3Q20 Part 1 of 1

RNS Number : 2598D

BP PLC

27 October 2020

FOR IMMEDIATE RELEASE
London 27 October 2020
BP p.l.c. Group results
Third quarter and nine months 2020

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Highlights

Performance improving despite difficult environment

Financial results and progress

- Underlying replacement cost profit for the quarter was $0.1 billion, compared with a loss of $6.7 billion for the second quarter of 2020 and $2.3 billion profit for the third quarter of 2019. Compared to the previous quarter, the result benefitted from the absence of significant exploration write-offs and recovering oil and gas prices and demand. This was partly offset by a significantly lower oil trading result.

- Reported loss for the quarter was $0.5 billion, compared with losses of $16.8 billion for the previous quarter of 2020, reflecting absence of significant exploration write-offs and impairment charges, and $0.7 billion for the third quarter of 2019.

- Operating cash flow for the quarter, excluding Gulf of Mexico oil spill payments, was resilient at $5.3 billion, including $0.9 billion working capital release (after adjusting for net inventory holding gains). Gulf of Mexico oil spill payments in the quarter were $0.1 billion post-tax.

- Organic capital expenditure in the first three quarters of 2020 was $9.1 billion, in line with the full-year target of around $12 billion.

- BP continues to make progress towards its target of $2.5 billion in annual cash cost savings by end-2021 compared with 2019, with its new organization on schedule to be in place by start of 2021.

- Proceeds from divestments and other disposals in the quarter were $0.6 billion. BP has already completed or agreed transactions for approaching half its target of $25 billion in proceeds by 2025, including the agreed $5 billion sale of BP's petrochemicals business, expected to complete by year end.

- Net debt at quarter-end was $40.4 billion, down $0.5 billion. This includes the impact of the $1.1 billion payment for the completion of the joint venture with Reliance. Net debt is expected to fall in the fourth quarter as proceeds from divestments are received.

- A dividend of 5.25 cents per share was announced for the quarter.

Performing while transforming

- BP has brought two new Upstream major projects into production since mid-year: Atlantis Phase 3 in the US Gulf of Mexico and, ahead of schedule, Khazzan Phase 2 (Ghazeer) in Oman.

- Operations continued to be good with refining availability of 96.2% and Upstream plant reliability of 93.0%. Upstream unit production costs for the nine months of 2020 were 10% lower than 2019, reflecting progress on cost efficiency and strategic divestments.

- While refining margins remained at historical lows, driven by the extremely weak environment, BP's marketing businesses recovered strongly in the quarter, with fuels marketing earnings growing 3% year on year and lubricants result broadly in line with a year earlier.

- BP agreed to enter the offshore wind sector through a strategic partnership with Equinor to pursue offshore wind opportunities in the US, including taking a 50% stake in two leases off the US east coast.

- BP announced plans for a network of ultra-fast chargers in Germany and BP Chargemaster won a contract to deliver over 1,000 charging points for Police Scotland.

- BP also announced a partnership with Microsoft under which the two companies will co-operate to progress their sustainability aims. As part of this, BP has agreed to supply Microsoft with renewable energy and to extend its use of Microsoft's cloud-based services.

See chart on pdf

Bernard Looney - chief executive officer :

Having set out our new strategy in detail, our priority is execution and, despite a challenging environment, we are doing just that - performing while transforming. Major projects are coming online, our consumer-facing businesses are really delivering and we remain firmly focused on cost and capital discipline. Importantly , net debt continues to fall. We are firmly committed to our updated financial frame, including the dividend - the first call on our funds.

Financial summary	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Profit (loss) for the period attributable to BP shareholders	(450)	(16,848)	(749)	(21,663)	4,007
Inventory holding (gains) losses, net of tax	(194)	(809)	398	2,734	(488)
RC profit (loss)	(644)	(17,657)	(351)	(18,929)	3,519
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	730	10,975	2,605	13,124	3,904
Underlying RC profit (loss)	86	(6,682)	2,254	(5,805)	7,423
RC profit (loss) per ordinary share (cents)	(3.18)	(87.32)	(1.72)	(93.63)	17.33
RC profit (loss) per ADS (dollars)	(0.19)	(5.24)	(0.10)	(5.62)	1.04
Underlying RC profit (loss) per ordinary share (cents)	0.42	(33.05)	11.06	(28.72)	36.57
Underlying RC profit (loss) per ADS (dollars)	0.03	(1.98)	0.66	(1.72)	2.19

RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments, working capital, organic capital expenditure, net debt and gearing are non-GAAP measures. These measures and inventory holding gains and losses, non-operating items, fair value accounting effects, major project, Upstream plant reliability. refining availability and cash balance point are defined in the Glossary on page 32.

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BP p.l.c. Group results

Third quarter and nine months 2020

Murray Auchincloss - chief financial officer :

The underlying business performance in the quarter remained resilient a nd we made substantial progress in strengthening our balance sheet. In the quarter, net debt reduced to around $40 billion and our cash balance point was around $42 Brent, despite weak refining margins, low gas prices reduced product demand and the payment to Reliance. Funding the dividend remains our first priority and we are confident in moving towards our $35 billion net debt target, supported by value accretive divestments.

COVID-19 Update

Strengthening finances:

- BP has continued to take deliberate steps to strengthen its finances and drive down its cash balance point.

- Organic capital expenditure is on track for the revised full-year target of around $12 billion, announced in April. Total for the first nine months was $9.1 billion.

- BP has continued to progress its divestment programme towards delivery of $25 billion of proceeds by 2025. The $5 billion sale of its petrochemicals business is expected to complete by year end. In the quarter, BP also sold an interest in a portfolio of UK retail properties for $0.5 billion.

- BP's headcount has reduced by a total of around 2,800 so far during 2020, including around 300 who have already left the organization as part of the reinvent bp programme. A further 2,100 have elected to leave under the programme, which is expected to result in a total reduction of around 10,000 positions, the majority by the end of this year. BP expects to incur people-related costs associated with the reinvent programme, including redundancy payments, of around $1.4 billion over the next 1-2 years, primarily in 2020.

- Net debt was $40.4 billion at quarter-end and is expected to fall further in the fourth quarter as divestment proceeds are received. BP also continues to actively manage the profile of its debt portfolio, buying back/retiring $4.0 billion of shorter-term debt in the quarter. At quarter end BP had around $44 billion of liquidity, including cash and undrawn revolving credit facilities.

- BP will continue to review these actions, and any further actions that may be appropriate, in response to changes in prevailing market conditions.

- BP's future financial performance, including cash flows, net debt and gearing, 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 current supply and demand imbalances will be resolved and what the ultimate impact of COVID-19 will be.

- Costs that are directly attributable to COVID-19 were around $0.1 billion for the quarter (second quarter 2020 $0.2 billion).

Protecting our people and operations:

- BP continues to monitor the impact of COVID-19 on global operations and to date there has been no direct significant operational impact, although this could change through the rest of the fourth quarter.

- Refinery utilization in the quarter was around 10% below 2019 levels, driven by COVID-19 impacts. Year-on-year, demand for retail fuels was lower by 7% and for aviation by around 60%. However fuels marketing earnings grew, benefitting from continued growth in convenience sales.

- Despite the significant challenges of the environment, BP's operations performed safely and reliably in the quarter. BP-operated Upstream plant reliability was 93.0% and BP-operated refining availability 96.2%.

- BP continues to take steps to protect and support its staff through the pandemic. The great majority of BP staff who are able to work from home are still doing so. Precautions in operations and offices include: reduced manning levels, changing working patterns, deploying appropriate personal protective equipment (PPE), enhanced cleaning and social distancing measures at plants and retail sites. Decisions on repopulating offices are being taken with caution and in compliance with local and national guidelines and regulations.

- BP is providing enhanced support and guidance to staff on safety, health and hygiene, homeworking and mental health.

Outlook:

- The ongoing impacts of the COVID-19 pandemic continue to create a volatile and challenging trading environment. There have been some early signs of global economic recovery as countries move to more regional or localised restrictions on movement and governments continue to offer monetary and fiscal policy stimulus. However, the shape and pace of the recovery is uncertain, as it depends on the further spread of the pandemic.

- The gradual recovery in oil demand seen since the spring looks set to continue, led by strengthening demand in Asia. The IEA estimates an increase of around six million barrels a day in 2021, as economies continue to open up. OPEC+ production cuts have played a major role in stabilising the market and there is already a reduction in crude and product inventories. Inventories are likely to reduce through 2021, although the pace at which they normalise will depend on the strength of economic recovery and the degree of continued OPEC+ compliance.

- US gas supply is expected to continue on a declining trend in 2021, largely due to a drop in associated gas production. Tightening gas balances have caused the prompt price to rise, and the futures curve for Henry Hub now averages above $3 for 2021. This would be expected to provide some support to pricing in Europe and Asia until more gas comes to market.

- The refining margin outlook remains challenging, given record high inventory levels and a levelling off in demand recovery for gasoline and jet fuel due to COVID-19.

The commentary above and following should be read in conjunction with the cautionary statement on page 36.

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Group headlines

Results

For the nine months, underlying replacement cost (RC) loss* was $5,805 million, compared with a profit of $7,423 million in 2019. Underlying RC loss is after adjusting RC loss* for a net charge for non-operating items* of $13,357 million and net favourable fair value accounting effects* of $233 million (both on a post-tax basis).

RC loss was $18,929 million for the nine months, compared with a profit of $3,519 million in 2019.

For the third quarter, underlying RC profit was $86 million, compared with $2,254 million in 2019. Underlying RC profit is after adjusting RC loss for a net charge for non-operating items of $1,109 million and net favourable fair value accounting effects of $379 million (both on a post-tax basis).

RC loss was $644 million for the third quarter, compared with $351 million in 2019.

Loss for the third quarter and nine months attributable to BP shareholders was $450 million and $21,663 million respectively, compared with a loss of $749 million and a profit of $4,007 million for the same periods in 2019.

