Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F x Form 40-F ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨
THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-254751, 333-254751-01 AND 333-254751-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-253287) AND REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333- 254578) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.
BP p.l.c (“bp”) is furnishing this report on Form 6-K to provide restated financial statements as of and for the three years ended 31 December 2020, which supersede in their entirety the financial statements included in bp’s Annual Report on Form 20-F for the year ended 31 December 2020 (the “2020 Form 20-F”), and to update certain other business and financial information included in the 2020 Form 20-F, in each case to reflect a change in bp’s reporting segments in the three months ended 31 March 2021 and changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021.
In the three months ended 31 March 2021, bp’s reportable segments were changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the group chief executive, from that date. From the first quarter of 2021, the group’s reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group’s reportable segments were Upstream, Downstream and Rosneft. See the updated “Financial statements — Notes to the consolidated financial statements — Note 1. Significant accounting policies, judgments, estimates and assumptions” for bp’s 2020 Form 20-F, as included herein, for additional information.
In addition, bp has made changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group previously presented revenues and purchases for such contracts on a gross basis in the income statement upon physical settlement. However, the change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, resulted in the group determining that the revenue and corresponding purchases relating to such transactions should be presented net, as gains or losses within other operating revenues, from that date. See the updated “Financial statements — Notes to the consolidated financial statements — Note 1. Significant accounting policies, judgments, estimates and assumptions” for bp’s 2020 Form 20-F, as included herein, for additional information.
bp has updated the following applicable items that were contained in the 2020 Form 20-F reflecting the above mentioned changes:
a.Strategic report — Group performance
b.Financial statements — Group income statement
c.Financial statements — Notes to the consolidated financial statements — Note 1. Significant accounting policies, judgments, estimates and assumptions.
d.Financial statements — Notes to the consolidated financial statements — Note 2. Non-current assets held for sale
e.Financial statements — Notes to the consolidated financial statements — Note 3. Disposals and impairment
f.Financial statements — Notes to the consolidated financial statements — Note 5. Segmental analysis
g.Financial statements — Notes to the consolidated financial statements — Note 6. Sales and other operating revenues
h.Financial statements — Notes to the consolidated financial statements — Note 14. Goodwill and impairment review of goodwill
i.Additional disclosures — Additional information — Capital expenditure
j.Additional disclosures — Additional information — Adjusting items
k.Additional disclosures — Additional information — Non-GAAP information on fair value accounting effects
Other than the items listed above, bp is not updating any other portion of the 2020 Form 20-F previously filed and this document should be read in conjunction with the 2020 Form 20-F. This report on Form 6-K does not reflect any events occurring after filing of the 2020 Form 20-F on 22 March 2021. For significant developments since the filing of the 2020 Form 20-F on 22 March 2021, please refer to bp’s subsequent furnished or filed reports on Form 6-K.
bp began to report comparative results reflecting the above mentioned changes in the report on Form 6-K filed on 27 April 2021 for bp’s interim results for the three months ended 31 March 2021. By virtue of this report on Form 6-K, bp will be able to incorporate the updated information by reference into future registration statements or post-effective amendments to existing registration statements.
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement.
This document contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past, events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, plans and expectations regarding our electrification agenda; expectations used in accounting estimates, including those regarding price assumptions, the value of contingent asset and liabilities, reported amounts of reserves and expenses, accounting for the investment in Rosneft, exploration and appraisal of intangible assets, the recoverability of asset carrying values, the estimation of reserves, supplier financing arrangements, derivative financial instruments, provisions and contingencies, and pensions and other post-retirement benefits; expectations related to future oil and natural gas prices, production and reserves volumes, production and development costs, field decline rates and current fiscal regimes; expectations regarding world energy demand and the energy transition, including its impact on the future development or viability of exploration prospects and the useful lives of oil and gas industry assets and the related depreciation of bp’s existing upstream oil and natural gas properties; expectations about the demand for refined products; expectations regarding the timing and cost of decommissioning of oil and gas assets; expectations that COVID-19 will have an enduring impact on the global economy, with the potential for weaker demand for energy for a sustained period and an acceleration of the pace of transition to a lower carbon economy and energy system; expectations regarding the timing of production of bp’s reserves and resources; estimates related to future cash flows; expectations regarding post-retirement benefits; expectations regarding deferred tax assets and liabilities; expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals; plans and expectations related to Rosneft’s acquisition of JSC Taimyrneftegaz and LLC Taimyrburservis and its sale of a 10 percent interest in LLC Vostok Oil; plans and expectations regarding joint ventures and other agreements, including the Jio-bp JV; expectations regarding contingent consideration; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; plans and expectations regarding bp’s financial framework; plans and expectations regarding bp’s trading activities and supply and trading function; expectations regarding market risk, commodity price risk, foreign currency exchange risk, interest rate risk, credit risk and liquidity risk; expectations related to management of the group’s debt portfolio and associated derivatives; expectations regarding the effect of interest rate benchmark reform; expectations regarding risk management plans; plans and projections regarding oil and gas reserves; expectations regarding the costs of environmental restoration, remediation and abatement programmes; expectations with respect to reserves bookings from new discoveries; expectations regarding future government action, regulations and policy, their impact on bp’s business and plans regarding compliance with such regulations, including health, safety and environmental laws and regulations; and expectations regarding legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities, tax authorities and/ or other entities or parties, and the timing and potential impact of such proceedings and bp’s intentions in respect thereof are all forward looking in nature.
By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp.
Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the extent and duration of the impact of current market conditions including the volatility of oil prices, the impact of COVID-19, overall global economic and business conditions impacting our business and demand for our products as well as the specific factors identified in the discussions accompanying such forward-looking statements; changes in consumer preferences and societal expectations; the pace of development and adoption of alternative energy solutions; developments in policy, law, regulation, technology and markets, including societal and investor sentiment related to the issue of climate change; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new projects on-stream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC+ quota restrictions; production-sharing agreements effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp’s access to future credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and noncompliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; public health situations (including an outbreak of an epidemic or pandemic; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, as well those factors discussed under “Risk factors” in bp’s Annual Report and Form 20-F 2020 as filed with the US Securities and Exchange Commission and those factors discussed under “Principal risks and uncertainties” in bp’s Report on Form 6-K regarding results for the six-month period ended 30 June 2021.
In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.
3
bp Annual Report and Form 20-F 2020
Strategic report
Group performance
Murray Auchincloss
Group chief financial officer
$(5.7)bn
underlying replacement
cost (RC) loss«
(2019 profit $10.0bn)
$(20.3)bn
$12.2bn
loss attributable to
bp shareholders
(2019 profit $4.0bn)
operating cash flow«
(2019 $25.8bn)
Financial and operating performance
$ million except per share amounts
2020a
2019a
2018a
Sales and other operating revenuesa
105,944
159,307
165,165
Profit (loss) before interest and tax
(21,740)
11,706
19,378
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(3,148)
(3,552)
(2,655)
Taxation
4,159
(3,964)
(7,145)
Non-controlling interest
424
(164)
(195)
Profit (loss) for the year attributable to bp shareholders
(20,305)
4,026
9,383
Inventory holding (gains) losses«, before tax
2,868
(667)
801
Taxation charge (credit) on inventory holding gains and losses
(667)
156
(198)
Replacement cost (RC) profit (loss)«
(18,104)
3,515
9,986
Net (favourable) adverse impact of adjusting items« b, before tax
16,649
8,263
3,380
Total taxation charge (credit) on adjusting items
(4,235)
(1,788)
(643)
Underlying RC profit (loss)
(5,690)
9,990
12,723
Dividend paid per ordinary share
– cents
31.5
41.0
40.5
– pence
24.458
31.977
30.568
aAmounts have been restated as a result of changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. See Note 1 - Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts.
bAdjusting items were reported under two different headings – non-operating items and fair value accounting effects«. See pages 94-96 of this report for more information.
Results
The loss for the year ended 31 December 2020 attributable to bp shareholders was $20.3 billion, compared with a profit of $4.0 billion in 2019. Adjusting for inventory holding losses, replacement cost (RC) loss was $18.1 billion, compared with a profit of $3.5 billion in 2019.
After adjusting RC loss for a net adverse impact of adjusting items of $12.4 billion (on a post-tax basis), underlying RC loss for the year ended 31 December 2020 was $5.7 billion. The result reflected lower oil and gas prices, significant exploration write-offs and lower refining margins and depressed demand.
The profit for the year ended 31 December 2019 attributable to bp shareholders was $4.0 billion, excluding inventory holding gains, RC profit was $3.5 billion. After adjusting RC profit for a net adverse impact of adjusting items of $6.5 billion (on a post-tax basis), underlying RC profit for the year ended 31 December 2019 was $10.0 billion, a decrease of $2.7 billion compared with 2018.
The decrease was predominantly due to lower oil and gas prices and a significantly weaker environment.
