Form 6-K BP PLC For: Feb 02

February 2, 2021 7:33 AM

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Issuer

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

the Securities Exchange Act of 1934

for the period ended 02 February, 2021

BP p.l.c.

(Translation of registrant's name into English)

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

(Address of principal executive offices)

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

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

Form 20-F |X| Form 40-F

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

Indicate by check mark whether the registrant by furnishing the information

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

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

1934.

Yes No |X|


London 2 February 2021
BP p.l.c. Group results
Fourth quarter and full year 2020

For a printer friendly copy of this announcement, please click on the link below to open a PDF version.

http://www.rns-pdf.londonstockexchange.com/rns/6348N_1-2021-2-1.pdf

Highlights

Resilient operations and strategic progress in a challenging environment

Bernard Looney – chief executive officer:

2020 will forever be remembered for the pain and sadness caused by COVID-19. Lives were lost – livelihoods destroyed. Our sector was hit hard as well. Road and air travel are down, as are oil demand, prices and margins. It was also a pivotal year for the company. We launched a net zero ambition, set a new strategy to become an integrated energy company and created an offshore wind business in the US. We began reinventing bp – with nearly 10 thousand people leaving the company. We strengthened our finances – taking out costs and closing major divestments. And through all of this, the underlying operations of the company remained safe – one of our safest years – and reliable, and major new projects were brought on line. I appreciate our team’s commitment to deliver the energy the world needed and am grateful for the support we received from investors and the communities where we work. We expect much better days ahead for all of us in 2021.

Financial results and progress

Underlying replacement cost profit for the quarter was $0.1 billion, similar to the previous quarter. Performance was significantly impacted by lower marketing performance in the Downstream, with volumes remaining under pressure due to COVID-19 and continuing pressure on refining margins and utilization. In addition, the result was impacted by a significantly weaker result in gas marketing and trading and higher exploration write-offs, partially offset by a higher Rosneft contribution and a lower underlying tax charge. The full-year result was a loss of $5.7 billion compared to $10 billion profit in 2019, driven by lower oil and gas prices, significant exploration write-offs and refining margins and depressed demand.

Reported profit for the quarter was $1.4 billion, compared with $0.5 billion loss in the previous quarter. The result included $2.3 billion gain on disposal from the sale of BP’s petrochemicals business. For the full year, the reported loss was $20.3 billion, including significant impairments and exploration write-offs taken in the second quarter, compared with a profit of $4.0 billion in 2019.

Operating cash flow for the quarter, excluding Gulf of Mexico oil spill payments of $0.1 billion, was $2.4 billion. Compared to the third quarter, this reflected the significant impact of lower marketing volumes in the Downstream and a significantly weaker contribution from gas marketing and trading. There was also the absence of the working capital release and other working capital effects, absence of the Rosneft dividend, and severance payments for reinvent bp, partly offset by lower tax payments.

Proceeds from divestments and other disposals in the quarter were $4.2 billion, including $3.5 billion on completion of the petrochemicals divestment. In February 2021, BP agreed to sell a 20% interest in Oman's Block 61 for $2.6 billion subject to final adjustments. BP has now completed or agreed transactions for over half of its target of $25 billion in proceeds by 2025. BP expects proceeds from divestments and other disposals of $4-6 billion in 2021, weighted toward the second half.

At year end net debt was $39 billion, down $1.4 billion over the quarter and $6.5 billion over the full year. Net debt is expected to increase in the first half of 2021, driven by severance payments, the annual Gulf of Mexico oil spill payment and payment following completion of the offshore wind joint venture with Equinor. It is expected to then fall in the second half with growing operating cash flow and the receipt of divestment proceeds. BP continues to expect to reach our $35 billion net debt target around fourth quarter 2021 and first quarter 2022. This assumes oil prices in the range of $45-50 a barrel and BP planning assumptions for RMM and gas prices.

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

Performing while transforming

Operations were strong in 2020, with full-year BP-operated refining availability of 96% and Upstream plant reliability of 94%. Safety performance was also strong with both tier1/tier2 process safety events and reported recordable injury frequency significantly lower than in 2019. Upstream unit production costs for the year were 6.5% lower than 2019. Full-year Upstream production was 9.9% lower than 2019 primarily due to divestments.

BP continues to make strong progress in reinventing its organization. The new organization was in place at the start of 2021 and over half of the approximately 10,000 people expected to leave BP as a result of the reinvent programme had left by year-end. Around $1.4 billion in people-related costs are expected associated with the reinvent programme, with the majority of the cash outflow incurred in the first half of 2021.

Four new Upstream major projects began production in the year, including three in the fourth quarter – Ghazeer in Oman, Vorlich in the UK and KG D6 R-cluster in India. In the quarter, the Trans Adriatic Pipeline began gas deliveries, completing the Southern Gas Corridor pipeline system.

Demonstrating the resilience of BP's convenience offer, while retail fuel volumes were 14% lower for the full year, BP's convenience gross margin grew by 6%. Through the year, around 300 strategic convenience sites were added to the network.

BP had developed 3.3GW net renewable generating capacity to FID by end-2020, 0.7GW more than a year earlier. In January 2021 BP completed formation of its strategic US offshore wind partnership with Equinor, including the purchase of 50% in the Empire Wind and Beacon Wind projects. The projects were also selected to supply 2.5GW of power to the State of New York, adding to an existing commitment to supply 0.8GW.

Working in partnership with other companies, BP has announced: plans to develop a ‘green’ hydrogen project at its Lingen refinery in Germany with Ørsted; a BP-operated multi-company partnership to develop offshore infrastructure to support planned UK carbon capture, use and storage projects; and agreements to provide additional supplies of renewable energy to Amazon.

Financial summary	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Profit (loss) for the period attributable to BP shareholders	1,358	(450)	19	(20,305)	4,026
Inventory holding (gains) losses, net of tax	(533)	(194)	(23)	2,201	(511)
RC profit (loss)	825	(644)	(4)	(18,104)	3,515
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	(710)	730	2,571	12,414	6,475
Underlying RC profit (loss)	115	86	2,567	(5,690)	9,990
RC profit (loss) per ordinary share (cents)	4.08	(3.18)	(0.02)	(89.53)	17.32
RC profit (loss) per ADS (dollars)	0.24	(0.19)	0.00	(5.37)	1.04
Underlying RC profit (loss) per ordinary share (cents)	0.57	0.42	12.67	(28.14)	49.24
Underlying RC profit (loss) per ADS (dollars)	0.03	0.03	0.76	(1.69)	2.95

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

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BP p.l.c. Group results

Fourth quarter and full year 2020

Murray Auchincloss – chief financial officer:

These results reflect a truly tough quarter, with a challenging price environment and COVID-19 related demand impacts. Nonetheless, we made strong progress in reducing net debt again, to $39 billion in the quarter. We remain on track to meet our target of $35 billion between the fourth quarter of 2021 and first quarter of 2022, which will trigger the start of share buybacks, subject to maintaining a strong investment grade credit rating.

COVID-19 Update

Strengthening finances:

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

BP has continued to progress its divestment programme towards delivery of $25 billion of proceeds by 2025. The petrochemicals and Alaska midstream disposals both completed in the fourth quarter. Divestment proceeds for the full year were $5.5 billion.

Organic capital expenditure in 2020 was $12.0 billion, in line with the guidance given in April and compared with $15.2 billion in 2019.

Costs that are directly attributable to COVID-19 were around $0.1 billion for the quarter (full year 2020 around $0.4 billion).

At year end net debt was $39 billion, and BP continues to actively manage the profile of its debt portfolio. During the third quarter and January 2021, the group bought back an aggregate of $6 billion of debt. At year-end BP had around $44 billion of liquidity, including cash and undrawn revolving credit facilities.

Net debt is expected to increase in the first half of 2021 before reducing in the second half of the year supported by growing operating cash flow and the receipt of divestment proceeds. BP continues to expect to reach our $35 billion net debt target around fourth quarter 2021 and first quarter 2022. This assumes oil prices in the range of $45-50 a barrel and BP planning assumptions for RMM and gas prices.

Protecting our people and operations:

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 continue to do so. Precautions in operations and offices include: reduced manning levels, changing working patterns, deploying appropriate personal protective equipment (PPE) and enhanced cleaning and social distancing measures at plants and retail sites. Decisions on working practices 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.

While the pandemic did not result in significant outages in our ongoing operations, it resulted in delays to in-year major projects in the North Sea and India and has impacted development of the Mad Dog 2, Tangguh Expansion, Trinidad Cassia Compression and Greater Tortue Ahmeyin Phase 1 major projects. However production from four major projects commenced during the year.

Refinery utilization for the full year was around 6% lower than 2019 due to the impact of COVID-19 on demand, with refining margins remaining extremely weak. Year on year, demand for retail fuels was lower by 14% and for aviation by 50%. Despite this, convenience gross margin grew by 6% at BP retail sites for the full year.

Despite the challenges of the environment, BP's operations have performed safely and reliably over the course of the year. BP-operated Upstream plant reliability was 94% and BP-operated refining availability was 96% for the year.

Outlook:

From the oil supply side, limited growth from non-OPEC+ countries coupled with active market management from OPEC+ means that for 2021 we anticipate a normalization of the currently high inventory levels.

Oil demand is anticipated to recover in 2021. The speed and degree of the rebound depends on governments’ policies and individuals’ self-imposed actions as vaccine distribution proceeds.

Oil prices have risen since the end of October, supported by vaccine rollout programmes and continued active supply management by OPEC+ countries. Prices are expected to remain subject to the decisions of OPEC+, confidence in efforts to manage the rollout of vaccination and further virus control measures.

