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 October 2024

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¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

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 September 2024(a)

		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-September 2024(b)	3-16, 27-33, 34-39
2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-September 2024	17-26
3.	Legal proceedings	34
4.	Cautionary statement	40
5.	Capitalization and Indebtedness	41
6.	Signatures	42

(a)In this Form 6-K, references to the nine months2024 and nine months 2023 refer to the nine-month periods ended 30 September 2024 and 30 September 2023 respectively. References to the third quarter 2024 and third quarter 2023 refer to the three-month periods ended 30 September 2024 and 30 September 2023 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 2023.

2

Group results third quarter and nine months 2024

Driving focus and efficiencies; delivering resilient operations

Financial summary	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2024	2024	2023	2024	2023
Profit for the period	370	70	5,069	2,849	15,444
Less: Non-controlling interests	164	199	211	509	576
Profit (loss) for the period attributable to bp shareholders	206	(129)	4,858	2,340	14,868
Inventory holding (gains) losses*, before tax	1,182	136	(1,593)	467	(261)
Taxation charge (credit) on inventory holding gains and losses	(276)	(23)	381	(105)	50
Replacement cost (RC) profit (loss)*	1,112	(16)	3,646	2,702	14,657
Net (favourable) adverse impact of adjusting items*, before tax	1,646	3,053	(511)	5,925	(3,783)
Taxation charge (credit) on adjusting items	(491)	(281)	158	(881)	(29)
Underlying RC profit*	2,267	2,756	3,293	7,746	10,845

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Operating cash flow*	6,761	8,747	19,870	22,662
Capital expenditure*	(4,542)	(3,603)	(12,511)	(11,542)
Divestment and other proceeds(a)	290	655	1,463	1,543
Net cash issue (repurchase) of shares(b)	(2,001)	(2,047)	(5,502)	(6,568)
Finance debt	57,470	48,810	57,470	48,810
Net debt*(c)	24,268	22,324	24,268	22,324
Adjusted EBITDA*	9,654	10,306	29,599	33,142
Announced dividend per ordinary share (cents per share)	8.000	7.270	23.270	21.150
Profit per ordinary share (cents)	1.26	28.24	14.19	84.77
Profit per ADS (dollars)	0.08	1.69	0.85	5.09
Underlying RC profit per ordinary share* (cents)	13.89	19.14	46.79	61.83
Underlying RC profit per ADS* (dollars)	0.83	1.15	2.81	3.71

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

(b)Third quarter and nine months 2024 include $0.3 billion to offset the expected dilution from the vesting of awards under employee share schemes (third quarter 2023 $0.2 billion, nine months 2023 $0.7 billion).

(c)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 ADSare 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 34.

3

Highlights(a)
3Q24 profit $0.2 billion; underlying replacement cost (RC) profit* $2.3 billion
•	Profit for the quarter attributable to bp shareholders was $0.2 billion, compared with a loss of $0.1 billion for the second quarter 2024 and a profit of $4.9 billion for the third quarter 2023. The result for the third quarter 2024 is adjusted for inventory holding losses* of $1.2 billion (pre-tax) and a net adverse impact of adjusting items* of $1.6 billion (pre-tax) to derive the underlying RC profit. Adjusting items pre-tax include impairments of $1.7 billion (see Note 3) and favourable fair value accounting effects* of $0.4 billion. See page 28 for more information on adjusting items.
•	Underlying RC profit for the quarter was $2.3 billion, compared with $2.8 billion for the previous quarter and $3.3 billion for the third quarter 2023. Compared with the second quarter 2024, the underlying result reflects weaker realized refining margins, a weak oil trading result and lower liquids realizations, partly offset by higher gas realizations. The gas marketing and trading result was average.
Segment results
•	Gas & low carbon energy: The RC profit before interest and tax for the third quarter 2024 was $1.0 billion, compared with a loss of $0.3 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.7 billion, the underlying RC profit before interest and tax* for the third quarter was $1.8 billion, compared with $1.4 billion in the second quarter 2024. The third quarter underlying result before interest and tax is largely driven by higher gas realizations. The gas marketing and trading result was average.
•	Oil production & operations: The RC profit before interest and tax for the third quarter 2024 was $1.9 billion, compared with $3.3 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.9 billion, the underlying RC profit before interest and tax for the third quarter was $2.8 billion, compared with $3.1 billion in the second quarter 2024. The third quarter underlying result before interest and tax reflects lower liquids realizations and higher exploration write-offs.
•	Customers & products: The RC profit before interest and tax for the third quarter 2024 was $23 million, compared with a loss of $0.1 billion for the previous quarter. After adjusting RC profit before interest and tax for a net adverse impact of adjusting items of $0.4 billion, the underlying RC profit before interest and tax (underlying result) for the third quarter was $0.4 billion, compared with $1.1 billion in the second quarter 2024. The customers third quarter underlying result was higher by $0.1 billion, reflecting broadly flat fuels margins, seasonally higher volumes partly offset by costs. The products third quarter underlying result was lower by $0.9 billion, mainly reflecting weaker realized refining margins and a weak oil trading contribution which was lower than the second quarter.
Operating cash flow* $6.8 billion, finance debt $57.5 billion and net debt* $24.3 billion
•	Operating cash flow in the quarter was $6.8 billion, compared with $8.7 billion for the same period of 2023. Finance debt at the end of the third quarter 2024 was $57.5 billion, compared with $52.0 billion for the end of the fourth quarter 2023. Net debt increased to $24.3 billion compared to the second quarter, primarily driven by lower operating cash flow, higher capital expenditures and lower divestment and other proceeds. Net debt at the end of the fourth quarter 2023 was $20.9 billion.
Growing distributions within an unchanged financial frame
•	A resilient dividend is bp’s first priority within its disciplined financial frame, underpinned by a cash balance point* of around $40 per barrel Brent, $11 per barrel RMM and $3 per mmBtu Henry Hub (all 2021 real). For the third quarter, bp has announced a dividend per ordinary share of 8 cents.
•	bp is committed to maintaining a strong balance sheet and strong investment grade credit rating. Through the cycle, we are targeting to further improve our credit metrics within an 'A' grade credit range.
•	bp continues to invest with discipline and a returns focused approach in our transition growth* engines and in our oil, gas and refining businesses.
•	The $1.75 billion share buyback programme announced with the second quarter results was completed on 25 October 2024. Related to the third quarter results, bp intends to execute a $1.75 billion share buyback prior to reporting the fourth quarter results. Furthermore, bp is committed to announcing $1.75 billion for the fourth quarter of 2024. In addition, our previous guidance for at least $14 billion of share buybacks through 2025 at market conditions around bp's fourth quarter 2023 results(b) and subject to maintaining a strong investment grade credit rating, is currently unchanged, although as part of the update to our medium term plans in February 2025, we intend to review elements of our financial guidance, including our expectations for 2025 share buybacks.
•	In setting the dividend per ordinary share and buyback each quarter, the board will continue to take into account factors including the cumulative level of and outlook for surplus cash flow, the cash balance point and maintaining a strong investment grade credit rating.

(a)This report discusses certain material changes in bp’s results of operations with respect to the quarter ended 30 September 2024 as compared to the quarter ended 30 June 2024. Financial information for the quarter ended 30 June 2024 can be in found in our Current Report on Form 6-K filed with the SEC on 30 July 2024.

(b)6 February 2024.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.

4

Financial results

In addition to the highlights on page 4:

•Profit attributable to bp shareholders in the third quarter and nine months was $0.2 billion and $2.3 billion respectively, compared with a profit of $4.9 billion and $14.9 billion in the same periods of 2023.

–After adjusting profit attributable to bp shareholders for inventory holding losses or gains* and net impact of adjusting items*, underlying replacement cost (RC) profit* for the third quarter and nine months was $2.3 billion and $7.7 billion respectively, compared with $3.3 billion and $10.8 billionfor the same periods of 2023. The underlying RC profit for the third quarter mainly reflects lower refining margins and a weak oil trading contribution compared with a very strong result in the same period of 2023. The gas marketing and trading result for the quarter was average compared with a weak result in the third quarter of 2023. For the nine months, the reduction mainly reflects lower refining margins, a lower gas marketing and trading result, a lower oil trading contribution and lower realizations, partly offset by lower taxation.

–Adjusting items in the third quarter and nine months had a net adverse pre-tax impact of $1.6 billion and $5.9 billion respectively, compared with a net favourable pre-tax impact of $0.5 billion and $3.8 billion in the same periods of 2023.

–Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are a favourable pre-tax impact of $0.4 billion for the third quarter and an adverse pre-tax impact of $0.9 billion for the nine months, compared with a favourable pre-tax impact of $1.5 billion and $6.8 billion in the same periods of 2023. This is primarily due to an increase in the forward price of LNG over the 2024 periods, compared to a decline in the comparative periods of 2023. The third quarter 2024 is also impacted by the favourable impact of the fair value accounting effects relating to the hybrid bonds.

–Adjusting items for the third quarter and nine months of 2024 include an adverse pre-tax impact of asset impairments of $1.7 billionand $3.7 billion respectively, compared with an adverse pre-tax impact of $0.6 billion and $1.8 billionin the same periods of 2023. Third quarter and nine months 2023 included a $0.5 billion impairment charge recognized through equity-accounted earnings relating to US offshore wind projects.

