DGAP-News: BP p.l.c. / Key word(s): Annual Results
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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 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.
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'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.
- 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.
- 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.
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Analysis of underlying RC profit (loss)* before interest and tax
Analysis of RC profit (loss)* before interest and tax and reconciliation to profit (loss) for the period
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(a) Reflecting lower costs and divestment impacts.
(b) Represents dividend announced in the quarter (vs. prior year quarter).
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(a) See page 7 for a reconciliation to segment RC profit before interest and tax by region.
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.
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%.
We expect first-quarter 2021 reported production to be slightly higher than fourth-quarter 2020.
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(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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(a) See page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.
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.
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.
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.
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.
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(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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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.
(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
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.
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.
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Group income statement
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Condensed group statement of comprehensive income
(a) See Note 1 - Pensions and other post retirement benefits for further information.
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Condensed group statement of changes in equity
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Group balance sheet
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Condensed group cash flow statement
Investment in joint ventures
Investment in associates
Total cash capital expenditure
Proceeds from disposal of fixed assets
Proceeds from disposal of businesses, net of cash disposed
Proceeds from loan repayments
Net cash used in investing activities
Net issue (repurchase) of shares (Note 9)
Lease liability payments
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Issue of perpetual hybrid bonds
Payments on perpetual hybrid bonds
Payments relating to transactions involving non-controlling interests (other)
Receipts relating to transactions involving non-controlling interests (other)
Dividends paid - BP shareholders
- non-controlling interests
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period(a)
(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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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:
Brent oil ($/bbl)
Henry Hub gas ($/mmBtu)
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.
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.
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.
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.
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.
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.
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
Other businesses and corporate
Consolidation adjustment - UPII*
RC profit (loss) before interest and tax*
Inventory holding gains (losses)*
Rosneft (net of tax)
Profit (loss) before interest and tax
Net finance expense relating to pensions and other post-retirement benefits
Profit (loss) before taxation
RC profit (loss) before interest and tax*
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Note 6. Sales and other operating revenues
Other businesses and corporate
Less: sales and other operating revenues between segments
Other businesses and corporate
Third party sales and other operating revenues
Other businesses and corporate
Total sales and other operating revenues
By geographical area
Less: sales and other operating revenues between areas
Revenues from contracts with customers(a)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Natural gas, LNG and NGLs
Non-oil products and other revenues from contracts with customers(b)
Revenue from contracts with customers
Other operating revenues(c)
Total sales and other operating revenues
(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
Other businesses and corporate
Note 8. Production and similar taxes
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)
Results for the period
Profit (loss) for the period attributable to BP shareholders
Less: preference dividend
Profit (loss) attributable to BP ordinary shareholders
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding
Weighted average number of shares outstanding used to calculate diluted earnings per share
Shares in issue at period-end
(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
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 $0.315 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the fourth quarter 2020 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the fourth quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
Dividends paid per ordinary share
Dividends paid per ADS (cents)
Number of shares issued (millions)
Value of shares issued ($ million)
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Note 11. Net debt
Fair value (asset) liability of hedges related to finance debt(c)
Less: cash and cash equivalents(b)
(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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Capital expenditure on a cash basis
Organic capital expenditure*
Inorganic capital expenditure*(a)(b)
Organic capital expenditure by segment
Other businesses and corporate
Organic capital expenditure by geographical area
(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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Gains on sale of businesses and fixed assets
Impairment and losses on sale of businesses and fixed assets(a)
Environmental and other provisions
Restructuring, integration and rationalization costs(b)
Gains on sale of businesses and fixed assets(e)
Impairment and losses on sale of businesses and fixed assets(a)
Environmental and other provisions
Restructuring, integration and rationalization costs(b)
Other businesses and corporate
Gains on sale of businesses and fixed assets
Impairment and losses on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs(b)
Gulf of Mexico oil spill
Total before interest and taxation
Total before taxation
Taxation credit (charge) on non-operating items
Taxation - impact of foreign exchange(h)
Total after taxation for period
(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
Favourable (adverse) impact relative to management's measure of performance
Other businesses and corporate
Taxation credit (charge)
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*
Net partner (receivable) payable for leases entered into on behalf of joint operations
Net debt including leases
Gearing including leases*
Readily marketable inventory* (RMI)
RMI at fair value*
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.
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST
Plus: difference between RMI at fair value and RMI on an IFRS basis
RMI at fair value
Less: unpaid RMI* at fair value
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Gulf of Mexico oil spill
Net cash provided by operating activities as per condensed group cash flow statement
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis
Operating cash flow, excluding Gulf of Mexico oil spill payments*
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.
Trade and other payables
Gulf of Mexico oil spill payables and provisions
Of which - current
Deferred tax asset
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
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill
Adjusted for Inventory holding gains (losses)* (Note 5)
Working capital release (build)
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Realizations* and marker prices
Rest of World
Natural gas ($/mcf)
Rest of World
Total hydrocarbons* ($/boe)
Rest of World
Average oil marker prices ($/bbl)
West Texas Intermediate
Western Canadian Select
Alaska North Slope
Urals (NWE - cif)
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)
UK Gas - National Balancing Point (p/therm)
(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b) Henry Hub First of Month Index.
$/£ average rate for the period
$/£ period-end rate
$/€ average rate for the period
$/€ period-end rate
$/AUD average rate for the period
$/AUD period-end rate
Rouble/$ average rate for the period
Rouble/$ period-end rate
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For a full discussion of the group's material legal proceedings, see pages 319-320 of BP Annual Report and Form 20-F 2019.
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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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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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 e