We expect the US gas market to tighten in 2021 as supply declines and demand for LNG exports recovers. The current tightness on global LNG markets and higher US gas prices will lift other regional gas prices.

US gas markets are likely to benefit from lower production and a recovery in international LNG demand driven by demand in Asia.

In the first quarter of 2021 we expect material impacts in Downstream as a result of the pandemic, with increased COVID-19 restrictions resulting in lower product demand. We expect industry refining margins and utilization to remain under pressure. In our marketing businesses we expect renewed COVID-19 restrictions to have a greater impact on product demand, with January retail volumes down by around 20% year on year, compared with a decline of 11% in the fourth quarter.

BP will continue to review all actions and respond to any further changes in prevailing market conditions.

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 full year, underlying replacement cost (RC) loss* was $5,690 million, compared with a profit of $9,990 million in 2019. Underlying RC loss is after adjusting RC loss* for a net charge for non-operating items* of $12,191 million and net adverse fair value accounting effects* of $223 million (both on a post-tax basis).

RC loss was $18,104 million for the full year, compared with a profit of $3,515 million in 2019.

For the fourth quarter, underlying RC profit was $115 million, compared with $2,567 million in 2019. Underlying RC profit is after adjusting RC profit for a net gain for non-operating items of $1,166 million and net adverse fair value accounting effects of $456 million (both on a post-tax basis).

RC profit was $825 million for the fourth quarter, compared with a loss of $4 million in 2019.

Profit or loss for the fourth quarter and full year attributable to BP shareholders was a profit of $1,358 million and a loss of $20,305 million respectively, compared with a profit of $19 million and $4,026 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 $3.4 billion in the quarter and $14.9 billion in the full year, compared with $4.4 billion and $17.8 billion for the same periods in 2019. In 2021, we expect the full-year charge to be similar to the 2020 level.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the fourth quarter and full year was -141% and 16% respectively, compared with 102% and 51% for the same periods in 2019. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the fourth quarter and full year was 40% and -14% respectively, compared with 27% and 36% for the same periods a year ago. The higher underlying ETR for the fourth quarter reflects changes in the mix of profits and losses. The lower underlying ETR for the full year mainly reflects the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition in the second quarter. The underlying ETR for 2021 is expected to be higher than 40% but is sensitive to the impact that volatility in the current environment may have on the geographical mix of the group’s profits and losses. 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 26 March 2021. The corresponding amount in sterling is due to be announced on 15 March 2021, calculated based on the average of the market exchange rates for the four dealing days commencing on 9 March 2021. 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 full year 2020, all of which was completed in the first quarter of 2020. 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 $2.4 billion for the fourth quarter and $13.8 billion for the full year. These amounts include a working capital* build of $4.0 million in the fourth quarter and $1.3 billion in the full year, 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 $7.6 billion and $28.2 billion.

Operating cash flow as reported in the group cash flow statement was $2.3 billion for the fourth quarter and $12.2 billion for the full year, including a working capital build of $0.7 billion and $0.1 billion respectively, compared with $7.6 billion and $25.8 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 fourth quarter and full year was $2.9 billion and $12.0 billion respectively, compared with $4.0 billion and $15.2 billion for the same periods in 2019.

Inorganic capital expenditure* for the fourth quarter and full year was $0.5 billion and $2.0 billion respectively, compared with $0.2 billion and $4.2 billion for the same periods in 2019.

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

Divestment and other proceeds

Divestment proceeds* for the fourth quarter and full year were $4.0 billion and $5.5 billion respectively, including $3.5 billion and $3.9 billion of proceeds from the petrochemicals divestment respectively. For the same periods in 2019 divestment proceeds were $0.8 billion and $2.2 billion respectively.

In addition, $0.2 billion was received in the fourth quarter in relation to the sale of an interest in BP's New Zealand retail property portfolio. For the full year, $1.1 billion in other proceeds were received including from the TANAP pipeline refinancing and the sale of an interest in BP's UK retail property portfolio. Other proceeds for the fourth quarter and full year in 2019 were $0.6 billion.

Total divestment and other proceeds for the quarter and full year in 2020 were $4.2 billion and $6.6 billion respectively. Total divestment and other proceeds for the fourth quarter and full year in 2019 were $1.4 billion and $2.8 billion respectively.

Net debt* and gearing*

Net debt at 31 December 2020 was $38.9 billion, compared with $45.4 billion a year ago. Gearing at 31 December 2020 was 31.3%, compared with 31.1% a year ago. Gearing including leases* at 31 December 2020 was 36.0%, compared with 35.3% a year ago. Net debt, gearing and gearing including leases are non-GAAP measures. See pages 25 and 29 for more information.

Reserves replacement ratio*

The organic reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities was 78% for the year. Including acquisitions and divestments, the total reserves replacement ratio was -5%.

* 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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Underlying RC profit (loss) before interest and tax
Upstream	697	878	2,678	(5,041)	11,158
Downstream	126	636	1,438	3,088	6,419
Rosneft	311	(177)	412	56	2,419
Other businesses and corporate	(89)	(130)	(250)	(1,040)	(1,280)
Consolidation adjustment – UPII*	(77)	34	24	89	75
Underlying RC profit (loss) before interest and tax	968	1,241	4,302	(2,848)	18,791
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(568)	(610)	(781)	(2,523)	(3,041)
Taxation on an underlying RC basis	(158)	(402)	(955)	(743)	(5,596)
Non-controlling interests	(127)	(143)	1	424	(164)
Underlying RC profit (loss) attributable to BP shareholders	115	86	2,567	(5,690)	9,990

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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
RC profit (loss) before interest and tax
Upstream	(592)	30	614	(21,547)	4,917
Downstream	1,245	915	1,433	3,418	6,502
Rosneft	270	(278)	503	(149)	2,316
Other businesses and corporate	308	24	(1,432)	(683)	(2,771)
Consolidation adjustment – UPII	(77)	34	24	89	75
RC profit (loss) before interest and tax	1,154	725	1,142	(18,872)	11,039
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(759)	(808)	(903)	(3,148)	(3,552)
Taxation on a RC basis	557	(418)	(244)	3,492	(3,808)
Non-controlling interests	(127)	(143)	1	424	(164)
RC profit (loss) attributable to BP shareholders	825	(644)	(4)	(18,104)	3,515
Inventory holding gains (losses)*	695	233	10	(2,868)	667
Taxation (charge) credit on inventory holding gains and losses	(162)	(39)	13	667	(156)
Profit (loss) for the period attributable to BP shareholders	1,358	(450)	19	(20,305)	4,026

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Operational updates

Upstream

Upstream production, which excludes Rosneft, for the full year averaged 2,375mboe/d, 9.9% lower than for 2019, driven primarily by divestments in BPX Energy and Alaska. Underlying production* for the full year was 3.5% lower than 2019.

For the full year of 2020, BP-operated Upstream plant reliability* was 94.0% and Upstream unit production costs* of $6.39/boe were 6.5% lower than in 2019.

Production from three Upstream major projects started in the quarter – the Ghazeer project in Oman, Vorlich in the UK North Sea and the KG D6 R Cluster project offshore India. This follows the Gulf of Mexico Atlantis Phase 3 project in the previous quarter. The Raven project in Egypt is currently undergoing commissioning. The Trans Adriatic Pipeline began gas deliveries, completing the Southern Gas Corridor pipeline system.

BP reached agreement to sell its interests in the Wamsutter asset in Wyoming to Williams Field Services LLC. In February 2021 BP also agreed to sell a 20% participating interest in Oman’s Block 61 to PTT Exploration and Production Public Company Limited.

Downstream

BP-operated refining availability for the full year was 96.0%. In the quarter BP announced plans to cease production at the Kwinana refinery and convert it to an import terminal, helping to secure ongoing fuel supply for Western Australia.

BP continued to make progress in fuels marketing in 2020, expanding its retail network by more than 1,400 to over 20,300 sites worldwide. This includes more than 1,900 strategic convenience sites, around 300 more than a year earlier.

The $5-billion sale of BP's petrochemicals business to INEOS completed on 31 December and BP received the second payment of $3.6 billion, less $0.1 billion of third-party indebtedness. Final payments totalling $1 billion are expected in the first half of 2021.

Through 2020, the number of BP and joint venture operated electric vehicle charging points increased to more than 10,000 worldwide, with growth in the UK, Germany and through the DiDi joint venture in China.

Strategic progress

At the end of 2020, BP had developed 3.3GW net renewable generating capacity to FID, compared with 2.6GW a year earlier.

The formation of BP's strategic partnership with Equinor for offshore wind opportunities in the US was completed in January 2021, including BP's purchase of a 50% interest in the Empire Wind and Beacon Wind projects. Empire Wind 2 and Beacon Wind 1 were selected to provide New York state with additional offshore wind power which, subject to negotiation of a purchase and sale agreement, will bring the total secured by the projects to 3.3GW, 75% of the maximum potential installed capacity across the projects.

In the quarter BP also acquired a majority stake in Finite Carbon, the biggest developer of forest carbon offsets in the US. BP's investment is expected to support the accelerated growth of the business, including international expansion.

Financial framework

Operating cash flow excluding Gulf of Mexico oil spill payments* was $13.8 billion for the full year of 2020, compared with $28.2 billion for the same period in 2019.

Organic capital expenditure* for the full year of 2020 was $12.0 billion. BP expects total capital expenditure, including inorganic capital expenditure, to be around $13 billion in 2021.

Divestment and other proceeds were $6.6 billion for the full year of 2020. BP has now completed or agreed transactions for over half of its target of $25 billion in proceeds by 2025. BP expects proceeds from divestments and other disposals of $4-6 billion in 2021, weighted toward the second half.