For more information
For a further discussion of bp’s financial and operating performance for the year ending 31 December 2018, see bp Annual Report and Form 20-F 2019, pages 36-38 and 50-65 and bp Annual Report and Form 20-F 2018, pages 19-39.
bp Annual Report and Form 20-F 2020
4
Adjusting items
$ million
2020
2019
2018
Gains on sale of businesses and fixed assets
2,874
192
456
Impairment and losses on sale of businesses and fixed assets
(14,369)
(8,074)
(860)
Environmental and other provisions
(212)
(341)
(758)
Restructuring, integration and rationalization costs
(1,296)
2
(726)
Fair value accounting effectsa
(212)
866
73
Gulf of Mexico oil spill
(255)
(319)
(714)
Other
(2,554)
(78)
(372)
Total before interest and taxation
(16,024)
(7,752)
(2,901)
Finance costs
(625)
(511)
(479)
Total before taxation
(16,649)
(8,263)
(3,380)
Taxation credit (charge) on adjusting items
4,334
1,788
522
Taxation - impact of US tax reform
—
—
121
Taxation – impact of foreign exchange
(99)
—
—
Total taxation on adjusting items
4,235
1,788
643
(12,414)
(6,475)
(2,737)
a2018 includes $17 million reported on fair value gain (loss) on embedded derivatives.
Adjusting items were reported under two different headings – non-operating items and fair value accounting effects.
In 2020 the net adverse impact of adjusting items was $12.4 billion, mainly related to impairment charges, a gain on the disposal of our petrochemicals business, certain exploration write-offs (reported within the ‘other’ category), and restructuring costs associated with the reinvent bp programme. The impairment charges mainly relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. Impairment charges also include amounts relating to the disposal of the group’s interests in its Alaska business.
In 2019 the net adverse impact of adjusting items was $6.5 billion, mainly related to impairment charges, principally resulting from the announcements to dispose of certain assets in the US and reclassification of accumulated foreign exchange losses from reserves to the income statement on the formation of the bp Bunge Bioenergia joint venture«.
See pages 94-96 of this report for more information on adjusting items and fair value accounting effects.
Taxation
%
Effective tax rate
2020
2019
2018
Effective tax rate (ETR) on profit or loss for the year
17
49
43
Underlying ETR«
(14)
36
38
The credit for corporate income taxes was $4,159 million in 2020 compared with a charge of $3,964 million in 2019. The decrease mainly reflects the loss in 2020. The effective tax rate (ETR) on the loss for the year in 2020 was impacted by the impairment charges and exploration write-offs. The ETRs for 2020 and 2019 were also impacted by various other one-off items. Adjusting for inventory holding impacts, adjusting items, the underlying ETR in 2020 was lower than in 2019, mainly reflecting the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition. The underlying ETR is sensitive to the impact that volatility in the current environment may have on the geographical mix of the group’s profits and losses. Underlying ETR is a non-GAAP measure. A reconciliation to GAAP information is provided on page 101 of this report.
Reporting
During the first quarter of 2021, the group's reportable segments were changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the group chief executive, from 1 January. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment.
Customers & products comprises the group’s customer-focused businesses, spanning convenience and mobility, which includes fuels retail and next-gen offers such as electrification, as well as aviation, midstream, and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business is also reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal.
The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.
$ million
2020a
2019a
2018a
Sales and other operating revenuesa
gas & low carbon energy
16,275
27,045
27,208
oil production & operations
17,234
28,702
29,675
customers & productions
90,744
132,864
139,520
other businesses & corporate
1,666
1,418
1,112
Less: sales and other operating revenues between segments
19,975
30,722
32,350
Total sales and other operating revenues
105,944
159,307
165,165
RC profit (loss) before interest and taxation
gas & low carbon energy
(7,068)
2,945
4,214
oil production & operations
(14,583)
1,049
9,690
customers & productions
3,418
6,502
6,940
Rosneft
(149)
2,316
2,221
other businesses & corporate
(579)
(1,848)
(3,097)
Consolidation adjustment – UPII«
89
75
211
(18,872)
11,039
20,179
Net (favourable) adverse impact of adjusting items
gas & low carbon energy
7,757
503
380
oil production & operations
8,695
6,616
132
customers & productions
(330)
(83)
621
Rosneft
205
103
95
other businesses & corporate
(303)
613
1,673
16,024
7,752
2,901
Underlying RC profit (loss) before interest and tax
gas & low carbon energy
689
3,448
4,594
oil production & operations
(5,888)
7,665
9,822
customers & productions
3,088
6,419
7,561
Rosneft
56
2,419
2,316
5
bp Annual Report and Form 20-F 2020
Strategic report
other businesses & corporate
(882)
(1,235)
(1,424)
Consolidation adjustment – UPII«
89
75
211
(2,848)
18,791
23,080
bp average realizationsa
$ per barrel
Crude oilb
38.46
61.56
67.81
Natural gas liquids
12.91
18.23
29.42
Liquids«
36.16
57.73
64.98
$ thousand cubic feet
Natural gas
2.75
3.39
3.92
US natural gas
1.30
1.93
2.43
$ per barrel of oil equivalent
Total hydrocarbons«
26.31
38.00
43.47
$ per barrel
Brent«
41.84
64.21
71.31
West Texas Intermediate«
38.25
57.03
65.20
$ per million British thermal units
Average Henry Hub« gas priced
2.08
2.63
3.09
pence per thermal units
Average UK National Balancing Point gas price«
24.93
34.70
60.38
$/bbl
bp average refining marker margin (RMM)«
6.7
13.2
13.1
a Amounts have been restated as a result of changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. See Note 1 - Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts.
Gas & low carbon energy
Sales and other operating revenues for 2020 were lower than in 2019 due to lower gas and liquids realizations, lower gas marketing and trading revenues and were further impacted by lower sales volumes. The decrease in 2019 compared with 2018 primarily reflected lower gas and liquids realizations partially offset by higher production and strong gas marketing and trading revenues.
RC loss before interest and tax for the segment included a net adverse impact of adjusting items of $7,757 million (including adverse fair value accounting effects of $738 million relative to management’s view of performance). This primarily relates to impairments associated with revisions to the long-term price assumptions. See Financial statements – Note 5 for further information.
RC profit before interest and tax for 2019 included a net adverse impact of adjusting items of $503 million (including favourable fair value accounting effects of $714 million relative to management’s view of performance), primarily related to reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP Bunge Bioenergia.
RC profit before interest and tax for 2018 included a net adverse impact of adjusting items of $380 million (including favourable fair value accounting effects of $60 million relative to management’s view of performance), primarily related to impairment charges.
After excluding adjusting items, the underlying RC result before interest and tax was lower in 2020 compared with 2019. This primarily reflected lower gas realizations and the impact of writing down certain exploration intangible carrying values.
Compared with 2018, the 2019 underlying RC result before interest and tax reflected lower gas and liquids realizations and higher depreciation, depletion and amortization partly offset by strong gas marketing and trading results and higher production.
Oil production & operations
Sales and other operating revenues for 2020 were lower than in 2019 due to lower liquids and gas realizations and were further impacted by lower sales volumes. The decrease in 2019 compared with 2018 primarily reflected lower liquids and gas realizations partially offset by higher production.
RC loss before interest and tax for the segment included a net adverse impact of adjusting items of $8,695 million. This primarily relates to impairments associated with revisions to the long-term price assumptions. See Financial statements – Note 5 for further information.
RC profit before interest and tax for 2019 included a net adverse impact of adjusting items of $6,616 million (including adverse fair value accounting effects of $8 million), primarily related to impairment charges arising from disposal transactions.
RC profit before interest and tax for 2018 included a net adverse impact of adjusting items of $132 million (including adverse fair value accounting effects of $99 million relative to management’s view of performance).
After excluding adjusting items, the underlying RC result before interest and tax was lower in 2020 compared with 2019. This primarily reflected lower liquids and gas realizations and the impact of writing down certain exploration intangible carrying values.
Compared with 2018, the 2019 underlying RC result before interest and tax reflected lower liquids and gas realizations and higher depreciation, depletion and amortization partly offset by higher production.
Customers & products
Sales and other operating revenues in 2020 were lower than in 2019, mainly due to lower crude and product prices and the demand impact of COVID-19. The decrease in 2019 compared with 2018 was mainly due to lower crude and production prices.
RC profit before interest and tax for 2020 included a net favourable impact of adjusting items of $330 million (including adverse fair value accounting effects of $149 million). The net favourable impact reflected a profit of $2.3 billion on the sale of our petrochemicals business, which was partially offset by restructuring costs and impairments.
bp Annual Report and Form 20-F 2020
6
RC profit before interest and tax for 2019 included a net favourable impact of adjusting items of $83 million (including favourable fair value accounting effects of $160 million).
RC profit before interest and tax for 2018 included a net adverse impact of adjusting items of $621 million (including favourable fair value accounting effects of $95 million), primarily reflecting restructuring costs.
After excluding adjusting items, underlying RC profit before interest and tax for 2020 was $3,088 million (2019 $6,419 million, 2018 $7,561 million).
The fuels business reported a lower underlying RC profit before interest and tax compared with 2019, due to an exceptionally weak refining environment, with COVID-19 restrictions impacting refining utilization and fuel volumes. The 2020 result also reflects a higher contribution from supply and trading.