See further information on pages 4, 27 and 28.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $3.5 billion in the quarter and $11.5 billion in the nine months, compared with $4.3 billion and $13.3 billion for the same periods in 2019. BP now expects the 2020 full-year charge to be around 15% lower than 2019.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was -504% and 13% respectively, compared with 168% and 49% for the same periods in 2019. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the third quarter and nine months was 64% and -10% respectively, compared with 40% and 38% for the same periods a year ago. The higher underlying ETR for the third quarter reflects changes in the mix of profits and losses. The lower underlying ETR for the nine months mainly reflects the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition in the second quarter. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 5.25 cents per ordinary share ($0.315 per ADS), which is expected to be paid on 18 December 2020. The corresponding amount in sterling will be announced on 7 December 2020. See page 24 for more information.

Share buybacks

BP repurchased 120 million ordinary shares at a cost of $776 million (including fees and stamp duty) in the nine months of 2020, all of which was completed in the first quarter. In January 2020, the share dilution buyback programme had fully offset the impact of scrip dilution since the third quarter 2017.

Operating cash flow*

Operating cash flow excluding Gulf of Mexico oil spill payments* was $5.3 billion for the third quarter and $11.4 billion for the nine months. These amounts include a working capital* release of $0.9 billion in the third quarter and a working capital build of $1.3 billion in the nine months, after adjusting for net inventory holding gains or losses* and working capital effects of the Gulf of Mexico oil spill. The comparable amount for the same periods in 2019 was $6.5 billion and $20.6 billion.

Operating cash flow as reported in the group cash flow statement was $5.2 billion for the third quarter and $9.9 billion for the nine months, including a working capital release of $0.6 billion and $0.6 billion respectively, compared with $6.1 billion and $18.2 billion for the same periods in 2019.

See page 30 and Glossary for further information on Gulf of Mexico oil spill cash flows and on working capital.

Capital expenditure*

Organic capital expenditure* for the third quarter and nine months was $2.5 billion and $9.1 billion respectively, compared with $3.9 billion and $11.3 billion for the same periods in 2019.

Inorganic capital expenditure* for the third quarter and nine months was $1.1 billion and $1.5 billion respectively, compared with $0.1 billion and $4.0 billion for the same periods in 2019.

BP expects total capital expenditure for 2021 to be at the lower end of a $13-15 billion range.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 26 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.1 billion for the third quarter and $1.5 billion for the nine months, compared with $0.7 billion and $1.4 billion for the same periods in 2019. In addition, $0.5 billion was received in the third quarter of 2020 in relation to the sale of an interest in BP's UK retail property portfolio.

Net debt* and gearing*

Net debt at 30 September 2020 was $40.4 billion, compared with $46.5 billion a year ago. Gearing at 30 September 2020 was 33.0%, compared with 31.7% a year ago, reflecting the reduction in equity in the period. Gearing including leases* at 30 September 2020 was 37.7%, compared with 35.9% a year ago. Net debt, gearing and gearing including leases are non-GAAP measures. See pages 25 and 29 for more information.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 32.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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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	2020	2020	2019	2020	2019
Underlying RC profit (loss) before interest and tax
Upstream	878	(8,487)	2,139	(5,738)	8,480
Downstream	636	1,405	1,883	2,962	4,981
Rosneft	(177)	(61)	802	(255)	2,007
Other businesses and corporate	(130)	(260)	(322)	(951)	(1,030)
Consolidation adjustment - UPII*	34	(46)	30	166	51
Underlying RC profit (loss) before interest and tax	1,241	(7,449)	4,532	(3,816)	14,489
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(610)	(677)	(754)	(1,955)	(2,260)
Taxation on an underlying RC basis	(402)	770	(1,506)	(585)	(4,641)
Non-controlling interests	(143)	674	(18)	551	(165)
Underlying RC profit (loss) attributable to BP shareholders	86	(6,682)	2,254	(5,805)	7,423

Reconciliations of underlying RC profit or loss attributable to BP shareholders to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-11 for the segments.

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	2020	2020	2019	2020	2019
RC profit (loss) before interest and tax
Upstream	30	(22,008)	(1,050)	(20,955)	4,303
Downstream	915	594	2,016	2,173	5,069
Rosneft	(278)	(124)	802	(419)	1,813
Other businesses and corporate	24	(317)	(412)	(991)	(1,339)
Consolidation adjustment - UPII	34	(46)	30	166	51
RC profit (loss) before interest and tax	725	(21,901)	1,386	(20,026)	9,897
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(808)	(791)	(899)	(2,389)	(2,649)
Taxation on a RC basis	(418)	4,361	(820)	2,935	(3,564)
Non-controlling interests	(143)	674	(18)	551	(165)
RC profit (loss) attributable to BP shareholders	(644)	(17,657)	(351)	(18,929)	3,519
Inventory holding gains (losses)*	233	1,088	(512)	(3,563)	657
Taxation (charge) credit on inventory holding gains and losses	(39)	(279)	114	829	(169)
Profit (loss) for the period attributable to BP shareholders	(450)	(16,848)	(749)	(21,663)	4,007

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Operational updates

Upstream

Upstream production, which excludes Rosneft, for the nine months of the year averaged 2,448mboe/d, 6.4% lower than a year earlier. Underlying production*, for the nine months was slightly lower than 2019 reflecting adverse weather, primarily in the US Gulf of Mexico.

For the first nine months of 2020, BP-operated Upstream plant reliability* was 93.8% and Upstream unit production costs of $6.30/boe were more than 10% lower than in 2019 reflecting ongoing progress on cost efficiency in operations, and strategic divestments.

Since mid-year, BP has started production on the Atlantis Phase 3 project in the Gulf of Mexico, followed by the Ghazeer gas project, the second phase of development on Block 61 in Oman, that began production three months ahead of schedule. These are the first of five Upstream major projects* expected to begin production in 2020. BP also brought the Galeota expansion project in Trinidad into operation during the quarter.

In September, BP confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt.

The Trans Adriatic Gas pipeline (TAP) has completed construction and is expected to soon commence gas exports from Azerbaijan to customers in Europe.

Downstream

Fuels marketing earnings for the third quarter were 3% higher than in 2019, benefiting from continued growth in store gross margin, despite COVID-driven fuel demand impacts.

BP-operated refining availability continued to be strong, at 96.2% in the quarter. However, refining margins were extremely weak and refinery utilization was around 10% below 2019 levels.

Lubricants saw strong demand recovery in the third quarter, including year-on-year growth in key markets such as India and China.

The sale of BP's petrochemicals business to INEOS, agreed in June, remains on track to complete by the end of 2020.

Strategicprogress

In September, BP agreed to enter into a strategic partnership with Equinor to develop offshore wind projects in the US. This includes the purchase of a 50% interest in two existing wind leases and associated projects off the east coast of the US. Subject to customary regulatory and other approvals, the transaction is expected to close in early 2021.

BP continued to progress electrification in the quarter with plans announced in July to build a network of ultra-fast charging points across Germany, including more than 100 charging points at Aral retail sites over the next 12 months. BP Chargemaster was recently awarded a contract by Police Scotland, to deliver more than 1,000 charging points over the next four years.

BP announced a strategic partnership with Microsoft under which the two companies will co-operate to progress their sustainability aims. As part of this, BP has agreed to supply Microsoft with renewable energy and to extend its use of Microsoft's cloud-based services.

BP announced an agreement to partner with Aberdeen City Council to help it achieve the goals of its Net Zero Vision to reduce emissions and become a climate positive city. This follows the partnership with the City of Houston that BP announced in July.

Financial framework

Operating cash flow excluding Gulf of Mexico oil spill payments* was $11.4 billion for the nine months of 2020, compared with $20.6 billion for the same period in 2019.

Organic capital expenditure * for the nine months of 2020 was $9.1 billion. BP expects 2020 organic capital expenditure to be around $12 billion.

Divestment and other proceeds were $2.4 billion for the nine months of 2020.

Gulf of Mexico oil spill payments on a post-tax basis were $1.5 billion in the nine months of 2020. Payments for the full year are expected to be around $1.5 billion on a post-tax basis.

Gearing * at 30 September 2020 was 33.0%, in part reflecting the recent hybrid bond issue. See page 25 for more information.

Operating metrics	Nine months 2020	Financial metrics	Nine months 2020
Operating metrics	(vs. Nine months 2019)	Financial metrics	(vs. Nine months 2019)
Tier 1 and tier 2 process safety events	66	Underlying RC profit (loss)*	$(5.8)bn
Tier 1 and tier 2 process safety events	(-7)	Underlying RC profit (loss)*	(-$13.2bn)
Reported recordable injury frequency*	0.127	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	$11.4bn
Reported recordable injury frequency*	(-29.2%)		(-$9.2bn)
Group production	3,542mboe/d	Organic capital expenditure	$9.1bn
Group production	(-5.7%)	Organic capital expenditure	(-$2.2bn)
Upstream production (excludes Rosneft segment)	2,448mboe/d	Gulf of Mexico oil spill payments (post-tax)	$1.5bn
Upstream production (excludes Rosneft segment)	(-6.4%)	Gulf of Mexico oil spill payments (post-tax)	(-$1.0bn)
Upstream unit production costs _(a)	$6.30/boe	Divestment proceeds*	$1.5bn
Upstream unit production costs _(a)	(-10.3%)	Divestment proceeds*	(+$0.1bn)
BP-operated Upstream plant reliability	93.8%	Gearing	33.0%
BP-operated Upstream plant reliability	(-0.6)	Gearing	(+1.3)
BP-operated refining availability*	96.0%	Dividend per ordinary share _(b)	5.25 cents
BP-operated refining availability*	(+1.4)	Dividend per ordinary share _(b)	(-48.8%)

(a) Reflecting lower costs and divestment impacts.

(b) Represents dividend announced in the quarter (vs. prior year quarter).