•The effective tax rate (ETR) on the profit or loss before taxation for the third quarter and nine months was 74% and 61% respectively, compared with 31% and 32% for the same periods in 2023. The ETR on RC profit or loss* for the third quarter and nine months was 51% and 59% respectively, compared with 33% and 32% for the same periods in 2023. Excluding adjusting items, the underlying ETR* for the third quarter and nine months was 42% and 40%, compared with 33% and 39% for the same periods a year ago. The higher underlying ETR for the third quarter reflects changes in the geographical mix of profits and the absence of adjustments in respect of prior periods. ETR on RC profit or loss and underlying ETR are non-IFRS measures.

•Operating cash flow* for the third quarter and nine months was $6.8 billion and $19.9 billion respectively, compared with $8.7 billion and $22.7 billion for the same periods in 2023.

•Capital expenditure* in the third quarter and nine months was $4.5 billion and $12.5 billion respectively, compared with $3.6 billion and $11.5 billion in the same periods of 2023. Third quarter and nine months 2024 include a $0.7-billion initial payment in respect of German offshore wind. Nine months 2023 includes $1.1 billion in respect of the TravelCenters of America acquisition.

•Total divestment and other proceeds for the third quarter and nine months were $0.3 billion and $1.5 billion respectively, compared with $0.7 billion and $1.5 billionfor the same periods in 2023. There were no other proceeds for the third quarter 2024. Other proceeds for the nine months 2024 were $0.5 billion of proceeds from the sale of a 49% interest in a controlled affiliate holding certain midstream assets offshore US. Other proceeds for the third quarter and nine months of 2023 were $0.5 billion of proceeds from the sale of a 49% interest in a similar controlled affiliate holding certain midstream assets onshore US.

•Finance debt at the end of the third quarter was $57.5 billion, compared with $52.0 billion at the end of the fourth quarter 2023 and $48.8 billion at the end of the third quarter 2023. At the end of the third quarter, net debt* was $24.3 billion, compared with $20.9 billion at the end of the fourth quarter 2023 and $22.3 billion at the end of the third quarter 2023 driven primarily by the impact of weaker realized refining margins and by the rephasing of around $1 billion of divestment proceeds into the fourth quarter.

5

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
RC profit (loss) before interest and tax
gas & low carbon energy	1,007	2,275	1,728	11,911
oil production & operations	1,891	3,427	8,218	9,312
customers & products	23	1,549	878	4,784
other businesses & corporate	653	(500)	173	(887)
Consolidation adjustment – UPII*	65	(57)	24	(109)
	3,639	6,694	11,021	25,011
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(1,059)	(978)	(3,269)	(2,622)
Taxation on a RC basis	(1,304)	(1,859)	(4,541)	(7,156)
Non-controlling interests	(164)	(211)	(509)	(576)
RC profit (loss) attributable to bp shareholders*	1,112	3,646	2,702	14,657
Inventory holding gains (losses)*	(1,182)	1,593	(467)	261
Taxation (charge) credit on inventory holding gains and losses	276	(381)	105	(50)
Profit (loss) for the period attributable to bp shareholders	206	4,858	2,340	14,868

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Underlying RC profit (loss) before interest and tax
gas & low carbon energy	1,756	1,256	4,816	6,945
oil production & operations	2,794	3,136	9,013	9,232
customers & products	381	2,055	2,819	5,610
other businesses & corporate	231	(303)	(81)	(769)
Consolidation adjustment – UPII	65	(57)	24	(109)
	5,227	6,087	16,591	20,909
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(1,001)	(882)	(2,914)	(2,303)
Taxation on an underlying RC basis	(1,795)	(1,701)	(5,422)	(7,185)
Non-controlling interests	(164)	(211)	(509)	(576)
Underlying RC profit attributable to bp shareholders*	2,267	3,293	7,746	10,845

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 8-16 for the segments.

Operating Metrics

Operating metrics	Nine months 2024	vs Nine months 2023
Tier 1 and tier 2 process safety events*	35	+6
Reported recordable injury frequency*	0.286	+4.8%
upstream* production(a) (mboe/d)	2,378	+3.0%
upstream unit production costs*(b) ($/boe)	6.25	+6.3%
bp-operated upstream plant reliability*	95.3%	-0.4
bp-operated refining availability*(a)	94.1%	-1.9

(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)Mainly reflecting portfolio mix.

6

Outlook & Guidance

4Q 2024 guidance

•Looking ahead, bp expects fourth quarter 2024 reported upstream* production to be lower compared with the third-quarter 2024.

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

•In products, bp expects realized refining margins to remain low in the fourth quarter, albeit to continue to remain sensitive to relative movements in product cracks.

2024 guidance

In addition to the guidance on page 4:

•bp continues to expect both reported and underlying upstream production* to be slightly higher compared with 2023. Within this, bp continues to expect underlying production from oil production & operations to be higher and production from gas & low carbon energy to be lower.

•In its customers business, bp continues to expect growth from convenience, including a full year contribution from TravelCenters of America; a stronger contribution from Castrol underpinned by volume growth in focus markets; and continued margin growth from bp pulse driven by higher energy sold. In addition, bp continues to expect fuels margins to remain sensitive to the cost of supply.

•In products, bp continues to expect a lower level of industry refining margins relative to 2023, with realized margins impacted by narrower North American heavy crude oil differentials. bp continues to expect refinery turnaround activity to have a lower financial impact compared to 2023, reflecting the lower margin environment. Phasing of turnaround activity in 2024 is heavily weighted towards the second half, with the highest impact in the fourth quarter.

•bp now expects other businesses & corporate underlying annual charge to be $0.3-0.4 billion for 2024.

•bp continues to expect the depreciation, depletion and amortization to be slightly higher than 2023.

•bp continues to expect the underlying ETR* for 2024 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 capital expenditure* for 2024 to be around $16 billion.

•bp now expects divestment and other proceeds to be greater than $3 billion in 2024. Having realized $19.2 billion of divestment and other proceeds since the second quarter of 2020, bp continues to expect to reach $25 billion of divestment and other proceeds between the second half of 2020 and 2025.

•During the fourth quarter, bp completed the transactions to acquire a further 50% of the issued ordinary shares of bp Bunge Bioenergia and 50.03% of the issued ordinary shares of Lightsource bp (see Note 10) and now owns 100% of the ordinary shares of both companies. Full earnings from both companies will be included in bp’s results from the date the transactions complete and finance debt acquired is expected to be approximately $3.7 billion.

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

bp expects to update on our medium-term plans at the same time as our full year results in February 2025.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.

7

gas & low carbon energy*

Financial results

•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,007 million and $1,728 million respectively, compared with $2,275 million and $11,911 million for the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $749 million and $3,088 million respectively, compared with a favourable impact of net adjusting items of $1,019 million and $4,966 million for the same periods in 2023. Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are an adverse impact of $275 million and $1,173 million for the third quarter and nine months in 2024 and a favourable impact of $1,816 million and $6,972 million for the same periods in 2023. Under IFRS, reported earnings include the mark-to-market value of the hedges used to risk-manage LNG contracts, but not of the LNG contracts themselves. The underlying result includes the mark-to-market value of the hedges but also recognizes changes in value of the LNG contracts being risk managed. 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 third quarter and nine months was $1,756 million and $4,816 million respectively, compared with $1,256 million and $6,945 million for the same periods in 2023.

•The underlying RC profit before interest and tax for the third quarter compared with the same period in 2023, reflects a lower depreciation, depletion and amortization charge partly offset by lower production. The gas marketing and trading result for the quarter was average compared with a weak result in the third quarter of 2023. The underlying RC profit before interest and tax for the nine months, compared with the same period in 2023, reflects a lower gas marketing and trading result, lower realizations, lower production, higher exploration write-offs and the foreign exchange loss in the first quarter, partly offset by a lower depreciation, depletion and amortization charge.

Operational update

•Reported production for the quarter was 890mboe/d, 6.0% lower than the same period in 2023. Underlying production* was 4.0% lower, mainly due to base decline, partially offset by major projects*.

•Reported production for the nine months was 901mboe/d, 4.1% lower than the same period in 2023. Underlying production was 2.4% lower, mainly due to reduced performance partially offset by major projects ramp up.

•Renewables pipeline* at the end of the quarter was 46.8GW (bp net), including 20.5GW bp net share of Lightsource bp's (LSbp's) pipeline. The renewables pipeline decreased by 11.5GW net during the nine months following high-grading and focus of hydrogen and CCUS projects. In addition, there is over 10GW (bp net) of early stage opportunities in LSbp's hopper.

Strategic progress

gas

•On 1 August bp announced it has completed the acquisition of GETEC ENERGIE GmbH, a leading supplier of energy to commercial and industrial (C&I) customers in Germany. Agreement for this deal was announced in January 2024 and will accelerate the growth of bp’s European gas and power presence.

•On 27 August bp announced it has agreed with EOG Resources Trinidad Limited (EOG) to partner on the Coconut gas development. Coconut will be a 50/50 joint venture with EOG as operator. The final investment decision has been taken by the joint venture partners and first gas is expected in 2027.

•On 2 September bp announced it has entered into an agreement with Perenco T&T to sell four mature offshore gas fields and associated production facilities in Trinidad & Tobago (Immortelle, Flamboyant, Amherstia and Cashima). The deal will also include undeveloped resources from the Parang area. Subject to government approval, the deal is expected to complete by the end of 2024.

•On 16 September bp announced it has agreed for Apollo-managed funds to purchase a non-controlling stake in bp Pipelines TAP Limited, the bp subsidiary that holds a 20% share in Trans Adriatic Pipeline AG (TAP). Upon completion, bp will remain the controlling shareholder of bp Pipelines TAP Limited.

low carbon energy

•On 12 September bp announced that bp and Iberdrola have taken a final investment decision for construction of a 25MW green hydrogen project at bp's Castellón refinery in Spain which is expected to be operational in second half of 2026. The project will be developed by Castellón Green Hydrogen S.L., a 50:50 joint venture between bp and Iberdrola.