Gulf of Mexico oil spill payments on a post-tax basis were $1.6 billion in the full year of 2020. Payments for 2021 are expected to be around $1 billion on a post-tax basis.

Gearing* at 31 December 2020 was 31.3%, in part reflecting the hybrid bond issue in the second quarter of 2020. See page 25 for more information.

Operating metrics	Year 2020	Financial metrics	Year 2020
Operating metrics	(vs. Year 2019)	Financial metrics	(vs. Year 2019)
Tier 1 and tier 2 process safety events	70	Underlying RC profit (loss)*	$(5.7)bn
Tier 1 and tier 2 process safety events	(-28)	Underlying RC profit (loss)*	(-$15.7bn)
Reported recordable injury frequency*	0.132	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	$13.8bn
Reported recordable injury frequency*	(-20.7%)		(-$14.4bn)
Group production	3,473mboe/d	Organic capital expenditure	$12.0bn
Group production	(-8.1%)	Organic capital expenditure	(-$3.2bn)
Upstream production (excludes Rosneft segment)	2,375mboe/d	Gulf of Mexico oil spill payments (post-tax)	$1.6bn
Upstream production (excludes Rosneft segment)	(-9.9%)	Gulf of Mexico oil spill payments (post-tax)	(-$0.8bn)
Upstream unit production costs(a)	$6.39 6.39/boe	Divestment proceeds*	$5.5bn
Upstream unit production costs(a)	(-6.5%)	Divestment proceeds*	(+$3.3bn)
BP-operated Upstream plant reliability	94.0%	Gearing	31.3%
BP-operated Upstream plant reliability	(-0.4)	Gearing	(+0.2)
BP-operated refining availability*	96.0%	Dividend per ordinary share(b)	5.25 cents
BP-operated refining availability*	(+1.1)	Dividend per ordinary share(b)	(-50.0%)
		Return on average capital employed*	(3.8)%
		Return on average capital employed*	(-12.7)

(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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Profit (loss) before interest and tax	(572)	38	614	(21,530)	4,909
Inventory holding (gains) losses*	(20)	(8)	—	(17)	8
RC profit (loss) before interest and tax	(592)	30	614	(21,547)	4,917
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	1,289	848	2,064	16,506	6,241
Underlying RC profit (loss) before interest and tax*(a)	697	878	2,678	(5,041)	11,158

(a)

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

Financial results

The replacement cost loss before interest and tax for the fourth quarter and full year was $592 million and $21,547 million respectively, compared with a profit of $614 million and $4,917 million for the same periods in 2019. The fourth quarter and full year included a net non-operating charge of $612 million and $15,768 million respectively, compared with a net charge of $2,723 million and $6,947 million for the same periods in 2019. The net non-operating charge for the quarter primarily reflects a net impairment charge and a provision for restructuring costs partly offset by disposal gains. The charge for the full year is principally related to impairments associated with revisions to long-term price assumptions. Fair value accounting effects in the fourth quarter and full year had an adverse impact of $677 million and $738 million respectively, compared with a favourable impact of $659 million and $706 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 fourth quarter and full year was a profit of $697 million and a loss of $5,041 million respectively, compared with a profit of $2,678 million and $11,158 million for the same periods in 2019. The result for the fourth quarter mainly reflects lower liquids and gas realizations, lower production including the impact of divestments, and a significantly weaker gas marketing and trading contribution, partly offset by lower depreciation, depletion and amortization. The result for the full year mainly reflects lower liquids and gas realizations and the impact of writing down certain exploration intangible carrying values.

Production

Production for the quarter was 2,155mboe/d, 20.1% lower than the fourth quarter of 2019. This includes the impact of divestments mainly in BPX Energy and Alaska. Underlying production* for the quarter decreased by 11.1% mainly due to impacts from reduced capital investment levels and decline, significant weather impacts from hurricanes in the higher-margin US Gulf of Mexico and maintenance activity.

For the full year, production was 2,375mboe/d, 9.9% lower than the full year of 2019 mainly due to the impact of divestments in BPX Energy and Alaska. Underlying production for the full year decreased by 3.5% mainly due to impacts from reduced capital investment levels and decline, and significant weather impacts from hurricanes in the US Gulf of Mexico.

Key events

On 26 October, BP announced the start of production from the Qattameya field in the North Damietta concession, located offshore Egypt (BP operator 100%).

On 29 October, BP confirmed oil discoveries at the Cappahayden and Cambriol prospects in the Flemish Pass basin, offshore Newfoundland, Canada (Equinor operator 60%, BP 40%).

On 15 November, the Trans Adriatic Pipeline (TAP), an 878-km gas transportation system crossing Greece, Albania, the Adriatic Sea and Italy, became operational (BP 20%, SOCAR 20%, Snam 20%, Fluxys 19%, Enagás 16% and Axpo 5%), with first gas exports from Azerbaijan to Europe commencing in December.

On 26 November, BP announced the start of production from the Vorlich field in the UK North Sea (BP 66%, Ithaca Energy operator 34%).

On 15 December, BP signed an agreement to sell its interest in the Wamsutter asset, located in the Greater Green River Basin, Wyoming, US, to Williams Field Services LLC. Subject to approvals, the transaction is expected to complete in first quarter 2021.

On 18 December, BP and Reliance Industries Limited (RIL) announced the start of production from the R Cluster ultra-deep-water gas field in block KG D6 off the east coast of India. (RIL operator 66.67%, BP 33.33%).

On 1 February 2021, BP announced it has agreed to sell a 20% participating interest in Oman’s Block 61 to PTT Exploration and Production Public Company Limited (PTTEP). Subject to approvals, the transaction is expected to complete in 2021 and following which the participating interests in Block 61 will be: BP operator 40%, OQ 30%, PTTEP 20%, and PETRONAS 10%.

Outlook

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

We expect first-quarter 2021 reported production to be slightly higher than fourth-quarter 2020.

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)

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Underlying RC profit (loss) before interest and tax
US	(100)	125	645	(2,396)	2,670
Non-US	797	753	2,033	(2,645)	8,488
	697	878	2,678	(5,041)	11,158
Non-operating items(a)(b)
US	(101)	(114)	(2,451)	(2,969)	(6,265)
Non-US	(511)	(517)	(272)	(12,799)	(682)
	(612)	(631)	(2,723)	(15,768)	(6,947)
Fair value accounting effects
US	104	57	120	198	(179)
Non-US	(781)	(274)	539	(936)	885
	(677)	(217)	659	(738)	706
RC profit (loss) before interest and tax
US	(97)	68	(1,686)	(5,167)	(3,774)
Non-US	(495)	(38)	2,300	(16,380)	8,691
	(592)	30	614	(21,547)	4,917
Exploration expense
US	104	40	86	2,724	233
Non-US	110	150	180	7,556	731
	214	190	266	10,280	964
Of which: Exploration expenditure written off(b)	154	50	155	9,920	631
Production (net of royalties)(c)(d)
Liquids* (mb/d)
US	359	363	517	424	482
Europe	160	143	149	154	141
Rest of World	600	623	662	651	666
	1,119	1,129	1,328	1,229	1,288
Natural gas (mmcf/d)
US	1,232	1,419	2,317	1,561	2,358
Europe	320	265	275	282	185
Rest of World	4,459	4,774	5,354	4,800	5,279
	6,011	6,457	7,945	6,643	7,823
Total hydrocarbons* (mboe/d)
US	571	608	916	694	888
Europe	215	188	196	202	173
Rest of World	1,369	1,446	1,585	1,479	1,576
	2,155	2,243	2,698	2,375	2,637
Average realizations*(e)
Total liquids(f) ($/bbl)	38.42	38.17	55.90	36.16	57.73
Natural gas ($/mcf)	3.10	2.56	3.12	2.75	3.39
Total hydrocarbons ($/boe)	28.48	26.42	36.42	26.31	38.00

(a)

Full year 2020 principally relates to impairments in a number of our businesses resulting from the revisions to BP’s long-term price assumptions. Full year 2020 also includes impairment charges related to the disposal of our Alaska business. Fourth quarter and full year 2019 include impairment charges related to the disposal of heritage BPX Energy assets, Alaska and GUPCO divestment. See Note 3 for further information.

(b)

Full year 2020 includes the write-off of $1,974 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 and the impairment of certain intangible assets in Mauritania and Senegal. This has been classified within the ‘other’ category of non-operating items. See Note 4 for further information.

(c)

Includes BP’s share of production of equity-accounted entities in the Upstream segment.

(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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Profit before interest and tax	1,895	1,106	1,412	622	7,187
Inventory holding (gains) losses*	(650)	(191)	21	2,796	(685)
RC profit before interest and tax	1,245	915	1,433	3,418	6,502
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(1,119)	(279)	5	(330)	(83)
Underlying RC profit before interest and tax*(a)	126	636	1,438	3,088	6,419

(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 fourth quarter and full year was $1,245 million and $3,418 million respectively, compared with $1,433 million and $6,502 million for the same periods in 2019.

The fourth quarter and full year include a net non-operating gain of $1,403 million and $479 million respectively, compared with a charge of $28 million and $77 million for the same periods in 2019. The gain for the quarter and full year reflects a profit of $2.3 billion on the sale of our petrochemicals business, which is partially offset by restructuring costs and impairments. Fair value accounting effects in the fourth quarter and full year had an adverse impact of $284 million and $149 million respectively, compared with a favourable impact of $23 million and $160 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 fourth quarter and full year was $126 million and $3,088 million respectively, compared with $1,438 million and $6,419 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 loss before interest and tax of $169 million for the fourth quarter and a profit of $2,037 million for the full year, compared with a profit of $1,068 million and $4,759 million for the same periods in 2019.

