3Q21 SEA Part 1 of 1, 2 Nov 2021 07:00

02 November 2021, 07:00

Source - LSE Regulatory

RNS Number : 9904Q

BP PLC

02 November 2021

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FOR IMMEDIATE RELEASE
London 2 November 2021
BP p.l.c. Group results
Third quarter and nine months 2021

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Reducing net debt, growing distributions, executing strategy

Financial summary	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Profit (loss) for the period attributable to bp shareholders	(2,544)	3,116	(450)	5,239	(21,663)
Inventory holding (gains) losses*, net of tax	(390)	(736)	(194)	(2,468)	2,734
Replacement cost (RC) profit (loss)*	(2,934)	2,380	(644)	2,771	(18,929)
Net (favourable) adverse impact of adjusting items*_(a), net of tax	6,256	418	730	5,979	13,124
Underlying RC profit (loss)*	3,322	2,798	86	8,750	(5,805)
Operating cash flow*	5,976	5,411	5,204	17,496	9,893
Capital expenditure*	(2,903)	(2,514)	(3,636)	(9,215)	(10,564)
Divestment and other proceeds_(b)	313	215	597	5,367	2,413
Net issue (repurchase) of shares	(926)	(500)	-	(1,426)	(776)
Net debt*_(c)	31,971	32,706	40,379	31,971	40,379
Announced dividend per ordinary share (cents per share)	5.46	5.46	5.25	16.17	21.00
Underlying RC profit (loss) per ordinary share* (cents)	16.48	13.80	0.42	43.22	(28.72)
Underlying RC profit (loss) per ADS* (dollars)	0.99	0.83	0.03	2.59	(1.72)

• Strong underlying results and cash flow underpinning continued net debt reduction

• Further $1.25 billion buyback planned - delivering on commitment to distributions

• Six-year target for major project delivery completed on schedule and around 15% under-budget

• Continued momentum across strategic focus areas

This has been another good quarter for bp - our businesses are generating strong underlying earnings and cash flow while maintaining their focus on safe and reliable operations. Rising commodity prices certainly helped, but I am most pleased that quarter by quarter, we're doing what we said we would - delivering significant cash to strengthen our finances, grow distributions to shareholders and invest in our strategic transformation. This is what we mean by performing while transforming.

Bernard Looney

Chief executive officer

(a) Prior to 2021 adjusting items were reported under two different headings - non-operating items and fair value accounting effects*. See page 30 for more information.

(b) Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. Other proceeds were $675 million from the sale of a 49% interest in a controlled affiliate holding certain refined product and crude logistics assets onshore US in the nine months 2021, $481 million in relation to the sale of an interest in bp's UK retail property portfolio in the third quarter and nine months 2020 and also $455 million in relation to TANAP pipeline refinancing in the nine months 2020. There are no other proceeds in the third quarter 2021.

RC profit (loss), underlying RC profit (loss) and net debt are non-GAAP measures. Inventory holding (gains) losses and adjusting items are non-GAAP adjustments.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 35.

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	Highlights
	Strong underlying results and cash flow underpins continued net debt reduction
	• Underlying replacement cost profit* was $3.3 billion, compared with $2.8 billion for the previous quarter. This result was driven by higher oil and gas realizations, higher refining availability and throughput enabling the capture of a stronger environment and a stronger gas marketing and trading result, partly offset by a higher underlying tax charge. • Reported loss for the quarter was $2.5 billion, compared with a $3.1 billion profit for the second quarter 2021. This was driven by significant adverse fair value accounting effects* of $6.1 billion pre-tax, primarily due to the exceptional increase in forward gas prices towards the end of the quarter. 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. This mismatch at the end of the third quarter is expected to unwind if prices decline and as the cargoes are delivered. The underlying result is adjusted to remove this mismatch. • Operating cash flow* of $6.0 billion includes a working capital* build of $1.8 billion (after adjusting for inventory holding gains and fair value accounting effects). • bp received $5.4 billion of divestment and other proceeds in the first nine months including $0.3 billion during the third quarter. bp now expects proceeds of $6-7 billion by the end of 2021. • Net debt* fell to $32.0 billion at the end of the third quarter.
	Further $1.25 billion share buyback planned - delivering on commitment to distributions
	• bp is committed to the disciplined execution of its financial frame with a resilient dividend the first priority. For the third quarter bp has announced a dividend of 5.46 cents per ordinary share payable in the fourth quarter - unchanged following the 4% increase announced with second quarter results. • With second quarter results, bp announced an intention to execute a buyback of $1.4 billion from first half 2021 surplus cash flow* of $2.4 billion. This programme was completed on 1 November 2021 with $0.9 billion executed during the third quarter. • Taking into account the cumulative level of and outlook for surplus cash flow and subject to maintaining a strong investment grade credit rating, the board remains committed to using 60% of 2021 surplus cash flow for share buybacks and plans to allocate the remaining 40% to continue strengthening the balance sheet. • Recognizing third quarter surplus cash flow of $0.9 billion and reflecting confidence in the outlook bp intends to execute a further buyback of $1.25 billion prior to announcing its fourth quarter 2021 results. bp expects to outline plans for the final tranche of buybacks from 2021 surplus cash flow at the time of such results. • On average, based on bp's current forecasts, at around $60 per barrel Brent and subject to the board's discretion each quarter, bp continues to expect to be able to deliver buybacks of around $1.0 billion per quarter and have capacity for an annual increase in the dividend per ordinary share of around 4% through 2025. • The board will take into account factors including the cumulative level of and outlook for surplus cash flow, the cash balance point* and the maintenance of a strong investment grade credit rating in setting the dividend per ordinary share and the buyback each quarter.
	Continued momentum across our strategic focus areas
	• In resilient and focused hydrocarbons, bp delivered its six-year programme of major project* execution, on average around 15% under-budget, hitting its target of bringing online 900 thousand barrels oil equivalent per day of new production by 2021. Six major projects have now come online in 2021, including two in the third quarter - Matapal, offshore Trinidad, under budget and ahead of its 2022 schedule, and Thunder Horse South Expansion Phase 2 in the Gulf of Mexico. • Operational performance in resilient and focused hydrocarbons was robust. Relative to the second quarter, upstream* reported production rose by 4%, hydrocarbon plant reliability* increased to 95.4% and refining availability* increased to 95.6%. • In convenience and mobility, bp delivered record year-to-date convenience gross margin; strong growth in next-gen mobility, with 45% growth in electrons sold into EV charging compared to last quarter; and record year-to-date underlying earnings in China, a key growth market. • In low carbon, confidence in bp's 2025 target of 20GW developed renewables to FID has been strengthened with a further 2GW added to the renewables pipeline* and Lightsource bp's announcement of their increased 25GW development target for 2025.

Underpinned by the disciplined execution of our financial frame, we have delivered another quarter of strong underlying earnings and cash flow. We are maintaining a resilient dividend, have reduced net debt for the sixth consecutive quarter, are demonstrating capital discipline and are delivering on our distribution commitment with a further $1.25 billion of share buybacks planned.

Murray Auchincloss

Chief financial officer

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

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Financial results

At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see note 1 Basis of preparation - Change in segmentation.

In addition to the highlights on page 2:

• Loss attributable to bp shareholders in the third quarter was $2,544 million with a profit of $5,239 million for the nine months compared with losses of $450 million and $21,663 million in the third quarter and nine months of 2020 respectively. Underlying replacement cost profits have improved as result of higher oil and gas prices and refining margins and strong trading results, with adjusting items* being the other significant driver of the movements in the loss/profit attributable to bp shareholders.

• Adjusting items in the third quarter and nine months were an adverse pre-tax impact of $6,416 million and $5,712 million respectively compared with an adverse pre-tax impact of $714 million and $16,644 million in the same periods of 2020. The third quarter and nine months 2021 charges were driven by adverse fair value accounting effects* of $6,101 million in the third quarter primarily arising from the exceptional increase in forward gas prices towards the end of the quarter. The 2020 nine months charge was primarily driven by net impairment charges of $12,912 million which were mainly recorded in the second quarter. Pre-tax net impairment reversals of $2,483 million are included in the nine months 2021 adjusting items total.

• Capital expenditure* in the third quarter and nine months was $2.9 billion and $9.2 billion respectively, compared with $3.6 billion and $10.6 billion in the same periods of 2020.

• At the end of the third quarter, net debt* was $32.0 billion, compared to $32.7 billion at the end of the second quarter 2021 and $40.4 billion at the end of the third quarter 2020.

• Operating cash flow* was $6.0 billion for the third quarter, and $17.5 billion for the nine months, compared with $5.2 billion and $9.9 billion for the same periods of 2020. Third quarter and nine months 2021 includes $0.1 billion and $0.8 billion respectively of cash flow relating to severance costs associated with the reinvent programme.

• The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was -175% and 57% respectively, compared with -504% and 13% for the same periods in 2020. Excluding adjusting items*, the underlying ETR* for the third quarter and nine months was 35% and 31% respectively, compared with 64% and -10% for the same periods a year ago. The lower underlying ETR for the third quarter reflects changes in the geographical mix of profits. The underlying ETR for the nine months is higher than the same period a year ago due to the absence of the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
RC profit (loss) before interest and tax
gas & low carbon energy	(4,135)	927	252	222	(6,430)
oil production & operations	2,692	3,118	(156)	7,289	(14,649)
customers & products	1,060	640	915	2,634	2,173
Rosneft	868	643	(278)	1,874	(419)
other businesses & corporate	(750)	(425)	(42)	(1,853)	(867)
Consolidation adjustment - UPII*	(42)	(31)	34	(60)	166
RC profit (loss) before interest and tax	(307)	4,872	725	10,106	(20,026)
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(688)	(687)	(808)	(2,104)	(2,389)
Taxation on a RC basis	(1,740)	(1,567)	(418)	(4,561)	2,935
Non-controlling interests	(199)	(238)	(143)	(670)	551
RC profit (loss) attributable to bp shareholders*	(2,934)	2,380	(644)	2,771	(18,929)
Inventory holding gains (losses)*	500	953	233	3,183	(3,563)
Taxation (charge) credit on inventory holding gains and losses	(110)	(217)	(39)	(715)	829
Profit (loss) for the period attributable to bp shareholders	(2,544)	3,116	(450)	5,239	(21,663)

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Underlying RC profit (loss) before interest and tax
gas & low carbon energy	1,807	1,240	502	5,317	535
oil production & operations	2,461	2,242	367	6,268	(6,451)
customers & products	1,158	827	636	2,641	2,962
Rosneft	923	689	(177)	1,975	(255)
other businesses & corporate	(373)	(305)	(121)	(848)	(773)
Consolidation adjustment - UPII	(42)	(31)	34	(60)	166
Underlying RC profit (loss) before interest and tax	5,934	4,662	1,241	15,293	(3,816)
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(513)	(485)	(610)	(1,579)	(1,955)
Taxation on an underlying RC basis	(1,900)	(1,141)	(402)	(4,294)	(585)
Non-controlling interests	(199)	(238)	(143)	(670)	551
Underlying RC profit (loss) attributable to bp shareholders*	3,322	2,798	86	8,750	(5,805)

Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-14 for the segments.