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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Upstream

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Profit (loss) before interest and tax	38	(21,951)	(1,050)	(20,958)	4,295
Inventory holding (gains) losses*	(8)	(57)	-	3	8
RC profit (loss) before interest and tax	30	(22,008)	(1,050)	(20,955)	4,303
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	848	13,521	3,189	15,217	4,177
Underlying RC profit (loss) before interest and tax*_(a)	878	(8,487)	2,139	(5,738)	8,480

(a) See page 7 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost result before interest and tax for the third quarter and nine months was a profit of $30 million and a loss of $20,955 million respectively, compared with a loss of $1,050 million and a profit of $4,303 million for the same periods in 2019. The third quarter and nine months included a net non-operating charge of $631 million and $15,156 million respectively, compared with a net charge of $3,454 million and $4,224 million for the same periods in 2019. The net non-operating charge for the nine months is principally related to impairments associated with revisions to long-term price assumptions. Fair value accounting effects in the third quarter and nine months had an adverse impact of $217 million and $61 million respectively, compared with a favourable impact of $265 million and $47 million in the same periods of 2019.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost result before interest and tax for the third quarter and nine months was a profit of $878 million and a loss of $5,738 million respectively, compared with a profit of $2,139 million and $8,480 million for the same periods in 2019. The result for the third quarter mainly reflects lower liquids and gas realizations, partly offset by lower depreciation, depletion and amortization. The result for the nine months mainly reflects lower liquids and gas realizations and the impact of writing down certain exploration intangible carrying values.

Production

Production for the quarter was 2,243mboe/d, 12.7% lower than the third quarter of 2019 mainly due to divestments in BPX Energy, Alaska and Gulf of Suez oil concessions in Egypt. Underlying production* for the quarter decreased by 3.0% mainly due to decline associated with reduced capital investment levels and significant weather impacts from hurricanes in the US Gulf of Mexico.

For the nine months, production was 2,448mboe/d, 6.4% lower than the nine months of 2019. Underlying production for the nine months was slightly lower than 2019 reflecting adverse weather, primarily in the US Gulf of Mexico.

Key events

During the third quarter, BP was awarded eight operated and three non-operated blocks in the North Sea as part of the UK Oil & Gas Authority 32nd offshore licensing round.

On 25 August, BP confirmed it started production on Atlantis Phase 3 in the US Gulf of Mexico (BP operator 56%, BHP Billiton 44%).

On 16 September, BP confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt (Eni operator 75%, BP 25%).

On 28 September, BP Trinidad and Tobago LLC started up the Galeota expansion project in Trinidad.

On 1 October, BP confirmed force majeure was lifted on the Greater Tortue Ahmeyim (GTA) project offshore Mauritania and Senegal (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%).

On 6 October, BP confirmed the planned divestment to Premier Oil of its interests in the Andrew area and Shearwater assets, both located in the UK North Sea, will not proceed following the announcement of a proposed merger between Chrysaor and Premier Oil.

On 12 October, BP announced the start-up of production from Block 61 Phase 2 Ghazeer gas field in Oman (BP operator 60%, Makarim Gas Development Limited 30%, PC Oman Ventures Limited 10%).

Outlook

Looking ahead, we expect fourth-quarter 2020 reported production to be slightly lower than the third quarter due to maintenance activity.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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Upstream (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Underlying RC profit (loss) before interest and tax
US	125	(2,960)	552	(2,296)	2,025
Non-US	753	(5,527)	1,587	(3,442)	6,455
	878	(8,487)	2,139	(5,738)	8,480
Non-operating items _(a)(b)
US	(114)	(2,122)	(3,338)	(2,868)	(3,814)
Non-US	(517)	(11,332)	(116)	(12,288)	(410)
	(631)	(13,454)	(3,454)	(15,156)	(4,224)
Fair value accounting effects
US	57	39	19	94	(299)
Non-US	(274)	(106)	246	(155)	346
	(217)	(67)	265	(61)	47
RC profit (loss) before interest and tax
US	68	(5,043)	(2,767)	(5,070)	(2,088)
Non-US	(38)	(16,965)	1,717	(15,885)	6,391
	30	(22,008)	(1,050)	(20,955)	4,303
Exploration expense
US	40	2,560	53	2,620	147
Non-US	150	7,114	132	7,446	551
	190	9,674	185	10,066	698
Of which: Exploration expenditure written off_(b)	50	9,618	115	9,766	476
Production (net of royalties)_(c)(d)
Liquids* (mb/d)
US	363	472	449	446	470
Europe	143	166	118	152	138
Rest of World	623	728	657	668	667
	1,129	1,366	1,224	1,266	1,274
Natural gas (mmcf/d)
US	1,419	1,549	2,396	1,671	2,372
Europe	265	298	188	269	155
Rest of World	4,774	4,878	5,211	4,915	5,254
	6,457	6,725	7,795	6,855	7,782
Total hydrocarbons* (mboe/d)
US	608	739	862	735	879
Europe	188	217	151	198	165
Rest of World	1,446	1,569	1,555	1,516	1,573
	2,243	2,525	2,568	2,448	2,616
Average realizations* _(e)
Total liquids_(f) ($/bbl)	38.17	22.75	55.68	35.51	58.38
Natural gas ($/mcf)	2.56	2.53	3.11	2.65	3.49
Total hydrocarbons ($/boe)	26.42	19.06	35.48	25.68	38.55

(a) Second quarter and nine months 2020 principally relate to impairments in a number of our businesses resulting from the revisions to BP's long-term price assumptions. Nine months 2020 also includes impairment charges and loss principally related to the disposal of our Alaska business, BPX Energy assets and oil price impacts in the UK North Sea. Third quarter and nine months 2019 include impairment charges related to the disposal of heritage BPX Energy assets, Alaska and GUPCO divestment. See Note 3 for further information.

(b) Second quarter and nine months 2020 include the write-off of $1,969 million relating to value ascribed to certain licences as part of the accounting for the acquisition of upstream assets in Brazil, India and the Gulf of Mexico. This has been classified within the 'other' category of non-operating items. See Note 4 for further information.

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

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

(f) Includes condensate, natural gas liquids and bitumen.

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Downstream

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Profit (loss) before interest and tax	1,106	1,572	1,583	(1,273)	5,775
Inventory holding (gains) losses*	(191)	(978)	433	3,446	(706)
RC profit before interest and tax	915	594	2,016	2,173	5,069
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(279)	811	(133)	789	(88)
Underlying RC profit before interest and tax*_(a)	636	1,405	1,883	2,962	4,981

(a) See page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results

The replacement cost profit before interest and tax for the third quarter and nine months was $915 million and $2,173 million respectively, compared with $2,016 million and $5,069 million for the same periods in 2019.

The third quarter and nine months include a net non-operating charge of $146 million and $924 million respectively, compared with a charge of $14 million and $49 million for the same periods in 2019. The charge for the quarter mainly relates to restructuring, while the charge for the nine months primarily reflects impairments. Fair value accounting effects in the third quarter and nine months had a favourable impact of $425 million and $135 million respectively, compared with a favourable impact of $147 million and $137 million in the same periods in 2019.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $636 million and $2,962 million respectively, compared with $1,883 million and $4,981 million for the same periods in 2019.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 9.

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $222 million for the third quarter and $2,206 million for the nine months, compared with $1,438 million and $3,691 million for the same periods in 2019.

Across fuels marketing we saw earnings growth of 3% year on year primarily driven by increased store gross margin. This growth is despite continued COVID-19 demand impacts with retail volumes in the quarter 7% lower than last year. The result for the nine months, however, remained impacted by COVID-19, with year to date retail volumes 15% lower than 2019, and aviation volumes down by 50%.

The refining result for the quarter and nine months continued to be impacted by an extremely weak environment with refining margins remaining at historical lows. Utilization of 83% for the quarter improved compared with the second quarter, albeit still around 10% lower than 2019, driven by continued COVID-19 demand impacts. These factors were partially offset by a lower level of turnaround activity and strong refining availability.

The quarterly result also reflects a weaker contribution from supply and trading, although the contribution for the nine months remains higher year on year.

We continued to progress our advanced mobility agenda in the quarter with plans announced in July to build a network of ultra-fast charging across Germany, beginning with the roll out of more than 100 charging points at Aral retail sites over the next 12 months. In addition, BP Chargemaster was recently awarded the UK's largest ever EV infrastructure contract by Police Scotland, to deliver more than 1,000 charging points over the next four years.

Lubricants

The lubricants business saw significant recovery in the third quarter as volumes improved to levels similar to 2019, supported by growth of more than 5% in China and India. The result for the nine months, however, continued to reflect significant COVID-19 demand destruction seen in the first half of 2020.

Underlying replacement cost profit before interest and tax was $326 million for the third quarter and $556 million for the nine months, compared with $332 million and $925 million for the same periods in 2019.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $88 million for the third quarter and $200 million for the nine months, compared with $113 million and $365 million for the same periods in 2019. The result for the quarter and nine months reflects a significantly weaker margin environment and the demand impact of COVID-19.

As previously reported, in the second quarter we announced the sale of BP's petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary adjustments. The transaction remains on track and, subject to approvals, is expected to complete by the end of the year.