•On 16 September bp announced plans to sell its existing US onshore wind energy business and aims to bring together the development of onshore renewable power projects through Lightsource bp. The sale comprises 10 operating onshore wind farms across seven US states with a combined gross capacity of 1.7GW (1.3GW net to bp).

•On 24 October bp announced it has completed its acquisition of the remaining 50.03% interest in Lightsource bp, one of the world’s leading developers and operators of utility-scale solar and battery storage assets operators.

8

gas & low carbon energy (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2024	2024	2023	2024	2023
Profit (loss) before interest and tax	1,007	(315)	2,275	1,728	11,912
Inventory holding (gains) losses*	—	—	—	—	(1)
RC profit (loss) before interest and tax	1,007	(315)	2,275	1,728	11,911
Net (favourable) adverse impact of adjusting items	749	1,717	(1,019)	3,088	(4,966)
Underlying RC profit before interest and tax	1,756	1,402	1,256	4,816	6,945
Taxation on an underlying RC basis	(545)	(369)	(448)	(1,432)	(1,984)
Underlying RC profit before interest	1,211	1,033	808	3,384	4,961

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,180	1,543	3,682	4,390
Exploration write-offs
Exploration write-offs	1	15	232	13
Adjusted EBITDA*(a)
Total adjusted EBITDA	2,937	2,814	8,730	11,348
Capital expenditure*
gas	1,188	833	2,696	2,177
low carbon energy	908	222	1,703	778
Total capital expenditure	2,096	1,055	4,399	2,955

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
Production (net of royalties)(b)
Liquids* (mb/d)	92	106	97	107
Natural gas (mmcf/d)	4,627	4,875	4,661	4,826
Total hydrocarbons* (mboe/d)	890	946	901	940
Of which equity-accounted entities:
Liquids (mb/d)	2	2	2	2
Natural gas (mmcf/d)	—	—	—	—
Total hydrocarbons (mboe/d)	2	2	2	2
Average realizations*(c)
Liquids ($/bbl)	74.80	76.69	77.23	76.51
Natural gas ($/mcf)	5.80	5.38	5.57	6.11
Total hydrocarbons ($/boe)	37.91	36.82	37.13	40.23

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

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

9

gas & low carbon energy (continued)

	30 September 2024	30 September 2023
low carbon energy(d)
Renewables (bp net, GW)
Installed renewables capacity*	2.8	2.5
Developed renewables to FID*	6.6	6.1
Renewables pipeline	46.8	43.9
of which by geographical area:
Renewables pipeline – Americas	17.8	18.4
Renewables pipeline – Asia Pacific	12.9	12.1
Renewables pipeline – Europe	15.4	13.4
Renewables pipeline – Other	0.7	—
of which by technology:
Renewables pipeline – offshore wind	9.6	9.3
Renewables pipeline – onshore wind	6.7	6.1
Renewables pipeline – solar	30.5	28.5
Total Developed renewables to FID and Renewables pipeline	53.4	50.0

(d)Because of rounding, some totals may not agree exactly with the sum of their component parts.

10

oil production & operations

Financial results

•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,891 million and $8,218 million respectively, compared with $3,427 million and $9,312 million for the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $903 million and $795 million respectively, compared with a favourable impact of net adjusting items of $291 million and $80 million for the same periods in 2023. 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 third quarter and nine months was $2,794 million and $9,013 million respectively, compared with $3,136 million and $9,232 million for the same periods in 2023.

•The underlying RC profit before interest and tax for the third quarter and nine months, compared with the same periods in 2023, primarily reflect increased depreciation charges, higher costs and higher exploration write-offs partly offset by increased volume.

Operational update

•Reported production for the quarter was 1,488mboe/d, 7.7% higher than the third quarter of 2023. Underlying production* for the quarter was 6.8% higher compared with the third quarter of 2023 reflecting bpx energy performance and major projects* partly offset by base performance and adverse weather conditions in the Gulf of Mexico.

•Reported production for the nine months was 1,477mboe/d, 7.8% higher than the nine months of 2023. Underlying production for the quarter was 7.5% higher compared with the nine months of 2023 reflecting bpx energy performance and major projects* partly offset by base performance.

Strategic Progress

•The Azeri and Chirag fields and the deepwater portion of the Gunashli field (ACG) venture announced the signing of an addendum to the existing production-sharing agreement (PSA)* which enables the parties to progress the exploration, appraisal, development of and production from the non-associated natural gas reservoirs of the ACG field (bp operator with 30.37% equity).

•bp and the State Oil Company of Azerbaijan Republic (SOCAR) signed a memorandum of understanding announcing bp’s intention to join SOCAR in two exploration and development blocks in the Azerbaijan sector of the Caspian Sea. The first block is the Karabagh oil field, the second block is the Ashrafi – Dan Ulduzu – Aypara area, containing a number of existing discoveries and prospective structures.

•Following on from the final investment decision on the Kaskida project in the Gulf of Mexico, bp entered into agreements with Enbridge Offshore Facilities LLC to construct, own and operate oil and gas export pipelines to transport oil from Kaskida to the Green Canyon 19 platform and gas to markets in Louisiana. bp also entered into agreements with Shell Pipeline Company LP to transport oil from Green Canyon 19 to markets in Louisiana via a new build pipeline.

•bp has signed a memorandum of understanding with the government of the Republic of Iraq to negotiate a material integrated redevelopment programme for the Kirkuk region, spanning oil and gas investment, power generation and solar, together with wider exploration activities.

•Aker BP - Oil production has started from the Tyrving field in the Alvheim area. Tyrving is operated by Aker BP (61.26% working interest).The Tyrving development is part of the life extension of the Alvheim field and is expected to increase production while reducing both unit costs and, at just 0.3kg of CO2 per barrel, emissions per barrel. Recoverable resources in Tyrving are approximately 25 million barrels of oil equivalent (gross) (bp 15.9% holding in Aker BP).

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2024	2024	2023	2024	2023
Profit before interest and tax	1,889	3,268	3,426	8,216	9,312
Inventory holding (gains) losses*	2	(1)	1	2	—
RC profit before interest and tax	1,891	3,267	3,427	8,218	9,312
Net (favourable) adverse impact of adjusting items	903	(173)	(291)	795	(80)
Underlying RC profit before interest and tax	2,794	3,094	3,136	9,013	9,232
Taxation on an underlying RC basis	(1,259)	(1,171)	(1,386)	(3,939)	(4,565)
Underlying RC profit before interest	1,535	1,923	1,750	5,074	4,667

11

oil production & operations (continued)

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,708	1,432	5,063	4,129
Exploration write-offs
Exploration write-offs	309	59	411	352
Adjusted EBITDA*(a)
Total adjusted EBITDA	4,811	4,627	14,487	13,713
Capital expenditure*
Total capital expenditure	1,410	1,644	4,720	4,642

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
Production (net of royalties)(b)
Liquids* (mb/d)	1,084	1,011	1,075	1,005
Natural gas (mmcf/d)	2,348	2,155	2,335	2,118
Total hydrocarbons* (mboe/d)	1,488	1,382	1,477	1,371
Of which equity-accounted entities:
Liquids (mb/d)	274	266	271	271
Natural gas (mmcf/d)	443	453	430	439
Total hydrocarbons (mboe/d)	350	344	346	346
Average realizations*(c)
Liquids ($/bbl)	70.22	71.10	71.26	70.65
Natural gas ($/mcf)	2.25	3.44	2.32	4.37
Total hydrocarbons ($/boe)	53.65	56.76	54.51	57.86

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

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

12

customers & products

Financial results

•The replacement cost (RC) profit before interest and tax for the third quarter and nine monthswas $23 million and $878 million respectively, compared with $1,549 million and $4,784 millionfor the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $358 million and $1,941 million respectively, mainly related to impairment of the Gelsenkirchen refinery and associated onerous contract provisions, compared with an adverse impact of net adjusting items of $506 million and $826 million for the same periods in 2023. 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 third quarter and nine months was $381 million and $2,819 million respectively, compared with $2,055 million and $5,610 million for the same periods in 2023.

•The customers & products underlying result for the third quarter was significantly lower than the same period in 2023, primarily reflecting lower refining margins and a weak oil trading contribution compared with a very strong result in the same period last year, partly offset by a higher customers result. The customers & products underlying result for the nine months was significantly lower than the same period in 2023, primarily reflecting lower refining margins and a lower oil trading contribution, partly offset by a higher customers result.

•customers – the customers underlying result for the third quarter and nine months was higher compared with the same periods in 2023, benefiting from higher retail fuels margins, a stronger Castrol result driven by higher volumes and margins and favourable foreign exchange movements. The underlying result was partly offset by a weaker European midstream performance driven by biofuels margins, lower retail volumes, and the continued impact of the US freight recession on TravelCenters of America.

•products – the products underlying result for the third quarter and nine months was significantly lower compared with the same periods in 2023. In refining, the underlying result for the third quarter was mainly impacted by lower industry refining margins, partly offset by higher commercial optimization. The oil trading contribution for the third quarter was weak, compared with the very strong result in the same period last year. The underlying result for the nine months was lower, primarily due to lower realized refining margins and the first quarter plant-wide power outage at the Whiting refinery, partly offset by a lower impact of turnaround activity. The underlying oil trading result for the nine months was lower than the same period last year.