The result for the quarter and full year reflected an exceptionally weak refining environment, with COVID-19 restrictions impacting refining utilization and fuel volumes. The result for the full year also reflected a higher contribution from supply and trading.

Fuels marketing demonstrated continued resilience, delivering significant profit for the quarter and full year, despite COVID-19 which adversely impacted retail fuel and aviation volumes by 14% and 50% respectively for the full year.

The refining loss for the quarter and full year reflects the continued impact of historically low industry margins. For the full year, although availability was strong at 96%, utilization was around 6% lower than 2019 due to the impact of COVID-19 on demand. These factors were partially offset by a lower level of turnaround activity and lower costs. The result for the quarter was also impacted by narrower heavy crude oil discounts compared with the same period in 2019.

In the quarter we announced our plans to cease production at our Kwinana refinery and convert it to an import terminal, helping to secure ongoing fuel supply for Western Australia.

During the year we continued to progress our agenda to redefine convenience, delivering a 6% growth in convenience gross margin* for the full year, and we expanded our retail network by over 1,400 sites, to a total of 20,300, which now includes more than 1,900 strategic convenience sites.

We also progressed our electrification agenda, growing our network to more than 10,000 BP and joint venture operated EV charging points. This included rolling out ultra-fast chargers at retail sites in the UK and Germany, and the continued expansion of our electrification joint venture with DiDi in China.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $262 million for the fourth quarter and $818 million for the full year, compared with $333 million and $1,258 million for the same periods in 2019. The result for the quarter and full year reflects significant demand impacts, with volumes lower than the prior quarter and 15% lower for the full year. In the second half of the year we have seen volumes in growth markets recover to 2019 levels as COVID-19 restrictions eased during that period.

In 2020 we continued to expand our service offer, growing the number of Castrol branded independent workshops by more than 4,000 to over 28,000 globally. We also continued to establish strong partnerships with OEMs, with BMW selecting Castrol to be its exclusive supplier of lubricants to all BMW and MINI authorized dealers across the US, Canada and Mexico.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $33 million for the fourth quarter and $233 million for the full year, compared with $37 million and $402 million for the same periods in 2019. The result for the full year reflects the impact of COVID-19 on demand, and a significantly weaker margin environment.

In December we completed the divestment of BP’s petrochemicals business to INEOS for a total consideration of $5 billion. Final payments, totalling $1 billion are expected to be received in the first half of 2021.

Outlook

Looking to the first quarter of 2021, we expect industry refining margins and utilization to remain under pressure. In our marketing businesses we expect renewed COVID-19 restrictions to have a greater impact on product demand, with January retail volumes down by around 20% year on year, compared with a decline of 11% in the fourth 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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Downstream (continued)

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Underlying RC profit before interest and tax - by region
US	(231)	96	556	1,141	2,190
Non-US	357	540	882	1,947	4,229
	126	636	1,438	3,088	6,419
Non-operating items
US	890	(27)	(40)	800	(42)
Non-US	513	(119)	12	(321)	(35)
	1,403	(146)	(28)	479	(77)
Fair value accounting effects(a)
US	(125)	78	(37)	27	148
Non-US	(159)	347	60	(176)	12
	(284)	425	23	(149)	160
RC profit before interest and tax
US	534	147	479	1,968	2,296
Non-US	711	768	954	1,450	4,206
	1,245	915	1,433	3,418	6,502
Underlying RC profit before interest and tax - by business(b)(c)
Fuels	(169)	222	1,068	2,037	4,759
Lubricants	262	326	333	818	1,258
Petrochemicals	33	88	37	233	402
	126	636	1,438	3,088	6,419
Non-operating items and fair value accounting effects(a)
Fuels	(1,037)	288	(41)	(1,754)	32
Lubricants	(121)	(7)	39	(179)	57
Petrochemicals	2,277	(2)	(3)	2,263	(6)
	1,119	279	(5)	330	83
RC profit before interest and tax(b)(c)
Fuels	(1,206)	510	1,027	283	4,791
Lubricants	141	319	372	639	1,315
Petrochemicals	2,310	86	34	2,496	396
	1,245	915	1,433	3,418	6,502

BP average refining marker margin (RMM)* ($/bbl)	5.9	6.2	12.4	6.7	13.2

Refinery throughputs (mb/d)
US	708	701	761	693	737
Europe	720	699	848	742	787
Rest of World	200	187	238	192	225
	1,628	1,587	1,847	1,627	1,749
BP-operated refining availability* (%)	96.1	96.2	95.7	96.0	94.9

Marketing sales of refined products (mb/d)
US	1,055	1,083	1,156	1,011	1,145
Europe	801	849	1,051	823	1,073
Rest of World	457	422	537	441	509
	2,313	2,354	2,744	2,275	2,727
Trading/supply sales of refined products	2,942	2,618	3,519	3,026	3,268
Total sales volumes of refined products	5,255	4,972	6,263	5,301	5,995

Petrochemicals production (kte)
US	640	541	518	2,201	2,267
Europe	1,241	1,325	1,141	5,183	4,714
Rest of World	1,261	1,211	1,353	4,896	5,133
	3,142	3,077	3,012	12,280	12,114

(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.

(c)

Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany are reported in the fuels business.

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Rosneft

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020(a)	2020	2019	2020(a)	2019
Profit (loss) before interest and tax(b)(c)	295	(244)	534	(238)	2,306
Inventory holding (gains) losses*	(25)	(34)	(31)	89	10
RC profit (loss) before interest and tax	270	(278)	503	(149)	2,316
Net charge (credit) for non-operating items*	41	101	(91)	205	103
Underlying RC profit (loss) before interest and tax*	311	(177)	412	56	2,419

Financial results

Replacement cost (RC) profit before interest and tax for the fourth quarter was $270 million and RC loss for the full year was $149 million, compared with a profit of $503 million and $2,316 million for the same periods in 2019.

After adjusting for non-operating items, the underlying RC profit before interest and tax for the fourth quarter and full year was $311 million and $56 million respectively, compared with a profit of $412 million and $2,419 million for the same periods in 2019.

Compared with the same period in 2019, the result for the fourth quarter primarily reflects lower oil prices partially offset by favourable foreign exchange effects. Compared with the same period in 2019, the result for the full year primarily reflects lower oil prices, unfavourable foreign exchange and adverse duty lag effects.

Key events

On 28 December, Rosneft announced completion of the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10% interest in LLC Vostok Oil.

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
	2020(a)	2020	2019	2020(a)	2019
Production (net of royalties) (BP share)
Liquids* (mb/d)	876	858	923	877	923
Natural gas (mmcf/d)	1,360	1,260	1,306	1,286	1,279
Total hydrocarbons* (mboe/d)	1,111	1,075	1,148	1,098	1,144

(a)

The operational and financial information of the Rosneft segment for the fourth quarter and full year is based on preliminary operational and financial results of Rosneft for the three months and full year ended 31 December 2020. Actual results may differ from these amounts. Amounts reported for the fourth quarter are based on BP’s 22.01% average economic interest for the quarter (third quarter 2020 21.96% and fourth quarter 2019 19.75%). A preliminary assessment of the fair values of the assets and liabilities acquired and the consideration transferred in respect of the acquisitions announced by Rosneft on 28 December is being undertaken and the impact, if any, on BP’s accounting for its equity-accounted investment in Rosneft will be updated once this has been completed.

(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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Profit (loss) before interest and tax	308	24	(1,432)	(683)	(2,771)
Inventory holding (gains) losses*	—	—	—	—	—
RC profit (loss) before interest and tax	308	24	(1,432)	(683)	(2,771)
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(397)	(154)	1,182	(357)	1,491
Underlying RC profit (loss) before interest and tax*	(89)	(130)	(250)	(1,040)	(1,280)
Underlying RC profit (loss) before interest and tax
US	(135)	(65)	(85)	(453)	(713)
Non-US	46	(65)	(165)	(587)	(567)
	(89)	(130)	(250)	(1,040)	(1,280)
Non-operating items
US	(303)	(62)	(268)	(475)	(559)
Non-US	250	(50)	(914)	157	(932)
	(53)	(112)	(1,182)	(318)	(1,491)
Fair value accounting effects
US	—	—	—	—	—
Non-US	450	266	—	675	—
	450	266	—	675	—
RC profit (loss) before interest and tax
US	(438)	(127)	(353)	(928)	(1,272)
Non-US	746	151	(1,079)	245	(1,499)
	308	24	(1,432)	(683)	(2,771)

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 fourth quarter and full year was a profit of $308 million and a loss of $683 million respectively, compared with a loss of $1,432 million and $2,771 million for the same periods in 2019.

The results include a net non-operating charge of $53 million for the fourth quarter and $318 million for the full year, compared with a charge of $1,182 million and $1,491 million for the same periods in 2019. Fair value accounting effects in the fourth quarter and full year had a favourable impact of $450 million and $675 million respectively. 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 fourth quarter and full year was $89 million and $1,040 million respectively, compared with $250 million and $1,280 million for the same periods in 2019. The results include an uplift in valuation of a venture investment of $229 million for the fourth quarter and $284 million for the full year.

Alternative Energy

BP's net ethanol-equivalent production* for the fourth quarter and full year averaged 14.9kb/d and 20.3kb/d respectively, compared with 11.6kb/d and 13.7kb/d for the 100% BP-owned business for the same periods in 2019.

Net wind generation capacity* was 1,071MW at 31 December 2020, compared with 926MW at 31 December 2019. BP’s net share of wind generation for the fourth quarter and full year was 902GWh and 2,806GWh respectively, compared with 785GWh and 2,752GWh for the same periods in 2019.