Outlook

Looking to the fourth quarter of 2020, we expect continued pressure on industry refining margins and for marketing volumes to remain impacted by COVID-19 restrictions.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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Downstream (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Underlying RC profit before interest and tax - by region
US	96	719	537	1,372	1,634
Non-US	540	686	1,346	1,590	3,347
	636	1,405	1,883	2,962	4,981
Non-operating items
US	(27)	(69)	(5)	(90)	(2)
Non-US	(119)	(711)	(9)	(834)	(47)
	(146)	(780)	(14)	(924)	(49)
Fair value accounting effects_(a)
US	78	(71)	116	152	185
Non-US	347	40	31	(17)	(48)
	425	(31)	147	135	137
RC profit before interest and tax
US	147	579	648	1,434	1,817
Non-US	768	15	1,368	739	3,252
	915	594	2,016	2,173	5,069
Underlying RC profit before interest and tax - by business _(b)(c)
Fuels	222	1,295	1,438	2,206	3,691
Lubricants	326	63	332	556	925
Petrochemicals	88	47	113	200	365
	636	1,405	1,883	2,962	4,981
Non-operating items and fair value accounting effects _(a)
Fuels	288	(748)	135	(717)	73
Lubricants	(7)	(51)	-	(58)	18
Petrochemicals	(2)	(12)	(2)	(14)	(3)
	279	(811)	133	(789)	88
RC profit before interest and tax _(b)(c)
Fuels	510	547	1,573	1,489	3,764
Lubricants	319	12	332	498	943
Petrochemicals	86	35	111	186	362
	915	594	2,016	2,173	5,069

BP average refining marker margin (RMM)* ($/bbl)	6.2	5.9	14.7	7.0	13.4

Refinery throughputs (mb/d)
US	701	614	781	687	730
Europe	699	716	815	750	766
Rest of World	187	157	217	189	221
	1,587	1,487	1,813	1,626	1,717
BP-operated refining availability* (%)	96.2	95.6	96.1	96.0	94.6

Marketing sales of refined products (mb/d)
US	1,083	872	1,172	997	1,141
Europe	849	685	1,157	830	1,081
Rest of World	422	364	459	435	500
	2,354	1,921	2,788	2,262	2,722
Trading/supply sales of refined products	2,618	3,172	3,157	3,054	3,183
Total sales volumes of refined products	4,972	5,093	5,945	5,316	5,905

Petrochemicals production (kte)
US	541	410	564	1,562	1,749
Europe	1,325	1,246	1,187	3,942	3,573
Rest of World	1,211	1,271	1,325	3,635	3,780
	3,077	2,927	3,076	9,139	9,102

(a) For Downstream, fair value accounting effects arise solely in the fuels business. See page 28 for further information.

(b) Segment-level overhead expenses are included in the fuels business result.

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Rosneft

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020 _(a)	2020	2019	2020 _(a)	2019
Profit (loss) before interest and tax_(b)(c)	(244)	(71)	723	(533)	1,772
Inventory holding (gains) losses*	(34)	(53)	79	114	41
RC profit (loss) before interest and tax	(278)	(124)	802	(419)	1,813
Net charge (credit) for non-operating items*	101	63	-	164	194
Underlying RC profit (loss) before interest and tax*	(177)	(61)	802	(255)	2,007

Financial results

Replacement cost (RC) loss before interest and tax for the third quarter and nine months was $278 million and $419 million respectively, compared with a profit of $802 million and $1,813 million for the same periods in 2019.

After adjusting for non-operating items, the underlying RC loss before interest and tax for the third quarter and nine months was $177 million and $255 million respectively, compared with a profit of $802 million and $2,007 million for the same periods in 2019.

Compared with the same periods in 2019, the results for the third quarter and nine months primarily reflects lower oil prices and adverse foreign exchange effects and lower production as a result of OPEC+ agreement.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2020 _(a)	2020	2019	2020 _(a)	2019
Production (net of royalties) (BP share)
Liquids* (mb/d)	858	856	920	877	923
Natural gas (mmcf/d)	1,260	1,248	1,236	1,261	1,271
Total hydrocarbons* (mboe/d)	1,075	1,071	1,133	1,094	1,142

(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 2020. Actual results may differ from these amounts. Amounts reported for the third quarter are based on BP's 21.96% average economic interest for the quarter (second quarter 2020 21.20%, first quarter 2020 and 2019 19.75%).

(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.

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Other businesses and corporate

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Profit (loss) before interest and tax	24	(317)	(412)	(991)	(1,339)
Inventory holding (gains) losses*	-	-	-	-	-
RC profit (loss) before interest and tax	24	(317)	(412)	(991)	(1,339)
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(154)	57	90	40	309
Underlying RC profit (loss) before interest and tax*	(130)	(260)	(322)	(951)	(1,030)
Underlying RC profit (loss) before interest and tax
US	(65)	(129)	(249)	(318)	(628)
Non-US	(65)	(131)	(73)	(633)	(402)
	(130)	(260)	(322)	(951)	(1,030)
Non-operating items
US	(62)	(62)	(85)	(172)	(291)
Non-US	(50)	46	(5)	(93)	(18)
	(112)	(16)	(90)	(265)	(309)
Fair value accounting effects
US	-	-	-	-	-
Non-US	266	(41)	-	225	-
	266	(41)	-	225	-
RC profit (loss) before interest and tax
US	(127)	(191)	(334)	(490)	(919)
Non-US	151	(126)	(78)	(501)	(420)
	24	(317)	(412)	(991)	(1,339)

Other businesses and corporate comprises our alternative energy business, shipping, treasury, BP ventures and corporate activities including centralized functions, and any residual costs of the Gulf of Mexico oil spill.

Financial results

The replacement cost result before interest and tax for the third quarter and nine months was a profit of $24 million and a loss of $991 million respectively, compared with a loss of $412 million and $1,339 million for the same periods in 2019.

The results included a net non-operating charge of $112 million for the third quarter and $265 million for the nine months, compared with a charge of $90 million and $309 million for the same periods in 2019. Fair value accounting effects in the third quarter and nine months had a favourable impact of $266 million and $225 million. See page 28 for further information.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $130 million and $951 million respectively, compared with $322 million and $1,030 million for the same periods in 2019.

Alternative Energy

BP's net ethanol-equivalent production* for the third quarter and nine months of the year averaged 36.5kb/d and 22.1kb/d respectively, compared with 24.4kb/d and 14.4kb/d for the 100% BP-owned business for the same periods in 2019.

Net wind generation capacity* was 1,072MW at 30 September 2020, compared with 926MW at 30 September 2019. BP's net share of wind generation for the third quarter and nine months was 454GWh and 1,904GWh respectively, compared with 506GWh and 1,967GWh for the same periods in 2019. In September BP acquired the remaining 50% interest in the BP-operated Fowler Ridge 1 wind asset. The asset increased net wind capacity by 150MW to 1,072MW.

In September BP and Equinor announced the formation of a new strategic partnership to develop four assets in two existing offshore wind leases located offshore New York and Massachusetts. Subject to customary regulatory and other approvals, the transaction is expected to close in early 2021 and will mark BP's first entry into the offshore wind sector, one of the fastest growing energy sectors.

Lightsource BP has developed 637MW for the nine months of the year to 30 September 2020. In September Lightsource BP reached financial close and mobilized construction for the 300MW Bighorn Solar project in the US, which will deliver energy to the EVRAZ North America steel mill in Pueblo, Colorado. In October they completed construction on three solar sites in Franklin County, Pennsylvania in the US. The sites will deliver electricity to Penn State University under the 70MW Power Purchase Agreement (PPA) to provide over 100 million kilowatt-hours of electricity in year one.

BP has developed a total of 3GW net renewable energy generating capacity by 30 September 2020 across our businesses. We intend to continue building our renewable energy businesses and to have developed 20GW by 2025.

Outlook

Other businesses and corporate average quarterly charges, excluding non-operating items, fair value accounting effects and foreign exchange volatility impact, are expected to be around $350 million although this will fluctuate quarter to quarter.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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Financial statements

Group income statement

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019

Sales and other operating revenues (Note 6)	44,251	31,676	68,291	135,577	207,288
Earnings from joint ventures - after interest and tax	73	(567)	90	(516)	413
Earnings from associates - after interest and tax	(332)	(100)	784	(676)	2,041
Interest and other income	183	107	126	430	559
Gains on sale of businesses and fixed assets	27	74	1	117	145
Total revenues and other income	44,202	31,190	69,292	134,932	210,446
Purchases	31,645	18,778	52,273	99,301	156,228
Production and manufacturing expenses	5,073	5,211	5,259	16,383	16,006
Production and similar taxes (Note 8)	140	124	340	467	1,135
Depreciation, depletion and amortization (Note 7)	3,467	3,937	4,297	11,463	13,346
Impairment and losses on sale of businesses and fixed assets (Note 3)	294	11,770	3,416	13,213	4,418
Exploration expense (Note 4)	190	9,674	185	10,066	698
Distribution and administration expenses	2,435	2,509	2,648	7,628	8,061
Profit (loss) before interest and taxation	958	(20,813)	874	(23,589)	10,554
Finance costs	800	783	883	2,366	2,603
Net finance expense relating to pensions and other post-retirement benefits	8	8	16	23	46
Profit (loss) before taxation	150	(21,604)	(25)	(25,978)	7,905
Taxation	457	(4,082)	706	(3,764)	3,733
Profit (loss) for the period	(307)	(17,522)	(731)	(22,214)	4,172
Attributable to
BP shareholders	(450)	(16,848)	(749)	(21,663)	4,007
Non-controlling interests	143	(674)	18	(551)	165
	(307)	(17,522)	(731)	(22,214)	4,172

Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	(2.22)	(83.32)	(3.68)	(107.15)	19.74
Diluted	(2.22)	(83.32)	(3.68)	(107.15)	19.63
Per ADS (dollars)
Basic	(0.13)	(5.00)	(0.22)	(6.43)	1.18
Diluted	(0.13)	(5.00)	(0.22)	(6.43)	1.18

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Condensed group statement of comprehensive income

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019

Profit (loss) for the period	(307)	(17,522)	(731)	(22,214)	4,172
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences_(a)	(166)	1,371	(986)	(3,437)	134
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	-	3	-	4	-
Cash flow hedges and costs of hedging	(90)	68	(17)	63	135
Share of items relating to equity-accounted entities, net of tax	308	(333)	119	417	39
Income tax relating to items that may be reclassified	(16)	(37)	12	64	(31)
	36	1,072	(872)	(2,889)	277
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset_(b)	78	(1,960)	(260)	(163)	(1,152)
Cash flow hedges that will subsequently be transferred to the balance sheet	8	(2)	(10)	(2)	(9)
Income tax relating to items that will not be reclassified	(16)	623	27	(16)	302
	70	(1,339)	(243)	(181)	(859)
Other comprehensive income	106	(267)	(1,115)	(3,070)	(582)
Total comprehensive income	(201)	(17,789)	(1,846)	(25,284)	3,590
Attributable to
BP shareholders	(364)	(17,142)	(1,848)	(24,723)	3,434
Non-controlling interests	163	(647)	2	(561)	156
	(201)	(17,789)	(1,846)	(25,284)	3,590

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

(b) See Note 1 for further information.