Operating Metrics

Operating metrics	Nine months 2021	vs Nine months 2020
Tier 1 and tier 2 process safety events*	49	-16
Reported recordable injury frequency*	0.145	+15.4%
Group production (mboe/d)_(a)	3,269	-7.7%
upstream* production (mboe/d) (excludes Rosneft segment)	2,180	-10.9%
upstream unit production costs*_(b) ($/boe)	6.96	+10.4%
bp-operated hydrocarbon plant reliability*	94.3%	+0.5
bp-operated refining availability*_(a)	94.6%	-1.4

(a) See Operational updates on pages 6, 8 and 10.

(b) Reflecting lower volumes and higher costs including phasing impacts.

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Outlook & Guidance

Macro outlook

• Oil prices have continued to increase, and inventories have reduced back towards pre-pandemic levels. We expect oil prices to be supported by continued inventory draw-down, with the potential for additional demand from gas to oil switching.

• OPEC+ decision making on production levels continues to be a key factor in oil prices and market rebalancing.

• Gas markets were very strong in the quarter and we expect they will remain tight during the period of peak winter demand.

• In the fourth quarter industry refining margins are expected to be lower compared to the third quarter driven by seasonal demand.

4Q21 guidance

• Looking ahead, we expect fourth quarter reported upstream* production to be higher than the third quarter reflecting major project* ramp-up, mainly in gas regions, recovery from seasonal maintenance activity and continuing impacts from Hurricane Ida on our non-operated production in the US Gulf of Mexico. Within this, we expect production from both oil production & operations and gas & low carbon to be higher.

• In our customer businesses, we expect lower product demand due to seasonal impacts and continued base oil tightness and additive supply shortages in Castrol. In products, refining margins are expected to be lower in the fourth quarter driven by seasonal demand and we expect energy prices to remain under pressure and maintenance activity to remain high.

2021 Guidance

In addition to the guidance on page 2:

• We now expect divestment and other proceeds for the year of $6-7 billion. Our target of $25 billion of divestment and other proceeds between the second half of 2020 and 2025 is now underpinned by agreed or completed transactions of around $15.2 billion with over $10 billion of proceeds received.

• The underlying ETR* for 2021 is now expected to be below 35% but is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group's profits and losses.

• For full year 2021 we continue to expect reported upstream production to be lower than 2020 due to the impact of the ongoing divestment programme. However, we expect upstream underlying production* to be slightly higher than 2020 with the ramp-up of major projects, primarily in gas regions, partly offset by the impacts of reduced capital investment and decline in lower-margin gas assets.

• bp continues to expect capital expenditure*, including inorganic capital expenditure*, of around $13 billion in 2021.

• Depreciation, depletion and amortization is still expected to be at a similar level to 2020.

• Gulf of Mexico oil spill payments for the year are still expected to be around $1.5 billion pre-tax.

• The other businesses & corporate underlying annual charge is still expected to be in the range of $1.2-1.4 billion for 2021. The quarterly charges may vary from quarter to quarter.

COVID-19 Update

• bp's future financial performance, including cash flows and net debt, will be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. It is difficult to predict when all current supply and demand imbalances will be resolved and what the ultimate impact of COVID-19 will be.

• bp continues to take steps to protect and support its staff through the pandemic. Precautions in operations and offices together with enhanced support and guidance to staff continue with a focus on safety, health and hygiene, homeworking and mental health. Decisions on working practices and return to office based working are being taken with caution and in compliance with local and national guidelines and regulations.

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

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gas & low carbon energy

Financial results

• The replacement cost loss before interest and tax for the third quarter and profit for the nine months was $4,135 million and $222 million respectively, compared with a profit of $252 million and a loss of $6,430 million for the same periods in 2020. The third quarter and nine months included an adverse impact of net adjusting items* of $5,942 million and $5,095 million respectively, compared with an adverse impact of net adjusting items of $250 million and $6,965 million for the same periods in 2020.

• After excluding adjusting items, the underlying replacement cost profit before interest and tax* for the third quarter and nine months was $1,807 million and $5,317 million respectively, compared with a profit of $502 million and $535 million for the same periods in 2020. Adjusting items* include adverse fair value accounting effects* of $5,808 million, primarily arising from the exceptional increase in forward gas prices towards the end of the quarter. Under IFRS, reported earnings include the mark-to-market value of the hedges used to risk-manage forward LNG contracts, but not of the LNG contracts themselves. This mismatch at the end of the third quarter is expected to unwind if prices decline and as the cargoes are delivered. The underlying result is adjusted to remove this mismatch.

• The underlying replacement cost profit for the third quarter, compared with the same period in 2020, reflects higher realizations, the higher depreciation, depletion and amortization charge, and the very strong trading result. For the nine months, compared with the same period in 2020, the underlying replacement cost profit mainly reflects higher realizations, the higher depreciation, depletion and amortization charge, lower exploration write-offs and the exceptional trading result.

Operational update

• Reported production for the quarter and nine months were 889mboe/d and 891mboe/d respectively, higher than the same periods in 2020 due to growth in underlying production*, partly offset by the partial divestment in Oman. Underlying production was higher, mainly due to major project* start-ups, partially offset by base decline.

• Renewables pipeline* at the end of the quarter was 23GW (bp net). The renewables pipeline grew by 2GW (bp net) in the quarter due to increases in Lightsource bp's (LSbp's) pipeline and 12.1GW (bp net) in the nine months, as a result of growth in LSbp and the acquisition of a 9GW development pipeline from 7X Energy.

Strategic progress

gas

• On 20 September, bp Trinidad and Tobago announced that its Matapal subsea gas development safely achieved first gas seven months ahead of schedule and under budget.

• On 16 September, Gas Natural Açu (GNA), a joint venture between bp, Prumo, Siemens and SPIC Brasil, announced the start of commercial operations at GNA I, a LNG to power thermoelectric plant located in Porto do Açu, Rio de Janeiro, Brazil. The project has a 1.3GW capacity.

• On 6 September, bp Singapore announced its first carbon offset LNG cargo had been delivered to CPC Corporation, Taiwan, sourced from bp's LNG portfolio.

• On 7 October, bp China signed a 10-year pipeline gas supply agreement with Shenzhen Gas. Starting in 2023, bp has agreed to provide up to 300,000 tonnes per year of pipeline gas. The supply will be re-gasified through Guangdong Dapeng LNG's receiving terminal, in which bp has a 30% stake.

low carbon energy

• On 20 September, Lightsource bp announced its new global growth strategy of developing 25GW of solar projects by 2025.

• On 16 September, bp announced a strategic partnership with ADNOC and Masdar. Through this partnership we aim to jointly develop a range of low carbon energy projects, including the development of green and blue hydrogen hubs.

• On 19 October, the East Coast Cluster was selected as one of the UK's first two carbon capture and storage projects by the UK government. The East Coast Cluster is enabled by the Northern Endurance Partnership - a collaboration between bp, Eni, Equinor, National Grid, Shell and Total, with bp as operator.

• On 7 July, bp closed its transaction with US solar developer 7X Energy to acquire 9GW of solar development projects. Projects with a combined generating capacity of 2.2GW are expected to reach final investment decision (FID) by 2025, with further projects expected to progress by 2030.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Profit (loss) before interest and tax	(4,120)	931	259	263	(6,421)
Inventory holding (gains) losses*	(15)	(4)	(7)	(41)	(9)
RC profit (loss) before interest and tax	(4,135)	927	252	222	(6,430)
Net (favourable) adverse impact of adjusting items	5,942	313	250	5,095	6,965
Underlying RC profit (loss) before interest and tax	1,807	1,240	502	5,317	535
Taxation on an underlying RC basis	(389)	(244)	(249)	(1,168)	(621)
Underlying RC profit (loss) before interest	1,418	996	253	4,149	(86)

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gas & low carbon energy (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,230	1,115	746	3,199	2,736

Exploration write-offs
Exploration write-offs_(a)	14	21	65	41	1,699

Adjusted EBITDA*
Total adjusted EBITDA	3,051	2,376	1,311	8,557	4,300

Capital expenditure*
gas	736	705	892	2,252	3,083
low carbon energy_(b)	336	42	43	1,452	55
Total capital expenditure	1,072	747	935	3,704	3,138

(a) Third quarter and nine months 2020 include a write-off of $2 million and $670 million respectively, which have been classified within the 'other' category of adjusting items.

(b) Nine months 2021 includes $712 million in respect of the remaining payment to Equinor for our investment in our strategic US offshore wind partnership and $326 million as a lease option fee deposit paid to The Crown Estate in connection with our participation in the UK Round 4 Offshore Wind Leasing together with our partner EnBW.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
Production (net of royalties)_(c)
Liquids* (mb/d)	109	109	92	110	96
Natural gas (mmcf/d)	4,520	4,440	4,343	4,527	4,490
Total hydrocarbons* (mboe/d)	889	875	841	891	870

Average realizations*_(d)
Liquids ($/bbl)	66.39	61.69	37.77	61.11	35.41
Natural gas ($/mcf)	5.26	4.14	2.99	4.44	3.21
Total hydrocarbons* ($/boe)	34.91	28.97	19.64	30.21	20.55

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
low carbon energy	2021	2021	2020	2021	2020

Renewables (bp net, GW)
Installed renewables capacity*	1.7	1.6	1.2	1.7	1.2

Developed renewables to FID*_(e)	3.6	3.5	3.1	3.6	3.1
Renewables pipeline	23.3	21.2		23.3
of which by geographical area:
Renewables pipeline - Americas	16.8	15.3		16.8
Renewables pipeline - Asia Pacific	1.1	0.8		1.1
Renewables pipeline - Europe	5.2	5.1		5.2
Renewables pipeline - Other	0.2	-		0.2
of which by technology:
Renewables pipeline - offshore wind	3.7	3.7		3.7
Renewables pipeline - solar	19.6	17.5		19.6
Total Developed renewables to FID and Renewables pipeline_(e)	26.9	24.7		26.9

(e) An amendment of 0.2GW has been made to the amount presented for the second quarter 2021 (previously Developed renewables to FID 3.7GW.)

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oil production & operations

Financial results

• The replacement cost profit before interest and tax for the third quarter and nine months was $2,692 million and $7,289 million respectively, compared with a loss of $156 million and $14,649 million for the same periods in 2020. The third quarter and nine months includes a favourable impact of net adjusting items* of $231 million and $1,021 million respectively, compared with an adverse impact of net adjusting items of $523 million and $8,198 million for the same periods in 2020.

• After excluding adjusting items, the underlying replacement cost profit before interest and tax* for the third quarter and nine months was $2,461 million and $6,268 million respectively, compared with a profit of $367 million and a loss of $6,451 million for the same periods in 2020.

• The underlying replacement cost profit for the third quarter, compared with the same period in 2020, primarily reflects higher liquids and gas realizations. For the nine months, compared with the same period in 2020, the underlying replacement cost profit mainly reflects higher liquids and gas realizations, significantly lower exploration write-offs, and lower volumes.

Operational update

• Reported production for the quarter was 1,313mboe/d, 6.3% lower than the third quarter of 2020. This includes price impacts on PSA* and TSC* entitlement volumes and the impact of BPX Energy divestments. Underlying production* for the quarter was flat reflecting major project* ramp-up offset by impacts from reduced capital investment, decline and weather impacts in the US Gulf of Mexico.

