total hydrocarbons ($/boe)	40.84	36.85	43.00	36.75

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

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

10

oil production & operations

Financial results

•Sales and other operating revenues for the second quarter and half year were $6.1 billion and $12.6 billion respectively, compared with $6.7 billion and $13.1 billion for the corresponding periods in 2024. For the second quarter and half year, revenues were lower mainly due to lower liquids realizations, partly offset by higher volumes.

•The replacement cost (RC) profit before interest and tax for the second quarter and half year was $1,916 million and $4,704 million respectively, compared with $3,267 million and $6,327 million for the same periods in 2024. The second quarter and half year are adjusted by an adverse impact of net adjusting items* of $346 million and $453 million respectively, compared with a favourable impact of net adjusting items of $173 million and $108 million for the same periods in 2024. See page 28 for more information on adjusting items.

•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the second quarter and half year was $2,262 million and $5,157 million respectively, compared with $3,094 million and $6,219 million for the same periods in 2024.

•The underlying RC profit before interest and tax for the second quarter and half year, compared with the same periods in 2024, primarily reflects lower realizations and a higher depreciation, depletion and amortization charge, partially offset by higher production. Underlying operating expenditure* for the half year, compared with the same period in 2024, was broadly flat, with structural cost reductions offset by growth and inflation.

Operational update

•Reported production for the quarter was 1,518mboe/d, 2.5% higher than the same period in 2024. Underlying production* for the quarter was 0.8% higher reflecting higher production in bpx, partly offset by planned maintenance.

•Reported production for the half year was 1,497mboe/d, 1.7% higher than the same period in 2024. Underlying production was 1.1% higher reflecting improved base performance partly offset by planned maintenance.

Strategic progress

•In June bp announced it had signed fully termed agreements with the State Oil Company of the Azerbaijan Republic (SOCAR) to acquire 35% participating interests and become the operator of two exploration and development blocks in the Caspian Sea – the Karabagh oil field and the Ashrafi-Dan Ulduzu-Aypara (ADUA) area.

•In July, Azule Energy, bp's 50% joint venture (Azule), and operator of Block 15/06 in Angola, together with its partners, announced the successful start-up of the Agogo Integrated West Hub Project, which aims to fully develop the Agogo and Ndungu fields in Block 15/06.

•In July Azule, operator of Block 1/14, and its partners announced a gas discovery at the Gajajeira-01 exploration well, located offshore in the Lower Congo Basin, Angola. The well was spudded on 1 April 2025 in a water depth of 95 metres, approximately 60 kilometres off the coast.

•In June bpx Energy started up the Crossroads facility in the Permian Basin, bpx's fourth and final central delivery facility to be built, following the earlier Grand Slam, Checkmate and Bingo facilities.

•In July bpx Energy took over operations from Devon Energy of certain assets in the Eagle Ford Shale following the dissolution of their joint venture in the Blackhawk Field.

•In June bp took the final investment decision on the Atlantis Major Facility Expansion Project, which is expected to increase water injection capacity. First water injection is targeted for 2027.

•In August bp announced an exploration discovery at the Bumerangue prospect in the deepwater offshore Brazil. bp drilled exploration well 1-BP-13-SPS at the Bumerangue block, located in the Santos Basin, 404 kilometres (218 nautical miles) from Rio de Janeiro, in a water depth of 2,372 metres. The well was drilled to a total depth of 5,855 metres. The well intersected the reservoir about 500 metres below the crest of the structure and penetrated an estimated 500 metre gross hydrocarbon column, in high-quality pre-salt carbonate reservoir with an areal extent of greater than 300km2. Results from the rig-site analysis indicate elevated levels of carbon dioxide. bp will now begin laboratory analysis to further characterize the reservoir and fluids discovered, which will provide additional insight into the potential of the Bumerangue block. bp holds a 100% participation in the block with Pré-Sal Petróleo S.A. as the Production Sharing Contract manager. bp secured the block in December 2022 during the 1st Cycle of the Open Acreage of Production Sharing of the Brazilian national petroleum agency (ANP).

•In August bp announced the start-up of the Argos Southwest Extension project in the Gulf of America. The project consists of three wells and a new drill centre tied back to the Argos platform and is expected to add 20,000 barrels of oil equivalent per day of gross peak annualized average production. bp is operator of Argos with 60.5% working interest, with co-owners Woodside Energy (23.9%) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6%).

•These events build on the progress announced in our first-quarter results, which comprised the following: bp received final government ratification for its contract to invest in the redevelopment of several giant oil fields in Kirkuk, in the north of Iraq; bp announced a Miocene oil discovery at the Far South prospect in the US Gulf of America (bp 57.5% operator); in January the initial producer well from West Chirag, Azerbaijan, in the deeper non-associated gas reservoirs encountered hydrocarbons; Azule Energy, in collaboration with its New Gas Consortium (NGC) partners, completed installation of the jacket and deck of the Quiluma offshore platform, a key step in Angola’s first non-associated gas development; and in April, Rhino Resources (42.5%) along with co-venturers Azule Energy (42.5%), Namcor (10%), and Korres Investments (5%) announced the successful drilling of the Capricornus 1-X exploration well in block PEL-85 in the Orange basin, Namibia.

11

oil production & operations (continued)

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2025	2025	2024	2025	2024
Profit before interest and tax	1,914	2,795	3,268	4,709	6,327
Inventory holding (gains) losses*	2	(7)	(1)	(5)	—
RC profit before interest and tax	1,916	2,788	3,267	4,704	6,327
Net (favourable) adverse impact of adjusting items	346	107	(173)	453	(108)
Underlying RC profit before interest and tax	2,262	2,895	3,094	5,157	6,219
Taxation on an underlying RC basis	(1,062)	(1,375)	(1,171)	(2,437)	(2,680)
Underlying RC profit before interest	1,200	1,520	1,923	2,720	3,539

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Sales and other operating revenues(a)
Sales and other operating revenues	6,053	6,659	12,555	13,091
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,933	1,698	3,720	3,355
Exploration write-offs
Exploration write-offs	81	99	134	102
Adjusted EBITDA*(b)
Total adjusted EBITDA	4,276	4,891	9,011	9,676
Capital expenditure*
Total capital expenditure	1,706	1,534	3,402	3,310

(a)Includes sales to other segments.