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Condensed group statement of changes in equity

	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
Share of equity-accounted entities' changes in equity, net of tax	-	-	-	-
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

	BP shareholders'	Non-controlling interests		Total
$ million	equity	Hybrid bonds	Other interest	equity
At 31 December 2018	99,444	-	2,104	101,548
Adjustment on adoption of IFRS 16, net of tax_(a)	(329)	-	(1)	(330)
At 1 January 2019	99,115	-	2,103	101,218

Total comprehensive income	3,434	-	156	3,590
Dividends	(4,857)	-	(166)	(5,023)
Cash flow hedges transferred to the balance sheet, net of tax	18	-	-	18
Repurchase of ordinary share capital	(340)	-	-	(340)
Share-based payments, net of tax	544	-	-	544
Share of equity-accounted entities' changes in equity, net of tax	8	-	-	8
At 30 September 2019	97,922	-	2,093	100,015

(a) See Note 1 in BP Annual Report and Form 20-F 2019 for further information.

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Group balance sheet

	30 September	31 December
$ million	2020	2019
Non-current assets
Property, plant and equipment	116,580	132,642
Goodwill	12,457	11,868
Intangible assets	6,293	15,539
Investments in joint ventures	7,953	9,991
Investments in associates	16,929	20,334
Other investments	2,439	1,276
Fixed assets	162,651	191,650
Loans	711	630
Trade and other receivables	4,239	2,147
Derivative financial instruments	7,705	6,314
Prepayments	497	781
Deferred tax assets	6,816	4,560
Defined benefit pension plan surpluses	6,806	7,053
	189,425	213,135
Current assets
Loans	555	339
Inventories	13,840	20,880
Trade and other receivables	15,954	24,442
Derivative financial instruments	3,562	4,153
Prepayments	645	857
Current tax receivable	681	1,282
Other investments	298	169
Cash and cash equivalents	30,749	22,472
	66,284	74,594
Assets classified as held for sale (Note 2)	4,541	7,465
	70,825	82,059
Total assets	260,250	295,194
Current liabilities
Trade and other payables	33,823	46,829
Derivative financial instruments	3,088	3,261
Accruals	3,822	5,066
Lease liabilities	1,907	2,067
Finance debt	11,013	10,487
Current tax payable	804	2,039
Provisions	2,563	2,453
	57,020	72,202
Liabilities directly associated with assets classified as held for sale (Note 2)	1,057	1,393
	58,077	73,595
Non-current liabilities
Other payables	11,908	12,626
Derivative financial instruments	4,761	5,537
Accruals	908	996
Lease liabilities	7,375	7,655
Finance debt	61,796	57,237
Deferred tax liabilities	6,634	9,750
Provisions	17,892	18,498
Defined benefit pension plan and other post-retirement benefit plan deficits	8,744	8,592
	120,018	120,891
Total liabilities	178,095	194,486
Net assets	82,155	100,708
Equity
BP shareholders' equity	67,955	98,412
Non-controlling interests	14,200	2,296
Total equity	82,155	100,708

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Condensed group cash flow statement

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Operating activities
Profit (loss) before taxation	150	(21,604)	(25)	(25,978)	7,905
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	3,517	13,555	4,412	21,229	13,822
Impairment and (gain) loss on sale of businesses and fixed assets	267	11,696	3,415	13,096	4,273
Earnings from equity-accounted entities, less dividends received	1,018	860	(236)	2,383	(1,220)
Net charge for interest and other finance expense, less net interest paid	60	17	257	214	407
Share-based payments	199	351	149	544	563
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(46)	(34)	(50)	(100)	(195)
Net charge for provisions, less payments	293	(365)	(132)	(131)	(446)
Movements in inventories and other current and non-current assets and liabilities	556	(609)	141	630	(2,612)
Income taxes paid	(810)	(130)	(1,875)	(1,994)	(4,330)
Net cash provided by operating activities	5,204	3,737	6,056	9,893	18,167
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(2,577)	(3,018)	(3,954)	(9,384)	(11,482)
Acquisitions, net of cash acquired	(10)	-	13	(27)	(3,529)
Investment in joint ventures	(12)	(8)	(60)	(38)	(80)
Investment in associates	(1,037)	(41)	(22)	(1,115)	(221)
Total cash capital expenditure	(3,636)	(3,067)	(4,023)	(10,564)	(15,312)
Proceeds from disposal of fixed assets	32	10	171	52	476
Proceeds from disposal of businesses, net of cash disposed	84	670	536	1,425	909
Proceeds from loan repayments	50	543	63	656	182
Net cash used in investing activities	(3,470)	(1,844)	(3,253)	(8,431)	(13,745)
Financing activities
Net issue (repurchase) of shares (Note 9)	-	-	(215)	(776)	(340)
Lease liability payments	(578)	(664)	(594)	(1,811)	(1,806)
Proceeds from long-term financing	2,587	6,846	213	12,117	6,718
Repayments of long-term financing	(4,307)	(964)	(516)	(8,988)	(6,758)
Net increase (decrease) in short-term debt	(2,630)	(215)	(852)	(328)	118
Issue of perpetual hybrid bonds	-	11,861	-	11,861	-
Payments on perpetual hybrid bonds	(27)	-	-	(27)	-
Payments relating to transactions involving non-controlling interests (other)	-	(8)	-	(8)	-
Receipts relating to transactions involving non-controlling interests (other)	483	-	-	492	-
Dividends paid - BP shareholders	(1,060)	(2,119)	(1,656)	(5,281)	(4,870)
- non-controlling interests	(58)	(74)	(47)	(163)	(166)
Net cash provided by (used in) financing activities	(5,590)	14,663	(3,667)	7,088	(7,104)
Currency translation differences relating to cash and cash equivalents	268	(42)	(118)	43	(94)
Increase (decrease) in cash and cash equivalents	(3,588)	16,514	(982)	8,593	(2,776)
Cash and cash equivalents at beginning of period	34,653	18,139	20,674	22,472	22,468
Cash and cash equivalents at end of period_(a)	31,065	34,653	19,692	31,065	19,692

(a) Third quarter and nine months 2020 include $316 million (second quarter 2020 $436 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 2019 included in BP Annual Report and Form 20-F 2019.

The directors consider it appropriate to adopt the going concern basis of accounting in preparing the interim financial information. The 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 and a reverse stress test performed to support this assertion.

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 IFRS. IFRS as adopted by the EU differs 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 2020 which are the same as those used in preparing BP Annual Report and Form 20-F 2019 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 2020 onwards that have a significant impact on the interim financial information.

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

BP's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 2019. These have been subsequently reviewed 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 valuation of certain assets and liabilities is subject to a greater level of uncertainty than when reported in BP Annual Report and Form 20-F 2019, including those set out below.

Impairment testing assumptions

BP now sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for energy for a sustained period. BP's management also has a growing expectation that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system as countries seek to 'build back better' so that their economies will be more resilient in the future. As a result of all the above, during the second quarter, BP revised its price assumptions for value-in-use impairment testing, lowering them and extending the period covered to 2050. The price assumption for the remainder of 2020 for Henry Hub gas was subsequently increased during the third quarter to reflect improving observed market prices. A summary of the group's revised price assumptions, in real 2020 terms, is provided below:

	4Q20	2021	2025	2030	2040	2050
Brent oil ($/bbl)	40	50	50	60	60	50
Henry Hub gas ($/mmBtu)	2.75	3.00	3.00	3.00	3.00	2.75

As disclosed in BP Annual Report and Form 20-F 2019 - Note 1, the majority of BP's reserves and resources that support the carrying amount of the group's oil and gas properties are expected to be produced over the next ten years. The revised assumptions for Brent oil and Henry Hub gas for the next 10 years are lower by approximately 30% and 15% respectively than the average prices used to estimate cash flows over this period as disclosed in BP Annual Report and Form 20-F 2019 - Note 1. The revised impairment testing price assumptions are lower, on average, by approximately 27% and 31% respectively for the period from 2020 to 2050, than the prices referenced in BP Annual Report and Form 20-F 2019 - Note 1.

The group has identified oil and gas properties with carrying amounts totalling $40 billion where the headroom, based on the most recent impairment tests performed, was less than or equal to 20% of the carrying value. The significant majority of these assets have nil headroom. 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 were also reviewed. As these are set using a number of parameters that are applicable to longer-term assets, a revision of the discount rate assumption was determined not to be appropriate and therefore the rates, as disclosed in BP Annual Report and Form 20-F 2019, remain unchanged.

Provisions

The nominal risk-free discount rate applied to provisions is reviewed on a quarterly basis. Recent changes in long-dated US government bond yields have not affected the group's overall assessment of the discount rate applied to the group's provisions and therefore the rate, as disclosed in BP Annual Report and Form 20-F 2019, remains unchanged. The timing and amount of cash flows relating to the group's existing provisions are not currently expected to change significantly as a result of the current environment. The detailed annual review will take place later in 2020.

In addition, the group has recognized provisions for restructuring costs for plans that were formalized during the third quarter.

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Note 1. Basis of preparation (continued)

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 2020, the group's total net defined benefit pension plan deficit as at 30 September 2020 is $1.9 billion, a reduction in the deficit of $0.2 billion and an increase by $0.4 billion from 30 June 2020 and 31 December 2019 respectively. The movement for the nine months principally reflects actuarial losses reported in other comprehensive income arising from decreasing discount rates and higher inflation assumptions increasing the plan obligations partially offset by increases in the valuation of plan assets. 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.

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 2019. 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 although the full economic impact of COVID-19 on the forward-looking expected credit loss is subject to significant uncertainty due to the limited forward-looking information currently available.