Operational update

•bp-operated refining availability* for the third quarter and nine months was 95.6% and 94.1%, compared with 96.3% and 96.0% for the same periods in 2023, with the nine months lower mainly due to the first quarter Whiting refinery power outage.

Strategic progress

•In July, bp and Audi announced a new strategic partnership for Formula 1, including bp's development of the FIA defined advanced sustainable fuel(a) for Audi's 2026 entry and Castrol's development of lubricants and EV fluids for Audi's V6 turbo engine and electric motor and battery. The collaboration also included long-term sponsorship, making bp the first official partner of Audi's future Formula 1 factory team.

•On 1 October, bp took full ownership of bp Bunge Bioenergia, one of Brazil’s leading biofuels-producing companies, with capacity to produce around 50,000 barrels a day of ethanol equivalent from sugarcane.

•EV charge points* installed and energy sold in the first nine months grew by around 20% and two-fold respectively, compared to the same period last year, with energy sales now more than 1 TWh. bp continues to grow its global charging network, announcing an agreement in September with LAZ Parking, a privately owned parking operator in the US to collaborate in the development, deployment, and operation of ultra-fast(b) public charging hubs at LAZ-managed locations; and in India, Jio-bp, our fuels and mobility joint venture with Reliance, has now installed 5,000 charge points across India.

•In the third quarter, we continued to strengthen our convenience offer for our US customers, expanding the number of products offered by more than 50% in our recently launched private label brand epic goods. epic goods is our own line of private label consumer-packaged products for sale across our stores. In addition, bp announced the launch of earnify a loyalty program designed to provide customers with a seamless, integrated and rewarding experience, including exclusive discounts on retail store products and fuel purchases to around 5,500 bp, Amoco and ampm branded stores across the US.

•During the third quarter bp’s Archaea Energy started up three renewable natural gas (RNG) landfill plants with a total capacity of more than 4 million mmBtu per annum, bringing the total to seven RNG landfill plants started-up year to date, and expects to commission a further eight plants this year.

(a)For further details please refer to the press release dated 15 July 2024 on bp.com.

(b)"ultra-fast" includes charger capacity of ≥150kW.

13

customers & products (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2024	2024	2023	2024	2023
Profit (loss) before interest and tax	(1,157)	(270)	3,143	413	5,044
Inventory holding (gains) losses*	1,180	137	(1,594)	465	(260)
RC profit (loss) before interest and tax	23	(133)	1,549	878	4,784
Net (favourable) adverse impact of adjusting items	358	1,282	506	1,941	826
Underlying RC profit before interest and tax	381	1,149	2,055	2,819	5,610
Of which:(a)
customers – convenience & mobility	897	790	670	2,057	1,762
Castrol – included in customers	216	211	185	611	517
products – refining & trading	(516)	359	1,385	762	3,848
Taxation on an underlying RC basis	(67)	(125)	(167)	(525)	(1,215)
Underlying RC profit before interest	314	1,024	1,888	2,294	4,395

(a)A reconciliation to RC profit before interest and tax by business is provided on page 30.

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Adjusted EBITDA*(b)
customers – convenience & mobility	1,410	1,151	3,545	3,032
Castrol – included in customers	261	228	740	641
products – refining & trading	(66)	1,819	2,120	5,184
	1,344	2,970	5,665	8,216
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	963	915	2,846	2,606
Capital expenditure*
customers – convenience & mobility	455	435	1,518	2,345
Castrol – included in customers	50	60	167	172
products – refining & trading	476	367	1,578	1,305
Total capital expenditure	931	802	3,096	3,650

(b)A reconciliation to RC profit before interest and tax by business is provided on page 30.

Retail(c)	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
bp retail sites* – total (#)	21,200	21,150	21,200	21,150
Strategic convenience sites*	2,950	2,750	2,950	2,750

(c)Reported to the nearest 50.

Marketing sales of refined products (mb/d)	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
US	1,240	1,280	1,197	1,212
Europe	1,130	1,093	1,049	1,041
Rest of World	457	474	463	469
	2,827	2,847	2,709	2,722
Trading/supply sales of refined products	354	392	364	359
Total sales volume of refined products	3,181	3,239	3,073	3,081

14

customers & products (continued)

Refining marker margin*	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
bp average refining marker margin (RMM) ($/bbl)	16.5	31.8	19.2	28.2

Refinery throughputs (mb/d)	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
US	671	690	622	671
Europe	769	760	774	773
Total refinery throughputs	1,440	1,450	1,396	1,444
bp-operated refining availability* (%)	95.6	96.3	94.1	96.0

15

other businesses & corporate

Other businesses & corporate comprises technology, bp ventures, launchpad, regions, corporates & solutions, our corporate activities & functions and any residual costs of the Gulf of Mexico oil spill.

Financial results

•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $653 million and $173 million respectively, compared with a loss of $500 million and $887 million for the same periods in 2023. The third quarter and nine months are adjusted by a favourable impact of net adjusting items* of $422 million and $254 million respectively, compared with an adverse impact of net adjusting items of $197 million and $118 million for the same periods in 2023. Adjusting items include impacts of fair value accounting effects* which are a favourable impact of $494 million for the quarter and $272 million for the nine months in 2024, and an adverse impact of $146 million and a favourable impact of $51 millionfor the same periods in 2023. See page 28 for more information on adjusting items.

•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit or loss before interest and tax* for the third quarter and nine months was a profit of $231 million and a loss of $81 million respectively, compared with a loss of $303 million and $769 million for the same periods in 2023.

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Profit (loss) before interest and tax	653	(500)	173	(887)
Inventory holding (gains) losses*	—	—	—	—
RC profit (loss) before interest and tax	653	(500)	173	(887)
Net (favourable) adverse impact of adjusting items(a)	(422)	197	(254)	118
Underlying RC profit (loss) before interest and tax	231	(303)	(81)	(769)
Taxation on an underlying RC basis	(64)	162	38	201
Underlying RC profit (loss) before interest	167	(141)	(43)	(568)

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

16

Financial statements

Group income statement

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Sales and other operating revenues (Note 5)	47,254	53,269	143,433	157,989
Earnings from joint ventures – after interest and tax	406	(198)	834	357
Earnings from associates – after interest and tax	280	271	844	675
Interest and other income	438	410	1,233	1,036
Gains on sale of businesses and fixed assets	(48)	264	197	389
Total revenues and other income	48,330	54,016	146,541	160,446
Purchases	30,139	29,951	86,677	88,245
Production and manufacturing expenses	5,004	6,080	18,543	19,293
Production and similar taxes	469	456	1,397	1,334
Depreciation, depletion and amortization (Note 6)	4,117	4,145	12,365	11,868
Net impairment and losses on sale of businesses and fixed assets (Note 3)	1,842	542	3,888	1,899
Exploration expense	372	97	798	496
Distribution and administration expenses	3,930	4,458	12,319	12,039
Profit (loss) before interest and taxation	2,457	8,287	10,554	25,272
Finance costs	1,101	1,039	3,392	2,802
Net finance (income) expense relating to pensions and other post-retirement benefits	(42)	(61)	(123)	(180)
Profit (loss) before taxation	1,398	7,309	7,285	22,650
Taxation	1,028	2,240	4,436	7,206
Profit (loss) for the period	370	5,069	2,849	15,444
Attributable to
bp shareholders	206	4,858	2,340	14,868
Non-controlling interests	164	211	509	576
	370	5,069	2,849	15,444
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic	1.26	28.24	14.19	84.77
Diluted	1.23	27.59	13.83	82.99
Per ADS (dollars)
Basic	0.08	1.69	0.85	5.09
Diluted	0.07	1.66	0.83	4.98

17

Condensed group statement of comprehensive income

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Profit (loss) for the period	370	5,069	2,849	15,444
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	838	(590)	248	(126)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	—	(2)	—	(2)
Cash flow hedges and costs of hedging	(111)	(56)	(326)	434
Share of items relating to equity-accounted entities, net of tax	(41)	25	(39)	(205)
Income tax relating to items that may be reclassified	91	(69)	127	(74)
	777	(692)	10	27
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	(51)	(111)	(357)	(1,053)
Remeasurements of equity investments	(8)	—	(38)	—
Cash flow hedges that will subsequently be transferred to the balance sheet	10	(1)	7	(1)
Income tax relating to items that will not be reclassified(a)	12	57	745	388
	(37)	(55)	357	(666)
Other comprehensive income	740	(747)	367	(639)
Total comprehensive income	1,110	4,322	3,216	14,805
Attributable to
bp shareholders	922	4,140	2,705	14,241
Non-controlling interests	188	182	511	564
	1,110	4,322	3,216	14,805

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

18

Condensed group statement of changes in equity

	bp shareholders’	Non-controlling interests		Total
$ million	equity	Hybrid bonds	Other interest	equity
At 1 January 2024	70,283	13,566	1,644	85,493
Total comprehensive income	2,705	470	41	3,216
Dividends	(3,739)	—	(282)	(4,021)
Cash flow hedges transferred to the balance sheet, net of tax	(8)	—	—	(8)
Repurchase of ordinary share capital	(5,554)	—	—	(5,554)
Share-based payments, net of tax	903	—	—	903
Issue of perpetual hybrid bonds(a)	(4)	1,300	—	1,296
Redemption of perpetual hybrid bonds, net of tax(a)	9	(1,300)	—	(1,291)
Payments on perpetual hybrid bonds	—	(520)	—	(520)
Transactions involving non-controlling interests, net of tax	231	—	201	432
At 30 September 2024	64,826	13,516	1,604	79,946
	bp shareholders’	Non-controlling interests		Total
$ million	equity	Hybrid bonds	Other interest	equity
At 1 January 2023	67,553	13,390	2,047	82,990
Total comprehensive income	14,241	438	126	14,805
Dividends	(3,598)	—	(326)	(3,924)
Repurchase of ordinary share capital	(6,666)	—	—	(6,666)
Share-based payments, net of tax	531	—	—	531
Issue of perpetual hybrid bonds	(1)	163	—	162
Payments on perpetual hybrid bonds	(5)	(494)	—	(499)
Transactions involving non-controlling interests, net of tax	363	—	(86)	277
At 30 September 2023	72,418	13,497	1,761	87,676

(a)During the first quarter 2024 BP Capital Markets PLC issued $1.3 billion of US dollar perpetual subordinated hybrid bonds with a coupon fixed for an initial period up to 2034 of 6.45% and voluntarily bought back $1.3 billion of the non-call 2025 4.375% US dollar hybrid bond issued in 2020. Taken together these transactions had no significant impact on net debt or gearing.