In December Lightsource BP developed to FID the 163MW Elm Branch and 153MW Briar Creek projects in the US, 50MW South Lowfield and 21MW Thornham projects in the UK, taking their overall total capacity developed to FID to 1,403MW for the full year.

In January 2021 BP and Equinor formed a strategic partnership to initially develop four projects in two existing leases located offshore New York and Massachusetts which together are expected to have a total generating capacity of 4.4GW. Early in January Empire Wind 2 and Beacon Wind 1 projects were selected to provide New York State with an additional 2.5GW of power and subject to negotiation of a purchase and sale agreement will take total secured power offtake agreements on the projects to 3.3GW which represents a material de-risking of the overall project. Beyond these initial projects, the strategic partnership expects to participate in future offshore wind developments in the US.

In December, BP finalized its investment in India’s Green Growth Equity Fund (GGEF) with an initial investment of $30 million and a total commitment of $70 million to the fund. The fund itself was established in 2018 and is focused on identifying, investing in and supporting growth in clean energy projects in India and is managed by Lightsource BP and Everstone Capital.

We continue to progress our aim to build material renewable energy businesses by having developed 20GW of net renewable generating capacity to FID by 2025. Overall we have developed a total of 3.3GW of net renewable generating capacity to FID by 31 December 2020 across our businesses and are progressing a development pipeline with projects across nine countries totalling 11GW net BP. In addition our development teams are further evaluating potential options totalling over 20GW.

Outlook

Other businesses and corporate charges for 2021, excluding non-operating items, fair value accounting effects and foreign exchange volatility impact, are expected to be $1.2-1.4 billion although the quarterly charge may vary 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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019

Sales and other operating revenues (Note 6)	44,789	44,251	71,109	180,366	278,397
Earnings from joint ventures – after interest and tax	214	73	163	(302)	576
Earnings from associates – after interest and tax	575	(332)	640	(101)	2,681
Interest and other income	233	183	210	663	769
Gains on sale of businesses and fixed assets	2,757	27	48	2,874	193
Total revenues and other income	48,568	44,202	72,170	183,500	282,616
Purchases	32,803	31,645	53,444	132,104	209,672
Production and manufacturing expenses	6,111	5,073	5,809	22,494	21,815
Production and similar taxes (Note 8)	228	140	412	695	1,547
Depreciation, depletion and amortization (Note 7)	3,426	3,467	4,434	14,889	17,780
Impairment and losses on sale of businesses and fixed assets (Note 3)	1,168	294	3,657	14,381	8,075
Exploration expense (Note 4)	214	190	266	10,280	964
Distribution and administration expenses	2,769	2,435	2,996	10,397	11,057
Profit (loss) before interest and taxation	1,849	958	1,152	(21,740)	11,706
Finance costs	749	800	886	3,115	3,489
Net finance expense relating to pensions and other post-retirement benefits	10	8	17	33	63
Profit (loss) before taxation	1,090	150	249	(24,888)	8,154
Taxation	(395)	457	231	(4,159)	3,964
Profit (loss) for the period	1,485	(307)	18	(20,729)	4,190
Attributable to
BP shareholders	1,358	(450)	19	(20,305)	4,026
Non-controlling interests	127	143	(1)	(424)	164
	1,485	(307)	18	(20,729)	4,190

Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	6.71	(2.22)	0.09	(100.42)	19.84
Diluted	6.68	(2.22)	0.09	(100.42)	19.73
Per ADS (dollars)
Basic	0.40	(0.13)	0.01	(6.03)	1.19
Diluted	0.40	(0.13)	0.01	(6.03)	1.18

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Condensed group statement of comprehensive income

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019

Profit (loss) for the period	1,485	(307)	18	(20,729)	4,190
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	1,594	(166)	1,404	(1,843)	1,538
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	(357)	—	880	(353)	880
Cash flow hedges and costs of hedging	42	(90)	(76)	105	59
Share of items relating to equity-accounted entities, net of tax	(105)	308	43	312	82
Income tax relating to items that may be reclassified	2	(16)	(39)	66	(70)
	1,176	36	2,212	(1,713)	2,489
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset(a)	333	78	1,480	170	328
Cash flow hedges that will subsequently be transferred to the balance sheet	9	8	6	7	(3)
Income tax relating to items that will not be reclassified	(89)	(16)	(459)	(105)	(157)
	253	70	1,027	72	168
Other comprehensive income	1,429	106	3,239	(1,641)	2,657
Total comprehensive income	2,914	(201)	3,257	(22,370)	6,847
Attributable to
BP shareholders	2,740	(364)	3,240	(21,983)	6,674
Non-controlling interests	174	163	17	(387)	173
	2,914	(201)	3,257	(22,370)	6,847

(a)

See Note 1 - Pensions and other post retirement benefits 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	(21,983)	256	(643)	(22,370)
Dividends	(6,367)	—	(238)	(6,605)
Cash flow hedges transferred to the balance sheet, net of tax	6	—	—	6
Repurchase of ordinary share capital	(776)	—	—	(776)
Share-based payments, net of tax	726	—	—	726
Share of equity-accounted entities’ changes in equity, net of tax(a)	1,341	—	—	1,341
Issue of perpetual hybrid bonds	(48)	11,909	—	11,861
Payments on perpetual hybrid bonds	—	(89)	—	(89)
Tax on issue of perpetual hybrid bonds	3	—	—	3
Transactions involving non-controlling interests, net of tax	(64)	—	827	763
At 31 December 2020	71,250	12,076	2,242	85,568

	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(b)	(329)	—	(1)	(330)
At 1 January 2019	99,115	—	2,103	101,218

Total comprehensive income	6,674	—	173	6,847
Dividends	(6,929)	—	(213)	(7,142)
Cash flow hedges transferred to the balance sheet, net of tax	23	—	—	23
Repurchase of ordinary share capital	(1,511)	—	—	(1,511)
Share-based payments, net of tax	719	—	—	719
Share of equity-accounted entities’ changes in equity, net of tax	5	—	—	5
Transactions involving non-controlling interests, net of tax	316		233	549
At 31 December 2019	98,412	—	2,296	100,708

(a) Principally relates to a non-controlling interest transaction entered into by Rosneft.

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

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Group balance sheet

	31 December	31 December
$ million	2020	2019
Non-current assets
Property, plant and equipment	114,836	132,642
Goodwill	12,480	11,868
Intangible assets	6,093	15,539
Investments in joint ventures	8,362	9,991
Investments in associates	18,975	20,334
Other investments	2,746	1,276
Fixed assets	163,492	191,650
Loans	840	630
Trade and other receivables	4,351	2,147
Derivative financial instruments	9,755	6,314
Prepayments	533	781
Deferred tax assets	7,744	4,560
Defined benefit pension plan surpluses	7,957	7,053
	194,672	213,135
Current assets
Loans	458	339
Inventories	16,873	20,880
Trade and other receivables	17,948	24,442
Derivative financial instruments	2,992	4,153
Prepayments	1,269	857
Current tax receivable	672	1,282
Other investments	333	169
Cash and cash equivalents	31,111	22,472
	71,656	74,594
Assets classified as held for sale (Note 2)	1,326	7,465
	72,982	82,059
Total assets	267,654	295,194
Current liabilities
Trade and other payables	36,014	46,829
Derivative financial instruments	2,998	3,261
Accruals	4,650	5,066
Lease liabilities	1,933	2,067
Finance debt	9,359	10,487
Current tax payable	1,038	2,039
Provisions	3,761	2,453
	59,753	72,202
Liabilities directly associated with assets classified as held for sale (Note 2)	46	1,393
	59,799	73,595
Non-current liabilities
Other payables	12,112	12,626
Derivative financial instruments	5,404	5,537
Accruals	852	996
Lease liabilities	7,329	7,655
Finance debt	63,305	57,237
Deferred tax liabilities	6,831	9,750
Provisions	17,200	18,498
Defined benefit pension plan and other post-retirement benefit plan deficits	9,254	8,592
	122,287	120,891
Total liabilities	182,086	194,486
Net assets	85,568	100,708
Equity
BP shareholders’ equity	71,250	98,412
Non-controlling interests	14,318	2,296
Total equity	85,568	100,708

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Condensed group cash flow statement

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Operating activities
Profit (loss) before taxation	1,090	150	249	(24,888)	8,154
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	3,580	3,517	4,589	24,809	18,411
Impairment and (gain) loss on sale of businesses and fixed assets	(1,589)	267	3,609	11,507	7,882
Earnings from equity-accounted entities, less dividends received	(538)	1,018	(75)	1,845	(1,295)
Net charge for interest and other finance expense, less net interest paid	22	60	250	236	657
Share-based payments	179	199	167	723	730
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(182)	(46)	(43)	(282)	(238)
Net charge for provisions, less payments	866	293	270	735	(176)
Movements in inventories and other current and non-current assets and liabilities	(715)	556	(306)	(85)	(2,918)
Income taxes paid	(444)	(810)	(1,107)	(2,438)	(5,437)
Net cash provided by operating activities	2,269	5,204	7,603	12,162	25,770
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(2,922)	(2,577)	(3,936)	(12,306)	(15,418)
Acquisitions, net of cash acquired	(17)	(10)	(33)	(44)	(3,562)
Investment in joint ventures	(529)	(12)	(57)	(567)	(137)
Investment in associates	(23)	(1,037)	(83)	(1,138)	(304)
Total cash capital expenditure	(3,491)	(3,636)	(4,109)	(14,055)	(19,421)
Proceeds from disposal of fixed assets	439	32	24	491	500
Proceeds from disposal of businesses, net of cash disposed	3,564	84	792	4,989	1,701
Proceeds from loan repayments	61	50	64	717	246
Net cash used in investing activities	573	(3,470)	(3,229)	(7,858)	(16,974)
Financing activities
Net issue (repurchase) of shares (Note 9)	—	—	(1,171)	(776)	(1,511)
Lease liability payments	(631)	(578)	(566)	(2,442)	(2,372)
Proceeds from long-term financing	2,619	2,587	1,879	14,736	8,597
Repayments of long-term financing	(3,191)	(4,307)	(360)	(12,179)	(7,118)
Net increase (decrease) in short-term debt	(906)	(2,630)	62	(1,234)	180
Issue of perpetual hybrid bonds	—	—	—	11,861	—
Payments on perpetual hybrid bonds	(62)	(27)	—	(89)	—
Payments relating to transactions involving non-controlling interests (other)	—	—	—	(8)	—
Receipts relating to transactions involving non-controlling interests (other)	173	483	566	665	566
Dividends paid - BP shareholders	(1,059)	(1,060)	(2,076)	(6,340)	(6,946)
- non-controlling interests	(75)	(58)	(47)	(238)	(213)
Net cash provided by (used in) financing activities	(3,132)	(5,590)	(1,713)	3,956	(8,817)
Currency translation differences relating to cash and cash equivalents	336	268	119	379	25
Increase (decrease) in cash and cash equivalents	46	(3,588)	2,780	8,639	4
Cash and cash equivalents at beginning of period	31,065	34,653	19,692	22,472	22,468
Cash and cash equivalents at end of period(a)	31,111	31,065	22,472	31,111	22,472