Whilst credit risk has increased since 31 December 2019, there has also been a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 30 September 2020 have not significantly increased from the amounts disclosed in BP Annual Report and Form 20-F 2019 - Financial statements - Note 21 Valuation and qualifying accounts.

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 2019 - Financial statements - Note 29 Financial instruments and financial risk factors - credit risk.

Income taxes

None of the group's deferred tax assets in BP Annual Report and Form 20-F 2019 were determined to be a significant accounting estimate. The carrying amounts are, however, reviewed and updated quarterly to the extent that there are changes in the probability of sufficient taxable profits being available to utilize the reported deferred tax assets. The group has recognized deferred tax assets as at 30 September 2020 of $6.8 billion, an increase of $2.3 billion from 31 December 2019. The group continues to believe that the measurement of its deferred tax assets is not a significant accounting estimate.

Other accounting judgements and estimates

All other significant accounting judgements and estimates disclosed in BP Annual Report and Form 20-F 2019 remain applicable and no new significant accounting judgements or estimates have been identified.

Updates to significant accounting policies

Hybrid bond issuance

On 17 June 2020, a group subsidiary issued perpetual subordinated hybrid bonds in EUR, GBP and USD for a US dollar equivalent amount of $11.9 billion. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests in the condensed consolidated financial statements. The contractual terms of these instruments allow the group to defer coupon payments and the repayment of principal indefinitely, however their terms and conditions stipulate that any deferred payments must be made in the event of an announcement of an ordinary share or parity equity dividend distribution or certain share repurchases or redemptions.

Change in accounting policy - Interest Rate Benchmark Reform: Amendments to IFRS 9 'Financial instruments'

Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. Uncertainty around the method and timing of transition from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to certain hedging relationships.

BP is significantly exposed to benchmark interest rate components e.g. USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. All of the group's existing fair value hedge relationships are directly affected by interest rate benchmark reform as they all manage interest rate risk. Further information about the group's fair value hedges is included in BP Annual Report and Form 20-F 2019 - Financial statements - Note 30 Derivative financial instruments - Fair value hedges.

BP adopted the amendments to IFRS 9 and IFRS 7 'Financial Instruments: Disclosures' relating to interest rate benchmark reform with effect from 1 January 2020. This first phase of amendments provides temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by interest rate benchmark reforms.

The reliefs provided by the amendments allow BP, in the event that significant uncertainty around the reforms arise, to assume that:

- the interest rate benchmark component of fair value hedges only needs to be assessed as separately identifiable at initial designation; and

- the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the hedging instrument for fair value hedges.

In accordance with the transition provisions, the amendments have been adopted retrospectively to hedging relationships that existed at the start of the current reporting period and will be applied to new hedging relationships designated after that date.

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Note 1. Basis of preparation (continued)

The reliefs have meant that the uncertainty over the interest rate benchmark reforms has not resulted in discontinuation of hedge accounting for any of BP's fair value hedges.

The second phase of IFRS amendments were issued by the IASB in August 2020 to address the financial reporting impacts of transitioning from IBORs to RfRs. These amendments will be effective for BP from 1 January 2021.The amendments are not yet endorsed by the EU or the UK. BP has set up an internal working group to monitor and manage the transition to alternative benchmark rates and are currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts. BP is also participating on external committees and task forces dedicated to interest rate benchmark reform.

Change in accounting policy - physically settled derivative contracts

In March 2019, the IFRS Interpretations Committee ("IFRIC") issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item, such as commodities, that are not accounted for as 'own-use' contracts. IFRIC concluded that such contracts are settled by the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability.

BP regularly enters into forward sale and purchase contracts. As described in the group's accounting policy for revenue in BP Annual Report and Form 20-F 2019, revenue recognized at the time such contracts were physically settled was measured at the contractual transaction price and was presented together with revenue from contracts with customers in those financial statements.

BP changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020, as follows:

- Revenues and purchases from such contracts are measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues.

- There is no significant effect on current period or comparative information for 'Sales and other operating revenues' and 'Purchases' as presented in the group income statement, therefore no comparative information has been re-stated.

- There is no significant effect on net assets or on comparative information for 'Profit before taxation' or 'Profit after taxation' as presented in the group income statement.

In addition, BP chose to change its presentation of revenues from physically settled derivative sales contracts from first quarter 2020. Revenues from physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. They are now presented as other revenues. Comparative information in Note 6 for revenue from contracts with customers and other revenues have been re-presented to align with the current period.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2020 is $4,541 million, with associated liabilities of $1,057 million. These principally relate to two transactions.

Downstream segment

On 29 June 2020 BP announced that it had agreed to sell its global petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary closing adjustments. Under the terms of the agreement, INEOS paid BP a deposit of $400 million and will pay a further $3.6 billion on completion. An additional $1 billion will be deferred and paid in three separate instalments of $100 million in March, April and May 2021 with the remaining $700 million payable by the end of June 2021. The business has interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. Subject to regulatory and other approvals, the transaction is expected to complete by the end of 2020. Assets of $3,963 million and associated liabilities of $745 million have been classified as held for sale in the group balance sheet at 30 September 2020. Accumulated foreign exchange differences will be reclassified from the foreign currency translation reserve to the income statement when the sale transaction completes. At 30 September 2020 these foreign exchange differences amounted to a gain of approximately $375 million.

Upstream segment

On 27 August 2019, BP announced that it had agreed to sell all of its Alaska operations and interests to Hilcorp Energy ('Hilcorp'), including its ownership interests in BP Exploration (Alaska) Inc, which owned all of BP's upstream oil and gas interests in Alaska, and the assets of BP Pipelines (Alaska) Inc., including a 49% interest in the Trans Alaska Pipeline System (TAPS), for up to $5.6 billion, subject to customary closing adjustments. Assets of $6,518 million and associated liabilities of $969 million relating to this transaction were classified as held for sale at 31 December 2019. Deposit payments totalling $500 million in cash were received in 2019.

On 30 June 2020, BP completed the sale of BP Exploration (Alaska) Inc. On completion, BP received $209 million in cash and recognized a loan note with a principal amount of $2,100 million receivable from Hilcorp. The group also recognized other assets totalling $1,689 million, including amounts in relation to the 'earn-out' provisions of the agreement.

The sale of BP Pipelines (Alaska) Inc.'s 49% interest in the Trans Alaska Pipeline System (TAPS) and other midstream assets, which is subject to regulatory approvals, is expected to complete during the fourth quarter of 2020. On completion of the sale, BP will retain its decommissioning liability relating to TAPS, which will be partially offset by a 30% cost reimbursement from Harvest Alaska LLC, an affiliate of Hilcorp. Assets of $499 million and associated liabilities of $279 million relating to this transaction continue to be classified as held for sale at 30 September 2020.

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

Impairment and losses on sale of businesses and fixed assets for the third quarter and nine months were $294 million and $13,213 million and include net impairment charges of $277 million and $12,923 million respectively. Impairment charges also arose in certain equity-accounted entities in the nine months. The BP shares of these charges, amounting to $978 million for the nine months, are reported in the line items 'Earnings from joint ventures' and 'Earnings from associates' in the group income statement.

Upstream segment

Net impairment charges in the Upstream segment were $272 million and $12,157 million for the third quarter and nine months respectively.

Impairment charges for the nine months 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, BPX Energy, Canada, Egypt, India, Mauritania & Senegal, the North Sea, and Trinidad. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.

Impairment charges for the nine months also include amounts relating to the disposal of the group's interests in its Alaska business. See Note 2 for further information.

The BP share of impairment charges arising in equity-accounted entities reported in the Upstream segment in the nine months was $742 million.

Downstream segment

Impairment charges in the Downstream segment were $736 million for the nine months, principally relating to anticipated portfolio changes in the fuels business. Materially all of the impairment charges arose in the second quarter.

Note 4. Exploration expense

Exploration expense in the third quarter and nine months was $190 million and $10,066 million and includes exploration expenditure write-offs of $50 million and $9,766 million respectively. All exploration expenditure is recorded within the Upstream segment.

The exploration write-offs principally arose following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's price assumptions. The exploration write-offs for the nine months principally arose in Angola, Brazil, Canada, Egypt, India and the Gulf of Mexico.

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Note 5. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Upstream	30	(22,008)	(1,050)	(20,955)	4,303
Downstream	915	594	2,016	2,173	5,069
Rosneft	(278)	(124)	802	(419)	1,813
Other businesses and corporate	24	(317)	(412)	(991)	(1,339)
	691	(21,855)	1,356	(20,192)	9,846
Consolidation adjustment - UPII*	34	(46)	30	166	51
RC profit (loss) before interest and tax*	725	(21,901)	1,386	(20,026)	9,897
Inventory holding gains (losses)*
Upstream	8	57	-	(3)	(8)
Downstream	191	978	(433)	(3,446)	706
Rosneft (net of tax)	34	53	(79)	(114)	(41)
Profit (loss) before interest and tax	958	(20,813)	874	(23,589)	10,554
Finance costs	800	783	883	2,366	2,603
Net finance expense relating to pensions and other post-retirement benefits	8	8	16	23	46
Profit (loss) before taxation	150	(21,604)	(25)	(25,978)	7,905

RC profit (loss) before interest and tax*
US	105	(4,695)	(2,425)	(3,995)	(1,156)
Non-US	620	(17,206)	3,811	(16,031)	11,053
	725	(21,901)	1,386	(20,026)	9,897

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Note 6. Sales and other operating revenues

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
By segment
Upstream	7,797	7,194	12,396	26,455	40,546
Downstream	40,256	27,241	61,834	121,461	186,646
Other businesses and corporate	391	450	461	1,294	1,250
	48,444	34,885	74,691	149,210	228,442

Less: sales and other operating revenues between segments
Upstream	3,647	2,613	6,406	13,167	20,211
Downstream	124	330	(59)	(328)	589
Other businesses and corporate	422	266	53	794	354
	4,193	3,209	6,400	13,633	21,154

Third party sales and other operating revenues
Upstream	4,150	4,581	5,990	13,288	20,335
Downstream	40,132	26,911	61,893	121,789	186,057
Other businesses and corporate	(31)	184	408	500	896
Total sales and other operating revenues	44,251	31,676	68,291	135,577	207,288

By geographical area
US	16,513	10,117	23,413	47,849	71,347
Non-US	32,328	24,776	51,030	101,059	153,581
	48,841	34,893	74,443	148,908	224,928
Less: sales and other operating revenues between areas	4,590	3,217	6,152	13,331	17,640
	44,251	31,676	68,291	135,577	207,288

Revenues from contracts with customers_(a)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	1,366	1,062	2,194	3,863	7,261
Oil products	16,301	10,452	26,547	47,007	76,462
Natural gas, LNG and NGLs	2,844	2,992	4,387	9,474	14,038
Non-oil products and other revenues from contracts with customers	2,965	2,118	2,970	7,573	9,291
Revenue from contracts with customers	23,476	16,624	36,098	67,917	107,052
Other operating revenues_(b)	20,775	15,052	32,193	67,660	100,236
Total sales and other operating revenues	44,251	31,676	68,291	135,577	207,288

(a) Amounts shown for revenue from contracts with customers and other operating revenues for third quarter and nine months 2019 have been represented to align with the current period. See Note 1 for further information.