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

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
Production (net of royalties)(c)
Liquids* (mb/d)	1,115	1,085	1,101	1,071
Natural gas (mmcf/d)	2,338	2,292	2,298	2,328
Total hydrocarbons* (mboe/d)	1,518	1,481	1,497	1,472
Of which equity-accounted entities:
Liquids (mb/d)	271	265	267	270
Natural gas (mmcf/d)	443	445	440	423
Total hydrocarbons (mboe/d)	347	342	342	343
Average realizations*(d)
Liquids ($/bbl)	59.74	73.01	63.54	71.79
Natural gas ($/mcf)	3.66	2.02	4.18	2.35
Total hydrocarbons ($/boe)	49.03	55.78	52.66	54.94

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

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

12

customers & products

Financial results

•Sales and other operating revenues for the second quarter and half year were $37.4 billion and $73.6 billion respectively, compared with $41.1 billion and $81.0 billion for the corresponding periods in 2024. The decrease in the second quarter and half year was mainly due to lower product prices in 2025.

•The replacement cost (RC) profit before interest and tax for the second quarter and half year was $972 million and $1,075 million respectively, compared with a loss of $133 million and a profit of $855 million for the same periods in 2024. The second quarter and half year are adjusted by an adverse impact of net adjusting items* of $561 million and $1,135 million respectively, compared with an adverse impact of net adjusting items of $1,282 million and $1,583 million for the same periods in 2024. See page 28 for more information on adjusting items.

•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* (underlying result) for the second quarter and half year was $1,533 million and $2,210 million respectively, compared with $1,149 million and $2,438 million for the same periods in 2024.

•The customers & products underlying result for the second quarter was higher than the same period in 2024, primarily reflecting a stronger customers result and oil trading contribution, partly offset by a lower refining performance. The result for the half year was lower than the same period in 2024, primarily reflecting a lower refining performance, partly offset by a higher customers result and lower underlying operating expenditure* across customers and products as we build momentum in our structural cost reduction programme.

•customers – the customers underlying result for the second quarter and half year was higher compared with the same periods in 2024. The underlying result benefited from stronger integrated performance across fuels and midstream, with Castrol's earnings in the first half of 2025 more than 20% higher compared to the same period last year, driven by higher volumes and margins. The first half also benefited from lower underlying operating expenditure.

•products – the products underlying result for the second quarter was higher compared with the same period in 2024, mainly due to a strong oil trading contribution. In refining, the second quarter was impacted by significantly higher turnaround activity and lower realized margins reflecting narrower North American heavy crude oil differentials, partly offset by stronger operations and commercial delivery. The products result for the first half was lower compared with the same period in 2024, primarily reflecting significantly lower realized refining margins and higher turnaround activity, partly offset by the absence of the first quarter 2024 plant-wide power outage at the Whiting refinery and lower underlying operating expenditure.

Operational update

•bp-operated refining availability* for the second quarter and half year was 96.4% and 96.3%, compared with 96.4% and 93.4% for the same periods in 2024. The half year was higher reflecting strong performance and notably the absence of the Whiting refinery power outage.

Strategic progress

•In July, bp announced the sale of its Netherlands mobility & convenience and bp pulse businesses to Catom BV. The sale is expected to complete by the end of 2025 subject to regulatory approvals.

•During the second quarter, bp opened three EV fast charging Gigahubs near airports in Los Angeles, Boston and San Francisco, and signed a strategic agreement with Waffle House, in the US, to expand ultrafast(a) EV charging network at its locations.

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

◦bp announced a strategic review of its Castrol business with the intention of accelerating Castrol’s next phase of value delivery.

◦bp announced plans to sell its mobility and convenience business in Austria. bp is targeting to close the divestment by the end of 2025.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2025	2025	2024	2025	2024
Profit (loss) before interest and tax	420	255	(270)	675	1,570
Inventory holding (gains) losses*	552	(152)	137	400	(715)
RC profit (loss) before interest and tax	972	103	(133)	1,075	855
Net (favourable) adverse impact of adjusting items	561	574	1,282	1,135	1,583
Underlying RC profit before interest and tax	1,533	677	1,149	2,210	2,438
Of which:(b)
customers – convenience & mobility	1,056	664	790	1,720	1,160
Castrol – included in customers	245	238	211	483	395
products – refining & trading	477	13	359	490	1,278
Taxation on an underlying RC basis	(251)	(76)	(125)	(327)	(458)
Underlying RC profit before interest	1,282	601	1,024	1,883	1,980

(a)'ultra-fast' includes charger capacity of ≥150kW.

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

13

customers & products (continued)

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Sales and other operating revenues(c)
Sales and other operating revenues	37,449	41,100	73,612	80,995
Adjusted EBITDA*(d)
customers – convenience & mobility	1,698	1,281	2,929	2,135
Castrol – included in customers	295	253	579	479
products – refining & trading	895	807	1,326	2,186
	2,593	2,088	4,255	4,321
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,060	939	2,045	1,883
Capital expenditure*
customers – convenience & mobility	387	497	972	1,063
Castrol – included in customers	36	74	73	117
products – refining & trading(e)	410	401	768	840
Total capital expenditure(e)	797	898	1,740	1,903

(c)Includes sales to other segments.

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

(e)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.

	Second	Second	First	First
	quarter	quarter	half	half
Marketing sales of refined products (mb/d)	2025	2024	2025	2024
US	1,248	1,271	1,225	1,177
Europe	1,006	1,077	976	1,008
Rest of World	466	462	466	465
	2,720	2,810	2,667	2,650
Trading/supply sales of refined products	478	387	460	370
Total sales volume of refined products	3,198	3,197	3,127	3,020

bp average refining marker margin* (RMM) ($/bbl)	21.1	20.6	18.2	20.6
bp average refining indicator margin* (RIM) ($/bbl)	11.9	11.8	10.0	13.6

Refinery throughputs (mb/d)
US	573	670	623	598
Europe	715	722	768	775
Total refinery throughputs	1,288	1,392	1,391	1,373
bp-operated refining availability* (%)	96.4	96.4	96.3	93.4

14

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) profit before interest and tax for the second quarter and half year was $645 million and $623 million respectively, compared with a loss of $180 million and $480 million for the same periods in 2024. The second quarter and half year are adjusted by a favourable impact of net adjusting items* of $683 million and $778 million respectively, compared with an adverse impact of net adjusting items of $22 million and $168 million for the same periods in 2024. Adjusting items include favourable impacts of fair value accounting effects* of $740 million for the quarter and $1,109 million for the half year in 2025, and an adverse impact of $29 million and $222 million for the same periods in 2024. See page 28 for more information on adjusting items.