(a)

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

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Notes

Note 1. Basis of preparation

The 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 annual financial statements. 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 performed to support this assertion. Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the balance sheet date even if the Brent price fell to zero.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the 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 financial information.

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

BP's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 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 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 expects 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. A summary of the group’s revised price assumptions, in real 2020 terms, is provided below:

	2021	2025	2030	2040	2050
Brent oil ($/bbl)	50	50	60	60	50
Henry Hub gas ($/mmBtu)	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 Upstream 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 29% and 17%, 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 2021 to 2050, than the prices referenced in BP Annual Report and Form 20-F 2019 - Note 1.

The group has identified Upstream oil and gas properties with carrying amounts totalling approximately $45 billion where the headroom, based on the most recent impairment tests performed, was less than or equal to 20% of the carrying value. A change in price or other assumptions within the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a significant risk of impairment reversals or charges in that period.

The discount rates used in value-in-use impairment testing were also formally reassessed in the fourth quarter. Despite changing economic and geopolitical outlooks, as the discount rates are set using a number of parameters that are applicable to longer-term assets, the post-tax discount rate, as disclosed in BP Annual Report and Form 20-F 2019, remains unchanged. Pre-tax discount rates typically ranged from 7% to 15% (2019 7% to 13%). Post-tax premiums for certain higher-risk countries are 1% to 3% (2019 1% to 4%). The revisions to these rates did not have a material impact.

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 were reviewed during the fourth quarter and did not change significantly compared to the provisions balance reported as at 31 December 2019.

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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 fourth quarter of 2020, the group's total net defined benefit pension plan deficit as at 31 December 2020 is $1.3 billion, a reduction in the deficit of $0.6 billion and $0.2 billion from 30 September 2020 and 31 December 2019 respectively. This reduction in deficit and the overall actuarial gains of $0.3 billion during 4Q were predominantly driven by the adoption of approved assumption changes. The impact of further decreases in the UK, US and Eurozone discount rates were largely offset by asset performance and reduction in inflation rates. 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 31 December 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 31 December 2020 of $7.7 billion, an increase of $3.1 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 specifically arising from the impact of COVID-19.

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 arises, 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 have been endorsed by the EU and the UK. BP has 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 routinely 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 restated.

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, therefore no comparative information has been restated.

In addition, BP chose to change its presentation of revenues from physically settled derivative sales contracts from 1 January 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.

Voluntary changes to significant accounting policies - not yet adopted

Net presentation of revenues and purchases relating to physically settled derivative contracts from 1 January 2021

As described above, BP routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group has presented revenues and purchases for such contracts on a gross basis in the income statement upon physical settlement. These transactions have historically represented a substantial portion of the revenues and purchases reported in the group’s financial statements.

The group has determined that revenues and purchases relating to such transactions should, in future, be presented as a net gain or loss within other operating revenues. This will provide reliable and more relevant information for users of the accounts as the group’s revenue recognition will be more closely aligned with its assessment of ‘Scope 3’ emissions from its products, its ‘Net Zero’ ambition and how management monitors and manages performance of such contracts. In the group’s 2021 financial statements, comparative information for Sales and other operating revenues and Purchases in the consolidated income statements for 2019 and 2020 will be restated.

Change in segmentation for 2021 financial reporting

The group's reportable segments are expected to change for 2021 financial reporting consistent with a change in the way that resources will be allocated and performance assessed by the chief operating decision maker, who for BP is the chief executive officer. The group's reportable segments are expected to be Customers and products, Gas and low carbon energy, Oil production and operations and Rosneft. These are also expected to be the group's operating segments. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.

Customers and products is expected to comprise the group's convenience and mobility business, which manages the sale of fuels to wholesale and retail customers, convenience products, aviation fuels, and Castrol lubricants; and refining, supply and trading. The petrochemicals business will also be reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers and products segment is expected, therefore, to be substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal.

Gas and low carbon energy is expected to comprise regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group's renewables businesses, including biofuels, solar and wind. In the group's financial reporting for 2020, gas producing regions are part of the Upstream segment and the group's renewables businesses are part of 'Other businesses and corporate'.

Oil production and operations is expected to comprise regions with upstream activities that predominantly produce crude oil. In the group's financial reporting for 2020, these activities are part of the Upstream segment.

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Note 1. Basis of preparation (continued)

The Rosneft segment is expected to continue to include equity-accounted earnings from the group's investment in Rosneft.

Segmental information presented in these financial statements is based on the segment structure as at 31 December 2020.

In the group's financial reporting for 2021, comparative information for 2019 and 2020 will be restated to reflect the changes in reportable segments. It is expected that reporting under the new segment structure will begin with the first quarter 2021 interim financial statements.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 31 December 2020 is $1,326 million, with associated liabilities of $46 million.

The balance consists primarily of a 20% participating interest from BP’s 60% participating interest in Block 61 in Oman. As announced on 1 February 2021, BP has agreed to sell this interest to PTT Exploration and Production Public Company Limited of Thailand for a total consideration of up to $2.6 billion, subject to final adjustments. Under the terms of the agreement, BP will receive $2,450 million on completion, with up to an additional $140 million receivable contingent on pre-agreed future conditions. Subject to approvals, the transaction is expected to complete during 2021. Assets of $1,298 million and associated liabilities of $10 million have been classified as held for sale in the group balance sheet at 31 December 2020.

Transactions that have been classified as held for sale during 2020, but have now completed, are described below.

Upstream segment

On 27 August 2019, BP announced that it had agreed to sell its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to customary closing adjustments. The sale included BP’s upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owned BP’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS). These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The disposal of BP Exploration (Alaska) Inc. completed on 30 June 2020. The disposal of BP's interest in TAPS and other midstream assets completed on 18 December 2020. BP retained the decommissioning liability relating to its interest in TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp.

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. The assets and liabilities of the business were classified as held for sale from that date until the disposal completed on 31 December 2020. Under the terms of the agreement, INEOS paid BP a deposit of $400 million and a further $3.6 billion on completion, less $0.1 billion of third-party indebtedness remaining in petrochemicals on completion. The remaining $1 billion is payable in instalments of $100 million in each of March, April and May 2021, and $700 million by the end of June 2021 at the latest. The business had interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. A gain on disposal of $2,270 million was recognised in the fourth quarter 2020, which included a $340 million gain relating to the reclassification of accumulated foreign exchange from reserves.

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

Impairment and losses on sale of businesses and fixed assets for the fourth quarter and full year 2020 were $1,168 million and $14,381 million and include net impairment charges of $777 million and $13,700 million respectively. Impairment charges also arose in certain equity-accounted entities in the full year. The BP shares of these charges, amounting to $847 million for the full year, 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 $674 million and $12,831 million for the fourth quarter and full year respectively.

Impairment charges for the full year 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, 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 full year also include amounts relating to the disposal of the group’s interests in its Alaska business.

The BP share of impairment charges arising in equity-accounted entities reported in the Upstream segment in the full year was $545 million.

Downstream segment

Net impairment charges in the Downstream segment were $104 million and $840 million for the fourth quarter and full year respectively. These principally relate to portfolio changes in the fuels business, including the conversion of Kwinana refinery to an import terminal.

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Note 4. Exploration expense

Exploration expense in the fourth quarter and full year was $214 million and $10,280 million and includes exploration expenditure write-offs of $154 million and $9,920 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 full year principally arose in Angola, Brazil, Canada, Egypt, the Gulf of Mexico and India.