19

Group balance sheet

	30 September	31 December
$ million	2024	2023
Non-current assets
Property, plant and equipment	99,555	104,719
Goodwill	12,873	12,472
Intangible assets	10,626	9,991
Investments in joint ventures	12,446	12,435
Investments in associates	7,932	7,814
Other investments	1,340	2,189
Fixed assets	144,772	149,620
Loans	2,270	1,942
Trade and other receivables	2,270	1,767
Derivative financial instruments	11,849	9,980
Prepayments	1,419	623
Deferred tax assets	5,478	4,268
Defined benefit pension plan surpluses	7,968	7,948
	176,026	176,148
Current assets
Loans	220	240
Inventories	21,493	22,819
Trade and other receivables	26,133	31,123
Derivative financial instruments	6,358	12,583
Prepayments	1,149	2,520
Current tax receivable	1,153	837
Other investments	167	843
Cash and cash equivalents	34,595	33,030
	91,268	103,995
Assets classified as held for sale (Note 2)	2,414	151
	93,682	104,146
Total assets	269,708	280,294
Current liabilities
Trade and other payables	54,385	61,155
Derivative financial instruments	3,762	5,250
Accruals	5,818	6,527
Lease liabilities	2,726	2,650
Finance debt	4,484	3,284
Current tax payable	1,706	2,732
Provisions	4,106	4,418
	76,987	86,016
Liabilities directly associated with assets classified as held for sale (Note 2)	32	62
	77,019	86,078
Non-current liabilities
Other payables	9,063	10,076
Derivative financial instruments	12,303	10,402
Accruals	1,197	1,310
Lease liabilities	8,292	8,471
Finance debt	52,986	48,670
Deferred tax liabilities	8,950	9,617
Provisions	14,649	14,721
Defined benefit pension plan and other post-retirement benefit plan deficits	5,303	5,456
	112,743	108,723
Total liabilities	189,762	194,801
Net assets	79,946	85,493
Equity
bp shareholders’ equity	64,826	70,283
Non-controlling interests	15,120	15,210
Total equity	79,946	85,493

20

Condensed group cash flow statement

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Operating activities
Profit (loss) before taxation	1,398	7,309	7,285	22,650
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,427	4,219	13,008	12,233
Net impairment and (gain) loss on sale of businesses and fixed assets	1,890	278	3,691	1,510
Earnings from equity-accounted entities, less dividends received	(196)	421	(273)	391
Net charge for interest and other finance expense, less net interest paid	324	136	1,040	301
Share-based payments	278	298	946	519
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(52)	(40)	(118)	(130)
Net charge for provisions, less payments	(48)	(342)	33	(1,662)
Movements in inventories and other current and non-current assets and liabilities	1,798	(783)	1,223	(5,280)
Income taxes paid	(3,058)	(2,749)	(6,965)	(7,870)
Net cash provided by operating activities	6,761	8,747	19,870	22,662
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(4,223)	(3,456)	(11,404)	(10,038)
Acquisitions, net of cash acquired	(218)	(9)	(440)	(761)
Investment in joint ventures	(76)	(102)	(524)	(692)
Investment in associates	(25)	(36)	(143)	(51)
Total cash capital expenditure	(4,542)	(3,603)	(12,511)	(11,542)
Proceeds from disposal of fixed assets	16	59	117	102
Proceeds from disposal of businesses, net of cash disposed	274	79	840	924
Proceeds from loan repayments	19	12	59	39
Cash provided from investing activities	309	150	1,016	1,065
Net cash used in investing activities	(4,233)	(3,453)	(11,495)	(10,477)
Financing activities
Net issue (repurchase) of shares (Note 7)	(2,001)	(2,047)	(5,502)	(6,568)
Lease liability payments	(703)	(663)	(2,076)	(1,838)
Proceeds from long-term financing	2,401	8	7,396	6,046
Repayments of long-term financing	(956)	(264)	(2,253)	(3,891)
Net increase (decrease) in short-term debt	(73)	(71)	(8)	(948)
Issue of perpetual hybrid bonds(a)	—	30	1,296	162
Redemption of perpetual hybrid bonds(a)	—	—	(1,288)	—
Payments relating to perpetual hybrid bonds	(271)	(258)	(798)	(744)
Payments relating to transactions involving non-controlling interests (Other interest)	—	—	—	(180)
Receipts relating to transactions involving non-controlling interests (Other interest)	(7)	527	517	536
Dividends paid - bp shareholders	(1,297)	(1,249)	(3,720)	(3,585)
- non-controlling interests	(96)	(191)	(282)	(326)
Net cash provided by (used in) financing activities	(3,003)	(4,178)	(6,718)	(11,336)
Currency translation differences relating to cash and cash equivalents	179	(104)	(92)	(118)
Increase (decrease) in cash and cash equivalents	(296)	1,012	1,565	731
Cash and cash equivalents at beginning of period	34,891	28,914	33,030	29,195
Cash and cash equivalents at end of period	34,595	29,926	34,595	29,926

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

21

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 2023 included in bp Annual Report and Form 20-F 2023.

bp prepares its consolidated financial statements included within bp Annual Report and Form 20-F on the basis of International Financial Reporting 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 2024 which are the same as those used in preparing bp Annual Report and Form 20-F 2023.

In July 2024, the new UK government announced further changes (effective from 1 November 2024) to the Energy Profits Levy including a 3% increase in the rate, an extension to 31 March 2030 and the removal of the Levy’s main investment allowance. The 30 October 2024 Autumn Budget may also announce further restrictions on capital allowance claims for Levy purposes. These changes have not yet been substantively enacted and therefore have not been applied in accounting for deferred tax in the third quarter 2024. The impacts will be reflected in the group consolidated financial statements when the changes are substantively enacted.

There are no new or amended standards or interpretations adopted from 1 January 2024 onwards that have a significant impact on the financial information.

Significant accounting judgements and estimates

bp's significant accounting judgements and estimates were disclosed in bp Annual Report and Form 20-F 2023. 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.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2024 is $2,414 million, with associated liabilities of $32 million and includes agreed sales of receivables relating to a prior divestment monetized at the beginning of the fourth quarter and divestments that are agreed but not yet completed as described below.

On 14 February 2024, bp and ADNOC announced that they had agreed to form a new joint venture (JV) in Egypt (51% bp and 49% ADNOC). As part of the agreement, bp will contribute its interests in three development concessions, as well as exploration agreements, in Egypt to the new JV. ADNOC will make a proportionate cash contribution. Subject to regulatory approvals and clearances, the formation of the JV is expected to complete during the fourth quarter of 2024. The carrying amount of assets classified as held for sale at 30 September 2024 is $1,453 million, with associated liabilities of $23 million.

On 16 November 2023, bp entered into an agreement to sell its Türkiye ground fuels business to Petrol Ofisi. This includes the group's interest in three joint venture terminals in Türkiye. Completion of the sale is subject to regulatory approvals and is expected to complete during the fourth quarter 2024. The carrying amount of assets classified as held for sale at 30 September 2024 is $107 million, with associated liabilities of $9 million. Cumulative foreign exchange losses within reserves of approximately $950 million are expected to be recycled to the group income statement at completion.

22

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

Net impairment charges and losses on sale of businesses and fixed assets for the third quarter and nine months were $1,842 million and $3,888 million respectively, compared with net charges of $542 million and $1,899 million for the same periods in 2023 and include net impairment charges for the third quarter and nine months of $1,730 million and $3,675 million respectively, compared with net impairment charges of $612 million and $1,779 millionfor the same periods in 2023. 

Gas & low carbon energy

Third quarter and nine months of 2024 impairments includes a net impairment charge of $734 million and $1,859 million respectively, compared with net charges of $224 million and $1,284 million for the same periods in 2023 in the gas & low carbon energy segment. 2024 includes amounts in Mauritania & Senegal which principally arose as a result of increased forecast future expenditure. The recoverable amount of the cash generating unit within this business was based on a value-in-use calculation.

Oil production & operations

Third quarter and nine months of 2024 impairments includes a net impairment charge of $767 million and $900 million respectively, compared with net charges of $142 million and $178 million for the same periods in 2023 in the oil production & operations segment. 2024 includes amounts in the North Sea. The recoverable amounts of the cash generating units within this business were based on value-in-use calculations.

Customers & products

Third quarter and nine months of 2024 impairments includes a net impairment charge of $223 million and $914 million respectively, compared with net charges of $221 million and $247 million for the same periods in 2023 in the customers & products segment. 2024 includes amounts in Germany relating to the ongoing review of the Gelsenkirchen refinery. The recoverable amount of the cash generating unit within this business was based on a value-in-use calculation.