• Reported production for the nine months was 1,289mboe/d, 18.3% lower than the same period in 2020. This includes price impacts on PSA and TSC entitlement volumes and the impact of divestments in Alaska and BPX Energy. Underlying production for the nine months decreased by 6.1% mainly due to impacts from reduced capital investment and decline.

Strategic progress

• On 28 September, bp announced the start-up of its Thunder Horse South Expansion Phase 2 project in the deepwater Gulf of Mexico (bp 75% operator, ExxonMobil 25%).

• On 29 September, bp announced it has agreed to sell a 25% participating interest in the Shallow Water Absheron Peninsula (SWAP) exploration project in the Azerbaijan sector of the Caspian Sea to LUKOIL. Subject to approval, the transaction, with an effective date of 1 July 2021, is expected to complete in the fourth quarter of 2021, following which the participating interests will be: SOCAR Oil Affiliate 50%, bp operator 25% and LUKOIL 25%.

• Furthermore, Yermak IJV (Rosneft 51%, bp 49%) secured access to two new license blocks, Khoshgortyeganskiy and Kharayeganskiy, in the established West Siberia basin.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Profit (loss) before interest and tax	2,691	3,112	(155)	7,297	(14,661)
Inventory holding (gains) losses*	1	6	(1)	(8)	12
RC profit (loss) before interest and tax	2,692	3,118	(156)	7,289	(14,649)
Net (favourable) adverse impact of adjusting items	(231)	(876)	523	(1,021)	8,198
Underlying RC profit (loss) before interest and tax	2,461	2,242	367	6,268	(6,451)
Taxation on an underlying RC basis	(1,220)	(939)	(247)	(2,888)	345
Underlying RC profit (loss) before interest	1,241	1,303	120	3,380	(6,106)

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oil production & operations (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Depreciation, depletion and amortization
Total depreciation, depletion and amortization	1,767	1,559	1,814	4,900	6,001

Exploration write-offs
Exploration write-offs_(a)	16	8	(15)	80	8,067

Adjusted EBITDA*
Total adjusted EBITDA	4,244	3,809	2,166	11,248	6,316

Capital expenditure*
Total capital expenditure	1,099	1,148	1,117	3,566	4,696

(a) Nine months 2020 includes a write-off of $1,301 million which has been classified within the 'other' category of adjusting items.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
Production (net of royalties)_(b)
Liquids* (mb/d)	975	938	1,037	970	1,171
Natural gas (mmcf/d)	1,961	1,786	2,115	1,853	2,365
Total hydrocarbons* (mboe/d)	1,313	1,245	1,402	1,289	1,578

Average realizations*_(c)
Liquids ($/bbl)	65.53	60.55	38.21	59.60	35.52
Natural gas ($/mcf)	5.61	3.90	1.42	4.59	1.31
Total hydrocarbons* ($/boe)	57.72	52.47	31.21	52.35	28.94

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

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customers & products

Financial results

• The replacement cost profit before interest and tax for the third quarter and nine months was $1,060 million and $2,634 million respectively, compared with $915 million and $2,173 million for the same periods in 2020. The third quarter and nine months included an adverse impact of net adjusting items* of $98 million and $7 million respectively, compared with a favourable impact of net adjusting items of $279 million and an adverse impact of net adjusting items of $789 million for the same periods in 2020.

• After excluding adjusting items, the underlying replacement cost profit before interest and tax* for the third quarter and nine months was $1,158 million and $2,641 million respectively, compared with $636 million and $2,962 million for the same periods in 2020.

• The customers & products result for the third quarter reflects a materially stronger performance, nearly double that of last year, primarily driven by a stronger refining environment. The result for the nine months, reflects a stronger customers performance, more than offset by a lower trading result in products and absence of earnings from our divested petrochemicals business.

• customers - convenience and mobility results, excluding Castrol, for the quarter and nine months demonstrated resilient performance, albeit with lower earnings than the same periods last year. These results were supported by higher volumes and resilient fuel margins despite rising crude prices, as well as strong convenience performance, with record year-to-date gross margin*. Costs for both periods were higher in support of the re-opening of some markets following COVID and increased digital and marketing expenditure underpinning our growth agenda.

Castrol results in the quarter were lower than last year, with industry base oil prices more than doubling and severe lockdown restrictions in place across key Asian markets. For the nine months performance was strong, with volumes and earnings materially higher than the same period in 2020, and with China delivering record underlying earnings.

• products - the products result for the quarter was materially stronger than last year, with higher results in both refining and trading. The result for the nine months was lower than last year due to an exceptionally strong trading performance in the second quarter of last year. In refining the result for the quarter and the nine months was stronger due to higher utilization, which enabled the capture of improved realized refining margins. This was partially offset by a higher level of turnaround and maintenance activity and increased energy prices.

Operational update

• Utilization for the quarter was around 9 percentage points higher than the same period last year due to lower COVID related demand impacts. bp-operated refining availability* for the third quarter and nine months was 95.6% and 94.6% respectively, lower compared with 96.2% and 96.0% for the same periods last year, due to a higher level of maintenance activity.

Strategic progress

• In support of our strategic agenda to redefine convenience, we have grown our strategic convenience sites* to 2,050 at the end of the third quarter. Additionally, we have:

◦ expanded our convenience partnership model with Albert Heijn, the leading supermarket chain in the Netherlands, with plans to roll out a new exclusive food-to-go offer to more than 100 retail sites by the end of next year;

◦ completed the transaction to take full ownership of the Thorntons business, positioning bp to be a leading convenience operator in the Midwest US.

• In next-gen mobility, nearly half of our network is now either rapid or ultra-fast charging and in the quarter we delivered 45% growth in electrons sold compared to the prior quarter. In addition, in October, our investment with Daimler and BMW in Digital Charging Solutions completed.

• In growth markets, our fuels and mobility joint venture in India with Reliance, Jio-bp, opened their first mobility station in October. The site has a fully-integrated customer offer, including high-quality additivised fuels, EV charging points, tailored convenience offers, as well as our Castrol products and services. Jio-bp also announced an agreement with EV demand partner, Swiggy, a leading food delivery company, to roll out a network of battery swap stations.

• In Castrol, our market leading position in advanced e-fluids, Castrol ON, was further strengthened with more than two-thirds of the world's major vehicle manufacturers_(a) having now approved Castrol ON products as part of their factory fill.

• In refining:

◦ we announced plans to invest $270 million at the Cherry Point refinery in the US, to improve efficiency, reduce CO₂ emissions and increase its renewable diesel production capability;

◦ bp Castellón in Spain, was the first refinery in the world to receive accreditation from the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA) for the production of sustainable fuel for aviation.

(a) Based on LMCA data for top 20 selling OEMs (total new car sales) in 2019.

Top of page 11

customers & products (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Profit (loss) before interest and tax	1,511	1,527	1,106	5,577	(1,273)
Inventory holding (gains) losses*	(451)	(887)	(191)	(2,943)	3,446
RC profit before interest and tax	1,060	640	915	2,634	2,173
Net (favourable) adverse impact of adjusting items	98	187	(279)	7	789
Underlying RC profit before interest and tax	1,158	827	636	2,641	2,962
Of which:_(a)
customers - convenience & mobility	806	951	1,081	2,415	2,201
Castrol - included in customers	231	265	326	830	556
products - refining & trading	352	(124)	(533)	226	561
petrochemicals	-	-	88	-	200
Taxation on an underlying RC basis	(314)	(123)	(51)	(570)	(637)
Underlying RC profit before interest	844	704	585	2,071	2,325

(a) A reconciliation to RC profit before interest and tax by business is provided on page 33.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Adjusted EBITDA*_(b)
customers - convenience & mobility	1,130	1,280	1,387	3,392	3,077
Castrol - included in customers	267	304	364	944	675
products - refining & trading	775	301	(98)	1,495	1,825
petrochemicals	-	-	90	-	302
	1,905	1,581	1,379	4,887	5,204

Depreciation, depletion and amortization
Total depreciation, depletion and amortization	747	754	743	2,246	2,242

Capital expenditure*
customers - convenience & mobility	301	255	1,266	872	1,756
Castrol - included in customers	37	42	33	120	104
products - refining & trading	296	264	244	776	702
petrochemicals	-	-	9	-	87
Total capital expenditure	597	519	1,519	1,648	2,545

(b) A reconciliation to RC profit before interest and tax by business is provided on page 33.

Retail_(c)	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
bp retail sites* - total (#)	20,350	20,300	20,550	20,350	20,550
bp retail sites in growth markets*	2,650	2,700	2,700	2,650	2,700
Strategic convenience sites*	2,050	2,000	1,900	2,050	1,900

Marketing sales of refined products (mb/d)	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
US	1,161	1,131	1,083	1,103	997
Europe	968	838	849	838	830
Rest of World	439	469	422	450	435
	2,568	2,438	2,354	2,391	2,262
Trading/supply sales of refined products_(d)	425	415	435	392	432
Total sales volume of refined products	2,993	2,853	2,789	2,783	2,694

(d) Comparative information for 2020 has been restated for the changes to net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 basis of preparation - Voluntary change in accounting policy.

Top of page 12

customers & products (continued)

Refining marker margin*_(a)	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
bp average refining marker margin (RMM) ($/bbl)	15.2	13.7	6.2	12.6	7.0

(a) In 2021 the RMM has been updated to reflect changes in bp's portfolio, and the update of crude reference for Mediterranean region. On this basis the third quarter and nine months 2020 RMM would be $6.4/bbl and $7.1/bbl respectively.

Refinery throughputs - operated refineries (mb/d)	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
US	737	692	701	719	687
Europe	804	763	699	771	750
Rest of World	81	52	187	87	189
Total refinery throughputs	1,622	1,507	1,587	1,577	1,626
bp-operated refining availability* (%)	95.6	93.5	96.2	94.6	96.0

Top of page 13

Rosneft

Financial results

• The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $868 million and $1,874 million respectively, compared with a loss of $278 million and $419 million for the same periods in 2020. The third quarter and nine months included an adverse impact of net adjusting items* of $55 million and $101 million respectively, compared with an adverse impact of net adjusting items of $101 million and $164 million for the same periods in 2020.

• After excluding adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $923 million and $1,975 million respectively, compared with a loss of $177 million and $255 million for the same periods in 2020.

• Compared with the same periods in 2020, the results for the third quarter and nine months primarily reflect higher oil prices and favourable foreign exchange effects.