(b) Principally relates to physically settled derivative sales contracts.

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Note 7. Depreciation, depletion and amortization

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Upstream
US	842	1,044	1,121	2,954	3,522
Non-US	1,713	1,973	2,295	5,768	7,189
	2,555	3,017	3,416	8,722	10,711
Downstream
US	336	344	336	1,022	992
Non-US	407	408	394	1,220	1,169
	743	752	730	2,242	2,161
Other businesses and corporate
US	13	16	14	44	41
Non-US	156	152	137	455	433
	169	168	151	499	474
Total group	3,467	3,937	4,297	11,463	13,346

Note 8. Production and similar taxes

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
US	14	13	66	40	226
Non-US	126	111	274	427	909
	140	124	340	467	1,135

Note 9. 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. No share buybacks were carried out during the quarter. A total of 120 million ordinary shares were repurchased for cancellation in the nine months, as part of the share buyback programme announced on 31 October 2017. The shares had a total cost of $776 million, including transaction costs of $4 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.

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Note 9. Earnings per share and shares in issue (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Results for the period
Profit (loss) for the period attributable to BP shareholders	(450)	(16,848)	(749)	(21,663)	4,007
Less: preference dividend	-	1	-	1	1
Profit (loss) attributable to BP ordinary shareholders	(450)	(16,849)	(749)	(21,664)	4,006

Number of shares (thousand) _(a)(b)
Basic weighted average number of shares outstanding	20,251,199	20,222,575	20,371,728	20,217,559	20,295,078
ADS equivalent	3,375,199	3,370,429	3,395,288	3,369,593	3,382,513

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,251,199	20,222,575	20,371,728	20,217,559	20,411,739
ADS equivalent	3,375,199	3,370,429	3,395,288	3,369,593	3,401,957

Shares in issue at period-end	20,254,417	20,249,046	20,417,220	20,254,417	20,417,220
ADS equivalent	3,375,736	3,374,841	3,402,870	3,375,736	3,402,870

(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 second quarter 2020, third quarter 2020 and nine months 2020 are 63,119 thousand (ADS equivalent 10,520 thousand), 81,097 thousand (ADS equivalent 13,516 thousand) and 94,302 thousand (ADS equivalent 15,717 thousand) respectively.

Note 10. Dividends

Dividends payable

BP today announced an interim dividend of 5.25 cents per ordinary share which is expected to be paid on 18 December 2020 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 6 November 2020. The corresponding amount in sterling is due to be announced on 7 December 2020, calculated based on the average of the market exchange rates for the four dealing days commencing on 1 December 2020. Holders of ADSs are expected to receive $0.315 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2020 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
	2020	2020	2019	2020	2019
Dividends paid per ordinary share
cents	5.250	10.500	10.250	26.250	30.750
pence	4.043	8.342	8.348	20.541	24.152
Dividends paid per ADS (cents)	31.50	63.00	61.50	157.50	184.50
Scrip dividends
Number of shares issued (millions)	-	-	72.5	-	208.9
Value of shares issued ($ million)	-	-	440	-	1,387

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Note 11. Net debt

Net debt*	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Finance debt_(a)(b)	72,828	76,003	65,867	72,828	65,867
Fair value (asset) liability of hedges related to finance debt_(c)	(1,384)	(430)	319	(1,384)	319
	71,444	75,573	66,186	71,444	66,186
Less: cash and cash equivalents_(b)	31,065	34,653	19,692	31,065	19,692
Net debt	40,379	40,920	46,494	40,379	46,494
Total equity	82,155	82,811	100,015	82,155	100,015
Gearing*	33.0%	33.1%	31.7%	33.0%	31.7%

(a) The fair value of finance debt at 30 September 2020 was $75,338 million (30 September 2019 $66,879 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 $372 million (second quarter 2020 liability of $554 million and third quarter 2019 liability of $682 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

In the third quarter, the group bought back $4.0 billion equivalent of euro and sterling bonds as part of actively managing its debt portfolio. Derivatives associated with the debt bought back were also terminated. There was no significant impact on net debt as a result of these transactions.

On 17 June 2020 the group issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion. See Note 1 for further information.

Note 12. Inventory valuation

A provision of $544 million was held against hydrocarbon inventories at 30 September 2020 ($289 million at 30 June 2020 and $290 million at 31 December 2019) to write them down to their net realizable value.

Note 13. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 26 October 2020, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2020. BP Annual Report and Form 20-F 2019 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*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Capital expenditure on a cash basis
Organic capital expenditure*	2,512	3,034	3,946	9,085	11,280
Inorganic capital expenditure*_(a)(b)	1,124	33	77	1,479	4,032
	3,636	3,067	4,023	10,564	15,312

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Organic capital expenditure by segment
Upstream
US	589	1,018	1,036	2,775	2,990
Non-US	1,367	1,517	2,110	4,546	5,856
	1,956	2,535	3,146	7,321	8,846
Downstream
US	139	135	197	395	655
Non-US	345	295	558	1,171	1,562
	484	430	755	1,566	2,217
Other businesses and corporate
US	13	21	8	66	32
Non-US	59	48	37	132	185
	72	69	45	198	217
	2,512	3,034	3,946	9,085	11,280
Organic capital expenditure by geographical area
US	741	1,174	1,241	3,236	3,677
Non-US	1,771	1,860	2,705	5,849	7,603
	2,512	3,034	3,946	9,085	11,280

(a) On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for the nine months 2019 relating to this transaction.

(b) 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 and 2019 also include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

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Non-operating items*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Upstream
Gains on sale of businesses and fixed assets	10	87	-	104	105
Impairment and losses on sale of businesses and fixed assets_(a)	(274)	(10,953)	(3,406)	(12,358)	(4,318)
Environmental and other provisions	(9)	-	-	(22)	-
Restructuring, integration and rationalization costs_(b)	(164)	(24)	(24)	(192)	(76)
Other_(c)(d)	(194)	(2,564)	(24)	(2,688)	65
	(631)	(13,454)	(3,454)	(15,156)	(4,224)
Downstream
Gains on sale of businesses and fixed assets	16	(13)	2	10	44
Impairment and losses on sale of businesses and fixed assets_(a)	(20)	(798)	(11)	(823)	(100)
Environmental and other provisions	-	-	(1)	-	(1)
Restructuring, integration and rationalization costs_(b)	(142)	31	(4)	(111)	14
Other	-	-	-	-	(6)
	(146)	(780)	(14)	(924)	(49)
Rosneft
Other	(101)	(63)	-	(164)	(194)
	(101)	(63)	-	(164)	(194)
Other businesses and corporate
Gains on sale of businesses and fixed assets	1	-	-	3	(4)
Impairment and losses on sale of businesses and fixed assets	-	(19)	-	(21)	-
Environmental and other provisions	(32)	-	-	(55)	(28)
Restructuring, integration and rationalization costs_(b)	(156)	(33)	-	(202)	7
Gulf of Mexico oil spill	(63)	(31)	(84)	(115)	(256)
Other_(e)	138	67	(6)	125	(28)
	(112)	(16)	(90)	(265)	(309)
Total before interest and taxation	(990)	(14,313)	(3,558)	(16,509)	(4,776)
Finance costs_(f)	(198)	(114)	(145)	(434)	(389)
Total before taxation	(1,188)	(14,427)	(3,703)	(16,943)	(5,165)
Taxation credit (charge) on non-operating items	(6)	3,456	772	3,752	1,121
Taxation - impact of foreign exchange_(g)	85	114	-	(166)	-
Total after taxation for period	(1,109)	(10,857)	(2,931)	(13,357)	(4,044)

(a) See Note 3 for further information.

(b) Third quarter 2020 includes recognized provisions for restructuring costs for plans that were formalized during the quarter.

(c) Second quarter and nine months 2020 include exploration write-offs of $1,969 million relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil, India and the Gulf of Mexico and the impairment of certain intangible assets in Mauritania and Senegal.

(d) Second quarter and nine months 2020 include $585 million and $742 million of impairments reported by equity-accounted entities.

(e) From first quarter 2020, BP is presenting temporary valuation differences associated with the group's interest rate and foreign currency exchange risk management of finance debt as non-operating items. These amounts represent: (i) the impact of ineffectiveness and the amortisation of cross currency basis resulting from the application of fair value hedge accounting; and (ii) the net impact of foreign currency exchange movements on finance debt and associated derivatives where hedge accounting is not applied. Relevant amounts in the comparative periods presented were not material.

(f) All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. Third quarter and nine months 2020 also include the income statement impact associated with the buyback of finance debt. See Note 11 for further information.