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
gas & low carbon energy	1,007	2,275	1,728	11,911
oil production & operations	1,891	3,427	8,218	9,312
customers & products	23	1,549	878	4,784
other businesses & corporate	653	(500)	173	(887)
	3,574	6,751	10,997	25,120
Consolidation adjustment – UPII*	65	(57)	24	(109)
	3,639	6,694	11,021	25,011
Inventory holding gains (losses)*
gas & low carbon energy	—	—	—	1
oil production & operations	(2)	(1)	(2)	—
customers & products	(1,180)	1,594	(465)	260
Profit (loss) before interest and tax	2,457	8,287	10,554	25,272
Finance costs	1,101	1,039	3,392	2,802
Net finance expense/(income) relating to pensions and other post-retirement benefits	(42)	(61)	(123)	(180)
Profit (loss) before taxation	1,398	7,309	7,285	22,650
RC profit (loss) before interest and tax*
US	1,122	1,467	4,277	6,786
Non-US	2,517	5,227	6,744	18,225
	3,639	6,694	11,021	25,011

23

Note 5. Sales and other operating revenues

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
By segment
gas & low carbon energy	8,526	10,313	23,010	38,627
oil production & operations	6,468	6,225	19,559	18,155
customers & products	38,437	42,908	119,432	119,841
other businesses & corporate	614	672	1,746	2,000
	54,045	60,118	163,747	178,623
Less: sales and other operating revenues between segments
gas & low carbon energy	385	367	1,026	1,743
oil production & operations	5,860	5,747	17,755	17,244
customers & products	(138)	508	180	472
other businesses & corporate	684	227	1,353	1,175
	6,791	6,849	20,314	20,634
External sales and other operating revenues
gas & low carbon energy	8,141	9,946	21,984	36,884
oil production & operations	608	478	1,804	911
customers & products	38,575	42,400	119,252	119,369
other businesses & corporate	(70)	445	393	825
Total sales and other operating revenues	47,254	53,269	143,433	157,989
By geographical area
US	19,388	22,032	59,586	61,257
Non-US	36,712	43,382	112,752	128,224
	56,100	65,414	172,338	189,481
Less: sales and other operating revenues between areas	8,846	12,145	28,905	31,492
	47,254	53,269	143,433	157,989
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	618	496	1,704	1,653
Oil products	30,997	35,486	93,385	96,845
Natural gas, LNG and NGLs	6,458	6,396	17,196	21,881
Non-oil products and other revenues from contracts with customers	3,213	2,765	9,249	7,387
Revenue from contracts with customers	41,286	45,143	121,534	127,766
Other operating revenues(a)	5,968	8,126	21,899	30,223
Total sales and other operating revenues	47,254	53,269	143,433	157,989

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

Note 6. Depreciation, depletion and amortization

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Total depreciation, depletion and amortization by segment
gas & low carbon energy	1,180	1,543	3,682	4,390
oil production & operations	1,708	1,432	5,063	4,129
customers & products	963	915	2,846	2,606
other businesses & corporate	266	255	774	743
	4,117	4,145	12,365	11,868
Total depreciation, depletion and amortization by geographical area
US	1,735	1,479	5,008	4,071
Non-US	2,382	2,666	7,357	7,797
	4,117	4,145	12,365	11,868

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. Against the authority granted at bp's 2024 annual general meeting, 350 million ordinary shares repurchased for cancellation were settled during the third quarter 2024 for a total cost of $2,001 million. A further 150 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 $796 million. This amount has been accrued at 30 September 2024. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period.

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

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Results for the period
Profit (loss) for the period attributable to bp shareholders	206	4,858	2,340	14,868
Less: preference dividend	—	—	1	1
Less: (gain) loss on redemption of perpetual hybrid bonds(a)	—	—	(10)	—
Profit (loss) attributable to bp ordinary shareholders	206	4,858	2,349	14,867
Number of shares (thousand)(b)(c)
Basic weighted average number of shares outstanding	16,321,349	17,204,488	16,553,408	17,537,170
ADS equivalent(d)	2,720,224	2,867,414	2,758,901	2,922,861
Weighted average number of shares outstanding used to calculate diluted earnings per share	16,709,108	17,609,601	16,980,519	17,914,383
ADS equivalent(d)	2,784,851	2,934,933	2,830,086	2,985,730
Shares in issue at period-end	16,155,806	17,061,004	16,155,806	17,061,004
ADS equivalent(d)	2,692,634	2,843,500	2,692,634	2,843,500

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

(b)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).

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

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

Issued ordinary share capital as at 30 September 2024 comprised 16,262,632,593 ordinary shares (31 December 2023 17,174,461,587 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 717,435,379 ordinary shares which have been bought back and are held in treasury by bp (31 December 2023 726,338,898 ordinary shares).

Note 8. Dividends

Dividends payable

bp today announced an interim dividend of 8.000 cents per ordinary share which is expected to be paid on 20 December 2024 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 8 November 2024. The ex-dividend date will be 7 November 2024 for ordinary shareholders and 8 November 2024 for ADS holders. The corresponding amount in sterling is due to be announced on 5 December 2024, calculated based on the average of the market exchange rates over three dealing days between 29 November 2024 and 3 December 2024. Holders of ADSs are expected to receive $0.48 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2024 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
Dividends paid per ordinary share
cents	8.000	7.270	22.540	20.490
pence	6.050	5.732	17.425	16.592
Dividends paid per ADS (cents)	48.00	43.62	135.24	122.94

25

Note 9. Net debt

Net debt*	30 September	31 December	30 September
$ million	2024	2023	2023
Finance debt(a)	57,470	51,954	48,810
Fair value (asset) liability of hedges related to finance debt(b)	1,393	1,988	3,440
	58,863	53,942	52,250
Less: cash and cash equivalents	34,595	33,030	29,926
Net debt(c)	24,268	20,912	22,324
Total equity	79,946	85,493	87,676
Gearing*	23.3%	19.7%	20.3%

(a)The fair value of finance debt at 30 September 2024 was $54,324 million (31 December 2023 $48,795 million, 30 September 2023 $43,387 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 $123 million at 30 September 2024 (fourth quarter 2023 liability of $73 million and third quarter 2023 liability of $102 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

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

Note 10. Events after the reporting period

On 1 October 2024, the group acquired a further 50% of the issued ordinary shares of bp Bunge Bioenergia and now owns 100% of the ordinary shares. The transaction will be accounted for as a business combination achieved in stages using the acquisition method. Total consideration is estimated at $0.8 billion including deferred consideration. Reported finance debt and cash acquired in the transaction is expected to be approximately $0.7 billion and $0.3 billion, respectively.

On 24 October 2024, the group acquired a further 50.03% of the issued ordinary shares of Lightsource bp and now owns 100% of the ordinary shares. The transaction will be accounted for as a business combination achieved in stages using the acquisition method. Total consideration is estimated at $0.5 billion including deferred and contingent consideration. Reported finance debt and cash acquired in the transaction is expected to be approximately $3.0 billion and $0.3 billion, respectively.

Immediately prior to the business combination, 2.4GW of Lightsource bp’s operational and construction assets in the United States were transferred from Lightsource bp into a new joint venture between bp and the Lightsource bp founders, and certain management and staff. bp will apply equity accounting to this investment for bp’s approximate 50% share.

As the above transactions have only recently completed, the initial provisional purchase price allocations and the related measurement of acquired asset and liability fair values, and accounting policy alignments are ongoing.

Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 28 October 2024, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in bp Annual Report and Form 20-F 2024.

26

Additional information

Capital expenditure*

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Capital expenditure
Organic capital expenditure*	4,341	3,597	11,906	10,325
Inorganic capital expenditure*(a)	201	6	605	1,217
	4,542	3,603	12,511	11,542

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Capital expenditure by segment
gas & low carbon energy	2,096	1,055	4,399	2,955
oil production & operations	1,410	1,644	4,720	4,642
customers & products(a)	931	802	3,096	3,650
other businesses & corporate	105	102	296	295
	4,542	3,603	12,511	11,542
Capital expenditure by geographical area
US	1,389	1,583	4,801	5,941
Non-US	3,153	2,020	7,710	5,601
	4,542	3,603	12,511	11,542

(a)Nine months 2023 includes $1.1 billion, net of adjustments, in respect of the TravelCenters of America acquisition.