• The extraordinary general meeting held on 30 September adopted a resolution to pay interim dividends of 18.03 roubles per ordinary share which constitute 50% of Rosneft's IFRS net profit for the first half of 2021. bp expects to receive dividends of 34 billion roubles (net of withholding tax) in the fourth quarter.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021_(a)	2021	2020	2021_(a)	2020
Profit (loss) before interest and tax_(b)(c)	903	711	(244)	2,065	(533)
Inventory holding (gains) losses*	(35)	(68)	(34)	(191)	114
RC profit (loss) before interest and tax	868	643	(278)	1,874	(419)
Net (favourable) adverse impact of adjusting items	55	46	101	101	164
Underlying RC profit (loss) before interest and tax	923	689	(177)	1,975	(255)
Taxation on an underlying RC basis	(93)	(68)	17	(196)	28
Underlying RC profit (loss) before interest	830	621	(160)	1,779	(227)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021_(a)	2021	2020	2021_(a)	2020
Production: Hydrocarbons (net of royalties, bp share)
Liquids* (mb/d)	876	858	858	854	877
Natural gas (mmcf/d)	1,418	1,374	1,260	1,363	1,261
Total hydrocarbons* (mboe/d)	1,120	1,095	1,075	1,089	1,094

(a) The operational and financial information of the Rosneft segment for the third quarter and nine months is based on preliminary operational and financial results of Rosneft for the three months and nine months ended 30 September 2021. Actual results may differ from these amounts. Amounts reported for the third quarter are based on bp's 22.03% average economic interest for the quarter (second quarter 2021 22.03% and third quarter 2020 21.96%).

(b) The Rosneft segment result includes equity-accounted earnings arising from bp's economic interest in Rosneft as adjusted for accounting required under IFRS relating to bp's purchase of its interest in Rosneft, and the amortization of the deferred gain relating to the divestment of bp's interest in TNK-BP.

(c) bp's adjusted share of Rosneft's earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the bp group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.

Top of page 14

other businesses & corporate

Other businesses & corporate comprises our innovation & engineering business including bp ventures and Launchpad, regions, cities & solutions, our corporate activities & functions and any residual costs of the Gulf of Mexico oil spill.

Financial results

• The replacement cost loss before interest and tax for the third quarter and nine months was $750 million and $1,853 million respectively, compared with $42 million and $867 million for the same periods in 2020. The third quarter and nine months included an adverse impact of net adjusting items* of $377 million and $1,005 million respectively, including $263 million and $637 million of adverse fair value accounting effects* respectively, compared with a favourable impact of net adjusting items of $79 million and an adverse impact of net adjusting items of $94 million, including $266 million and $225 million of favourable fair value accounting effects respectively, for the same periods in 2020.

• After excluding adjusting items*, the underlying replacement cost loss before interest and tax* for the third quarter and nine months was $373 million and $848 million respectively, compared with $121 million and $773 million for the same periods in 2020, reflecting foreign exchange and employee cost impacts.

Strategic progress

• bp and NYK Line signed a memorandum of understanding on 24 August to collaborate on future fuels and transportation solutions to help industrial sectors, including shipping, decarbonize.

• On 2 September, bp Launchpad acquired Blueprint Power (Blueprint), a US-based company whose technology is focused on optimizing the power networks of buildings by connecting them to energy markets through cloud-based software. Blueprint's technology presents an opportunity to help decarbonize commercial real estate, help real estate owners meet their environmental goals and give them access to new revenue streams.

• On 24 September, bp ventures led a $25 million investment round in all-electric ride hailing & EV charging start-up BluSmart. BluSmart is India's first and largest integrated EV ride-hailing and charging service. BluSmart intends to use the capital to expand its fleet of electric vehicles and charging stations in its home city of Delhi and into five additional Indian cities in the next two years.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Profit (loss) before interest and tax	(750)	(425)	(42)	(1,853)	(867)
Inventory holding (gains) losses*	-	-	-	-	-
RC profit (loss) before interest and tax	(750)	(425)	(42)	(1,853)	(867)
Net (favourable) adverse impact of adjusting items_(a)	377	120	(79)	1,005	94
Underlying RC profit (loss) before interest and tax	(373)	(305)	(121)	(848)	(773)
Taxation on an underlying RC basis	11	101	13	166	(18)
Underlying RC profit (loss) before interest	(362)	(204)	(108)	(682)	(791)

(a) Includes fair value accounting effects relating to the hybrid bonds that were issued on 17 June 2020. See page 36 for more information.

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Financial statements

Group income statement

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020

Sales and other operating revenues (Note 5)_(a)	36,174	36,467	26,312	107,185	78,547
Earnings from joint ventures - after interest and tax	197	(57)	73	300	(516)
Earnings from associates - after interest and tax	1,103	856	(332)	2,560	(676)
Interest and other income	158	82	183	322	430
Gains on sale of businesses and fixed assets	235	250	27	1,590	117
Total revenues and other income	37,867	37,598	26,263	111,957	77,902
Purchases_(a)	23,937	21,241	13,706	60,834	42,271
Production and manufacturing expenses	6,026	6,562	5,073	19,446	16,383
Production and similar taxes	354	295	140	902	467
Depreciation, depletion and amortization (Note 6)	3,944	3,631	3,467	10,942	11,463
Impairment and losses on sale of businesses and fixed assets (Note 3)	220	(2,937)	294	(2,344)	13,213
Exploration expense	116	107	190	322	10,066
Distribution and administration expenses	3,077	2,874	2,435	8,566	7,628
Profit (loss) before interest and taxation	193	5,825	958	13,289	(23,589)
Finance costs	693	682	800	2,098	2,366
Net finance (income) expense relating to pensions and other post-retirement benefits	(5)	5	8	6	23
Profit (loss) before taxation	(495)	5,138	150	11,185	(25,978)
Taxation	1,850	1,784	457	5,276	(3,764)
Profit (loss) for the period	(2,345)	3,354	(307)	5,909	(22,214)
Attributable to
BP shareholders	(2,544)	3,116	(450)	5,239	(21,663)
Non-controlling interests	199	238	143	670	(551)
	(2,345)	3,354	(307)	5,909	(22,214)

Earnings per share (Note 7)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	(12.63)	15.37	(2.22)	25.88	(107.15)
Diluted	(12.63)	15.30	(2.22)	25.72	(107.15)
Per ADS (dollars)
Basic	(0.76)	0.92	(0.13)	1.55	(6.43)
Diluted	(0.76)	0.92	(0.13)	1.54	(6.43)

(a) 2020 numbers have been restated as a result of changes to the net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 Basis of preparation - Voluntary change in accounting policy.

Top of page 16

Condensed group statement of comprehensive income

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020

Profit (loss) for the period	(2,345)	3,354	(307)	5,909	(22,214)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences_(a)	(599)	902	(166)	(302)	(3,437)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	-	-	-	-	4
Cash flow hedges and costs of hedging	(398)	(207)	(90)	(667)	63
Share of items relating to equity-accounted entities, net of tax	(3)	(68)	308	(60)	417
Income tax relating to items that may be reclassified	80	8	(16)	89	64
	(920)	635	36	(940)	(2,889)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset_(b)	494	590	78	3,110	(163)
Cash flow hedges that will subsequently be transferred to the balance sheet	(2)	1	8	1	(2)
Income tax relating to items that will not be reclassified	(130)	(165)	(16)	(883)	(16)
	362	426	70	2,228	(181)
Other comprehensive income	(558)	1,061	106	1,288	(3,070)
Total comprehensive income	(2,903)	4,415	(201)	7,197	(25,284)
Attributable to
BP shareholders	(3,084)	4,183	(364)	6,559	(24,723)
Non-controlling interests	181	232	163	638	(561)
	(2,903)	4,415	(201)	7,197	(25,284)

(a) Second quarter 2021 and nine months 2020 principally affected by movements in the Russian rouble against the US dollar.

(b) See Note 1 - Basis of preparation - Pensions and other post-retirement benefits for further information.

Top of page 17

Condensed group statement of changes in equity

	bp shareholders'	Non-controlling interests		Total
$ million	equity	Hybrid bonds	Other interest	equity
At 1 January 2021	71,250	12,076	2,242	85,568

Total comprehensive income	6,559	377	261	7,197
Dividends	(3,236)	-	(245)	(3,481)
Cash flow hedges transferred to the balance sheet, net of tax	(8)	-	-	(8)
Repurchase of ordinary share capital	(1,897)	-	-	(1,897)
Share-based payments, net of tax	407	-	-	407
Share of equity-accounted entities' changes in equity, net of tax	558	-	-	558
Issue of perpetual hybrid bonds(a)	(24)	883	-	859
Payments on perpetual hybrid bonds	(7)	(431)	-	(438)
Transactions involving non-controlling interests, net of tax	873	-	(372)	501
At 30 September 2021	74,475	12,905	1,886	89,266

	bp shareholders'	Non-controlling interests		Total
$ million	equity	Hybrid bonds	Other interest	equity
At 1 January 2020	98,412	-	2,296	100,708

Total comprehensive income	(24,723)	133	(694)	(25,284)
Dividends	(5,305)	-	(163)	(5,468)
Cash flow hedges transferred to the balance sheet, net of tax	7	-	-	7
Repurchase of ordinary share capital	(776)	-	-	(776)
Share-based payments, net of tax	547	-	-	547
Issue of perpetual hybrid bonds	(48)	11,909	-	11,861
Payments on perpetual hybrid bonds	-	(27)	-	(27)
Tax on issue of perpetual hybrid bonds	1	-	-	1
Transactions involving non-controlling interests, net of tax	(160)	-	746	586
At 30 September 2020	67,955	12,015	2,185	82,155

(a) See note 1 - Issuance of hybrid securities for further information.

Top of page 18

Group balance sheet

	30 September	31 December
$ million	2021	2020
Non-current assets
Property, plant and equipment	114,458	114,836
Goodwill	12,428	12,480
Intangible assets	6,261	6,093
Investments in joint ventures	9,777	8,362
Investments in associates	21,359	18,975
Other investments	2,396	2,746
Fixed assets	166,679	163,492
Loans	972	840
Trade and other receivables	3,815	4,351
Derivative financial instruments	7,203	9,755
Prepayments	473	533
Deferred tax assets	6,259	7,744
Defined benefit pension plan surpluses	10,659	7,957
	196,060	194,672
Current assets
Loans	478	458
Inventories	25,232	16,873
Trade and other receivables	25,327	17,948
Derivative financial instruments	6,542	2,992
Prepayments	1,479	1,269
Current tax receivable	494	672
Other investments	191	333
Cash and cash equivalents	30,694	31,111
	90,437	71,656
Assets classified as held for sale (Note 2)	39	1,326
	90,476	72,982
Total assets	286,536	267,654
Current liabilities
Trade and other payables	49,406	36,014
Derivative financial instruments	10,666	2,998
Accruals	5,623	4,650
Lease liabilities	1,762	1,933
Finance debt	3,693	9,359
Current tax payable	1,346	1,038
Provisions	5,585	3,761
	78,081	59,753
Liabilities directly associated with assets classified as held for sale (Note 2)	31	46
	78,112	59,799
Non-current liabilities
Other payables	10,603	12,112
Derivative financial instruments	6,095	5,404
Accruals	978	852
Lease liabilities	6,866	7,329
Finance debt	59,521	63,305
Deferred tax liabilities	8,044	6,831
Provisions	18,820	17,200
Defined benefit pension plan and other post-retirement benefit plan deficits	8,231	9,254
	119,158	122,287
Total liabilities	197,270	182,086
Net assets	89,266	85,568
Equity
BP shareholders' equity	74,475	71,250
Non-controlling interests	14,791	14,318
Total equity	89,266	85,568