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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Upstream	(592)	30	614	(21,547)	4,917
Downstream	1,245	915	1,433	3,418	6,502
Rosneft	270	(278)	503	(149)	2,316
Other businesses and corporate	308	24	(1,432)	(683)	(2,771)
	1,231	691	1,118	(18,961)	10,964
Consolidation adjustment – UPII*	(77)	34	24	89	75
RC profit (loss) before interest and tax*	1,154	725	1,142	(18,872)	11,039
Inventory holding gains (losses)*
Upstream	20	8	—	17	(8)
Downstream	650	191	(21)	(2,796)	685
Rosneft (net of tax)	25	34	31	(89)	(10)
Profit (loss) before interest and tax	1,849	958	1,152	(21,740)	11,706
Finance costs	749	800	886	3,115	3,489
Net finance expense relating to pensions and other post-retirement benefits	10	8	17	33	63
Profit (loss) before taxation	1,090	150	249	(24,888)	8,154

RC profit (loss) before interest and tax*
US	(21)	105	(1,603)	(4,016)	(2,759)
Non-US	1,175	620	2,745	(14,856)	13,798
	1,154	725	1,142	(18,872)	11,039

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Note 6. Sales and other operating revenues

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
By segment
Upstream	7,742	7,797	13,955	34,197	54,501
Downstream	41,513	40,256	64,251	162,974	250,897
Other businesses and corporate	422	391	538	1,716	1,788
	49,677	48,444	78,744	198,887	307,186

Less: sales and other operating revenues between segments
Upstream	3,963	3,647	6,823	17,130	27,034
Downstream	486	124	384	158	973
Other businesses and corporate	439	422	428	1,233	782
	4,888	4,193	7,635	18,521	28,789

Third party sales and other operating revenues
Upstream	3,779	4,150	7,132	17,067	27,467
Downstream	41,027	40,132	63,867	162,816	249,924
Other businesses and corporate	(17)	(31)	110	483	1,006
Total sales and other operating revenues	44,789	44,251	71,109	180,366	278,397

By geographical area
US	15,980	16,513	24,148	63,829	95,495
Non-US	33,886	32,328	54,450	134,945	208,031
	49,866	48,841	78,598	198,774	303,526
Less: sales and other operating revenues between areas	5,077	4,590	7,489	18,408	25,129
	44,789	44,251	71,109	180,366	278,397

Revenues from contracts with customers(a)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	1,185	1,366	1,880	5,048	9,141
Oil products(b)	16,216	16,642	25,946	63,564	102,408
Natural gas, LNG and NGLs	3,252	2,844	4,871	12,726	18,909
Non-oil products and other revenues from contracts with customers(b)	2,608	2,624	2,878	9,840	12,169
Revenue from contracts with customers	23,261	23,476	35,575	91,178	142,627
Other operating revenues(c)	21,528	20,775	35,534	89,188	135,770
Total sales and other operating revenues	44,789	44,251	71,109	180,366	278,397

(a)

Amounts shown for revenue from contracts with customers and other operating revenues for fourth quarter and full year 2019 have been represented to align with the current period. See Note 1 Change in accounting policy - physically settled derivative contracts for further information.

(b) An amendment of $341 million has been made to amounts presented for oil products and non-oil products and other revenues from contracts with customers for the third quarter 2020 with no overall effect on revenue from contracts with customers.

(c)

Principally relates to physically settled derivative sales contracts.

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Note 7. Depreciation, depletion and amortization

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Upstream
US	818	842	1,150	3,772	4,672
Non-US	1,679	1,713	2,371	7,447	9,560
	2,497	2,555	3,521	11,219	14,232
Downstream
US	337	336	343	1,359	1,335
Non-US	411	407	417	1,631	1,586
	748	743	760	2,990	2,921
Other businesses and corporate
US	19	13	14	63	55
Non-US	162	156	139	617	572
	181	169	153	680	627
Total group	3,426	3,467	4,434	14,889	17,780

Note 8. Production and similar taxes

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
US	17	14	89	57	315
Non-US	211	126	323	638	1,232
	228	140	412	695	1,547

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 full year, 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)

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Results for the period
Profit (loss) for the period attributable to BP shareholders	1,358	(450)	19	(20,305)	4,026
Less: preference dividend	—	—	—	1	1
Profit (loss) attributable to BP ordinary shareholders	1,358	(450)	19	(20,306)	4,025

Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding	20,233,240	20,251,199	20,254,234	20,221,514	20,284,859
ADS equivalent	3,372,206	3,375,199	3,375,705	3,370,252	3,380,809

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,329,326	20,251,199	20,351,808	20,221,514	20,399,670
ADS equivalent	3,388,221	3,375,199	3,391,968	3,370,252	3,399,945

Shares in issue at period-end	20,264,027	20,254,417	20,241,170	20,264,027	20,241,170
ADS equivalent	3,377,337	3,375,736	3,373,528	3,377,337	3,373,528

(a)

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

(b)

If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the third quarter 2020 and full year 2020 are 81,097 thousand (ADS equivalent 13,516 thousand) and 101,450 thousand (ADS equivalent 16,908 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 26 March 2021 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 19 February 2021. The ex-dividend date will be 18 February 2021. The corresponding amount in sterling is due to be announced on 15 March 2021, calculated based on the average of the market exchange rates for the four dealing days commencing on 9 March 2021. 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 fourth 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 fourth quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
	2020	2020	2019	2020	2019
Dividends paid per ordinary share
cents	5.250	5.250	10.250	31.500	41.000
pence	3.917	4.043	7.825	24.458	31.977
Dividends paid per ADS (cents)	31.50	31.50	61.50	189.00	246.00
Scrip dividends
Number of shares issued (millions)	—	—	—	—	208.9
Value of shares issued ($ million)	—	—	—	—	1,387

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Note 11. Net debt

Net debt*	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Finance debt(a)(b)	72,664	72,828	67,724	72,664	67,724
Fair value (asset) liability of hedges related to finance debt(c)	(2,612)	(1,384)	190	(2,612)	190
	70,052	71,444	67,914	70,052	67,914
Less: cash and cash equivalents(b)	31,111	31,065	22,472	31,111	22,472
Net debt	38,941	40,379	45,442	38,941	45,442
Total equity	85,568	82,155	100,708	85,568	100,708
Gearing*	31.3%	33.0%	31.1%	31.3%	31.1%

(a)

The fair value of finance debt at 31 December 2020 was $76,092 million (31 December 2019 $69,376 million).

(b)

Third quarter 2020 includes $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 $236 million (third quarter 2020 liability of $372 million and fourth quarter 2019 liability of $601 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

As part of actively managing its debt portfolio, on 18 December 2020 BP exercised its option to redeem finance debt with an outstanding aggregate principal amount of $2.0 billion on 22 January 2021. In addition, in the third quarter, the group bought back $4.0 billion equivalent of euro and sterling bonds and terminated derivatives associated with the debt bought back. These transactions have no significant impact on net debt or gearing.

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 $216 million was held against hydrocarbon inventories at 31 December 2020 ($544 million at 30 September 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 1 February 2021, 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*

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Capital expenditure on a cash basis
Organic capital expenditure*	2,949	2,512	3,958	12,034	15,238
Inorganic capital expenditure*(a)(b)	542	1,124	151	2,021	4,183
	3,491	3,636	4,109	14,055	19,421

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Organic capital expenditure by segment
Upstream
US	566	589	1,029	3,341	4,019
Non-US	1,463	1,367	2,029	6,009	7,885
	2,029	1,956	3,058	9,350	11,904
Downstream
US	237	139	258	632	913
Non-US	527	345	522	1,698	2,084
	764	484	780	2,330	2,997
Other businesses and corporate
US	14	13	15	80	47
Non-US	142	59	105	274	290
	156	72	120	354	337
	2,949	2,512	3,958	12,034	15,238
Organic capital expenditure by geographical area
US	817	741	1,302	4,053	4,979
Non-US	2,132	1,771	2,656	7,981	10,259
	2,949	2,512	3,958	12,034	15,238

(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 full year 2019 relating to this transaction.

(b)

Fourth quarter and full year 2020 includes a $500 million deposit in respect of the strategic partnership with Equinor. Third quarter and full year 2020 include $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries. Full year 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*

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Upstream
Gains on sale of businesses and fixed assets	256	10	38	360	143
Impairment and losses on sale of businesses and fixed assets(a)	(856)	(274)	(2,718)	(13,214)	(7,036)
Environmental and other provisions	20	(9)	(32)	(2)	(32)
Restructuring, integration and rationalization costs(b)	(209)	(164)	(13)	(401)	(89)
Other(c)(d)	177	(194)	2	(2,511)	67
	(612)	(631)	(2,723)	(15,768)	(6,947)
Downstream
Gains on sale of businesses and fixed assets(e)	2,310	16	7	2,320	51
Impairment and losses on sale of businesses and fixed assets(a)	(313)	(20)	(23)	(1,136)	(123)
Environmental and other provisions	(33)	—	(77)	(33)	(78)
Restructuring, integration and rationalization costs(b)	(522)	(142)	71	(633)	85
Other	(39)	—	(6)	(39)	(12)
	1,403	(146)	(28)	479	(77)
Rosneft
Other	(41)	(101)	91	(205)	(103)
	(41)	(101)	91	(205)	(103)
Other businesses and corporate
Gains on sale of businesses and fixed assets	191	1	3	194	(1)
Impairment and losses on sale of businesses and fixed assets	2	—	(916)	(19)	(916)
Environmental and other provisions	(122)	(32)	(203)	(177)	(231)
Restructuring, integration and rationalization costs(b)	(60)	(156)	(1)	(262)	6
Gulf of Mexico oil spill	(140)	(63)	(63)	(255)	(319)
Other(f)	76	138	(2)	201	(30)
	(53)	(112)	(1,182)	(318)	(1,491)
Total before interest and taxation	697	(990)	(3,842)	(15,812)	(8,618)
Finance costs(g)	(191)	(198)	(122)	(625)	(511)
Total before taxation	506	(1,188)	(3,964)	(16,437)	(9,129)
Taxation credit (charge) on non-operating items	593	(6)	822	4,345	1,943
Taxation – impact of foreign exchange(h)	67	85	—	(99)	—
Total after taxation for period	1,166	(1,109)	(3,142)	(12,191)	(7,186)

(a)

See Note 3 for further information. Also included in impairment charges in the fourth quarter and full year 2020 for Upstream is $156 million in relation to the likely disposal of an exploration asset.