•After adjusting RC profit before interest and tax for adjusting items, the underlying RC loss before interest and tax* for the second quarter and half year was $38 million and $155 million respectively, compared with a loss of $158 million and $312 million for the same periods in 2024.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2025	2025	2024	2025	2024
Profit (loss) before interest and tax	645	(22)	(180)	623	(480)
Inventory holding (gains) losses*	—	—	—	—	—
RC profit (loss) before interest and tax	645	(22)	(180)	623	(480)
Net (favourable) adverse impact of adjusting items(a)	(683)	(95)	22	(778)	168
Underlying RC profit (loss) before interest and tax	(38)	(117)	(158)	(155)	(312)
Taxation on an underlying RC basis	109	33	3	142	102
Underlying RC profit (loss) before interest	71	(84)	(155)	(13)	(210)

(a)Includes fair value accounting effects relating to hybrid bonds. See page 36 for more information.

15

Financial statements

Group income statement

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Sales and other operating revenues (Note 5)	46,627	47,299	93,532	96,179
Earnings from joint ventures – after interest and tax	241	250	568	428
Earnings from associates – after interest and tax	155	266	404	564
Interest and other income	375	414	760	795
Gains on sale of businesses and fixed assets	279	21	293	245
Total revenues and other income	47,677	48,250	95,557	98,211
Purchases	26,875	28,891	54,595	56,538
Production and manufacturing expenses	6,153	6,692	12,267	13,539
Production and similar taxes	414	484	861	928
Depreciation, depletion and amortization (Note 6)	4,641	4,098	8,824	8,248
Net impairment and losses on sale of businesses and fixed assets (Note 3)	1,157	1,309	1,660	2,046
Exploration expense	139	179	242	426
Distribution and administration expenses	4,242	4,167	8,653	8,389
Profit (loss) before interest and taxation	4,056	2,430	8,455	8,097
Finance costs	1,229	1,216	2,550	2,291
Net finance (income) expense relating to pensions and other post-employment benefits	(56)	(40)	(108)	(81)
Profit (loss) before taxation	2,883	1,254	6,013	5,887
Taxation	954	1,184	3,102	3,408
Profit (loss) for the period	1,929	70	2,911	2,479
Attributable to
bp shareholders	1,629	(129)	2,316	2,134
Non-controlling interests	300	199	595	345
	1,929	70	2,911	2,479
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic	10.41	(0.78)	14.73	12.85
Diluted	10.27	(0.78)	14.44	12.54
Per ADS (dollars)
Basic	0.62	(0.05)	0.88	0.77
Diluted	0.62	(0.05)	0.87	0.75

16

Condensed group statement of comprehensive income

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Profit (loss) for the period	1,929	70	2,911	2,479
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences(a)	1,323	(142)	2,142	(590)
Cash flow hedges and costs of hedging	235	(100)	50	(215)
Share of items relating to equity-accounted entities, net of tax	3	10	4	2
Income tax relating to items that may be reclassified	(57)	40	(15)	36
	1,504	(192)	2,181	(767)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset	(214)	(240)	117	(306)
Remeasurements of equity investments	2	(17)	1	(30)
Cash flow hedges that will subsequently be transferred to the balance sheet	2	—	4	(3)
Income tax relating to items that will not be reclassified(b)	52	59	(43)	733
	(158)	(198)	79	394
Other comprehensive income	1,346	(390)	2,260	(373)
Total comprehensive income	3,275	(320)	5,171	2,106
Attributable to
bp shareholders	2,883	(520)	4,439	1,783
Non-controlling interests	392	200	732	323
	3,275	(320)	5,171	2,106

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

(b)First half 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%.

17

Condensed group statement of changes in equity

	bp shareholders’	Non-controlling interests		Total
$ million	equity	Hybrid bonds(a)	Other interest	equity
At 1 January 2025	59,246	16,649	2,423	78,318
Total comprehensive income	4,439	402	330	5,171
Dividends	(2,515)	—	(219)	(2,734)
Cash flow hedges transferred to the balance sheet, net of tax	(4)	—	—	(4)
Repurchase of ordinary share capital	(2,511)	—	—	(2,511)
Share-based payments, net of tax	594	—	—	594
Issue of perpetual hybrid bonds(b)	—	500	—	500
Payments on perpetual hybrid bonds	(9)	(511)	—	(520)
Transactions involving non-controlling interests, net of tax(c)	—	—	966	966
At 30 June 2025	59,240	17,040	3,500	79,780
	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	1,783	310	13	2,106
Dividends	(2,431)	—	(186)	(2,617)
Cash flow hedges transferred to the balance sheet, net of tax	(4)	—	—	(4)
Repurchase of ordinary share capital	(3,502)	—	—	(3,502)
Share-based payments, net of tax	654	—	—	654
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	—	(419)	—	(419)
Transactions involving non-controlling interests, net of tax	236	—	247	483
At 30 June 2024	67,024	13,457	1,718	82,199

(a)On 4 August 2025 BP Capital Markets p.l.c. issued notice to voluntarily redeem $1.2 billion of hybrid bonds effective 1 September 2025. This is expected to reduce non-controlling interest and increase net debt in the third quarter.

(b)During the first half 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.

(c)In the first half 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.

18

Group balance sheet

	30 June	31 December
$ million	2025	2024
Non-current assets
Property, plant and equipment	100,862	100,238
Goodwill	15,180	14,888
Intangible assets	9,271	9,646
Investments in joint ventures	12,299	12,291
Investments in associates	7,579	7,741
Other investments	1,227	1,292
Fixed assets	146,418	146,096
Loans	2,371	1,961
Trade and other receivables	2,712	1,815
Derivative financial instruments	16,540	16,114
Prepayments	555	548
Deferred tax assets	5,936	5,403
Defined benefit pension plan surpluses	8,132	7,457
	182,664	179,394
Current assets
Loans	224	223
Inventories	24,752	23,232
Trade and other receivables	27,583	27,127
Derivative financial instruments	4,959	5,112
Prepayments	2,875	2,594
Current tax receivable	966	1,096
Other investments	245	165
Cash and cash equivalents	35,067	39,204
	96,671	98,753
Assets classified as held for sale (Note 2)	5,402	4,081
	102,073	102,834
Total assets	284,737	282,228
Current liabilities
Trade and other payables	57,324	58,411
Derivative financial instruments	4,093	4,347
Accruals	5,244	6,071
Lease liabilities	2,865	2,660
Finance debt	5,843	4,474
Current tax payable	2,243	1,573
Provisions	5,101	3,600
	82,713	81,136
Liabilities directly associated with assets classified as held for sale (Note 2)	1,378	1,105
	84,091	82,241
Non-current liabilities
Other payables	8,016	9,409
Derivative financial instruments	15,670	18,532
Accruals	1,565	1,326
Lease liabilities	11,771	9,340
Finance debt	54,503	55,073
Deferred tax liabilities	8,654	8,428
Provisions	15,613	14,688
Defined benefit pension plan and other post-employment benefit plan deficits	5,074	4,873
	120,866	121,669
Total liabilities	204,957	203,910
Net assets	79,780	78,318
Equity
bp shareholders’ equity	59,240	59,246
Non-controlling interests	20,540	19,072
Total equity	79,780	78,318