Top of page 19

Condensed group cash flow statement

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Operating activities
Profit (loss) before taxation	(495)	5,138	150	11,185	(25,978)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	3,976	3,659	3,517	11,063	21,229
Impairment and (gain) loss on sale of businesses and fixed assets	(15)	(3,187)	267	(3,934)	13,096
Earnings from equity-accounted entities, less dividends received	(784)	(539)	1,018	(1,956)	2,383
Net charge for interest and other finance expense, less net interest paid	63	300	60	392	214
Share-based payments	219	228	199	401	544
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(80)	(371)	(46)	(471)	(100)
Net charge for provisions, less payments	666	1,172	293	2,740	(131)
Movements in inventories and other current and non-current assets and liabilities	3,850	26	556	1,083	630
Income taxes paid	(1,424)	(1,015)	(810)	(3,007)	(1,994)
Net cash provided by operating activities	5,976	5,411	5,204	17,496	9,893
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(2,647)	(2,435)	(2,577)	(8,115)	(9,384)
Acquisitions, net of cash acquired	(53)	-	(10)	(54)	(27)
Investment in joint ventures	(70)	(47)	(12)	(859)	(38)
Investment in associates	(133)	(32)	(1,037)	(187)	(1,115)
Total cash capital expenditure	(2,903)	(2,514)	(3,636)	(9,215)	(10,564)
Proceeds from disposal of fixed assets	(19)	93	32	625	52
Proceeds from disposal of businesses, net of cash disposed	332	122	84	4,067	1,425
Proceeds from loan repayments	33	67	50	161	656
Cash provided from investing activities	346	282	166	4,853	2,133
Net cash used in investing activities	(2,557)	(2,232)	(3,470)	(4,362)	(8,431)
Financing activities
Net issue (repurchase) of shares (Note 7)	(926)	(500)	-	(1,426)	(776)
Lease liability payments	(506)	(514)	(578)	(1,580)	(1,811)
Proceeds from long-term financing	2,398	1,985	2,587	6,339	12,117
Repayments of long-term financing	(6,745)	(67)	(4,307)	(13,841)	(8,988)
Net increase (decrease) in short-term debt	(81)	(33)	(2,630)	108	(328)
Issue of perpetual hybrid bonds(a)	859	-	-	859	11,861
Payments on perpetual hybrid bonds	(55)	(328)	(27)	(438)	(27)
Payments relating to transactions involving non-controlling interests (Other interest)	(560)	-	-	(560)	(8)
Receipts relating to transactions involving non-controlling interests (Other interest)	-	3	483	671	492
Dividends paid - BP shareholders	(1,101)	(1,062)	(1,060)	(3,227)	(5,281)
- non-controlling interests	(87)	(107)	(58)	(245)	(163)
Net cash provided by (used in) financing activities	(6,804)	(623)	(5,590)	(13,340)	7,088
Currency translation differences relating to cash and cash equivalents	(177)	24	268	(211)	43
Increase (decrease) in cash and cash equivalents	(3,562)	2,580	(3,588)	(417)	8,593
Cash and cash equivalents at beginning of period	34,256	31,676	34,653	31,111	22,472
Cash and cash equivalents at end of period_(b)	30,694	34,256	31,065	30,694	31,065

(a) See note 1 - Issuance of hybrid securities for further information.

(b) Third quarter and nine months 2020 includes $316 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.

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Notes

Note 1. Basis of preparation

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

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2020 included in BP Annual Report and Form 20-F 2020.

The directors consider it appropriate to adopt the going concern basis of accounting in preparing the interim financial statements. The ongoing impact of COVID-19 and the current economic environment has been considered as part of the going concern assessment. Forecast liquidity has been assessed under a number of stressed scenarios to support this assertion. Reverse stress tests indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the interim financial statements even if the Brent price fell to zero.

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 European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. As a result of the UK's withdrawal from the EU, with effect from 1 January 2021, the consolidated financial statements are also prepared in accordance with IFRS as adopted by the UK. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the EU and UK 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 2021 which are the same as those used in preparing BP Annual Report and Form 20-F 2020 with the exception of the changes described in the 'Updates to significant accounting policies' section below. There are no other new or amended standards or interpretations adopted from 1 January 2021 onwards that have a significant impact on the financial information.

Considerations in respect of COVID-19 and the current economic environment

bp's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 2020. These have been subsequently considered at the end of each quarter to determine if any changes were required to those judgements and estimates as a result of current market conditions. The conditions also result in the valuation of certain assets and liabilities remaining subject to more uncertainty, including those set out below.

Impairment testing assumptions

The group's price assumption for Brent oil was revised during the second quarter. The assumption up to 2030 was increased to reflect near-term supply constraints whereas the long-term assumption was decreased reaching $55 per barrel by 2040 and $45 per barrel by 2050 (in real 2020 terms) as bp's management expects an acceleration of the pace of transition to a lower carbon economy. The price assumption for Henry Hub gas were unchanged from those disclosed in BP Annual Report and Form 20-F 2020. A summary of the group's price assumptions, in real 2020 terms, is provided below:

	4Q21	2025	2030	2040	2050
Brent oil ($/bbl)	60	60	60	55	45
Henry Hub gas ($/mmBtu)	3.00	3.00	3.00	3.00	2.75

The group has identified upstream oil and gas properties with carrying amounts totalling approximately $30 billion where the headroom, based on the most recent impairment tests performed, was less than or equal to 20% of the carrying value. A change in price or other assumptions within the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a significant risk of impairment reversals or charges in that period.

The discount rates used in value-in-use impairment testing as disclosed in BP Annual Report and Form 20-F 2020, are unchanged.

Provisions

The nominal risk-free discount rate applied to provisions is reviewed on a quarterly basis. The discount rate applied to the group's provisions remains at 2.0% (31 December 2020 2.5%).

Pensions and other post-retirement benefits

The group's defined benefit pension plans are reviewed quarterly to determine any changes to the fair value of the plan assets or present value of the defined benefit obligations. As a result of the review during the third quarter of 2021, the group's total net defined benefit pension plan surplus as at 30 September 2021 is $2.4 billion, compared to a surplus of $2.0 billion and a deficit of $1.3 billion at 30 June 2021 and 31 December 2020 respectively.

The movement for the nine months principally reflects net actuarial gains reported in other comprehensive income arising from increases in the UK, US and Eurozone discount rates and positive asset performance, partly offset by increases in inflation rates. Also reflected in the nine months is a reduction in the liability of the UK funded final salary pension plan which was closed to future accrual on 30 June 2021. A curtailment gain of $0.3 billion was recognized in the income statement in the second quarter. For active members of the scheme at 30 June 2021, benefits payable are now linked to salary as at that date rather than to salary on retirement. The current environment is likely to continue to affect the values of the plan assets and obligations resulting in potential volatility in the amount of the net defined benefit pension plan surplus/deficit recognized.

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Note 1. Basis of preparation (continued)

Impairment of financial assets measured at amortized cost

The estimate of the loss allowance recognized on financial assets measured at amortized cost using an expected credit loss approach was determined not to be a significant accounting estimate in preparing BP Annual Report and Form 20-F 2020. Expected credit loss allowances are, however, reviewed and updated quarterly. Allowances are recognized on assets where there is evidence that the asset is credit-impaired and on a forward-looking expected credit loss basis for assets that are not credit-impaired. The current economic environment and future credit risk outlook have been considered in updating the estimate of loss allowances with no significant impact in the quarter.

The group continues to believe that the calculation of expected credit loss allowances is not a significant accounting estimate. The group continues to apply its credit policy as disclosed in BP Annual Report and Form 20-F 2020 - Financial statements - Note 29 Financial instruments and financial risk factors - credit risk.

Other accounting judgements and estimates

All other significant accounting judgements and estimates disclosed in BP Annual Report and Form 20-F 2020 remain applicable and no new significant accounting judgements or estimates have been identified specifically arising from the impact of COVID-19.

Issuance of hybrid securities

During the quarter, a group subsidiary issued perpetual subordinated hybrid capital securities of $0.9 billion. The proceeds from this issuance were specifically earmarked to fund a forward purchase and leaseback of an under-construction floating, production, storage, and offloading vessel (FPSO) to be used on one of the group's major projects.

As the group has the unconditional right to defer interest and principal indefinitely, they are classified as equity instruments and reported within non-controlling interests in the condensed consolidated financial statements.

Updates to significant accounting policies

Change in accounting policy - Interest Rate Benchmark Reform - Phase II

Financial authorities have announced the timing of interest rate benchmark transitions with market discussions continuing around benchmark application. The replacement of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with alternative benchmarks in the US, UK, EU and other territories is expected at the end of 2021 for most benchmarks, with remaining USD tenors expected to cease in 2023. bp is primarily exposed to USD LIBORs that will be available until June 2023.

Amendments to IFRS 9 'Financial instruments', IFRS 16 'Leases' and other IFRSs were issued by the IASB in August 2020 to provide practical expedients and reliefs when changes are made to contractual cash flows or hedging relationships because of the transition from Inter-bank Offered Rates to alternative risk-free rates. bp adopted these amendments from 1 January 2021 and they will be applied prospectively.

bp has set up an internal working group on interest rate benchmark reform to monitor market developments and manage the transition to alternative benchmark rates. The impacts on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts have been assessed and transition plans are being developed. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform.

Change in segmentation

During the first quarter of 2021, the group's reportable segments were changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the group chief executive, from that date. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.

Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'.

Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment.

Customers & products comprises the group's customer-focused businesses, spanning convenience and mobility, which includes fuels retail and next-gen offers such as electrification, as well as aviation, midstream, and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business will also be reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal.

The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.

The segment measure of profit or loss continues to be replacement cost profit or loss before interest and tax, which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and losses. See Note 4 for further information.

Comparative information for 2020 has been restated in Notes 4, 5 and 6 to reflect the changes in reportable segments.

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Note 1. Basis of preparation (continued)

Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts

bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group previously presented revenues and purchases for such contracts on a gross basis in the income statement upon physical settlement.

These transactions have historically represented a substantial portion of the revenues and purchases reported in the group's consolidated financial statements.

The change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, resulted in the group determining that the revenue and corresponding purchases relating to such transactions should be presented net, as gains or losses within other operating revenues, from that date.

Additionally the group's trading activity has continued to evolve over time from one of capturing third-party physical trades to provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which will continue under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant information for users of the accounts as the group's revenue recognition is more closely aligned with its assessment of 'Scope 3' emissions from its products, its 'Net Zero' ambition and how management monitors and manages performance of such contracts. Comparative information for sales and other operating revenues and purchases for 2020 has been restated as shown in the table below. There is no significant impact on comparative information for profit before income and tax or earnings per share.

In addition, as disclosed in the group's 2020 financial statements, in 2020 revenues from physically settled derivative contracts were reclassified as other operating revenues and were no longer presented together with revenues from contracts with customers. In these financial statements certain other similar contracts have been reclassified as other operating revenues and then been subject to net presentation as described above. Comparative information for natural gas, LNG and NGLs, and non-oil products and other revenue from contracts with customers in Note 5 has been amended to align with current period presentation as shown in the table below.