Our fuels marketing business demonstrated continued resilience, delivering significant profit in 2020, despite COVID-19 – which adversely impacted retail fuel and aviation volumes by 14% and 50% respectively.
Refining loss in 2020 reflects the continued impact of historically low industry margins. Although refining 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.
In the fourth quarter of 2020, we announced plans to cease production at our Kwinana refinery and convert it to an import terminal, helping secure ongoing fuel supply for Western Australia. We continued to redefine convenience in 2020, delivering a 6% growth in convenience gross margin«. We also expanded our retail network by more than 1,400 sites, to a total of 20,300, including more than 1,900 strategic convenience sites«. And we completed the formation of Jio-bp, our Indian joint venture with Reliance, helping more than double the number of retail sites in growth markets«, see page 24 of bp Annual Report and Form 20-F 2020.
We also progressed our electrification agenda, growing our network to 10,100 bp and joint venture operated electric vehicle charge points«, see Our strategy on page 15 of bp Annual Report and Form 20-F 2020.
The lubricants business reported a lower underlying RC profit before interest and tax compared with 2019 and this reflected significant COVID-19 demand impacts, with volumes 15% lower for the year. We continued to expand our service offer in 2020, growing the number of Castrol branded independent workshops by more than 4,000 to over 28,000 globally. The underlying RC profit before interest and tax for 2019 was similar to 2018, reflecting year-on-year unit margin improvement, offset by adverse foreign exchange rate movements.
The petrochemicals business reported a lower underlying RC profit before interest and tax compared with 2019, reflecting 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, were received in February 2021. The underlying RC profit before interest and tax for 2019 was lower compared with 2018, reflecting a significantly weaker margin environment across both aromatics and acetyls.
For more information see Additional information for Downstream on page 318 of bp Annual Report and Form 20-F 2020.
Rosneft
RC loss before interest and tax for 2020 and RC profit before interest and tax for 2019 for the segment included a net adverse impact of adjusting items of $205 million for 2020 and $103 million for 2019. The 2018 result included a net adverse impact of adjusting items of $95 million.
After excluding adjusting items, the underlying RC profit before interest and tax in 2020 primarily reflected lower oil prices and unfavourable foreign exchange and adverse duty lag effects compared with 2019 underlying profit. Compared with 2018, the underlying RC profit before interest and tax for 2019 was reflected favourable foreign exchange and certain one-off items offset by lower oil prices.
Financial and operating performance for 2020 also reflected the increased average economic interest that bp holds in Rosneft as a result of Rosneft’s share buyback programme and the transaction to sell Rosneft’s
business in Venezuela in exchange for its own shares, which completed in April 2020.
For more information see Additional information for Rosneft on page 320 of bp Annual Report and Form 20-F 2020.
Other businesses & corporate
RC loss before interest and tax for the year ended 31 December 2020 was $579 million (2019 $1,848 million, 2018 $3,097 million). The 2020 result included a net favourable impact of adjusting items of $303 million, primarily reflecting favourable fair value accounting effects of $675 million and a gain on disposal, partly offset by Gulf of Mexico oil spill related costs of $255 million and restructuring costs. The 2019 and 2018 results included a net adverse impact of adjusting items of $613 million and $1,673 million respectively, including Gulf of Mexico oil spill related costs of $319 million in 2019 and $714 million in 2018.
After excluding adjusting items, the underlying RC loss before interest and tax for the year ended 31 December 2020 was $882 million, mainly reflected an uplift in valuation of a venture investment of $284 million. Compared with 2018, the underlying RC loss before interest and tax for 2019 reflected improved shipping performance.
Cash flow and debt information
$ million
2020
2019
2018
Cash flow
Operating cash flow«
12,162
25,770
22,873
Net cash used in investing activities
(7,858)
(16,974)
(21,571)
Net cash provided by (used in) financing activities
3,956
(8,817)
(4,079)
Cash and cash equivalents at end of year
31,111
22,472
22,468
Capital expenditure«
Organic capital expenditure«
(12,034)
(15,238)
(15,140)
Inorganic capital expenditure«
(2,021)
(4,183)
(9,948)
(14,055)
(19,421)
(25,088)
Divestment and other proceeds
Divestment proceeds«
5,480
2,201
2,851
Other proceeds
1,106
566
666
6,586
2,767
3,517
Debt
Finance debt
72,664
67,724
65,132
Net debt«
38,941
45,442
43,477
Finance debt ratio« (%)
45.9%
40.2%
39.1%
Gearing« (%)
31.3%
31.1%
30.0%
Gearing including leases« (%)
36.0%
35.3%
N/A
Operating cash flow
Operating cash flow for the year ended 31 December 2020 was $12.2 billion, $13.6 billion lower than 2019. Operating cash flow in 2020 reflected $1.8 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2019, operating cash flows in 2020 reflected lower oil and gas realizations, lower refining margins and lower fuels volumes partly offset by lower tax payments and lower working capital« build.
Movements in working capital adversely impacted cash flow in the year by $0.1 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $1.6 billion. Other working capital effects, principally a decrease in inventory and other current and non-current assets partially offset by a decrease in other current and non-current liabilities, had a favourable effect of $1.5 billion. bp actively manages its working capital balances to optimize and reduce volatility in cash flow.
Operating cash flow for the year ended 31 December 2019 was $25.8 billion, $2.9 billion higher than 2018. Operating cash flow in 2019 reflected $2.7 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2018, operating cash flows in 2019 also reflected the favourable effect of an estimated $2.0 billion of lease payments being classified as financing cash flows from 1 January 2019 following the implementation of IFRS 16.
7
bp Annual Report and Form 20-F 2020
Strategic report
Movements in working capital adversely impacted cash flow in the year by $2.9 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $2.6 billion.
Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December 2020 decreased by $9.1 billion compared with 2019.
The decrease mainly reflected lower capital expenditure, particularly due to payments of $3.5 billion in 2019 for the acquisition of unconventional onshore US oil and gas assets from BHP, and $3.9 billion of disposal proceeds from the petrochemicals divestment.
Total capital expenditure for 2020 was $14.1 billion (2019 $19.4 billion), of which organic capital expenditure was $12.0 billion (2019 $15.2 billion) in line with the guidance given in April. Sources of funding are fungible, but the majority of the group’s funding requirements for new investment comes from cash generated by existing operations.
Total divestment and other proceeds for 2020 amounted to $6.6 billion, including $3.9 billion of proceeds from the petrochemicals divestment and $1.1 billion other proceeds. Other proceeds represented a loan repayment relating to the TANAP pipeline refinancing; and proceeds in relation to the sale of interests in bp’s retail property portfolio in the UK and New Zealand. Total divestment and other proceeds for 2019 amounted to $2.8 billion, including $0.6 billion received in relation to the sale of an interest in bp’s retail property portfolio in Australia. The proceeds from the UK, New Zealand and Australia property transactions are reported within financing activities in the group cash flow statement.
bp has completed or agreed transactions for over half of its target of $25 billion in proceeds by 2025.
Net cash provided by (used in) financing activities
Net cash provided by financing activities for the year ended 31 December 2020 was $4.0 billion, compared with net cash used of $8.8 billion in 2019. This was mainly due to the issue of perpetual hybrid bonds with a US$ equivalent value of $11.9 billion.
Total dividends distributed to shareholders in 2020 were 31.5 cents per share, 9.5 cents lower than 2019. This amounted to a total distribution to shareholders of $6.3 billion in 2020. In 2019 the total distribution to shareholders was $8.3 billion, of which shareholders elected to receive $1.4 billion in shares under the scrip dividend programme. The board decided not to offer a scrip dividend alternative in respect of the 2020 dividends.
Debt
Finance debt at the end of 2020 increased by $4.9 billion from the end of 2019. The finance debt ratio at the end of 2020 increased to 45.9% from 40.2% at the end of 2019. Net debt at the end of 2020 decreased by $6.5 billion from the 2019 year-end position. Gearing at the end of 2020 increased to 31.3% from 31.1%, reflecting significant impairments and exploration write-offs, offset by the hybrid bond issue in June 2020. Net debt and gearing are non-GAAP measures. See Financial statements – Notes 26 and 27 for further information on finance debt and net debt.
For information on financing the group’s activities see Financial statements – Note 29 and Liquidity and capital resources on page 306 of bp Annual Report and Form 20-F 2020.
Group reserves and production (including Rosneft segment)a
2020
2019
2018
Estimated net proved reserves (net of royalties)
Liquids (mmb)
10,661
11,478
11,456
Natural gas (bcf)
42,467
45,601
49,239
Total hydrocarbons (mmboe)
17,982
19,341
19,945
Of which:
Equity-accounted entitiesb
10,100
9,965
9,757
Production (net of royalties)
Liquids (mb/d)
2,106
2,211
2,191
Natural gas (mmcf/d)
7,929
9,102
8,659
Total hydrocarbons (mboe/d)
3,473
3,781
3,683
Of which:
Subsidiaries
2,146
2,420
2,328
Equity-accounted entitiesc
1,326
1,360
1,355
aBecause of rounding, some totals may not agree exactly with the sum of their component parts.
bIncludes BP’s share of Rosneft. See Supplementary information on oil and natural gas on page 231 of bp Annual Report and Form 20-F 2020 for further information.
cIncludes BP’s share of Rosneft. See Oil and gas disclosures for the group on page 312 of bp Annual Report and Form 20-F 2020 for further information.