19

Condensed group cash flow statement

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Operating activities
Profit (loss) before taxation	2,883	1,254	6,013	5,887
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,723	4,225	8,959	8,581
Net impairment and (gain) loss on sale of businesses and fixed assets	878	1,288	1,367	1,801
Earnings from equity-accounted entities, less dividends received	40	19	(160)	(77)
Net charge for interest and other finance expense, less net interest paid	126	524	273	716
Share-based payments	215	507	616	668
Net operating charge for pensions and other post-employment benefits, less contributions and benefit payments for unfunded plans	(36)	(34)	(47)	(66)
Net charge for provisions, less payments	666	764	1,770	81
Movements in inventories and other current and non-current assets and liabilities	(2,030)	1,556	(7,099)	(575)
Income taxes paid	(1,194)	(2,003)	(2,587)	(3,907)
Net cash provided by operating activities	6,271	8,100	9,105	13,109
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,236)	(3,463)	(6,587)	(7,181)
Acquisitions, net of cash acquired	(39)	(116)	(241)	(222)
Investment in joint ventures	(59)	(95)	(117)	(448)
Investment in associates	(27)	(17)	(39)	(118)
Total cash capital expenditure	(3,361)	(3,691)	(6,984)	(7,969)
Proceeds from disposal of fixed assets	322	35	614	101
Proceeds from disposal of businesses, net of cash disposed	76	219	112	566
Proceeds from loan repayments	31	24	62	40
Cash provided from investing activities	429	278	788	707
Net cash used in investing activities	(2,932)	(3,413)	(6,196)	(7,262)
Financing activities
Net issue (repurchase) of shares (Note 7)	(1,063)	(1,751)	(2,910)	(3,501)
Lease liability payments	(784)	(679)	(1,511)	(1,373)
Proceeds from long-term financing	1,155	2,736	1,209	4,995
Repayments of long-term financing	(848)	(623)	(2,214)	(1,297)
Net increase (decrease) in short-term debt	39	49	(86)	65
Issue of perpetual hybrid bonds	—	—	500	1,296
Redemption of perpetual hybrid bonds	—	—	—	(1,288)
Payments relating to perpetual hybrid bonds	(332)	(271)	(604)	(527)
Receipts relating to transactions involving non-controlling interests (Other interest)	965	508	965	524
Dividends paid - bp shareholders	(1,238)	(1,204)	(2,495)	(2,423)
- non-controlling interests	(127)	(60)	(201)	(186)
Net cash provided by (used in) financing activities	(2,233)	(1,295)	(7,347)	(3,715)
Currency translation differences relating to cash and cash equivalents	193	(11)	299	(271)
Increase (decrease) in cash and cash equivalents	1,299	3,381	(4,139)	1,861
Cash and cash equivalents at beginning of period	33,831	31,510	39,269	33,030
Cash and cash equivalents at end of period(a)	35,130	34,891	35,130	34,891

(a)Second quarter and first half 2025 includes $63 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.

20

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.

The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements.

bp prepares its consolidated financial statements included within bp Annual Report and Form 20-F on the basis of IFRS Accounting Standards® (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the UK, and 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 approximately $0.5 billion.

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 is expected to result in a non-cash deferred tax charge of approximately $300 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.

21

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 June 2025 is $5,402 million, with associated liabilities of $1,378 million.

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. The carrying amount of assets classified as held for sale at 30 June 2025 is $569 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 these assets within one year of the acquisition date is considered to be highly probable. The carrying amount of assets classified as held for sale at 30 June 2025 is $1,894 million, with associated liabilities of $1,244 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 have, therefore, been classified as held for sale as at 30 June 2025. The carrying amount of assets classified as held for sale at 30 June 2025 is $2,546 million, with associated liabilities of $9 million.

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 June 2025 is $375 million, with associated liabilities of $86 million.

Transactions that were classified as held for sale during 2025, but completed during the second quarter, are described below.

On 31 January 2025 bp and Devon Energy agreed to dissolve their Eagle Ford partnership and divide up the assets. The carrying amount of assets classified as held for sale at 31 March 2025 was $593 million, with associated liabilities of $53 million. The dissolution completed on 1 April 2025.

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 second quarter and half year were $1,157 million and $1,660 million respectively, compared with net charges of $1,309 million and $2,046 million for the same periods in 2024 and include net impairment charges for the second quarter and half year of $1,130 million and $1,561 million respectively, compared with net impairment charges of $1,296 million and $1,945 million for the same periods in 2024. 

Gas & low carbon energy

Second quarter and half year 2025 impairments includes a net impairment charge of $431 million and $746 million respectively, compared with net charges of $589 million and $1,125 million for the same periods in 2024 in the gas & low carbon energy segment.

Customers & products

Second quarter and half year 2025 impairments includes a net impairment charge of $373 million and $477 million respectively, compared with net charges of $681 million and $691 million for the same periods in 2024 in the customers & products segment.