(b)

Fourth quarter and third quarter 2020 include recognized provisions for restructuring costs for plans that were formalized during the quarters.

(c)

Full year 2020 includes exploration write-offs of $1,974 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)

Full year 2020 includes $545 million net impairments reported by equity-accounted entities.

(e)

Fourth quarter and full year 2020 include a gain of $2.3 billion on the sale of our petrochemicals business.

(f)

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.

(g)

All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. Fourth quarter, third quarter and full year 2020 also include the income statement impact associated with the buyback of finance debt. See Note 11 for further information.

(h)

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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Favourable (adverse) impact relative to management’s measure of performance
Upstream	(677)	(217)	659	(738)	706
Downstream	(284)	425	23	(149)	160
Other businesses and corporate	450	266	—	675	—
	(511)	474	682	(212)	866
Taxation credit (charge)	55	(95)	(111)	(11)	(155)
	(456)	379	571	(223)	711

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*	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Net debt	38,941	40,379	45,442	38,941	45,442
Lease liabilities	9,262	9,282	9,722	9,262	9,722
Net partner (receivable) payable for leases entered into on behalf of joint operations	(7)	(41)	(158)	(7)	(158)
Net debt including leases	48,196	49,620	55,006	48,196	55,006
Total equity	85,568	82,155	100,708	85,568	100,708
Gearing including leases*	36.0%	37.7%	35.3%	36.0%	35.3%

Readily marketable inventory* (RMI)

	31 December	31 December
$ million	2020	2019
RMI at fair value*	6,528	6,837
Paid-up RMI*	3,365	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.

	31 December	31 December
$ million	2020	2019
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	16,873	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	(10,810)	(14,280)
	6,063	6,600
Plus: difference between RMI at fair value and RMI on an IFRS basis	465	237
RMI at fair value	6,528	6,837
Less: unpaid RMI* at fair value	(3,163)	(3,620)
Paid-up RMI	3,365	3,217

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Gulf of Mexico oil spill

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ million	2020	2020	2019	2020	2019
Net cash provided by operating activities as per condensed group cash flow statement	2,269	5,204	7,603	12,162	25,770
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis	88	142	(42)	1,608	2,429
Operating cash flow, excluding Gulf of Mexico oil spill payments*	2,357	5,346	7,561	13,770	28,199

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $116 million and $1,786 million in the fourth quarter and full year of 2020 respectively. For the same periods in 2019, the amount was an outflow of $125 million and $2,694 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.

	31 December	31 December
$ million	2020	2019
Trade and other payables	(11,387)	(12,480)
Provisions	(49)	(189)
Gulf of Mexico oil spill payables and provisions	(11,436)	(12,669)
Of which - current	(1,444)	(1,800)

Deferred tax asset	5,471	5,526

On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims processing operations of the Deepwater Horizon Court Supervised Settlement Programme (DHCSSP). The DHCSSP was established in 2012 to administer claims pursuant to the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement). The Court also concluded that future issues concerning EPD Settlement Agreement claims would be time barred under the DHCSSP and the claim administrator would proceed to complete post-closure administrative wind down activities. The provision presented in the table above 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 the DHCSSP and 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

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
$ 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	(715)	556	(306)	(85)	(2,918)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill	41	165	91	1,580	2,586
Adjusted for Inventory holding gains (losses)* (Note 5)
Upstream	20	8	—	17	(8)
Downstream	650	191	(21)	(2,796)	685
Working capital release (build)	(4)	920	(236)	(1,284)	345

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Realizations* and marker prices

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
	2020	2020	2019	2020	2019
Average realizations(a)
Liquids* ($/bbl)
US	32.40	31.74	49.34	33.06	51.88
Europe	43.39	43.52	63.01	41.79	63.95
Rest of World	41.60	41.46	60.34	37.42	61.50
BP Average	38.42	38.17	55.90	36.16	57.73
Natural gas ($/mcf)
US	1.76	1.29	1.65	1.30	1.93
Europe	5.37	2.34	4.06	3.13	4.01
Rest of World	3.37	2.99	3.77	3.25	4.10
BP Average	3.10	2.56	3.12	2.75	3.39
Total hydrocarbons* ($/boe)
US	24.20	22.04	31.84	23.25	33.30
Europe	39.39	36.14	51.91	35.52	56.87
Rest of World	29.28	27.40	37.91	26.91	39.23
BP Average	28.48	26.42	36.42	26.31	38.00
Average oil marker prices ($/bbl)
Brent	44.16	42.94	63.08	41.84	64.21
West Texas Intermediate	42.63	40.91	56.88	39.25	57.03
Western Canadian Select	31.57	31.62	37.70	28.53	43.42
Alaska North Slope	44.82	42.75	64.32	42.20	65.00
Mars	43.26	42.01	57.85	40.20	60.84
Urals (NWE – cif)	44.29	42.83	60.74	41.71	62.96
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)	2.67	1.98	2.50	2.08	2.63
UK Gas – National Balancing Point (p/therm)	40.46	21.06	31.77	24.93	34.70

(a)

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

(b)

Henry Hub First of Month Index.

Exchange rates

	Fourth	Third	Fourth
	quarter	quarter	quarter	Year	Year
	2020	2020	2019	2020	2019
$/£ average rate for the period	1.32	1.29	1.29	1.28	1.28
$/£ period-end rate	1.36	1.28	1.31	1.36	1.31

$/€ average rate for the period	1.19	1.17	1.11	1.14	1.12
$/€ period-end rate	1.23	1.17	1.12	1.23	1.12

$/AUD average rate for the period	0.73	0.71	0.68	0.69	0.69
$/AUD period-end rate	0.77	0.71	0.70	0.77	0.70

Rouble/$ average rate for the period	76.16	73.74	63.74	72.32	64.73
Rouble/$ period-end rate	74.44	77.57	61.98	74.44	61.98

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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.

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

Convenience gross margin comprises store gross margin as well as other merchandise and service contribution, not considered as retail fuels or store gross margin, received from the retail service stations operated under a BP brand.

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.

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.

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Glossary (continued)

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.

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.

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Glossary (continued)

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.

Reserves replacement ratio is the extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. The reserves replacement ratio will be reported in BP Annual Report and Form 20-F 2020.

Return on average capital employed (ROACE) is a non-GAAP measure and is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of tax, divided by average capital employed (total equity plus finance debt), excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding lease interest and the unwinding of the discount on provisions and other payables, and for full year 2020 interest expense was $1,808 million (2019 $2,032 million) before tax. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively.

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.

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Glossary (continued)

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.

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: expectations regarding the COVID-19 pandemic, including its risks, impacts, consequences and challenges and BP’s response, the impact on BP’s financial performance (including cash flows and net debt), operations and credit losses, and the impact on the trading environment, oil and gas prices, and global GDP; expectations regarding the shape of the COVID-19 recovery and the pace of transition to a lower-carbon economy and energy system; plans, expectations and assumptions regarding oil and gas demand, supply or prices, the timing of production of reserves; plans and expectations regarding the divestment programme, including the amount and timing of proceeds in 2021 and reaching $25 billion of proceeds by 2025; expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals, including further payments from INEOS in respect of the completed sale of BP’s petrochemicals business and the completion of the sale of BP’s interest in the Wamsutter asset; plans and expectations with respect to the total amount of organic capital expenditure and the DD&A charge in 2021; plans and expectations with respect to the total capital expenditure for 2021; plans and expectations regarding net debt, including delivery of the target of $35 billion; plans and expectations regarding new joint ventures and other agreements, including partnerships with Equinor, Ørsted, Amazon and BP’s multi-company partnership to develop offshore infrastructure to support planned UK carbon capture, use and storage projects, as well as plans and expectations related to BP’s stake in Finite Carbon; plans and expectations regarding BP’s strategic priorities; expectations regarding quarterly dividends and share buybacks; expectations regarding demand for BP’s products in the Upstream and Downstream; expectations regarding Downstream refining margins, utilization, marketing volumes and product demand; 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 the ongoing reduction of approximately 10,000 jobs, and the amount and timing of associated costs; expectations regarding the underlying effective tax rate for 2021; plans and expectations regarding BP’s renewable energy and alternative energy businesses, including BP’s ambition to reach 20GW of net renewable generating capacity to FID by the end of 2025; plans and expectations regarding Upstream and Downstream projects, including the conversion of the Kwinana refinery; expectations regarding Upstream first-quarter and full-year 2021 reported and underlying production and related major project ramp-up, capital investments, divestment 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 charges for 2021; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill, including expectations regarding the completion of the claims processing operations of the Deepwater Horizon Court Supervised Settlement Programme; and expectations regarding operational and financial results or acquisitions or divestments by Rosneft, including expectations regarding the ongoing assessment of the fair values of the assets and liabilities acquired and the consideration paid in respect of the acquisitions announced by Rosneft on 28 December 2020 and the impact, if any, on BP’s accounting for its equity-accounted investment in Rosneft of such acquisitions. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the extent and duration of the impact of current market conditions including the volatility of oil prices, the impact of COVID-19, overall global economic and business conditions impacting our business and demand for our products as well as the specific factors identified in the discussions accompanying such forward-looking statements; changes in consumer preferences and societal expectations; the pace of development and adoption of alternative energy solutions; 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, as well those factors discussed 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.

Contacts

	London	Houston

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

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

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

SIGNATURES

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

	BP p.l.c.
	(Registrant)

Dated: 02 February 2021
	/s/ Ben J. S. Mathews
	------------------------
	Ben J. S. Mathews
	Company Secretary

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Form 6-K BP PLC For: Feb 02

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