Group reserves and production
Total hydrocarbon proved reserves at 31 December 2020, on an oil equivalent basis including equity-accounted entities, decreased by 7% compared with 31 December 2019. Natural gas represented about 41% (47% for subsidiaries and 36% for equity-accounted entities) of these reserves. The change includes a net decrease from acquisitions and disposals of 1,069mmboe (decrease of 1,072mmboe within our subsidiaries and increase of 3mmboe within our equity-accounted entities). Acquisition and divestment activity occurred in our equity-accounted entities in Russia, and divestment activity in our subsidiaries in the US including Alaska.
Total hydrocarbon production for the group was 8% lower compared with 2019. The decrease comprised an 11% decrease (6% decrease for liquids and 16% decrease for gas) for subsidiaries and a 2% decrease (4% decrease for liquids and 2% increase for gas) for equity-accounted entities.
bp Annual Report and Form 20-F 2020
8
Consolidated financial statements of the bp group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on the financial statements
We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together the company) as of 31 December 2020 and 2019, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in equity, and group cash flow statements, for each of the three years in the period ended 31 December 2020, and the related notes (collectively referred to as the 'financial statements'). In our opinion, the financial statements present fairly, in all material respects, the financial position of the company as of 31 December 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2020, in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the company's internal control over financial reporting as of 31 December 2020, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting and our report dated 22 March 2021 expressed an unqualified opinion on the group's internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company has changed its accounting policy related to the presentation of revenues and purchases relating to physically settled derivative contracts.
Basis for opinion
These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
1.Property, plant and equipment (PP&E) assets – Impairment of upstream oil and gas – Notes 1, 4 and 12 to the financial statements
Critical Audit Matter Description
The group balance sheet at 31 December 2020 includes PP&E of $115 billion, of which $74 billion is oil and gas properties within the gas & low carbon energy and oil production & operations segments.
Management’s best estimate of oil and gas price assumptions for value–in-use impairment tests were revised downwards during 2020 compared to the prior year assumptions, as set out in Note 1 on page 19 of this report. The downward revisions reflect an expectation that the aftermath of the COVID-19 pandemic will accelerate the pace of transition to a lower carbon economy and energy system. Given the significance of these revisions, management tested all gas & low carbon energy and oil production & operations CGUs for impairment.
Management recorded $12.9 billion of pre-tax gas & low carbon energy and oil production & operations CGU impairment charges, in large part due to the oil and gas prices revisions detailed above, and $0.1 billion of pre-tax gas & low carbon energy and oil production & operations CGU impairment reversals. Further information has been provided in Note 1 on page 18 of this report, Note 4 on page 38 of this report and Note 12 on page 50 of this report.
Through our audit risk assessment procedures, we have a identified a critical audit matter in respect of PP&E impairment principally due to the following three key management estimates in management’s determination of the level of impairment charge and/or reversal to record.
•Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across the gas & low carbon energy and oil production & operations segments, and are inherently uncertain. As noted above, the estimation of future prices is subject to increased uncertainty given climate change, the global energy transition and the impact of COVID-19. There is a risk that management do not forecast reasonable “best estimate” oil and gas price forecasts when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to most gas & low carbon energy and oil production & operations impairment tests, such that any misstatements would also aggregate. There is also a risk that management’s oil and gas price related disclosures are not reasonable.
•Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied. Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that management do not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also a pervasive input across gas & low carbon energy and oil production & operations impairment tests, before adjustments for asset specific risks and tax rates, such that any misstatements would also aggregate.
.
9
bp Annual Report and Form 20-F 2020
Financial statements
•Reserves and resources estimates - A key input to certain CGU impairment assessments is the oil and gas production forecast, which is based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk adjusted resource volumes, in addition to proved or probable reserves estimates, that are inherently less certain than reserves; and assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and resources estimation policies across the segment.
We identified certain individual CGUs with a total carrying value of $32.1 billion which we determined would be most at risk of material impairment charges or reversals as a result of a plausible change in the key assumptions, particularly oil and gas price and discount rate assumptions.
We also identified CGUs with a further $16.0 billion of combined carrying value which were less sensitive as they would be potentially at risk, in aggregate, to a material impairment or reversal by a plausible change in some or all of the key assumptions.
Further information regarding these sensitivities is given in Note 1 on page 25 of this report.
How the Critical Audit Matter was addressed in the Audit
We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and resources estimates, as well as key internal controls over the performance of the impairment assessments where we identified audit risks. In addition, we conducted the following substantive procedures.
Oil and gas prices
•We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil and gas price assumptions in order to challenge whether they are reasonable.
•In developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and other relevant market data.
•In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change, the energy transition and COVID-19.
•We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving the Paris 2°C Goal and considered whether they presented contradictory audit evidence.
•We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price assumptions to reduced demand scenarios whether due to climate change or other reasons.
Discount rates
•We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation specialists, against relevant third party market and peer data.
•We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates.
•We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate assumptions.
Reserves and resources estimates
With the assistance of Deloitte oil and gas reserves specialists we:
•assessed bp’s reserves and resources estimation methods and policies;
•assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and resources estimates which included those that we judged to represent the greatest risk of material misstatement;
•read a sample of reports provided by management’s external reserves experts and assessed the scope of work and findings of these third parties;
•assessed the competence, capability and objectivity of bp’s internal and external reserve experts; through understanding their relevant professional qualifications and experience.
•compared the production forecasts used in the impairment tests with management’s approved reserves and resources estimates, those estimates having been subjected to the controls that we had tested; and
•performed a retrospective assessment to check for indications of estimation bias over time
Other procedures
•We challenged management’s CGU determinations, and considered whether there was any contradictory evidence present.
•We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical accuracy of certain impairment models based on our risk assessment.
•We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax forecasts, by comparing forecasts to approved internal and third party budgets, development plans, independent expectations and historical actuals.
•Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been determined and applied on a consistent basis across the group.
2.Intangible assets – Write-off of Exploration and Appraisal (E&A) assets, included within 'intangible assets' within the Group balance sheet – Notes 1, 8 and 15 to the financial statements
Critical Audit Matter Description
The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At 31 December 2020, $4.1 billion of E&A expenditure was carried on the group balance sheet.
E&A activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the related capitalised costs when the relevant criteria in IFRS 6 and bp’s accounting policy are met.
Furthermore, similar to gas & low carbon energy and oil production & operations PP&E assets discussed above, E&A assets are also potentially exposed to climate change, the global energy transition, and COVID-19, in that a greater number of E&A projects may not proceed as a consequence of lower forecast future demand and oil and gas pricing, lower appetite by management and the board to allocate capital to certain projects, and/or increased objections from stakeholders to the development of certain projects.
bp Annual Report and Form 20-F 2020
10
As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition and a decision not to explore in new countries, and reflecting lower oil and gas price assumptions, management identified IFRS 6 impairment indicators at a number of gas & low carbon energy and oil production & operations’s largest E&A assets during the year. This led to management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020, detailed further in Notes 1 and 8 on pages 22 and 45 of this report.
The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A assets, can be complex and require significant judgement from management in assessing this. There is a risk that certain capitalised E&A costs are written off or impaired when they should not have been, due to inappropriate and/or inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material misstatements. There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or impaired, leading to material misstatements.
We identified a critical audit matter for the individually material E&A write-offs recorded in 2020, specifically the Kaskida and Tigris (Paleogene) licenses that were the largest part of the $2.5 billion Gulf of Mexico write downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion Canada write downs and the three licenses that were the largest part of the $2.1 billion Brazil write-downs. We also identified higher risks in relation to certain other 2020 E&A write-offs and impairments recorded; and higher risks at certain assets within the $4.4 billion of E&A costs that remain capitalised under IFRS 6 at 31 December 2020.
How the Critical Audit Matter was addressed in the Audit
We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal controls. This included the key internal controls operated by management for the key decisions taken as a result of bp’s new strategy, which when taken together with the lower forecast oil and gas prices, led to a large portion of the material write-offs and impairments recorded during 2020.
We challenged management’s key E&A judgements, with regards to the impairment criteria of IFRS 6 and bp’s accounting policy. We corroborated key internal and external evidence relevant to significant write-offs and the assets that remained on the balance sheet. This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting judgement papers, holding discussions to challenge top level operational and finance management on the key judgements taken and reading meeting minutes, license documentation and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms, and external press releases.
For E&A assets that were written off or impaired by management in 2020, including in particular those based upon decisions taken in line with management’s new strategy, we considered whether evidence (and potential contradictory evidence) about activity in the year, future budgeted expenditure and exploration/appraisal plans, including plans and expectations for licence relinquishment or retention, were consistent with the decisions taken by management to write-off or impair these assets.