22

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

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
gas & low carbon energy	1,047	(315)	2,405	721
oil production & operations	1,916	3,267	4,704	6,327
customers & products	972	(133)	1,075	855
other businesses & corporate	645	(180)	623	(480)
	4,580	2,639	8,807	7,423
Consolidation adjustment – UPII*	30	(73)	43	(41)
	4,610	2,566	8,850	7,382
Inventory holding gains (losses)*
gas & low carbon energy	—	—	—	—
oil production & operations	(2)	1	5	—
customers & products	(552)	(137)	(400)	715
Profit (loss) before interest and tax	4,056	2,430	8,455	8,097
Finance costs	1,229	1,216	2,550	2,291
Net finance expense/(income) relating to pensions and other post-employment benefits	(56)	(40)	(108)	(81)
Profit (loss) before taxation	2,883	1,254	6,013	5,887
RC profit (loss) before interest and tax*
US	1,417	1,545	2,950	3,155
Non-US	3,193	1,021	5,900	4,227
	4,610	2,566	8,850	7,382

23

Note 5. Sales and other operating revenues

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
By segment
gas & low carbon energy	9,172	5,809	19,950	14,484
oil production & operations	6,053	6,659	12,555	13,091
customers & products	37,449	41,100	73,612	80,995
other businesses & corporate	539	526	1,023	1,132
	53,213	54,094	107,140	109,702
Less: sales and other operating revenues between segments
gas & low carbon energy	337	371	1,068	641
oil production & operations	5,818	5,982	11,636	11,895
customers & products	(55)	25	(13)	318
other businesses & corporate	486	417	917	669
	6,586	6,795	13,608	13,523
External sales and other operating revenues
gas & low carbon energy	8,835	5,438	18,882	13,843
oil production & operations	235	677	919	1,196
customers & products	37,504	41,075	73,625	80,677
other businesses & corporate	53	109	106	463
Total sales and other operating revenues	46,627	47,299	93,532	96,179
By geographical area
US	18,890	20,340	37,979	40,198
Non-US	36,233	36,832	71,934	76,040
	55,123	57,172	109,913	116,238
Less: sales and other operating revenues between areas	8,496	9,873	16,381	20,059
	46,627	47,299	93,532	96,179
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	421	538	836	1,086
Oil products	28,572	32,548	55,734	62,388
Natural gas, LNG and NGLs	6,049	4,987	13,312	10,738
Non-oil products and other revenues from contracts with customers	3,697	3,108	7,330	6,036
Revenue from contracts with customers	38,739	41,181	77,212	80,248
Other operating revenues(a)	7,888	6,118	16,320	15,931
Total sales and other operating revenues	46,627	47,299	93,532	96,179

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

Note 6. Depreciation, depletion and amortization

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Total depreciation, depletion and amortization by segment
gas & low carbon energy	1,407	1,209	2,573	2,502
oil production & operations	1,933	1,698	3,720	3,355
customers & products	1,060	939	2,045	1,883
other businesses & corporate	241	252	486	508
	4,641	4,098	8,824	8,248
Total depreciation, depletion and amortization by geographical area
US	1,897	1,703	3,633	3,273
Non-US	2,744	2,395	5,191	4,975
	4,641	4,098	8,824	8,248

24

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. 170 million and 45 million ordinary shares repurchased were settled during the second quarter 2025 against the authority granted at bp's 2024 and 2025 annual general meetings respectively, for a total cost of $1,063 million. All of these shares were held as treasury shares. A further 98 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 June 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.

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Results for the period
Profit (loss) for the period attributable to bp shareholders	1,629	(129)	2,316	2,134
Less: preference dividend	1	1	1	1
Less: (gain) loss on redemption of perpetual hybrid bonds	—	—	—	(10)
Profit (loss) attributable to bp ordinary shareholders	1,628	(130)	2,315	2,143
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding	15,645,561	16,590,173	15,711,554	16,670,999
ADS equivalent(c)	2,607,593	2,765,028	2,618,592	2,778,499
Weighted average number of shares outstanding used to calculate diluted earnings per share	15,854,588	16,590,173	16,026,670	17,090,967
ADS equivalent(c)	2,642,431	2,765,028	2,671,111	2,848,494
Shares in issue at period-end	15,596,112	16,491,420	15,596,112	16,491,420
ADS equivalent(c)	2,599,352	2,748,570	2,599,352	2,748,570

(a)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the second quarter 2024 are 374,406 thousand (ADS equivalent 62,401 thousand).

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

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

Issued ordinary share capital as at 30 June 2025 comprised 15,900,733,509 ordinary shares (31 December 2024 16,180,991,411 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 585,579,485 ordinary shares which have been bought back and are held in treasury by bp (31 December 2024 481,473,840 ordinary shares).

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 September 2025 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 15 August 2025. The ex-dividend date will be 14 August 2025 for ordinary shareholders and 15 August 2025 for ADS holders. The corresponding amount in sterling is due to be announced on 9 September 2025, calculated based on the average of the market exchange rates over three dealing days between 3 September 2025 and 5 September 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 second 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 second quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
Dividends paid per ordinary share
cents	8.000	7.270	16.000	14.540
pence	5.899	5.683	12.075	11.375
Dividends paid per ADS (cents)	48.00	43.62	96.00	87.24

25

Note 9. Net debt

Net debt*	30 June	30 June	31 December
$ million	2025	2024	2024
Finance debt(a)	60,346	54,986	59,547
Fair value (asset) liability of hedges related to finance debt(b)	764	2,519	2,654
	61,110	57,505	62,201
Less: cash and cash equivalents	35,067	34,891	39,204
Net debt(c)	26,043	22,614	22,997
Total equity	79,780	82,199	78,318
Gearing*	24.6%	21.6%	22.7%

(a)The fair value of finance debt at 30 June 2025 was $57,135 million (30 June 2024 $50,677 million, 31 December 2024 $54,966 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 $96 million at 30 June 2025 (second quarter 2024 liability of $144 million and fourth quarter 2024 liability of $166 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. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 4 August 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.

26

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.

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Capital expenditure
Organic capital expenditure*	3,321	3,586	6,761	7,565
Inorganic capital expenditure*	40	105	223	404
	3,361	3,691	6,984	7,969

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Capital expenditure by segment
gas & low carbon energy(a)	790	1,152	1,693	2,565
oil production & operations	1,706	1,534	3,402	3,310
customers & products(a)	797	898	1,740	1,903
other businesses & corporate	68	107	149	191
	3,361	3,691	6,984	7,969
Capital expenditure by geographical area
US	1,576	1,636	3,009	3,412
Non-US	1,785	2,055	3,975	4,557
	3,361	3,691	6,984	7,969

(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.

27

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.