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Note 1. Basis of preparation (continued)

	Third	Third		Nine	Nine
	quarter	quarter		months	months
	2020	2020	Impact of net	2020	2020	Impact of net
$ million		Restated	presentation_(a)		Restated	presentation_(a)
Sales and other operating revenues (Note 5)
gas & low carbon energy	4,141	3,518	(623)	14,376	12,270	(2,106)
oil production & operations	3,998	3,998	-	13,133	13,133	-
customers & products	40,256	22,940	(17,316)	121,461	66,537	(54,924)
other businesses & corporate	383	383	-	1,262	1,262	-
	48,778	30,839	(17,939)	150,232	93,202	(57,030)
Less: sales and other revenues between segments
gas & low carbon energy	254	254	-	2,092	2,092	-
oil production & operations	3,726	3,726	-	12,097	12,097	-
customers & products	124	124	-	(328)	(328)	-
other businesses & corporate	423	423	-	794	794	-
	4,527	4,527	-	14,655	14,655	-
External sales and other operating revenues
gas & low carbon energy	3,887	3,264	(623)	12,284	10,178	(2,106)
oil production & operations	272	272	-	1,037	1,037	-
customers & products	40,132	22,816	(17,316)	121,789	66,865	(54,924)
other businesses & corporate	(40)	(40)	-	467	467	-
Total sales and other operating revenues	44,251	26,312	(17,939)	135,577	78,547	(57,030)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	1,366	1,366	-	3,863	3,863	-
Oil products	16,642	16,642	-	47,348	47,348	-
Natural gas, LNG and NGLs	2,844	1,443	(1,401)	9,474	6,693	(2,781)
Non-oil products and other revenues from contracts with customers	2,624	2,580	(44)	7,232	7,149	(83)
Revenues from contracts with customers	23,476	22,031	(1,445)	67,917	65,053	(2,864)
Other operating revenues	20,775	4,281	(16,494)	67,660	13,494	(54,166)
Total sales and other operating revenues	44,251	26,312	(17,939)	135,577	78,547	(57,030)

(a) Total purchases for the third quarter and nine months 2020 have been re-stated by the equal and opposite amount as total sales and other operating revenues.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2021 is $39 million, with associated liabilities of $31 million.

At 31 December 2020 the balance consists primarily of a 20% participating interest from BP's 60% participating interest in Block 61 in Oman, which is reported in the gas & low carbon energy segment. As announced on 1 February 2021, BP agreed to sell this interest to PTT Exploration and Production Public Company Limited (PTTEP) of Thailand for a total consideration of up to $2.6 billion, subject to final adjustments. On 28 March, a royal decree was published approving the sale and $2.4 billion was received in March 2021.

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Note 3. Impairment and losses on sale of businesses and fixed assets_(a)

Impairment charges net of losses on sale of businesses and fixed assets for the third quarter were $220 million and impairment reversals net of losses on sale of businesses and fixed assets for the nine months 2021 were $2,344 million respectively (charges of $294 million and $13,213 million for the comparative periods in 2020) and include net impairment charges for the third quarter of 2021 of $256 million and net impairment reversals for the nine months 2021 of $2,488 million (charges of $278 million and $12,924 million for the comparative periods in 2020).

gas & low carbon energy segment

In the gas & low carbon energy segment there was a net impairment charge of $197 million for the third quarter and a net impairment reversal of $951 million for the nine months 2021 (charges of $76 million and $6,188 million for the comparative periods in 2020).

Impairment reversals for the nine months 2021 mainly relate to producing assets and principally arose as a result of changes to the group's oil and gas price assumptions. They include amounts in Azerbaijan, India and Trinidad. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.

oil production & operations segment

In the oil production & operations segment there was a net impairment charge of $5 million for the third quarter and a net impairment reversal of $1,652 million for the nine months 2021 (charges of $197 million and $5,989 million for the comparative periods in 2020).

Impairment reversals for the nine months 2021 mainly relate to producing assets and principally arose as a result of changes to the group's oil and gas price assumptions. They include amounts in BPX Energy and the North Sea. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.

(a) All disclosures are pre-tax.

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
gas & low carbon energy	(4,135)	927	252	222	(6,430)
oil production & operations	2,692	3,118	(156)	7,289	(14,649)
customers & products	1,060	640	915	2,634	2,173
Rosneft	868	643	(278)	1,874	(419)
other businesses & corporate	(750)	(425)	(42)	(1,853)	(867)
	(265)	4,903	691	10,166	(20,192)
Consolidation adjustment - UPII*	(42)	(31)	34	(60)	166
RC profit (loss) before interest and tax*	(307)	4,872	725	10,106	(20,026)
Inventory holding gains (losses)*
gas & low carbon energy	15	4	7	41	9
oil production & operations	(1)	(6)	1	8	(12)
customers & products	451	887	191	2,943	(3,446)
Rosneft (net of tax)	35	68	34	191	(114)
Profit (loss) before interest and tax	193	5,825	958	13,289	(23,589)
Finance costs	693	682	800	2,098	2,366
Net finance expense/(income) relating to pensions and other post-retirement benefits	(5)	5	8	6	23
Profit (loss) before taxation	(495)	5,138	150	11,185	(25,978)

RC profit (loss) before interest and tax*
US	1,964	955	105	4,826	(3,995)
Non-US	(2,271)	3,917	620	5,280	(16,031)
	(307)	4,872	725	10,106	(20,026)

(a) Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 basis of preparation - Change in segmentation.

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Note 5. Sales and other operating revenues_(a)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
By segment
gas & low carbon energy	2,554	5,739	3,518	16,295	12,270
oil production & operations	6,285	5,597	3,998	17,037	13,133
customers & products	34,382	31,160	22,940	92,649	66,537
other businesses & corporate	423	381	383	1,240	1,262
	43,644	42,877	30,839	127,221	93,202

Less: sales and other operating revenues between segments
gas & low carbon energy	1,269	1,063	254	3,364	2,092
oil production & operations	5,423	4,928	3,726	15,206	12,097
customers & products	354	112	124	576	(328)
other businesses & corporate	424	307	423	890	794
	7,470	6,410	4,527	20,036	14,655

External sales and other operating revenues
gas & low carbon energy	1,285	4,676	3,264	12,931	10,178
oil production & operations	862	669	272	1,831	1,037
customers & products	34,028	31,048	22,816	92,073	66,865
other businesses & corporate	(1)	74	(40)	350	467
Total sales and other operating revenues	36,174	36,467	26,312	107,185	78,547

By geographical area
US	15,372	15,305	8,319	45,168	25,516
Non-US	28,578	29,700	22,583	85,161	66,361
	43,950	45,005	30,902	130,329	91,877
Less: sales and other operating revenues between areas	7,776	8,538	4,590	23,144	13,330
	36,174	36,467	26,312	107,185	78,547

Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	2,292	1,291	1,366	4,917	3,863
Oil products	27,699	24,651	16,642	71,628	47,348
Natural gas, LNG and NGLs_(b)	4,458	4,273	1,443	12,912	6,693
Non-oil products and other revenues from contracts with customers_(b)	2,275	1,603	2,580	5,276	7,149
Revenue from contracts with customers	36,724	31,818	22,031	94,733	65,053
Other operating revenues_(c)	(550)	4,649	4,281	12,452	13,494
Total sales and other operating revenues	36,174	36,467	26,312	107,185	78,547

(a) Comparative information for 2020 has been restated for the changes in reportable segments and also for the changes to net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 Basis of preparation - Voluntary change in accounting policy and Change in segmentation.

(b) Comparative information has been amended for certain contracts that have been reclassified to other operating revenues and restated to reflect the net presentation described in Note 1 Basis of preparation - Voluntary change in accounting policy.

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Note 6. Depreciation, depletion and amortization_(a)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Total depreciation, depletion and amortization by segment
gas & low carbon energy	1,230	1,115	746	3,199	2,736
oil production & operations	1,767	1,559	1,814	4,900	6,001
customers & products	747	754	743	2,246	2,242
other businesses & corporate	200	203	164	597	484
	3,944	3,631	3,467	10,942	11,463
Total depreciation, depletion and amortization by geographical area
US	1,206	1,161	1,191	3,488	4,020
Non-US	2,738	2,470	2,276	7,454	7,443
	3,944	3,631	3,467	10,942	11,463

(a) Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 basis of preparation - Change in segmentation.

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. During the third quarter 2021 221 million of ordinary shares were repurchased for cancellation for a total cost of $926 million, including transaction costs of $5 million, as part of the share buyback programme announced on 27 April 2021. This brings the total number of shares repurchased in the nine months to 336 million for a total cost of $1,426 million. The number of shares in issue is reduced when shares are repurchased.

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

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Results for the period
Profit (loss) for the period attributable to bp shareholders	(2,544)	3,116	(450)	5,239	(21,663)
Less: preference dividend	1	-	-	2	1
Profit (loss) attributable to bp ordinary shareholders	(2,545)	3,116	(450)	5,237	(21,664)

Number of shares (thousand)_(a)(b)
Basic weighted average number of shares outstanding	20,150,186	20,272,111	20,251,199	20,239,365	20,217,559
ADS equivalent_(c)	3,358,364	3,378,685	3,375,199	3,373,228	3,369,593

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,150,186	20,366,731	20,251,199	20,359,280	20,217,559
ADS equivalent_(c)	3,358,364	3,394,455	3,375,199	3,393,213	3,369,593

Shares in issue at period-end	20,008,900	20,224,314	20,254,417	20,008,900	20,254,417
ADS equivalent_(c)	3,334,816	3,370,719	3,375,736	3,334,816	3,375,736

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

(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 third quarter 2021, third quarter 2020 and nine months 2020 are 123,543 thousand (ADS equivalent 20,591 thousand), 81,097 thousand (ADS equivalent 13,516 thousand) and 94,302 thousand (ADS equivalent 15,717 thousand) respectively.

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Note 8. Dividends

Dividends payable

BP today announced an interim dividend of 5.46 cents per ordinary share which is expected to be paid on 17 December 2021 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 12 November 2021. The ex-dividend date will be 10 November 2021 for ADS holders and 11 November 2021 for ordinary shareholders. The corresponding amount in sterling is due to be announced on 7 December 2021, calculated based on the average of the market exchange rates over three dealing days between 1 December 2021 and 3 December 2021. Holders of ADSs are expected to receive $0.3276 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2021 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
Dividends paid per ordinary share
cents	5.460	5.250	5.250	15.960	26.250
pence	3.953	3.712	4.043	11.433	20.541
Dividends paid per ADS (cents)	32.76	31.50	31.50	95.76	157.50

Note 9. Net debt

Net debt*	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Finance debt_(a)(b)	63,214	68,247	72,828	63,214	72,828
Fair value (asset) liability of hedges related to finance debt_(c)	(549)	(1,285)	(1,384)	(549)	(1,384)
	62,665	66,962	71,444	62,665	71,444
Less: cash and cash equivalents_(b)	30,694	34,256	31,065	30,694	31,065
Net debt_(d)	31,971	32,706	40,379	31,971	40,379
Total equity	89,266	93,232	82,155	89,266	82,155
Gearing*	26.4%	26.0%	33.0%	26.4%	33.0%

(a) The fair value of finance debt at 30 September 2021 was $65,316 million (30 June 2021 $70,589 million, 30 September 2020 $75,338 million).