We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment assessments, taking account of in year judgements and historical look back considerations, and the relevant facts and circumstances of specific E&A assets.
When considering capital allocation decision making, we considered whether the progression of any projects that remain on the balance sheet would be inconsistent with elements of bp’s new strategy and in particular its net zero carbon commitments.
3.Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other Level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts, in particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements
Critical Audit Matter Description
In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these transactions requires significant audit effort to be directed towards challenging management’s valuation estimates or the adopted accounting treatment.
We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year focussing particularly on the impact of COVID-19 on the valuation assertion. This process has provided us with a deeper understanding of the impact of market volatility, demand destruction and the changing structure of the markets in which bp operates.
Accounting for structured commodity transactions:
T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the following features:
•Two or more counterparties with non-standard contractual terms;
•Multiple commodity-based transactions; and/or
•Contractual arrangements entered into in contemplation of each other.
SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or unobservable inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, ‘Fair Value Measurement’.
Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple elements that will have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance measures, including in particular the classification of liabilities as finance debt. Accordingly, we have identified the accounting for SCTs as a critical audit matter.
Level 3 financial instruments:
Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there are certain transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or unobservable inputs. These instruments are classified as level 3 financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk.
As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion and $8.4 billion, of which level 3 derivative financial assets were $6.4 billion and level 3 derivative financial liabilities were $5.3 billion.
How the Critical Audit Matter was addressed in the Audit
Accounting for SCTs
For structured commodity transactions, we:
•Tested controls related to the accounting for complex transactions.
.
11
bp Annual Report and Form 20-F 2020
Financial statements
•Developed an understanding of the commercial rationale of the transactions through reading transaction documents and executed agreements, and discussions with management.
•Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working capital arrangements, offtake arrangements and/or commitments. We confirmed that any day one profits were appropriately deferred.
For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our assessment in 2020 taking account of any amendments to the contracts.
To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team.
Level 3 financial instruments:
To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the following control and substantive procedures:
•We tested the group’s valuation controls including the:
–Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation methodology; and
–Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are significant to the financial instrument’s valuation.
•We performed substantive valuation testing procedures at interim and year-end balance sheet date, including:
–Comparing management’s input assumptions against the expected assumptions of other market participants and observable market data;
–Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is applied across the business period over period; and
–Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify consistency in management’s modelling and input assumptions throughout the year. Our independent estimates were established using independently sourced inputs (where available). We evaluated whether the differences between our independent estimates and management’s estimates were within a reasonable range. In situations where we utilised management’s inputs, these were compared to external data sources to determine whether they were reasonable.
/s/ Deloitte LLP
London
United Kingdom
22 March 2021, except for the change in accounting policy related to the presentation of revenues and purchases relating to physically settled derivative contracts disclosed in Note 1 and the change in segmentation disclosed in Notes 1 and 5, as to which the date is 31 January 2022.
The first accounting period we audited was the 12 month period ended 31 December 2018.
bp Annual Report and Form 20-F 2020
12
Group income statement
For the year ended 31 December
$ million
Note
2020a
2019a
2018a
Sales and other operating revenues(a)
6
105,944
159,307
165,165
Earnings from joint ventures – after interest and tax
16
(302)
576
897
Earnings from associates – after interest and tax
17
(101)
2,681
2,856
Interest and other income
7
663
769
773
Gains on sale of businesses and fixed assets
4
2,874
193
456
Total revenues and other income
109,078
163,526
170,147
Purchases(a)
19
57,682
90,582
96,287
Production and manufacturing expenses
22,494
21,815
23,005
Production and similar taxes
5
695
1,547
1,536
Depreciation, depletion and amortization
5
14,889
17,780
15,457
Impairment and losses on sale of businesses and fixed assets
4
14,381
8,075
860
Exploration expense
8
10,280
964
1,445
Distribution and administration expenses
10,397
11,057
12,179
Profit (loss) before interest and taxation
(21,740)
11,706
19,378
Finance costs
7
3,115
3,489
2,528
Net finance expense relating to pensions and other post-retirement benefits
24
33
63
127
Profit (loss) before taxation
(24,888)
8,154
16,723
Taxation
9
(4,159)
3,964
7,145
Profit (loss) for the year
(20,729)
4,190
9,578
Attributable to
bp shareholders
(20,305)
4,026
9,383
Non-controlling interests
(424)
164
195
(20,729)
4,190
9,578
Earnings per share
Profit (loss) for the year attributable to bp shareholders
Per ordinary share (cents)
Basic
11
(100.42)
19.84
46.98
Diluted
11
(100.42)
19.73
46.67
Per ADS (dollars)
Basic
11
(6.03)
1.19
2.82
Diluted
11
(6.03)
1.18
2.80
a Amounts have been restated as a result of changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. See Note 1 - Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts.
13
bp Annual Report and Form 20-F 2020
Financial statements
Group statement of comprehensive incomea
For the year ended 31 December
$ million
Note
2020
2019
2018
Profit (loss) for the year
(20,729)
4,190
9,578
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences
(1,843)
1,538
(3,771)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets
(353)
880
—
Cash flow hedges marked to market
30
78
(100)
(126)
Cash flow hedges reclassified to the income statement
30
(37)
106
120
Costs of hedging marked to market
30
42
(4)
(244)
Costs of hedging reclassified to the income statement
30
22
57
58
Share of items relating to equity-accounted entities, net of tax
16, 17
312
82
417
Income tax relating to items that may be reclassified
9
66
(70)
4
(1,713)
2,489
(3,542)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
24
170
328
2,317
Cash flow hedges that will subsequently be transferred to the balance sheet
30
7
(3)
(37)
Income tax relating to items that will not be reclassified
9
(105)
(157)
(718)
72
168
1,562
Other comprehensive income
(1,641)
2,657
(1,980)
Total comprehensive income
(22,370)
6,847
7,598
Attributable to
bp shareholders
(21,983)
6,674
7,444
Non-controlling interests
(387)
173
154
(22,370)
6,847
7,598
a See Note 32 for further information.
bp Annual Report and Form 20-F 2020
14
Group statement of changes in equitya
$ million
Share capital and capital reserves
Treasury shares
Foreign currency translation reserve
Fair value reserves
Profit and loss account
bp shareholders' equity
Non-controlling interests
Total equity
Hybrid bonds
Other interest
At 1 January 2020
46,525
(14,412)
(6,495)
(912)
73,706
98,412
—
2,296
100,708
Profit for the year
—
—
—
—
(20,305)
(20,305)
256
(680)
(20,729)
Other comprehensive income
—
—
(2,224)
98
448
(1,678)
—
37
(1,641)
Total comprehensive income
—
—
(2,224)
98
(19,857)
(21,983)
256
(643)
(22,370)
Dividendsb
—
—
—
—
(6,367)
(6,367)
—
(238)
(6,605)
Cash flow hedges transferred to the balance sheet, net of tax
—
—
—
6
—
6
—
—
6
Repurchase of ordinary share capital
—
—
—
—
(776)
(776)
—
—
(776)
Share-based payments, net of tax
176
1,188
—
—
(638)
726
—
—
726
Share of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
1,341
1,341
—
—
1,341
Issue of perpetual hybrid bonds
—
—
—
—
(48)
(48)
11,909
—
11,861
Payments on perpetual hybrid bonds
—
—
—
—
—
—
(89)
—
(89)
Tax on issue of perpetual hybrid bonds
—
—
—
—
3
3
—
—
3
Transactions involving non-controlling interests, net of tax
—
—
—
—
(64)
(64)
—
827
763
At 31 December 2020
46,701
(13,224)
(8,719)
(808)
47,300
71,250
12,076
2,242
85,568
At 31 December 2018
46,352
(15,767)
(8,902)
(987)
78,748
99,444
—
2,104
101,548
Adjustment on adoption of IFRS 16, net of tax
—
—
—
—
(329)
(329)
—
(1)
(330)
At 1 January 2019
46,352
(15,767)
(8,902)
(987)
78,419
99,115
—
2,103
101,218
Profit for the year
—
—
—
—
4,026
4,026
—
164
4,190
Other comprehensive income
—
—
2,407
52
189
2,648
—
9
2,657
Total comprehensive income
—
—
2,407
52
4,215
6,674
—
173
6,847
Dividendsb
—
—
—
—
(6,929)
(6,929)
—
(213)
(7,142)
Cash flow hedges transferred to the balance sheet, net of tax
—
—
—
23
—
23
—
—
23
Repurchase of ordinary share capital
—
—
—
—
(1,511)
(1,511)
—
—
(1,511)
Share-based payments, net of tax
173
1,355
—
—
(809)
719
—
—
719
Share of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
5
5
—
—
5
Transactions involving non-controlling interests, net of tax
—
—
—
—
316
316
—
233
549
At 31 December 2019
46,525
(14,412)
(6,495)
(912)
73,706
98,412
—
2,296
100,708
At 31 December 2017
46,122
(16,958)
(5,156)
(743)
75,226
98,491
—
1,913
100,404
Adjustment on adoption of IFRS 9, net of tax
—
—
—
(54)
(126)
(180)
—
—
(180)
At 1 January 2018
46,122
(16,958)
(5,156)
(797)
75,100
98,311
—
1,913
100,224
Profit for the year
—
—
—
—
9,383
9,383
—
195
9,578
Other comprehensive income
—
—
(3,746)
(216)
2,023
(1,939)
—
(41)
(1,980)
Total comprehensive income
—
—
(3,746)
(216)
11,406
7,444
—
154
7,598
Dividendsb
—
—
—
—
(6,699)
(6,699)
—
(170)
(6,869)
Cash flow hedges transferred to the balance sheet, net of tax
—
—
—
26
—
26
—
—
26
Repurchase of ordinary share capital
—
—
—
—
(355)
(355)
—
—
(355)
Share-based payments, net of tax
230
1,191
—
—
(718)
703
—
—
703
Share of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
14
14
—
—
14
Transactions involving non-controlling interests, net of tax
—
—
—
—
—
—
—
207
207
At 31 December 2018
46,352
(15,767)
(8,902)
(987)
78,748
99,444
—
2,104
101,548
a See Note 32 for further information.
b See Note 10 for further information.