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
gas & low carbon energy
Gains on sale of businesses and fixed assets	69	8	68	10
Net impairment and losses on sale of businesses and fixed assets(a)	(439)	(590)	(805)	(1,126)
Environmental and related provisions	—	—	—	—
Restructuring, integration and rationalization costs	3	—	(11)	—
Fair value accounting effects(b)(c)	18	(1,011)	686	(898)
Other	(66)	(124)	8	(325)
	(415)	(1,717)	(54)	(2,339)
oil production & operations
Gains on sale of businesses and fixed assets	196	7	205	191
Net impairment and losses on sale of businesses and fixed assets	(330)	(29)	(345)	(149)
Environmental and related provisions	(55)	195	(86)	118
Restructuring, integration and rationalization costs	(46)	—	(87)	—
Fair value accounting effects	—	—	—	—
Other	(111)	—	(140)	(52)
	(346)	173	(453)	108
customers & products
Gains on sale of businesses and fixed assets	16	4	19	9
Net impairment and losses on sale of businesses and fixed assets(a)	(389)	(678)	(503)	(774)
Environmental and related provisions	(1)	7	(1)	7
Restructuring, integration and rationalization costs	(86)	—	(177)	1
Fair value accounting effects(c)	(201)	25	(283)	(119)
Other(d)	100	(640)	(190)	(707)
	(561)	(1,282)	(1,135)	(1,583)
other businesses & corporate
Gains on sale of businesses and fixed assets	—	—	—	32
Net impairment and losses on sale of businesses and fixed assets	—	(11)	(5)	15
Environmental and related provisions	(18)	28	(90)	19
Restructuring, integration and rationalization costs	(39)	1	(237)	12
Fair value accounting effects(c)	740	(29)	1,109	(222)
Gulf of America oil spill	(9)	(8)	(18)	(19)
Other	9	(3)	19	(5)
	683	(22)	778	(168)
Total before interest and taxation	(639)	(2,848)	(864)	(3,982)
Finance costs(e)	(78)	(205)	(265)	(297)
Total before taxation	(717)	(3,053)	(1,129)	(4,279)
Taxation on adjusting items(f)	400	585	539	694
Taxation – tax rate change effect(g)	—	(304)	(539)	(304)
Total after taxation for period	(317)	(2,772)	(1,129)	(3,889)

(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 page 5, 8 and 36.

(d)Second quarter and first half 2024 include 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 and 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. All periods presented for 2025 include 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)First half 2025 and second quarter 2024 and first half 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.

28

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 June	30 June	31 December
$ million	2025	2024	2024
Net debt*	26,043	22,614	22,997
Lease liabilities	14,636	10,697	12,000
Net partner (receivable) payable for leases entered into on behalf of joint operations	(1,030)	(112)	(88)
Net debt including leases	39,649	33,199	34,909
Total equity	79,780	82,199	78,318
Gearing including leases*	33.2%	28.8%	30.8%

Gulf of America oil spill

	30 June	31 December
$ million	2025	2024
Gulf of America oil spill payables and provisions	(7,100)	(7,958)
Of which - current	(1,500)	(1,127)
Deferred tax asset	1,086	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.

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.

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Profit for the period	1,929	70	2,911	2,479
Finance costs	1,229	1,216	2,550	2,291
Net finance (income) expense relating to pensions and other post-employment benefits	(56)	(40)	(108)	(81)
Taxation	954	1,184	3,102	3,408
Profit before interest and tax	4,056	2,430	8,455	8,097
Inventory holding (gains) losses*, before tax	554	136	395	(715)
	4,610	2,566	8,850	7,382
Net (favourable) adverse impact of adjusting items*, before interest and tax	639	2,848	864	3,982
	5,249	5,414	9,714	11,364
Add back:
Depreciation, depletion and amortization	4,641	4,098	8,824	8,248
Exploration expenditure written off	82	127	135	333
Adjusted EBITDA	9,972	9,639	18,673	19,945

29

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.

	Second	Second	First	First
	quarter	quarter	half	half	Year	Year
$ million	2025	2024	2025	2024	2024	2023
From group income statement
Production and manufacturing expenses	6,153	6,692	12,267	13,539	26,584	25,044
Distribution and administration expenses	4,242	4,167	8,653	8,389	16,417	16,772
	10,395	10,859	20,920	21,928	43,001	41,816
Less certain variable costs:
Transportation and shipping costs(a)	2,634	2,199	5,080	5,090	10,516	9,650
Environmental costs(a)	1,630	1,309	2,967	1,868	3,987	4,271
Marketing and distribution costs	421	501	848	1,132	1,882	2,430
Commission, storage and handling costs	405	391	771	751	1,519	1,633
Other variable costs and non-cash costs	435	445	732	1,041	1,495	743
Certain variable costs and non-cash costs	5,525	4,845	10,398	9,882	19,399	18,727
Adjusted operating expenditure*	4,870	6,014	10,522	12,046	23,602	23,089
Less certain adjusting items*:
Gulf of America oil spill	9	8	18	19	51	57
Environmental and related provisions	74	(230)	177	(144)	181	647
Restructuring, integration and rationalization costs	168	(1)	512	(13)	222	(37)
Fair value accounting effects – derivative instruments relating to the hybrid bonds	(740)	29	(1,109)	222	221	(630)
Other certain adjusting items	(98)	767	163	1,010	601	419
Certain adjusting items	(587)	573	(239)	1,094	1,276	456
Underlying operating expenditure	5,457	5,441	10,761	10,952	22,326	22,633
(Decrease) increase in underlying operating expenditure			(191)		(307)
Of which:
Structural cost reduction*			(938)		(750)
Increase/(decrease) in underlying operating expenditure due to inflation, exchange movements, portfolio changes and growth			747		443
Structural cost reduction at 30 June 2025 compared with 2023
Structural cost reduction in 2024			(750)
Structural cost reduction in the first half 2025			(938)
Total structural cost reduction			(1,688)

(a)Comparatives have been restated for a reclassification in costs from transportation and shipping to environmental.