(g) From first quarter 2020, BP is presenting certain foreign exchange effects on tax as non-operating 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. Relevant amounts in the comparative periods presented were not material.

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Non-GAAP information on fair value accounting effects

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Favourable (adverse) impact relative to management's measure of performance
Upstream	(217)	(67)	265	(61)	47
Downstream	425	(31)	147	135	137
Other businesses and corporate	266	(41)	-	225	-
	474	(139)	412	299	184
Taxation credit (charge)	(95)	21	(86)	(66)	(44)
	379	(118)	326	233	140

Fair value accounting effects reflect differences in the way that BP manages the economic exposure and measures performance relating to certain activities and the way these activities are measured under IFRS. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below.

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 reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition 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 and corporate segment in the table above, 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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Net debt including leases

Net debt including leases*	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Net debt	40,379	40,920	46,494	40,379	46,494
Lease liabilities	9,282	9,331	9,639	9,282	9,639
Net partner (receivable) payable for leases entered into on behalf of joint operations	(41)	(90)	(197)	(41)	(197)
Net debt including leases	49,620	50,161	55,936	49,620	55,936
Total equity	82,155	82,811	100,015	82,155	100,015
Gearing including leases*	37.7%	37.7%	35.9%	37.7%	35.9%

Readily marketable inventory* (RMI)

	30 September	31 December
$ million	2020	2019
RMI at fair value*	4,506	6,837
Paid-up RMI*	1,474	3,217

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP's integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.

We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group's inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.

See the Glossary on page 32 for a more detailed definition of RMI. RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.

	30 September	31 December
$ million	2020	2019
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	13,840	20,880
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST	(9,474)	(14,280)
	4,366	6,600
Plus: difference between RMI at fair value and RMI on an IFRS basis	140	237
RMI at fair value	4,506	6,837
Less: unpaid RMI* at fair value	(3,032)	(3,620)
Paid-up RMI	1,474	3,217

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Gulf of Mexico oil spill

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Net cash provided by operating activities as per condensed group cash flow statement	5,204	3,737	6,056	9,893	18,167
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis	142	1,097	409	1,520	2,471
Operating cash flow, excluding Gulf of Mexico oil spill payments*	5,346	4,834	6,465	11,413	20,638

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $180 million and $1,670 million in the third quarter and nine months of 2020 respectively. For the same periods in 2019, the amount was an outflow of $443 million and $2,569 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2020 and 2019 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states.

	30 September	31 December
$ million	2020	2019
Trade and other payables	(11,298)	(12,480)
Provisions	(23)	(189)
Gulf of Mexico oil spill payables and provisions	(11,321)	(12,669)
Of which - current	(1,427)	(1,800)

Deferred tax asset	5,449	5,526

The provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts ultimately payable may differ from the amount 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 2019 - Financial statements - Notes 7, 9, 20, 22, 23, 29, 33 and pages 319 to 320 of Legal proceedings.

Working capital* reconciliation

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2020	2020	2019	2020	2019
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement	556	(609)	141	630	(2,612)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill	165	1,120	413	1,539	2,495
Adjusted for Inventory holding gains (losses)* (Note 5)
Upstream	8	57	-	(3)	(8)
Downstream	191	978	(433)	(3,446)	706
Working capital release (build)	920	1,546	121	(1,280)	581

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Realizations* and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2020	2020	2019	2020	2019
Average realizations _(a)
Liquids* ($/bbl)
US	31.74	21.63	50.46	33.24	52.80
Europe	43.52	28.91	61.90	41.35	64.21
Rest of World	41.46	22.58	59.14	36.13	61.91
BP Average	38.17	22.75	55.68	35.51	58.38
Natural gas ($/mcf)
US	1.29	0.97	1.72	1.19	2.02
Europe	2.34	1.38	3.03	2.22	3.98
Rest of World	2.99	3.12	3.82	3.21	4.21
BP Average	2.56	2.53	3.11	2.65	3.49
Total hydrocarbons* ($/boe)
US	22.04	16.05	31.23	23.01	33.81
Europe	36.14	23.00	52.47	34.34	58.55
Rest of World	27.40	20.21	36.82	26.19	39.69
BP Average	26.42	19.06	35.48	25.68	38.55
Average oil marker prices ($/bbl)
Brent	42.94	29.56	62.00	41.06	64.59
West Texas Intermediate	40.91	27.96	56.40	38.12	57.08
Western Canadian Select	31.62	22.19	43.61	27.54	45.30
Alaska North Slope	42.75	30.28	62.98	41.32	65.23
Mars	42.01	30.02	59.19	39.18	61.85
Urals (NWE - cif)	42.83	31.36	60.82	40.83	63.71
Average natural gas marker prices
Henry Hub gas price_(b) ($/mmBtu)	1.98	1.71	2.23	1.88	2.67
UK Gas - National Balancing Point (p/therm)	21.06	12.88	27.46	19.69	35.70

(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
	2020	2020	2019	2020	2019
$/£ average rate for the period	1.29	1.24	1.23	1.27	1.27
$/£ period-end rate	1.28	1.23	1.23	1.28	1.23

$/€ average rate for the period	1.17	1.10	1.11	1.12	1.12
$/€ period-end rate	1.17	1.12	1.09	1.17	1.09

Rouble/$ average rate for the period	73.74	72.40	64.64	71.00	65.06
Rouble/$ period-end rate	77.57	71.25	64.32	77.57	64.32

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Legal proceedings

For a full discussion of the group's material legal proceedings, see pages 319-320 of BP Annual Report and Form 20-F 2019.

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.

Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.

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.

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. 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. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

Ethanol-equivalent production (which includes ethanol and sugar) is converted to thousands of barrels a day at 6.289 million litres = 1 thousand barrels divided by the total number of days in the period reported.

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. Further information on fair value accounting effects is provided on page 28.

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. 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 25.

We are unable to present reconciliations of forward-looking information for 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 29.

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

Inorganic capital expenditure is a subset of capital expenditure and 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. Further information and a reconciliation to GAAP information is provided on page 26.

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Glossary (continued)

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, 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 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. 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. See Replacement cost (RC) profit or loss definition below.

Liquids - Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, 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.

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP's share of equity-accounted entities.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 7, 9 and 11, and by segment and type is shown on page 27.

Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment's share thereof.

Operating cash flow excluding Gulf of Mexico oil spill payments is a non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill from net cash provided by operating activities as reported in the condensed group cash flow statement. BP believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities.

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure 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. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 26.

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.

Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.

Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 29.

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.

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Glossary (continued)

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.

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. 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 the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. 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.

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.

Solomon availability - See Refining availability definition.

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.

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 is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. 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. 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, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.

Underlying production - 2020 underlying production, when compared with 2019, 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 is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 27 and 28 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. 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 non-operating items and fair value accounting effects. 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 is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 1.

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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 9. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share 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. 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 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 - Change in 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 is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and this therefore 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 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. In the context of describing operating cash flow excluding Gulf of Mexico oil spill payments, change in working capital also excludes movements in inventories and other current and non-current assets and liabilities relating to the Gulf of Mexico oil spill. See page 30 for further details.

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.

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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: the expectations regarding the COVID-19 pandemic including its risks, impacts, consequences and challenges and BP's response, including the impact on financial performance (including cash flows, net debt and gearing), operations, credit losses, trading environment, oil and gas prices, global GDP, the shape of the COVID-19 recovery and the pace of transition to a lower-carbon economy and energy system; plans and expectations regarding the divestment programme, including reaching $25 billion of proceeds by 2025 and expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals (including the expected completion of the sales of the midstream portion of BP's Alaskan business (including TAPS) to Hilcorp and BP's petrochemicals business to INEOS); plans and expectations with respect to the total amount of organic capital expenditure and the DD&A charge in 2020; plans and expectations with respect to the total capital expenditure for 2021; plans and expectations regarding net debt, including to deliver the target of $35 billion; plans and expectations regarding new joint ventures and other agreements, including partnerships with Equinor, Police Scotland, Microsoft, Aberdeen City and Aral in Germany; plans and expectations regarding BP's priorities, including to focus on maintaining capital discipline, driving costs down, delivering divestments and reducing debt while bringing new major projects onstream; plans to expand the India retail business; expectations regarding quarterly dividends; expectations regarding demand for BP's products in the Upstream and Downstream; expectations regarding the Downstream refining margins and marketing volumes; expectations regarding BP's future financial performance and cash flows; plans and expectations with respect to the implementation and impact of BP's strategic reinvention and redesign of its organization, including for the organization to be in place by the start of 2021, the announced reduction of up to 10,000 jobs, and plans for BP to deliver $2.5 billion in cash cost savings from 2019 to end-2021, and the amount and timing of associated people-related costs; expectations regarding the underlying effective tax rate in the fourth quarter of 2020; plans and expectations with respect the Lightsource BP Bighorn Solar project and BP's ambition to reach 20GW of developed assets by the end of 2025; plans and expectations regarding Upstream projects, including for five Upstream major projects to begin production in 2020 and the timing of the Trans Adriatic Gas pipeline project; expectations regarding Upstream fourth-quarter 2020 reported and underlying production and maintenance activity; expectations regarding the timing of implementation of new accounting policies; expectations regarding price assumptions used in accounting estimates; expectations regarding the Other businesses and corporate average quarterly charges; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill. 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 significant drop in the oil price, 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; 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; 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, under "Principal risks and uncertainties" in our results announcement for the period ended 30 June 2020 and under "Risk factors" in BP Annual Report and Form 20-F 2019 as filed with the US Securities and Exchange Commission. 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 significant drop in the oil price, 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; 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; 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, under "Principal risks and uncertainties" in our results announcement for the period ended 30 June 2020 and under "Risk factors" in BP Annual Report and Form 20-F 2019 as filed with the US Securities and Exchange Commission.

Top of page 37

Contacts

	London	Houston

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

Investor Relations	Craig Marshall	Brian Sullivan
bp.com/investors	+44 (0)20 7496 4962	+1 281 892 3421

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

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