(b) Third quarter and nine months 2020 include $316 million of cash and $19 million of finance debt included in assets and liabilities held for

sale in the group balance sheet.

(c) Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $151 million at 30 September 2021 (second quarter 2021 liability of $308 million and third quarter 2020 liability of $372 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

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

As part of actively managing its debt portfolio, in the third quarter the group bought back $4.2 billion equivalent of finance debt (second quarter 2021 $nil; third quarter 2020 $4.0 billion) consisting of $2.4 billion of USD bonds in July 2021, and a further $1.8 billion equivalent in September 2021 comprising $1.4 billion euro and sterling bonds and $0.4 billion other USD debt. Year to date the group has bought back a total of $8.1 billion equivalent of finance debt ($4.0 billion for the comparative period in 2020). Derivatives associated with debt bought back in each of these periods were also terminated. There was no significant impact on net debt or gearing as a result of these transactions.

Note 10. Inventory valuation

A provision of $129 million was held against hydrocarbon inventories at 30 September 2021 ($17 million at 30 June 2021 and $544 million at 30 September 2020) to write them down to their net realizable value. As a result of the changes in strategic direction of the group and the evolution of the trading strategy set out in Note 1, from 1 January, certain inventory, totalling $12.8 billion as at 30 September 2021 ($11.0 billion as at 30 June 2021), is now treated as trading inventory and is valued at fair value whereas the equivalent inventory was previously valued at the lower of cost or net realisable value in prior periods.

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Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 1 November 2021, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2021. BP Annual Report and Form 20-F 2020 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

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Additional information

Capital expenditure*_(a)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Capital expenditure
Organic capital expenditure*	2,850	2,511	2,512	8,267	9,085
Inorganic capital expenditure*_(b)(c)	53	3	1,124	948	1,479
	2,903	2,514	3,636	9,215	10,564

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Capital expenditure by segment
gas & low carbon energy_(b)	1,072	747	935	3,704	3,138
oil production & operations	1,099	1,148	1,117	3,566	4,696
customers & products	597	519	1,519	1,648	2,545
other businesses & corporate	135	100	65	297	185
	2,903	2,514	3,636	9,215	10,564
Capital expenditure by geographical area
US	1,176	890	741	3,553	3,177
Non-US	1,727	1,624	2,895	5,662	7,387
	2,903	2,514	3,636	9,215	10,564

(a) Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Change in segmentation.

(b) Nine months 2021 includes the final payment of $712 million in respect of the strategic partnership with Equinor.

(c) Third quarter and nine months 2020 include $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries. Nine months 2020 also includes amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

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Adjusting items*_(a)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
gas & low carbon energy
Gains on sale of businesses and fixed assets_(b)	-	-	-	1,034	-
Impairment and losses on sale of businesses and fixed assets_(c)	(197)	1,270	(83)	950	(6,197)
Environmental and other provisions	-	-	-	-	-
Restructuring, integration and rationalization costs_(d)	-	(21)	(36)	(29)	(40)
Fair value accounting effects_(e)(f)	(5,808)	(1,311)	(217)	(6,872)	(61)
Other_(g)	63	(251)	86	(178)	(667)
	(5,942)	(313)	(250)	(5,095)	(6,965)
oil production & operations
Gains on sale of businesses and fixed assets	261	216	9	645	103
Impairment and losses on sale of businesses and fixed assets_(c)	33	1,751	(191)	1,575	(6,182)
Environmental and other provisions_(h)	(68)	(776)	(9)	(909)	(22)
Restructuring, integration and rationalization costs_(d)	4	(90)	(129)	(90)	(153)
Fair value accounting effects	-	-	-	-	-
Other_(g)(i)	1	(225)	(203)	(200)	(1,944)
	231	876	(523)	1,021	(8,198)
customers & products
Gains on sale of businesses and fixed assets	(25)	8	16	(114)	10
Impairment and losses on sale of businesses and fixed assets	(58)	(35)	(20)	(136)	(823)
Environmental and other provisions	(1)	(8)	-	(9)	-
Restructuring, integration and rationalization costs_(d)	16	(10)	(142)	(35)	(111)
Fair value accounting effects_(f)	(30)	(139)	425	290	135
Other	-	(3)	-	(3)	-
	(98)	(187)	279	(7)	(789)
Rosneft
Other	(55)	(46)	(101)	(101)	(164)
	(55)	(46)	(101)	(101)	(164)
other businesses & corporate
Gains on sale of businesses and fixed assets	-	-	2	-	4
Impairment and losses on sale of businesses and fixed assets	1	(50)	-	(50)	-
Environmental and other provisions	(65)	(72)	(32)	(137)	(55)
Restructuring, integration and rationalization costs_(d)	(12)	(74)	(155)	(111)	(201)
Gulf of Mexico oil spill	(17)	(18)	(63)	(46)	(115)
Fair value accounting effects_(f)	(263)	73	266	(637)	225
Other	(21)	21	61	(24)	48
	(377)	(120)	79	(1,005)	(94)
Total before interest and taxation	(6,241)	210	(516)	(5,187)	(16,210)
Finance costs_(j)(k)	(175)	(202)	(198)	(525)	(434)
Total before taxation	(6,416)	8	(714)	(5,712)	(16,644)
Taxation credit (charge) on adjusting items	193	(396)	(101)	(191)	3,686
Taxation - impact of foreign exchange_(l)	(33)	(30)	85	(76)	(166)
Total taxation on adjusting items	160	(426)	(16)	(267)	3,520
Total after taxation for period	(6,256)	(418)	(730)	(5,979)	(13,124)

(a) Prior to 2021 adjusting items were reported under two different headings - non-operating items and fair value accounting effects. Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Change in segmentation.

(b) Nine months 2021 relates to a gain from the divestment of a 20% stake in Oman Block 61.

(d) All periods in 2021 include recognized provisions for restructuring costs associated with the reinvent programme that was formalized in 2020.

(e) Under IFRS bp marks-to-market the derivative financial instruments used to risk-manage LNG contracts, but does not mark-to-market the physical LNG contracts themselves, resulting in a mismatch in accounting treatment. The fair value accounting effect removes this mismatch, and the underlying result reflects how bp risk-manages its LNG contracts.

(f) For further information, including the nature of fair value accounting effects reported in each segment, see page 36.

(g) Nine months 2020 includes the exploration write-off of $670 million in gas and low carbon energy relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of gas & low carbon assets in India and the impairment of certain intangible assets in Mauritania and Senegal and $1,301 million in oil production & operations relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of oil production & operations assets in Brazil and the Gulf of Mexico.

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(h) Second quarter and nine months 2021 include adjustments relating to the change in discount rate on retained decommissioning provisions and the recognition of a decommissioning provision in relation to certain assets previously sold to a third party where the decommissioning obligation transferred may revert to bp due to the financial condition of the current owner.

(i) Nine months 2021 includes a $415 million charge relating to a remeasurement of deferred tax balances in our equity-accounted entity in Argentina following income tax rate changes partially offset by impairment reversals in equity-accounted entities.

(j) All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables and the income statement impact associated with the buyback of finance debt. See Note 9 for further information.

(k) From first quarter 2021 bp is presenting temporary valuation differences associated with the group's interest rate and foreign currency exchange risk management of finance debt as an adjusting item within finance costs. In 2020 these amounts were presented within production and manufacturing expenses and as an 'other' adjusting item in the other business & corporate segment. Relevant amounts in the comparative periods presented were not material.

(l) bp is presenting 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.

Net debt including leases

Net debt including leases*	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Net debt	31,971	32,706	40,379	31,971	40,379
Lease liabilities	8,628	8,863	9,282	8,628	9,282
Net partner (receivable) payable for leases entered into on behalf of joint operations	111	109	(41)	111	(41)
Net debt including leases	40,710	41,678	49,620	40,710	49,620
Total equity	89,266	93,232	82,155	89,266	82,155
Gearing including leases*	31.3%	30.9%	37.7%	31.3%	37.7%

Gulf of Mexico oil spill

	30 September	31 December
$ million	2021	2020
Gulf of Mexico oil spill payables and provisions	(10,329)	(11,436)
Of which - current	(1,272)	(1,444)

Deferred tax asset	4,016	5,471

During the second quarter pre-tax payments of $1,199 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 2020 - Financial statements - Notes 7, 9, 20, 22, 23, 29, and 33.

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Working capital* reconciliation_(a)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement_(b)	3,850	26	556	1,083	630
Adjusted for inventory holding gains (losses)* (Note 4 excluding Rosneft)	465	885	199	2,992	(3,449)
Adjusted for fair value accounting effects	(6,101)	(1,377)	474	(7,219)	299
Working capital release (build) after adjusting for net inventory gains (losses) and fair value accounting effects	(1,786)	(466)	1,229	(3,144)	(2,520)

(a) Commencing with second quarter 2021 results fair value accounting effects have been included in the working capital reconciliation. For further information see Glossary page 40.

(b) The movement in working capital includes outflows relating to the Gulf of Mexico oil spill on a pre-tax basis of $37 million and $1,375 million in the third quarter and nine months of 2021 respectively. For the same periods in 2020 the amount was an outflow of $180 million and $1,670 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2021 and 2020 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states.

Surplus cash flow* reconciliation

	Third	Nine
	quarter	months
$ million	2021	2021
Sources:
Net cash provided by operating activities	5,976	17,496
Cash provided from investing activities	346	4,853
Receipts relating to transactions involving non-controlling interests	-	671
Cash inflow	6,322	23,020

Uses:
Lease liability payments	(506)	(1,580)
Payments on perpetual hybrid bonds	(55)	(438)
Dividends paid - BP shareholders	(1,101)	(3,227)
- non-controlling interests	(87)	(245)
Total capital expenditure*	(2,903)	(9,215)
Net repurchase of shares relating to employee share schemes	-	(500)
Payments relating to transactions involving non-controlling interests	(560)	(560)
Currency translation differences relating to cash and cash equivalents	(177)	(211)
Cash outflow	(5,389)	(15,976)

Cash used to meet net debt target	-	(3,729)

Surplus cash flow	933	3,315

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

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2021	2021	2020	2021	2020
RC profit before interest and tax for customers & products	1,060	640	915	2,634	2,173
Less: Adjusting items gains (charges)	(98)	(187)	279	(7)	(789)
Underlying RC profit before interest and tax for customers & products	1,158	827	636	2,641	2,962
By business:
customers - convenience & mobility	806	951	1,081	2,415	2,201
Castrol - included in customers	231	265	326	830	556
products - refining & trading	352	(124)	(533)	226	561
petrochemicals	-	-	88	-	200

Add back: Depreciation, depletion and amortization	747	754	743	2,246	2,242
By business:
customers - convenience & mobility	324	329	306	977	876
Castrol - included in customers	36	39	38	114	119
products - refining & trading	423	425	435	1,269	1,264
petrochemicals	-	-	2	-	102

Adjusted EBITDA for customers & products	1,905	1,581	1,379	4,887	5,204
By business:
customers - convenience & mobility	1,130	1,280	1,387	3,392	3,077
Castrol - included in customers	267	304	364	944	675
products - refining & trading	775	301	(98)	1,495	1,825
petrochemicals	-	-	90	-	302

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Realizations* and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
Average realizations_(a)
Liquids* ($/bbl)
US	59.87	53.64	31.74	52.92	33.24
Europe	74.02	69.19	43.52	67.79	41.35
Rest of World	68.67	64.44	41.46	63.51	36.13
BP Average	65.63	60.69	38.17	59.78	35.51
Natural gas ($/mcf)
US	3.51	3.03	1.29	3.33	1.19
Europe	17.07	8.94	2.34	10.96	2.22
Rest of World	5.26	4.13	2.99	4.44	3.21
BP Average	5.35	4.08	2.56	4.48	2.65
Total hydrocarbons* ($/boe)
US	45.39	41.14	22.04	41.24	23.01
Europe	81.99	63.85	36.14	66.51	34.34
Rest of World	45.13	40.27	27.40	40.45	26.19
BP Average	47.57	41.84	26.42	42.37	25.68
Average oil marker prices ($/bbl)
Brent	73.51	68.97	42.94	67.92	41.06
West Texas Intermediate	70.54	66.19	40.91	65.06	38.12
Western Canadian Select	56.95	53.10	31.62	52.06	27.54
Alaska North Slope	72.66	68.58	42.75	67.53	41.32
Mars	69.09	66.01	42.01	64.67	39.18
Urals (NWE - cif)	70.63	66.69	42.83	65.60	40.83
Average natural gas marker prices
Henry Hub gas price_(b) ($/mmBtu)	4.02	2.83	1.98	3.19	1.88
UK Gas - National Balancing Point (p/therm)	118.81	64.79	21.06	78.38	19.69

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

(b) Henry Hub First of Month Index.