30

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

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
RC profit (loss) before interest and tax for customers & products	972	(133)	1,075	855
Less: Adjusting items* gains (charges)	(561)	(1,282)	(1,135)	(1,583)
Underlying RC profit (loss) before interest and tax for customers & products	1,533	1,149	2,210	2,438
By business:
customers – convenience & mobility	1,056	790	1,720	1,160
Castrol – included in customers	245	211	483	395
products – refining & trading	477	359	490	1,278
Add back: Depreciation, depletion and amortization	1,060	939	2,045	1,883
By business:
customers – convenience & mobility	642	491	1,209	975
Castrol – included in customers	50	42	96	84
products – refining & trading	418	448	836	908
Adjusted EBITDA for customers & products	2,593	2,088	4,255	4,321
By business:
customers – convenience & mobility	1,698	1,281	2,929	2,135
Castrol – included in customers	295	253	579	479
products – refining & trading	895	807	1,326	2,186

Reconciliation of gas & low carbon energy and oil production & operations RC profit before interest and tax to adjusted EBITDA*

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
gas & low carbon energy
RC profit before interest and tax	1,047	(315)	2,405	721
Less: Net favourable (adverse) impact of adjusting items*	(415)	(1,717)	(54)	(2,339)
Underlying RC profit before interest and tax*	1,462	1,402	2,459	3,060
Add back: Depreciation, depletion and amortization	1,407	1,209	2,573	2,502
Exploration write-offs	1	28	1	231
Adjusted EBITDA	2,870	2,639	5,033	5,793
oil production & operations
RC profit before interest and tax	1,916	3,267	4,704	6,327
Less: Net favourable (adverse) impact of adjusting items	(346)	173	(453)	108
Underlying RC profit before interest and tax	2,262	3,094	5,157	6,219
Add back: Depreciation, depletion and amortization	1,933	1,698	3,720	3,355
Exploration write-offs	81	99	134	102
Adjusted EBITDA	4,276	4,891	9,011	9,676

31

Reconciliation of basic earnings per ordinary share / ADS to underlying replacement cost profit (loss) per ordinary share* / ADS*

	Second	Second	First	First
	quarter	quarter	half	half
Per ordinary share (cents)	2025	2024	2025	2024
Profit (loss) for the period attributable to bp shareholders	10.41	(0.78)	14.73	12.85
Inventory holding (gains) losses*, before tax	3.54	0.82	2.51	(4.29)
Taxation charge (credit) on inventory holding gains and losses	(0.94)	(0.14)	(0.67)	1.03
	13.01	(0.10)	16.57	9.59
Net (favourable) adverse impact of adjusting items*, before tax(a)	4.58	18.40	7.19	25.59
Taxation charge (credit) on adjusting items(a)	(2.56)	(1.69)	—	(2.32)
Underlying RC profit (loss)	15.03	16.61	23.76	32.86
	Second	Second	First	First
	quarter	quarter	half	half
Per ADS (dollars)	2025	2024	2025	2024
Profit (loss) for the period attributable to bp shareholders	0.62	(0.05)	0.88	0.77
Inventory holding (gains) losses, before tax	0.21	0.05	0.15	(0.26)
Taxation charge (credit) on inventory holding gains and losses	(0.05)	(0.01)	(0.04)	0.07
	0.78	(0.01)	0.99	0.58
Net (favourable) adverse impact of adjusting items, before tax(a)	0.27	1.10	0.44	1.54
Taxation charge (credit) on adjusting items(a)	(0.15)	(0.09)	—	(0.15)
Underlying RC profit (loss)	0.90	1.00	1.43	1.97

(a)First half 2024 calculated based on adjusting items and taxation credits thereon of $4,279 million and $390 million respectively, as adjusted for the gain on redemption of hybrid bonds of $13 million and taxation thereon of $3 million respectively.

Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss* and underlying ETR*

Taxation (charge) credit	Second	Second	First	First
	quarter	quarter	half	half
$ million	2025	2024	2025	2024
Taxation on profit or loss before taxation	(954)	(1,184)	(3,102)	(3,408)
Taxation on inventory holding gains and losses	147	23	106	(171)
Taxation on a replacement cost (RC) profit or loss basis	(1,101)	(1,207)	(3,208)	(3,237)
Total taxation on adjusting items	400	281	—	390
Taxation on underlying replacement cost profit or loss	(1,501)	(1,488)	(3,208)	(3,627)

Effective tax rate	Second	Second	First	First
	quarter	quarter	half	half
%	2025	2024	2025	2024
ETR on profit or loss before taxation	33	94	52	58
Adjusted for inventory holding gains or losses	(1)	(7)	(2)	5
ETR on RC profit or loss	32	87	50	63
Excluding adjusting items	4	(54)	(7)	(25)
Underlying ETR	36	33	43	38

32

Realizations* and marker prices

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
Average realizations(a)
Liquids* ($/bbl)
US	53.39	65.88	57.54	64.11
Europe	64.62	80.55	70.09	82.90
Rest of World	69.69	83.58	72.09	81.67
bp average	60.16	73.73	63.88	72.49
Natural gas ($/mcf)
US	2.52	1.29	2.82	1.49
Europe	13.06	9.49	14.81	9.94
Rest of World	6.50	5.47	6.86	5.46
bp average	5.56	4.47	5.97	4.55
Total hydrocarbons* ($/boe)
US	39.51	44.26	42.77	42.90
Europe	68.02	73.21	74.91	75.08
Rest of World	48.44	47.49	50.82	47.05
bp average	45.84	47.49	48.95	46.95
Average oil marker prices ($/bbl)
Brent	67.88	84.97	71.87	84.06
West Texas Intermediate	63.81	80.82	67.60	78.95
Western Canadian Select	53.16	67.20	55.74	63.56
Alaska North Slope	68.82	86.42	72.30	83.91
Mars	64.89	81.37	68.69	79.17
Urals (NWE – cif)	57.08	72.79	60.71	70.55
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)	3.44	1.89	3.55	2.07
UK Gas – National Balancing Point (p/therm)	84.53	76.57	100.47	72.62

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

(b)Henry Hub First of Month Index.

Exchange rates

	Second	Second	First	First
	quarter	quarter	half	half
	2025	2024	2025	2024
$/£ average rate for the period	1.34	1.26	1.30	1.26
$/£ period-end rate	1.37	1.27	1.37	1.27
$/€ average rate for the period	1.13	1.08	1.09	1.08
$/€ period-end rate	1.17	1.07	1.17	1.07
$/AUD average rate for the period	0.64	0.66	0.63	0.66
$/AUD period-end rate	0.65	0.67	0.65	0.67

33

Principal risks and uncertainties

The principal risks and uncertainties affecting bp are described in the Risk factors section of bp Annual Report and Form 20-F 2024 (pages 65-67) and are summarized below. There are no material changes expected in those risk factors for the remaining six months of the financial year.

The risks and uncertainties summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks

•Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, climate policies and regulations, exchange rate fluctuations, and the general macroeconomic outlook.

