Coronavirus Update

BP plc Group Results: Fourth Quarter and Full Year 2020

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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 peoplerelated 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. 

 

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. BPoperated 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.

 

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%.

 

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. 

 

Upstream
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.