27

Adjusting items*

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
gas & low carbon energy
Gains on sale of businesses and fixed assets	19	—	29	16
Net impairment and losses on sale of businesses and fixed assets(a)	(772)	(224)	(1,898)	(1,284)
Environmental and related provisions	—	—	—	—
Restructuring, integration and rationalization costs	(24)	(1)	(24)	—
Fair value accounting effects(b)(c)	(275)	1,816	(1,173)	6,972
Other(d)	303	(572)	(22)	(738)
	(749)	1,019	(3,088)	4,966
oil production & operations
Gains on sale of businesses and fixed assets	(82)	246	109	352
Net impairment and losses on sale of businesses and fixed assets(a)	(770)	(52)	(919)	(184)
Environmental and related provisions	(53)	99	65	6
Restructuring, integration and rationalization costs	(1)	—	(1)	(1)
Fair value accounting effects	—	—	—	—
Other	3	(2)	(49)	(93)
	(903)	291	(795)	80
customers & products
Gains on sale of businesses and fixed assets	12	18	21	21
Net impairment and losses on sale of businesses and fixed assets(a)	(295)	(242)	(1,069)	(361)
Environmental and related provisions	(4)	—	3	(11)
Restructuring, integration and rationalization costs	(39)	1	(38)	—
Fair value accounting effects(c)	157	(198)	38	(230)
Other(e)	(189)	(85)	(896)	(245)
	(358)	(506)	(1,941)	(826)
other businesses & corporate
Gains on sale of businesses and fixed assets	3	—	35	—
Net impairment and losses on sale of businesses and fixed assets	(6)	(23)	9	(60)
Environmental and related provisions	(8)	(8)	11	(39)
Restructuring, integration and rationalization costs	(50)	(3)	(38)	(13)
Fair value accounting effects(c)	494	(146)	272	51
Gulf of Mexico oil spill	(20)	(19)	(39)	(46)
Other	9	2	4	(11)
	422	(197)	254	(118)
Total before interest and taxation	(1,588)	607	(5,570)	4,102
Finance costs(f)	(58)	(96)	(355)	(319)
Total before taxation	(1,646)	511	(5,925)	3,783
Taxation on adjusting items(g)	535	(158)	1,229	(203)
Taxation – tax rate change effect(h)	(44)	—	(348)	232
Total after taxation for period	(1,155)	353	(5,044)	3,812

(a)See Note 3 for further information.

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

(c)For further information, including the nature of fair value accounting effects reported in each segment, see pages 5, 8 and 35.

(d)Third quarter and nine months 2023 include a $540 million impairment charge recognized through equity-accounted earnings relating to US offshore wind projects.

(e)All periods in 2024 include recognition of onerous contract provisions related to the Gelsenkirchen refinery. The unwind of these provisions will be reported as an adjusting item as the contractual obligations are settled.

(f)Includes the unwinding of discounting effects relating to Gulf of Mexico oil spill payables and the income statement impact of temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt. Nine months 2023 also includes the income statement impact associated with the buyback of finance debt. Third quarter and nine months 2024 also includes the unwinding of discounting effects relating to certain onerous contract provisions.

(g)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.

(h)Nine months 2024 and nine months 2023 include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at 31 December 2022 that are expected to unwind before 31 March 2028. The EPL increases the headline rate of tax to 75% and applies to taxable profits from bp’s North Sea business made from 1 January 2023 until 31 March 2028. In July 2024 the new UK government announced further changes to the EPL including a 3% increase in the rate and an extension to 31 March 2030, together with changes to investment allowances and capital allowances. These changes have not yet been substantively enacted and have therefore not been accounted for at 30 September 2024. The impacts will be reflected in the financial statements when the changes are substantively enacted.

28

Net debt including leases

Net debt including leases*	30 September	31 December	30 September
$ million	2024	2023	2023
Net debt*	24,268	20,912	22,324
Lease liabilities	11,018	11,121	10,879
Net partner (receivable) payable for leases entered into on behalf of joint operations	(98)	(131)	(124)
Net debt including leases	35,188	31,902	33,079
Total equity	79,946	85,493	87,676
Gearing including leases*	30.6%	27.2%	27.4%

Gulf of Mexico oil spill

	30 September	31 December
$ million	2024	2023
Gulf of Mexico oil spill payables and provisions	(7,869)	(8,735)
Of which - current	(1,115)	(1,133)
Deferred tax asset	1,192	1,320

During the second quarter 2024 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 Mexico 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 Mexico 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 2023 - Financial statements - Notes 7, 22, 23, 29, and 33.

29

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Profit for the period	370	5,069	2,849	15,444
Finance costs	1,101	1,039	3,392	2,802
Net finance (income) expense relating to pensions and other post-retirement benefits	(42)	(61)	(123)	(180)
Taxation	1,028	2,240	4,436	7,206
Profit before interest and tax	2,457	8,287	10,554	25,272
Inventory holding (gains) losses*, before tax	1,182	(1,593)	467	(261)
	3,639	6,694	11,021	25,011
Net (favourable) adverse impact of adjusting items*, before interest and tax	1,588	(607)	5,570	(4,102)
	5,227	6,087	16,591	20,909
Add back:
Depreciation, depletion and amortization	4,117	4,145	12,365	11,868
Exploration expenditure written off	310	74	643	365
Adjusted EBITDA	9,654	10,306	29,599	33,142

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
RC profit before interest and tax for customers & products	23	1,549	878	4,784
Less: Adjusting items* gains (charges)	(358)	(506)	(1,941)	(826)
Underlying RC profit before interest and tax for customers & products	381	2,055	2,819	5,610
By business:
customers – convenience & mobility	897	670	2,057	1,762
Castrol – included in customers	216	185	611	517
products – refining & trading	(516)	1,385	762	3,848
Add back: Depreciation, depletion and amortization	963	915	2,846	2,606
By business:
customers – convenience & mobility	513	481	1,488	1,270
Castrol – included in customers	45	43	129	124
products – refining & trading	450	434	1,358	1,336
Adjusted EBITDA for customers & products	1,344	2,970	5,665	8,216
By business:
customers – convenience & mobility	1,410	1,151	3,545	3,032
Castrol – included in customers	261	228	740	641
products – refining & trading	(66)	1,819	2,120	5,184

30

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
gas & low carbon energy
RC profit before interest and tax	1,007	2,275	1,728	11,911
Less: Net favourable (adverse) impact of adjusting items*	(749)	1,019	(3,088)	4,966
Underlying RC profit before interest and tax*	1,756	1,256	4,816	6,945
Add back: Depreciation, depletion and amortization	1,180	1,543	3,682	4,390
Exploration write-offs	1	15	232	13
Adjusted EBITDA	2,937	2,814	8,730	11,348
oil production & operations
RC profit before interest and tax	1,891	3,427	8,218	9,312
Less: Net favourable (adverse) impact of adjusting items	(903)	291	(795)	80
Underlying RC profit before interest and tax	2,794	3,136	9,013	9,232
Add back: Depreciation, depletion and amortization	1,708	1,432	5,063	4,129
Exploration write-offs	309	59	411	352
Adjusted EBITDA	4,811	4,627	14,487	13,713

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

	Third	Third	Nine	Nine
	quarter	quarter	months	months
Per ordinary share (cents)	2024	2023	2024	2023
Profit (loss) for the period attributable to bp shareholders	1.26	28.24	14.19	84.77
Inventory holding (gains) losses*, before tax	7.24	(9.26)	2.82	(1.49)
Taxation charge (credit) on inventory holding gains and losses	(1.69)	2.21	(0.63)	0.29
	6.81	21.19	16.38	83.57
Net (favourable) adverse impact of adjusting items*, before tax(a)	10.08	(2.97)	35.71	(21.57)
Taxation charge (credit) on adjusting items(a)	(3.00)	0.92	(5.30)	(0.17)
Underlying RC profit (loss)	13.89	19.14	46.79	61.83
	Third	Third	Nine	Nine
	quarter	quarter	months	months
Per ADS (dollars)	2024	2023	2024	2023
Profit (loss) for the period attributable to bp shareholders	0.08	1.69	0.85	5.09
Inventory holding (gains) losses, before tax	0.43	(0.56)	0.17	(0.09)
Taxation charge (credit) on inventory holding gains and losses	(0.10)	0.14	(0.04)	0.01
	0.41	1.27	0.98	5.01
Net (favourable) adverse impact of adjusting items, before tax(a)	0.61	(0.18)	2.14	(1.29)
Taxation charge (credit) on adjusting items(a)	(0.19)	0.06	(0.31)	(0.01)
Underlying RC profit (loss)	0.83	1.15	2.81	3.71

(a)Nine months 2024 calculated based on adjusting items and taxation credits thereon of $5,925 million and $881 million respectively, as adjusted for the gain on redemption of hybrid bonds of $13 million and taxation thereon of $3 million respectively (see Note 7).

31

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

Taxation (charge) credit	Third	Third	Nine	Nine
	quarter	quarter	months	months
$ million	2024	2023	2024	2023
Taxation on profit or loss before taxation	(1,028)	(2,240)	(4,436)	(7,206)
Taxation on inventory holding gains and losses	276	(381)	105	(50)
Taxation on a replacement cost (RC) profit or loss basis	(1,304)	(1,859)	(4,541)	(7,156)
Total taxation on adjusting items	491	(158)	881	29
Taxation on underlying replacement cost profit or loss	(1,795)	(1,701)	(5,422)	(7,185)

Effective tax rate	Third	Third	Nine	Nine
	quarter	quarter	months	months
%	2024	2023	2024	2023
ETR on profit or loss before taxation	74	31	61	32
Adjusted for inventory holding gains or losses	(23)	2	(2)	—
ETR on RC profit or loss	51	33	59	32
Excluding adjusting items	(9)	—	(19)	7
Underlying ETR	42	33	40	39

32

Realizations* and marker prices

	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
Average realizations(a)
Liquids* ($/bbl)
US	63.31	63.95	63.83	62.44
Europe	75.45	90.76	80.44	80.59
Rest of World	80.79	78.34	81.39	80.05
bp average	70.68	71.85	71.89	71.40
Natural gas ($/mcf)
US	1.18	2.24	1.39	2.09
Europe	12.22	11.22	10.68	17.20
Rest of World	5.80	5.38	5.57	6.11
bp average	4.75	4.88	4.61	5.66
Total hydrocarbons* ($/boe)
US	42.18	45.39	42.65	43.77
Europe	74.03	80.61	74.73	87.43
Rest of World	47.57	45.61	47.22	48.73
bp average	46.81	47.28	46.91	49.47
Average oil marker prices ($/bbl)
Brent	80.34	86.75	82.79	82.07
West Texas Intermediate	75.28	82.54	77.71	77.36
Western Canadian Select	59.98	65.42	62.22	60.72
Alaska North Slope	78.95	87.95	82.24	81.74
Mars	74.20	82.99	77.50	76.80
Urals (NWE – cif)	70.10	73.62	70.39	58.20
Average natural gas marker prices
Henry Hub gas price(b)($/mmBtu)	2.15	2.54	2.10	2.69
UK Gas – National Balancing Point (p/therm)	81.77	82.04	75.75	99.01

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

(b)Henry Hub First of Month Index.