Exchange rates

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2021	2021	2020	2021	2020
$/£ average rate for the period	1.38	1.40	1.29	1.39	1.27
$/£ period-end rate	1.34	1.38	1.28	1.34	1.28

$/€ average rate for the period	1.18	1.21	1.17	1.20	1.12
$/€ period-end rate	1.16	1.19	1.17	1.16	1.17

$/AUD average rate for the period	0.73	0.77	0.71	0.76	0.67
$/AUD period-end rate	0.72	0.75	0.71	0.72	0.71

Rouble/$ average rate for the period	73.52	74.20	73.74	74.04	71.00
Rouble/$ period-end rate	72.78	72.70	77.57	72.78	77.57

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Legal proceedings

For a full discussion of the group's material legal proceedings, see pages 226-227 of bp Annual Report and Form 20-F 2020.

Glossary

Non-GAAP 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-GAAP measures are sometimes referred to as alternative performance measures.

New metrics have been introduced in 2021 to provide transparency against key strategic value drivers.

Adjusted EBITDA is a non-GAAP measure presented for bp's operating segments and is defined as replacement cost (RC) profit before interest and tax, excluding net adjusting items*, 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.

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 other provisions, restructuring, integration and rationalization costs, fair value accounting effects, 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-GAAP measures. An analysis of adjusting items by segment and type is shown on page 30. Prior to 2021 adjusting items were reported under two different headings - non-operating items and fair value accounting effects.

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

Cash balance point is defined as the implied Brent oil price for the quarter that would cause the sum of operating cash flow excluding Gulf of Mexico oil spill payments (assuming actual refining marker margins and Henry Hub gas prices for the quarter) and proceeds from loan repayments to equate to the sum of total cash capital expenditure, lease liability payments, dividend paid, and payments on perpetual hybrid bonds.

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

Convenience gross margin is a non-GAAP measure. Convenience gross margin is calculated as RC profit before interest and tax for the customers & products segment, excluding RC profit before interest and tax for the refining & trading and petrochemicals businesses, and adjusting items* (as defined above) for the convenience & mobility business to derive underlying RC profit before interest and tax for the convenience & mobility business; subtracting underlying RC profit before interest and tax for the Castrol business; adding back depreciation, depletion and amortization, production and manufacturing, distribution and administration expenses for convenience & mobility (excluding Castrol); subtracting earnings from equity-accounted entities in the convenience & mobility business (excluding Castrol) and gross margin for the retail fuels, next-gen, aviation, B2B and midstream businesses.

Convenience gross margin growth at constant foreign exchange is a non-GAAP measure. This metric requires a calculation of the comparative convenience gross margin ($ million) at current period foreign exchange rates (constant foreign exchange) and compares the current period value with the restated comparative period value, which results in the growth % at constant foreign exchange rates. bp believes the convenience gross margin and growth at constant foreign exchange are useful measures because these measures may help investors to understand and evaluate, in the same way as management, our progress against our strategic objectives of redefining convenience. The nearest GAAP measure to convenience gross margin is RC profit before interest and tax for the customer & products segment.

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). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity to FID will increase proportionately to share increase for any assets where bp held equity at the point of 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-GAAP 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-GAAP measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

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Glossary (continued)

Electric vehicle charge points are defined as charge points operated by either bp or a bp joint venture.

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

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, reduces the measurement differences between that of the derivative financial instruments used to risk manage the LNG contracts and the measurement of the LNG contracts themselves, which therefore gives a better representation of performance in each period.

In addition, from the second quarter 2020 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.

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Glossary (continued)

Gearing and net debt are non-GAAP 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 GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 27.

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 GAAP 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 a GAAP estimate.

Gearing including leases and net debt including leases are non-GAAP 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 GAAP 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 31.

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

Inorganic capital expenditure is a non-GAAP 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 GAAP information is provided on page 29.

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-GAAP adjustments to our IFRS profit (loss) and represent:

a. 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

b. 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 for oil production & operations, gas & low carbon energy and Rosneft comprises crude oil, condensate and natural gas liquids. For oil production & operations and gas & low carbon energy, liquids also includes bitumen.

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

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

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Glossary (continued)

Organic capital expenditure is a non-GAAP 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 GAAP information is provided on page 29.

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 GAAP 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.

Refining availability represents Solomon Associates' operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all 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 criteria to the point they can be considered developed to final investment decision (FID): Site based projects have obtained land exclusivity rights, or for PPA 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 GAAP 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 GAAP information is provided on page 1. RC profit or loss before interest and tax is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

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 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 and Thorntons, and also includes sites in India through our Jio-bp JV.

Retail sites in growth markets are retail sites that are either bp branded or co-branded with our partners in China, Mexico and Indonesia and also include 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 both sell bp branded fuel and carry one of the strategic convenience brands (e.g. M&S, Rewe to Go). To be considered a strategic convenience brand the convenience offer should be a strategic differentiator in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.

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Glossary (continued)

Surplus cash flow is a non-GAAP measure and 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. See page 32 for the components of our sources of cash and uses of cash.

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 this represents a more up to date reflection of the safety environment.

Underlying effective tax rate (ETR) is a non-GAAP 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-GAAP 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 GAAP 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 a GAAP estimate.

Underlying production - 2021 underlying production, when compared with 2020, 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-GAAP measure and is RC profit or loss* (as defined on page 38) after excluding net adjusting items and related taxation. See page 30 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 GAAP information is provided on page 1 for the group and pages 6-14 for the segments.

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Glossary (continued)

Underlying RC profit or loss per share is a non-GAAP 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 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 shareholders.

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

upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. 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 cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp's share of equity-accounted entities.

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

Change in working capital adjusted for inventory holding gains/losses and fair value accounting effects is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and from the second quarter onwards, it is also adjusted for fair value accounting effects reported within adjusting items for the period. This represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been underlying replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities.

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

Trade marks

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

bp, Amoco, Aral, Castrol ON and Thorntons

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Cautionary statement

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

The discussion in this 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: expectations regarding the COVID-19 pandemic, including its risks, impacts, consequences, duration, continued restrictions, challenges, bp's response, the impact on bp's financial performance (including cash flows and net debt), operations and credit losses, and the impact on the trading environment, oil and gas prices, and global GDP; expectations regarding the shape of the COVID-19 recovery and the pace of transition to a lower-carbon economy and energy system; plans, expectations and assumptions regarding oil and gas demand, supply or prices, the timing of production of reserves, or decision making by OPEC+; expectations regarding refining margins, refinery utilization rates and product demand; expectations regarding bp's future financial performance and cash flows; expectations regarding future upstream production and project ramp-up; expectations regarding supply shortages; expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals; expectations with regards to bp's transformation to an IEC; plans and expectations regarding bp's financial framework; expectations regarding price assumptions used in accounting estimates; bp's plans and expectations regarding the amount and timing of share buybacks; expectations regarding future quarterly dividends; plans and expectations regarding net debt; plans and expectations regarding bp's credit rating, including in respect of maintaining a strong investment grade credit rating; plans and expectations regarding the allocation of surplus cash flow to share buybacks and strengthening the balance sheet; plans and expectations regarding bp's 2025 target of 20GW renewables developed to FID and Lightsource bp's increased development target for 2025; plans and expectations regarding the East Coast Cluster and the Northern Endurance Partnership; plans and expectations with respect to the total capital expenditure, depreciation, depletion and amortization, expected tax rate and business and corporate underlying annual charge for 2021; plans and expectations regarding net debt; plans and expectations regarding the divestment programme, including the amount and timing of proceeds in 2021, and plans and expectations in respect of reaching $25 billion of divestment and other proceeds by 2025 and expectations that divestment and other proceeds for 2021 will be $6-7 billion; plans and expectations regarding bp's renewable energy and alternative energy businesses; expectations regarding reported and underlying production and related major project ramp-up, capital investments, divestment and maintenance activity; expectations regarding price assumptions used in accounting estimates; expectations regarding the underlying effective tax rate for 2021; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; plans and expectations that capital expenditure, including inorganic capital expenditure, will reach around $13 billion in 2021; expectations regarding Rosneft's operational and financial results and expectations with respect to Rosneft dividends; plans and expectations regarding new joint ventures and other agreements, including partnerships and other collaborations with Prumo, Siemens, SPIC Brazil, Reliance Industries, Shenzhen Gas, Swiggy, ADNOC, Masdar, Eni, Equinor, National Grid, Shell, Total, EnBW, Albert Heijn, NYK Line, ExxonMobil, Daimler, BMW, Albert Heijn and our Jio-bp JV, as well as plans and expectations regarding the solar development projects acquired from 7X Energy, the Thunder Horse South Expansion Phase 2 project, the sale of bp's participating interest in the Shallow Water Absheron Peninsula exploration project to LUKOIL, Yermak IJV's access to new license blocks, the Thorntons business, bp's investment in Digital Charging Solutions, bp's planned investment in the Cherry Point refinery, the acquisition of Blueprint Power, and bp ventures' investment in BluSmart.

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 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 impact of COVID-19, overall global economic and business conditions impacting our business and demand for our 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; 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; 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; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft's management and board of directors; 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 other factors discussed elsewhere in this report, as well those factors discussed under "Risk factors" in bp Annual Report and Form 20-F 2020 as filed with the US Securities and Exchange Commission.

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Contacts

	London	Houston

Press Office	David Nicholas	Brett Clanton
	+44 (0)20 7496 4708	+1 281 366 8346

Investor Relations	Craig Marshall	Geoff Carr
bp.com/investors	+44 (0)20 7496 4962	+1 281 892 3065

BP p.l.c.'s LEI Code 213800LH1BZH3D16G760

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