•Accessing and progressing hydrocarbon resources and low carbon opportunities – inability to access and progress hydrocarbon resources and low carbon opportunities could adversely affect delivery of our strategy.

•Major project* delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.

•Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.

•Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial frame could impact our ability to operate and result in financial loss.

•Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, including non-operated joint ventures (NOJVs), contractors and sub-contractors could result in legal liability and reputational damage.

•Digital infrastructure, cyber security and data protection – breach or failure of our or third parties’ digital infrastructure or cyber security, including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.

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

•Competition – inability to remain efficient, maintain a high-quality portfolio of assets and innovate could negatively impact delivery of our strategy in a highly competitive market.

•Talent and capability – inability to attract, develop and retain people with necessary skills, capabilities and behaviours could negatively impact delivery of our strategy.

•Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business.

•Insurance – our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks

•Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.

•Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities.

•Security – hostile acts against our employees and activities could cause harm to people and disrupt our operations.

•Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks

•Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.

•Regulation – changes in the law and regulation could increase costs, constrain our operations and affect our strategy, business plans and financial performance.

•Trading and treasury trading activities – ineffective oversight of trading and treasury trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation and affect our permissions to trade.

•Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.

34

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 31 for the segments.

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 29 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 30.

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 28.

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.

CMU Cash Flow and ROACE Targets are the following targets first announced by bp on 26 February 2025: (i) bp’s target for adjusted free cash flow compound annual growth of greater than 20% from 2024-2027; and (ii) bp’s target for group ROACE above 16% in 2027.

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

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

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.

35

Glossary (continued)

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. A reconciliation to IFRS information is provided on page 32.

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.

36

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 26.

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 29.

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 27.

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 27.

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.

The Refining marker margin (RMM) is the average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.

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 3. 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.

Solomon availability – See Refining availability definition.

Structural cost reduction is calculated as decreases in underlying operating expenditure* (as defined on page 39) 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 30.

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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. A reconciliation to IFRS information is provided on page 32.

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 30.

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 38) after excluding net adjusting items and related taxation. See page 28 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 3 for the group and pages 8-15 for the segments.

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. A reconciliation to IFRS information is provided on page 32.

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Glossary (continued)

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.

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; plans and expectations regarding bp’s net debt , investment strategy, capital expenditures, capital frame, underlying effective tax rate, and depreciation, depletion and amortization; plans and expectations regarding a review of bp’s portfolio of businesses and a further cost review including the outcomes of those reviews; expectations regarding bp’s tax liabilities and future impact of German tax legislation on bp’s results of operations, financial position and tax obligations; expectations regarding bp’s customers business, including with respect to volumes and fuel margins; expectations regarding bp’s products, including underlying performance, refinery turnaround activity, refining margins and operations; expectations regarding bp’s other businesses & corporate underlying annual charge; expectations regarding Gulf of America settlement payments; expectations regarding improvements associated with bp’s transition to a refining indicator margin (RIM) and the associated refining rule of thumb (RoT); expectations regarding TPAO’s participation in the Shafag-Asiman production-sharing agreement; expectations regarding bp’s low carbon energy business, including the JERA Nex bp offshore wind joint venture, bp’s plans to sell its US onshore wind business and timing of completion, and bp’s plans to exit the Australian Renewable Energy Hub project; expectations regarding the Agogo Integrated West Hub Project; expectations regarding the Gajajeira-01 exploration well, plans and expectations in relation to the discovery in the Bumerangue block including the outcome of laboratory testing of hydrocarbon samples and the potential of the discovery; plans and expectations regarding the Argos Southwest Extension project and oil production; expectations regarding bp’s investment in the Atlantis Major Facility Expansion Project; expectations regarding bp’s plans to sell its Netherlands mobility & convenience and bp pulse businesses, including timing of completion of the divestment; expectations regarding bp’s plans to sell its mobility and convenience business in Austria, including timing of the divestment; expectations regarding sale of certain assets of Lightsource bp, including timing of completion of the sale; and expectations regarding the principal risks and uncertainties affecting 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 “Risk factors” in bp’s Annual Report and Form 20-F for fiscal year 2024 as filed with the US Securities and Exchange Commission.

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2025:

Capitalization and indebtedness

	30 June
$ million	2025
Share capital and reserves
Capital shares (1-2)	4,142
Paid-in surplus (3)	16,916
Merger reserve (3)	27,206
Treasury shares	(7,773)
Investments in equity instruments	(3)
Cash flow hedge reserve	(89)
Costs of hedging reserve	(148)
Foreign currency translation reserve	(213)
Profit and loss account	19,202
BP shareholders' equity	59,240
Hybrid bonds	17,040
Other interest	3,500
Equity attributable to non-controlling interests	20,540
Total equity	79,780
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year	2,865
Finance debt due within one year	5,843
Lease liabilities due after more than one year	11,771
Finance debt due after more than one year	54,503
Total finance debt and lease liabilities	74,982
Total (7)(8)	154,762

1.Issued share capital as of 30 June 2025 comprised 15,900,733,509 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 585,579,485 ordinary shares which have been bought back and are held in treasury by bp. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.

2.Capital shares represent the ordinary and preference shares of bp which have been issued and are fully paid.

3.Paid-in surplus and merger reserve represent additional paid-in capital of bp which cannot normally be returned to shareholders.

4.Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2025.

5.Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under leases. This includes one hundred percent of lease liabilities for joint operations where bp is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2024 – Liquidity and capital resources for further information.

6.At 30 June 2025, the parent company, BP p.l.c. had issued guarantees totalling $59,454 million relating to group finance debt issued by subsidiaries. Thus 99% of the group’s finance debt had been guaranteed by BP p.l.c. In addition, BP p.l.c. guarantees $11.9 billion of perpetual subordinated hybrid bonds issued by a subsidiary. At 30 June 2025, $1,059 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

7.At 30 June 2025, the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $620 million in respect of the borrowings of equity-accounted entities and $370 million in respect of the borrowings of other third parties.

8.Total capitalisation and indebtedness includes non-controlling interests of $20,540 million at 30 June 2025 which includes $14.5 billion related to perpetual hybrid bonds and $2.5 billion related to perpetual subordinated hybrid securities issued by group subsidiaries. See Condensed group statement of changes in equity footnotes for further information.

9.There has been no material change since 30 June 2025 in the consolidated capitalization and indebtedness of bp.

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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:	5 August 2025	/s/ BEN MATHEWS
		Ben J. S. Mathews
		Company Secretary

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