15
bp Annual Report and Form 20-F 2020
Financial statements
Group balance sheet
At 31 December
$ million
Note
2020
2019
Non-current assets
Property, plant and equipment
12
114,836
132,642
Goodwill
14
12,480
11,868
Intangible assets
15
6,093
15,539
Investments in joint ventures
16
8,362
9,991
Investments in associates
17
18,975
20,334
Other investments
18
2,746
1,276
Fixed assets
163,492
191,650
Loans
840
630
Trade and other receivables
20
4,351
2,147
Derivative financial instruments
30
9,755
6,314
Prepayments
533
781
Deferred tax assets
9
7,744
4,560
Defined benefit pension plan surpluses
24
7,957
7,053
194,672
213,135
Current assets
Loans
458
339
Inventories
19
16,873
20,880
Trade and other receivables
20
17,948
24,442
Derivative financial instruments
30
2,992
4,153
Prepayments
1,269
857
Current tax receivable
672
1,282
Other investments
18
333
169
Cash and cash equivalents
25
31,111
22,472
71,656
74,594
Assets classified as held for sale
2
1,326
7,465
72,982
82,059
Total assets
267,654
295,194
Current liabilities
Trade and other payables
22
36,014
46,829
Derivative financial instruments
30
2,998
3,261
Accruals
4,650
5,066
Lease liabilities
28
1,933
2,067
Finance debt
26
9,359
10,487
Current tax payable
1,038
2,039
Provisions
23
3,761
2,453
59,753
72,202
Liabilities directly associated with assets classified as held for sale
2
46
1,393
59,799
73,595
Non-current liabilities
Other payables
22
12,112
12,626
Derivative financial instruments
30
5,404
5,537
Accruals
852
996
Lease liabilities
28
7,329
7,655
Finance debt
26
63,305
57,237
Deferred tax liabilities
9
6,831
9,750
Provisions
23
17,200
18,498
Defined benefit pension plan and other post-retirement benefit plan deficits
24
9,254
8,592
122,287
120,891
Total liabilities
182,086
194,486
Net assets
85,568
100,708
Equity
bp shareholders’ equity
32
71,250
98,412
Non-controlling interests
32
14,318
2,296
Total equity
32
85,568
100,708
Helge Lund Chairman
Bernard Looney Chief executive officer
22 March 2021
bp Annual Report and Form 20-F 2020
16
Group cash flow statement
For the year ended 31 December
$ million
Note
2020
2019
2018
Operating activities
Profit (loss) before taxation
(24,888)
8,154
16,723
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off
8
9,920
631
1,085
Depreciation, depletion and amortization
5
14,889
17,780
15,457
Impairment and (gain) loss on sale of businesses and fixed assets
4
11,507
7,882
404
Earnings from joint ventures and associates
403
(3,257)
(3,753)
Dividends received from joint ventures and associates
1,442
1,962
1,535
Interest receivable
(258)
(441)
(468)
Interest received
74
416
348
Finance costs
7
3,115
3,489
2,528
Interest paid
(2,728)
(2,870)
(1,928)
Net finance expense relating to pensions and other post-retirement benefits
24
33
63
127
Share-based payments
723
730
690
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
24
(282)
(238)
(386)
Net charge for provisions, less payments
735
(176)
986
(Increase) decrease in inventories
3,963
(3,406)
672
(Increase) decrease in other current and non-current assets
4,230
(2,335)
(2,858)
Increase (decrease) in other current and non-current liabilities
(8,278)
2,823
(2,577)
Income taxes paid
(2,438)
(5,437)
(5,712)
Net cash provided by operating activities
12,162
25,770
22,873
Investing activities
Expenditure on property, plant and equipment, intangible and other assets
(12,306)
(15,418)
(16,707)
Acquisitions, net of cash acquired
3
(44)
(3,562)
(6,986)
Investment in joint ventures
(567)
(137)
(382)
Investment in associates
(1,138)
(304)
(1,013)
Total cash capital expenditure
(14,055)
(19,421)
(25,088)
Proceeds from disposals of fixed assets
4
491
500
940
Proceeds from disposals of businesses, net of cash disposed
4
4,989
1,701
1,911
Proceeds from loan repayments
717
246
666
Net cash used in investing activities
(7,858)
(16,974)
(21,571)
Financing activities
Repurchase of shares
(776)
(1,511)
(355)
Lease liability payments
(2,442)
(2,372)
(35)
Proceeds from long-term financing
14,736
8,597
9,038
Repayments of long-term financing
(12,179)
(7,118)
(7,175)
Net increase (decrease) in short-term debt
(1,234)
180
1,317
Issue of perpetual hybrid bonds
11,861
—
—
Payments on perpetual hybrid bonds
(89)
—
—
Payments relating to transactions involving non-controlling interests (other)
(8)
—
—
Receipts relating to transactions involving non-controlling interests (other)
665
566
—
Dividends paid
bp shareholders
10
(6,340)
(6,946)
(6,699)
Non-controlling interests
(238)
(213)
(170)
Net cash provided by (used in) financing activities
3,956
(8,817)
(4,079)
Currency translation differences relating to cash and cash equivalents
379
25
(330)
Increase (decrease) in cash and cash equivalents
8,639
4
(3,107)
Cash and cash equivalents at beginning of year
22,472
22,468
25,575
Cash and cash equivalents at end of year
31,111
22,472
22,468
17
bp Annual Report and Form 20-F 2020
Financial statements
Notes on financial statements
1. Significant accounting policies, judgements, estimates and assumptions
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) for the year ended 31 December 2020 were originally approved and signed by the chief executive officer and chairman on 22 March 2021 having been duly authorized to do so by the board of directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. They were amended as of 31 January 2022 solely to reflect a change in segmentation and a voluntary change in accounting policy related derivative contracts. See Other changes to significant accounting policies below. The consolidated financial statements have been prepared in accordance with 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 years presented. As a result of the UK's withdrawal from the EU, with effect for periods starting subsequent to the year ended 31 December 2020, the consolidated financial statements will also be prepared in accordance with UK-adopted international accounting standards. There were no differences between IFRS as adopted by the EU and UK-adopted international accounting standards as at 1 January 2021. The UK’s withdrawal from the EU has not had and is not expected to have a significant impact on the consolidated financial statements. The significant accounting policies and accounting judgements, estimates and assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2020. The accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated.
Significant accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for the investment in Rosneft; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; and pensions and other post-retirement benefits. Judgements and estimates, not all of which are significant, made in assessing the impact of the COVID-19 pandemic, and climate change and the transition to a lower carbon economy on the consolidated financial statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text.
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group’s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future.
Impairment of property, plant and equipment, and goodwill
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions.
Impairments were recognized during 2020 on certain upstream oil and gas properties as a result of the lower price assumptions. See note 4 for further information.
No material impairments were recognized on customers & products assets. Though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery’s useful life.
Headroom on goodwill balances was reduced, however the recoverable amount exceeds the carrying amount. See note 14 for further information including sensitivity analysis on the assumptions used to test goodwill for impairment.
Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future.
Exploration and appraisal intangible assets
The energy transition may affect the future development or viability of exploration prospects. The lower price assumptions and work to develop bp’s new strategy resulted in a review of the recoverability of exploration and appraisal intangible assets during 2020. Certain intangible assets were subsequently written-off. See significant judgement: exploration and appraisal intangible assets and note 8 for further information.
The revised long-term price assumptions for investment appraisal (see page 28 of bp Annual Report and Form 20-F 2020) help create a framework that seeks to help ensure that currently unsanctioned future capital expenditure on property plant and equipment, and exploration and appraisal intangibles, is aligned with bp’s new strategy.