Exchange rates

	Third	Third	Nine	Nine
	quarter	quarter	months	months
	2024	2023	2024	2023
$/£ average rate for the period	1.30	1.27	1.28	1.24
$/£ period-end rate	1.34	1.22	1.34	1.22
$/€ average rate for the period	1.10	1.09	1.09	1.08
$/€ period-end rate	1.12	1.06	1.12	1.06
$/AUD average rate for the period	0.67	0.65	0.66	0.67
$/AUD period-end rate	0.69	0.64	0.69	0.64

33

Legal proceedings

For a full discussion of the group’s material legal proceedings, see pages 242-243 of bp Annual Report and Form 20-F 2023.

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, excluding 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 pages 30-31 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-retirement 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 30 for the group.

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 Mexico 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.

Blue hydrogen – Hydrogen made from natural gas in combination with carbon capture and storage (CCS).

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.

Cash balance point is defined as the implied Brent oil price 2021 real to balance bp’s sources and uses of cash assuming an average bp refining marker margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real terms.

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

Developed renewables to final investment decision (FID) – Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share at the time of FID). If asset is subsequently sold bp will continue to record capacity as developed to FID.

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

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.

Electric vehicle charge points / EV charge points are defined as the number of connectors on a charging device, operated by either bp or a bp joint venture as adjusted to be reflective of bp’s accounting share of joint arrangements.

34

Glossary (continued)

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

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

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

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

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

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

These include:

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

•Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments used to risk manage the near-term portions of the LNG contracts are fair valued under IFRS. The fair value accounting effect, which is reported in the gas and low carbon energy segment, represents the change in value of LNG contacts 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 were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that 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.

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. 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.

35

Glossary (continued)

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.

Green hydrogen – Hydrogen produced by electrolysis of water using renewable power.

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

Hydrogen pipeline – Hydrogen projects which have not been developed to final investment decision (FID) but which have advanced to the concept development stage.

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.

Installed renewables capacity is bp's share of capacity for operating assets owned by entities where bp has an equity share.

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.

Low carbon activity – An activity relating to low carbon including: renewable electricity; bioenergy; electric vehicles and other future mobility solutions; trading and marketing low carbon products; blue or green hydrogen* and carbon capture, use and storage (CCUS).

Note that, while there is some overlap of activities, these terms do not mean the same as bp’s strategic focus area of low carbon energy or our low carbon energy sub-segment, reported within the gas & low carbon energy segment.

36

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 flowis 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 availabilityrepresents 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 planned mechanical, process and regulatory downtime.

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.

Renewables pipeline – Renewable projects satisfying the following criteria until the point they can be considered developed to final investment decision (FID): Site based projects that have obtained land exclusivity rights, or for power purchase agreement based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted.

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.

Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents 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 incidents are investigated throughout the year and as a result there may be changes in previously reported incidents. 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.

Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral, Thorntons and TravelCenters of America and also includes sites in India through our Jio-bp JV.

Solomon availability – See Refining availability definition.

Strategic convenience sites are retail sites, within the bp portfolio, which sell bp-supplied vehicle energy (e.g. bp, Aral, Arco, Amoco, Thorntons, bp pulse, TA and PETRO) and either carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or a differentiated bp-controlled convenience offer. To be considered a strategic convenience site, the convenience offer should have a demonstrable level of differentiation in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.

37

Glossary (continued)

Surplus cash flow does not represent the residual cash flow available for discretionary expenditures. It is a non-IFRS financial measure that should be considered in addition to, not as a substitute for or superior to, net cash provided by operating activities, reported in accordance with IFRS. bp believes it is helpful to disclose the surplus cash flow because this measure forms part of bp's financial frame.

Surplus cash flow refers to the net surplus of sources of cash over uses of cash, after reaching the $35 billion net debt target. Sources of cash include net cash provided by operating activities, cash provided from investing activities and cash receipts relating to transactions involving non-controlling interests. Uses of cash include lease liability payments, payments on perpetual hybrid bond, dividends paid, cash capital expenditure, the cash cost of share buybacks to offset the dilution from vesting of awards under employee share schemes, cash payments relating to transactions involving non-controlling interests and currency translation differences relating to cash and cash equivalents as presented on the condensed group cash flow statement.

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.

Transition growth – Activities, represented by a set of transition growth engines, that transition bp toward its objective to be an integrated energy company, and that comprise our low carbon activity* alongside other businesses that support transition, such as our power trading and marketing business and convenience.

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 production – 2024 underlying production, when compared with 2023, 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 37) 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 8-16 for the segments.

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Glossary (continued)

Underlying RC profit or loss per share / underlying RC profit or loss per ADS is a non-IFRS measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders, rather than profit or loss attributable to bp ordinary shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp ordinary shareholders. A reconciliation to IFRS information is provided on page 31.

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 Mexico 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.

Trade marks

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

bp, Amoco, Aral, ampm, bp pulse, Castrol, PETRO, TA,Thorntons, Gigahub, epic goods and earnify

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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 results 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’ 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 reserves; expectations regarding production and volumes; expectations regarding bp’s customers & products business; expectations regarding margins; expectations regarding underlying effective tax rate; expectations regarding turnaround and maintenance activity; expectations regarding financial performance, results of operations, finance debt acquired in the fourth quarter, and cash flows; expectations regarding future project start-ups; expectations regarding the timing of bp’s update on its medium-term plans; expectations regarding shareholders returns; expectations regarding bp’s convenience businesses; bp’s financial guidance, including previous guidance for at least $14 billion of share buybacks through 2025; bp’s plans and expectations regarding the amount and timing of share buybacks and dividends; plans and expectations regarding bp’s credit rating, including in respect of maintaining a strong investment grade credit rating and targeting further improvements in credit metrics; plans and expectations regarding the allocation of surplus cash flow to share buybacks; plans and expectations regarding the sale of bp’s Türkiye ground fuels business; plans and expectations regarding development of bp’s electric vehicle (EV) charging infrastructure and RNG landfill plants; plans and expectations related to bp’s transition growth engines, including expected capital expenditures; plans and expectations regarding the amount or timing of payments related to divestment and other proceeds, and the timing, quantum and nature of certain acquisitions and divestments; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; expectations regarding bp’s development of hydrogen and sale of its US onshore wind energy business; plans and expectations regarding bp’s guidance for 2024 and the fourth quarter of 2024, including expected growth, margins, businesses & corporate underlying annual charge, timing and amount of divestment and other proceeds, depreciation, depletion and amortization; plans and expectations regarding capital expenditure; and plans and expectations regarding bp-operated projects, ventures, investments, joint ventures, partnerships and agreements with commercial entities and other third party partners, including but not limited to ADNOC, Audi, EOG Resources Trinidad Limited, Iberdrola, Perenco T&T, the Republic of Iraq, SOCAR, Shell Pipeline Company LP and Enbridge Offshore Facilities LC.

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.

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 Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp’s access to future credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; the possibility that international sanctions or other steps taken by governmental authorities or any other relevant persons may impact bp’s ability to sell its interests in Rosneft, or the price for which bp could sell such interests; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and those factors discussed under “Principal risks and uncertainties” in bp’s Report on Form 6-K regarding results for the six-month period ended 30 June 2024 as filed with the US Securities and Exchange Commission (the “SEC”) as well as those factors discussed under “Risk factors” in bp’s Annual Report and Form 20-F for fiscal year 2023 as filed with the SEC.

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 September 2024:

Capitalization and indebtedness

	30 September
$ million	2024
Share capital and reserves
Capital shares (1-2)	4,262
Paid-in surplus (3)	16,763
Merger reserve (3)	27,206
Treasury shares	(9,127)
Investments in equity instruments	5
Cash flow hedge reserve	1
Costs of hedging reserve	(95)
Foreign currency translation reserve	(1,644)
Profit and loss account	27,455
BP shareholders' equity	64,826
Hybrid bonds	13,516
Other interest	1,604
Equity attributable to non-controlling interests	15,120
Total equity	79,946
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year	2,726
Finance debt due within one year	4,484
Lease liabilities due after more than one year	8,292
Finance debt due after more than one year	52,986
Total finance debt and lease liabilities	68,488
Total (7)(8)	148,434

1.Issued share capital as of 30 September 2024 comprised 16,262,632,593 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 717,435,379 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 September 2024.

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 2023– Liquidity and capital resources for further information.

6.At 30 September 2024, the parent company, BP p.l.c. had issued guarantees totalling $56,754 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 September 2024, $211 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

7.At 30 September 2024, the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,838 million in respect of the borrowings of equity-accounted entities and $438 million in respect of the borrowings of other third parties.

8.Total capitalisation and indebtedness includes non-controlling interests of $15,120 million at 30 September 2024 which includes $12.0 billion related to perpetual hybrid bonds and $1.5 billion related to perpetual subordinated hybrid securities issued by a group subsidiary.

9.There has been no material change since 30 September 2024 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:	29 October 2024	/s/ BEN MATHEWS
		Ben J. S. Mathews
		Company Secretary

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