Property, plant and equipment – depreciation and expected useful lives
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, the significant majority of bp’s existing upstream oil and natural gas properties are likely to be fully depreciated within the next 10 years and, as outlined in bp's new strategy, oil and natural gas production will remain an important part of bp’s business activities over that period. Similarly, for customers & products refineries, demand for refined products is expected to remain strong over the remaining useful life of existing assets.
bp Annual Report and Form 20-F 2020
18
1. Significant accounting policies, judgements, estimates and assumptions – continued
Therefore, management does not expect the useful lives of bp’s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects and therefore the useful lives of future capital expenditure may, however, be different. See significant accounting policy: property, plant and equipment for more information.
Provisions: decommissioning
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp’s upstream oil and gas properties are expected to start decommissioning within the next two decades and management does not expect any reasonable change in the expected timeframe to have a material effect on the gas & low carbon energy and oil. production & operations decommissioning provisions, assuming cash flows remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For customers & products refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management will continue to review facts and circumstances to assess if decommissioning provisions need to be recognized. See significant judgements and estimates: provisions for further information.
Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment
In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the COVID-19 pandemic and current economic environment.
Going concern
Forecast liquidity has been assessed under a number of stressed scenarios, including a significant decline in oil prices over the 12-month period. Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the consolidated financial statements even if the Brent price fell to zero. No material uncertainties over going concern or significant judgements or estimates in the assessment were identified. See also Note 29 Financial instruments and financial risk factors – Liquidity risk for further information.
Discount rate assumptions
The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact was determined not to be significant and the post-tax impairment discount rate and nominal provisions discount rate were unchanged from 2019. Pre-tax impairment discount rates and post-tax premiums for certain higher-risk countries were changed but this did not have a material impact. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information.
Oil and natural gas price assumptions
The price assumptions used in value-in-use impairment testing were revised downwards during the year, in part due to lower demand for oil and natural gas. Material impairment charges and exploration write-offs were recognized in the gas & low carbon energy and oil, production & operations segments as a consequence of these price assumption changes. See significant judgements and estimates: recoverability of asset carrying values and exploration and appraisal intangible assets for further information.
Demand constraints for refined products during the year did not result in any material impairment charges on customers & products refinery assets.
Pensions and other post-retirement benefits
The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group’s defined benefit pension plans. See significant estimate: pensions and other post-retirement benefits and note 24 for further information.
Impairment of financial assets measured at amortized cost
The current economic environment and future credit risk outlook were considered in updating the estimate of expected credit loss allowances on financial assets measured at amortized cost. Whilst credit risk increased relative to 31 December 2019, there was also 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 did not significantly increase. Management does not consider the calculation of expected credit loss allowances to be a significant accounting estimate. See note 21 and 29 for further information.
Income taxes
The carrying amounts of the group’s deferred tax assets were reviewed and updated to the extent that there are changes in the probability of sufficient taxable profits being available to utilize the reported deferred tax assets. Management does not consider the measurement of deferred tax assets to be a significant accounting estimate. See significant accounting policy: income taxes and Note 9 for further information.
Basis of consolidation
The consolidated group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year. Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is obtained via potential voting rights, and continue to be consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-controlling interests are perpetual subordinated hybrid bonds issued by a subsidiary and for which the group has the unconditional right to avoid transferring cash or another financial asset to the bondholders. Profit or loss attributable to bp shareholders is adjusted to reflect the coupon related to these hybrid bonds whether or not such distribution has been deferred.
Interests in other entities
Business combinations and goodwill
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at their fair values at the acquisition date.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's proportionate share in
19
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments.
Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates.
Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.
Interests in joint arrangements
The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of accounting as described below.
Certain of the group’s activities, particularly in the gas & low carbon energy and oil production & operations segments, are conducted through joint operations. bp recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation.
Interests in associates
The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting as described below.
Significant judgement: investment in Rosneft
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Rosneft's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Rosneft's oil and natural gas reserves would be reported.
Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee.
bp owns 19.75% of the voting shares of Rosneft. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019 50% plus one share) of the voting shares of Rosneft . IFRS identifies several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making processes. bp’s group chief executive, Bernard Looney, was approved as a member of the board of directors of Rosneft in June 2020 as one of bp’s two nominated directors. bp’s other nominated director, Bob Dudley, has been a member of the Rosneft board since 2013. He is also chairman of the Rosneft board’s Strategic and Sustainable Development Committee. bp also holds the voting rights at general meetings of shareholders conferred by its 19.75% stake in Rosneft. Transactions by Rosneft in its own shares during the year have increased bp’s economic interest in Rosneft to 22.03% (2019 19.75%). bp's management considers, therefore, that the group has significant influence over Rosneft, as defined by IFRS.
The equity method of accounting
Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted entity is recognized in the group’s statement of changes in equity.
Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise in the accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group.
Unrealized gains on transactions, apart from those that meet the definition of a derivative, between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity.
The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.
Segmental reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief executive, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Note 5.
For information on changes to bp's segmental reporting see ‘Change in segmentation from 1 January 2021’ below.
bp Annual Report and Form 20-F 2020
20
1. Significant accounting policies, judgements, estimates and assumptions – continued
Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement, unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement.
Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.
Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.
Intangible assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses.
Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to fifteen years. Computer software costs generally have a useful life of three to five years.
The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the amortization method are accounted for prospectively.
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting as described below.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon internal approval for development and recognition of proved or sanctioned probable reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed.
Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are expensed.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly planned.
Development expenditure
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment.
21
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgement: exploration and appraisal intangible assets
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established.The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed.
As a result of the revised price assumptions detailed in Significant judgements and estimates: recoverability of asset carrying values below and a review of bp’s long-term strategic plan, management reviewed bp’s exploration prospects and the carrying value of the associated intangible assets. The outcome of the review resulted in revised judgements over management's expectations to extract value from certain prospects, thereby leading to material write-offs of the associated exploration and appraisal intangible assets in 2020.
The carrying amount of capitalized costs and further information on the write-offs are included in Note 8.
Property, plant and equipment
Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if applicable, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred.
Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.
Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties. Therefore, where this approach is adopted, charges are not dependent on management forecasts of future oil and gas prices.
However, for certain oil and natural gas assets, the use of reserves determined in accordance with SEC regulations would result in a charge that is not reflective of the pattern in which the future economic benefits are expected to be consumed. In these limited instances other approaches are applied to determine the reserves base used to calculate depreciation, depletion and amortization, including the use of management’s best estimate of price assumptions as disclosed in Significant judgements and estimates: recoverability of asset carrying values, to determine the commerciality of technical proved reserves.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production.
The estimation of oil and natural gas reserves and bp’s process to manage reserves bookings is described in Supplementary information on oil and natural gas on page 231 of bp Annual Report and Form 20-F 2020, which is unaudited. Details on bp’s proved reserves and production compliance and governance processes are provided on page 312 of bp Annual Report and Form 20-F 2020. The 2020 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary information on oil and natural gas (unaudited) on page 231 of bp Annual Report and Form 20-F 2020.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other property, plant and equipment are as follows:
Land improvements
15 to 25 years
Buildings
20 to 50 years
Refineries
20 to 30 years
Petrochemicals plants
20 to 30 years
Pipelines
10 to 50 years
Service stations
15 years
Office equipment
3 to 10 years
Fixtures and fittings
5 to 15 years
The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives or the depreciation method are accounted for prospectively.An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized.
bp Annual Report and Form 20-F 2020
22
1. Significant accounting policies, judgements, estimates and assumptions – continued
Impairment of property, plant and equipment, intangible assets, and goodwill
The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose rather than retain assets, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount.
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the group operates. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group that are not reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current market assessments of the time value of money.
Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. In limited circumstances where recent market transactions are not available for reference, discounted cash flow techniques are applied. Where discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period.
23
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgements and estimates: recoverability of asset carrying values
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill.
As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data.
Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15.
The estimates for assumptions made in impairment tests in 2020 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year.
Discount rates
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use the post-tax discount rate.
The discount rates applied in impairment tests are reassessed each year and in 2020, the post-tax discount rate was 6% (2019 6%). Where the CGU is located in a country that was judged to be higher risk an additional premium of 1% to 3% was reflected in the post-tax discount rate (2019 1% to 4%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors. The pre-tax discount rate typically ranged from 7% to 15% (2019 7% to 13%) depending on the risk premium and applicable tax rate in the geographic location of the CGU.
Oil and natural gas properties
For upstream oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors.
In 2020, the group identified upstream oil and gas properties with carrying amounts totalling $45,027 million (2019 $25,092 million) where the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in 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 risk of impairment reversals or charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year,see Sensitivity analyses, below.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above.
Oil and natural gas prices
The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisal price assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and demand forecasts under various energy transition scenarios. They are reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they are not met.
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, bp revised its price assumptions for value-in-use impairment testing, lowering them compared to those used in 2019 and extending the period covered to 2050. These price assumptions are derived from the central case investment appraisal assumptions (see page 28 of bp Annual Report and Form 20-F 2020). A summary of the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent management’s best estimate of future prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are considered by bp to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2% (2019 2%) is applied to determine the price assumptions in nominal terms.
2021
2025
2030
2040
2050
Brent oil ($/bbl)
50
50
60
60
50
Henry Hub gas ($/mmBtu)
3.00
3.00
3.00
3.00
2.75
bp Annual Report and Form 20-F 2020
24
1. Significant accounting policies, judgements, estimates and assumptions – continued
Material impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 4 for further information.
The long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests in 2019 were $70 per barrel for Brent and $4 per mmBtu for Henry Hub gas, both in 2015 prices. These long-term prices were applied from 2025 and 2032 respectively inflated for the remaining life of the asset.
The price assumptions used in 2019 over the periods to 2025 and 2032 were set such that there was a linear progression from our best estimate of 2020 prices to the long-term assumptions.
The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced over the next 10 years.
Oil prices fell 35% in 2020 from 2019 due to trade tensions, a macroeconomic downturn and a slowdown in oil demand, reflecting the impact of the COVID-19 pandemic. OPEC+ production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. bp's long-term assumption for oil prices is higher than the 2020 price average, based on the judgement that current price levels would not encourage sufficient investment to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing economies.
US gas prices dropped by around 20% in 2020 compared to 2019. Henry Hub gas prices were already low in early 2020 due to mild weather. The drop in demand from the second quarter onward as a result of the COVID-19 pandemic as well as significant US LNG shut-ins contributed to prices remaining below $2/mmBtu during the second and third quarters, despite a record consumption in the power sector and the drop in natural gas production. Prices recovered in the fourth quarter due to the seasonal gas demand increase and the strong recovery in US LNG exports. bp's long-term price assumption for US gas reflects the fact that over the coming decades US gas production increases with an increasing proportion of production being used as feedstock to supply expanding LNG exports, while in the longer-term falling gas consumption and declining demand for global LNG exports leads to increasing competitive pressure on US gas production.
Oil and natural gas reserves
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements.
Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable.
Sensitivity analyses
A change in revenue from upstream oil and gas properties can arise either due to changes in oil and natural gas prices, changes in oil and natural gas production, or a combination of the two.
Management tested the impact of a change in revenue cash flows in value-in-use impairment testing arising from changes in price assumptions and/or production volumes up to a combined effect on revenue of 10% in all future years.
Revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s upstream oil and gas properties in the range of $6-7 billion, which is approximately 5-6% of the net book value of property, plant and equipment as at 31 December 2020.
Revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp’s upstream oil and gas properties in the range of $4-5 billion, which is approximately 3-4% of the net book value of property, plant and equipment as at 31 December 2020. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments.
These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses therefore do not reflect a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors plus the diverse characteristics of our upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes.
Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of upstream oil and gas properties. If the discount rate was one percentage point higher across all tests performed, the impairment charge recognized in 2020 would have been approximately $2.4 billion higher. If the discount rate was one percentage point lower, the impairment charge recognized would have been approximately $2.7 billion lower.
Goodwill
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of approximately $12.5 billion on its balance sheet (2019 $11.9 billion), principally relating to the Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information relating to impairment testing of goodwill in the gas & low carbon and oil production & operations segments are provided in Note 14.
Inventories
Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence about their net realizable value at the end of the period.
Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement.
Supplies are valued at the lower of cost on a weighted average basis and net realizable value.
25
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Leases
Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any substitution rights held by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for as leases. See significant accounting policy: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise. The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate, payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are presented as financing cash flows and payments of interest are presented as operating cash flows.
Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or development expenditure.
The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting policy for impairment of property, plant and equipment, intangible assets and goodwill.
Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the calculation of the lease liability and right-of-use asset.
If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease expense is recognized in the income statement on a straight-line basis.
If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset adjusted by an equivalent amount.
Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole signatory to the lease. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over the right-of-use asset, otherwise no balances are recognized.
Financial assets
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or substantially all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This includes the derecognition of receivables for which discounting arrangements are entered into.
The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables.
Financial assets measured at fair value through other comprehensive income
Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest.
Financial assets measured at fair value through profit or loss
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
bp Annual Report and Form 20-F 2020
26
1. Significant accounting policies, judgements, estimates and assumptions – continued
Investments in equity instruments
Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by-instrument basis to recognise fair value gains and losses in other comprehensive income.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Cash equivalents
Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or, in the case of certain money market funds, fair value through profit or loss.
Impairment of financial assets measured at amortized cost
The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income statement.
A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
Equity instruments
Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments that cannot be settled in the group’s own equity instruments and that include no contractual obligation to deliver cash or another financial asset or to exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity. Equity instruments issued by the group are recognized at the proceeds received, net of direct issue costs.
Financial liabilities
Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.
This category of financial liabilities includes trade and other payables and finance debt.
The group’s trade payables include some supplier arrangements that utilize letter of credit facilities. Judgement is required to assesses the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information.
Financial guarantees
The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred because certain associates, joint ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.
27
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement.
For the purpose of hedge accounting, hedges are classified as:
•Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
•Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over the hedged item's remaining period to maturity.
Cash flow hedges
The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction affects profit or loss.
Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset or liability, such as a forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as appropriate.
Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.
Costs of hedging
The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to the hedged item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis over the term of the hedging relationship.
Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or bp’s assumptions about pricing by market participants.
bp Annual Report and Form 20-F 2020
28
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant estimate and judgement: derivative financial instruments
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. For more information, including the carrying amounts of level 3 derivatives, see Note 30.
In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement and so are accounted for on an accruals basis, rather than as a derivative.
Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether a current legally enforceable right to set off exists.
Provisions and contingencies
Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 2.5% (2019 2.5%).
Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current).
Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate.
An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is generating or is expected to generate future economic benefits.
Environmental expenditures and liabilities
Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been estimated using existing technology, at future prices and discounted using a nominal discount rate.
Emissions
Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the expenditure required to settle the present obligation at the balance sheet date. It is based on the excess of actual emissions over the free allowances held or set baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been purchased and held for own use on a first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the basis of the spot market price of allowances at the balance sheet date. The cost of allowances purchased to cover a shortfall is recognized separately on the balance sheet as an intangible asset unless the emission allowances acquired or generated by the group are risk-managed by the integrated supply and trading function, then they are recognized on the balance sheet as inventory.
29
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Restructuring provisions
The reinvent bp programme, expected to reduce headcount by around 10,000 positions, has resulted in recognition of provisions where a detailed formal plan exists, and a valid expectation of risk of redundancy has been made to those affected but where the specific outcomes remain uncertain . Where formal redundancy offers have been made, the obligations for those amounts are reported as payables and, if not, as provisions if unpaid at the year-end.
Significant judgements and estimates: provisions
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and the asset.
If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2020 (2019 no material provisions) for assets sold to third parties where the sale transferred the decommissioning obligation to the new owner.
Decommissioning provisions associated with customers & products refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates.Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates.
The group performs periodic reviews of its customers & products refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision.
The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2020 was 2.5% (2019 2.5%), which was based on long-dated US government bonds. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 18 years (2019 18 years) and 6 years (2019 6 years) respectively. Costs at future prices are determined by applying an inflation rate of 1.5% (2019 1.5%) to decommissioning costs and 2% (2019 2%) for all other provisions. A lower rate is applied to decommissioning as certain costs are expected to remain fixed at current or past prices.
Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 0.5 percentage point decrease in the nominal discount rate applied could increase the group’s provision balances by approximately $1.3 billion (2019 $1.4 billion). The pre-tax impact on the group income statement would be a charge of approximately $0.5 billion.
The discounting impact on the group's upstream decommissioning provisions of a two-year change in the timing of expected future decommissioning expenditures would not be material. Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year.
If all expected future decommissioning expenditures were 10% higher, the group's upstream decommissioning provisions would increase by approximately $1.4 billion and a pre-tax charge of approximately $0.5 billion would be recognized.
As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict.
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and any remaining unrecognized cost is expensed.
For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted.
bp Annual Report and Form 20-F 2020
30
1. Significant accounting policies, judgements, estimates and assumptions – continued
Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement.
Pensions and other post-retirement benefits
The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change.
Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or reductions in future contributions to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate: pensions and other post-retirement benefits
Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.
Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet, and pension and other post-retirement benefit expense for the following year.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the next financial year, in particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24.
Income taxes
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except:
•Where the deferred tax liability arises on the initial recognition of goodwill.
•Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss.
•In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.
Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
31
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously.
Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts the resolution of the uncertainty.
The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are required to be made of the amount of future taxable profits that will be available.Such judgements are inherently impacted by estimates affecting future taxable profits such as oil and natural gas prices and decommissioning expenditure, see significant judgements and estimates: recoverability of asset carrying values and provisions
Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 9 and Note 33.
Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new significant judgements were made in 2020 in this regard.
Customs duties and sales taxes
Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except:
•Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized as part of the cost of acquisition of the asset.
•Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
Own equity instruments – treasury shares
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement of changes in equity.
Revenue and other income
Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.
When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.
Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price adjustments, is disclosed as revenue from contracts with customers.
Sales and purchase of commodities accounted for under IFRS 15 are presented on a gross basis in Revenue from contracts with Customers and Purchases respectively. Physically settled derivatives which represent trading or optimization activities are presented net alongside financially settled derivative contracts in Other operating Revenues within sales and other operating income. Certain physically settled sale and purchase derivative contracts which are not part of trading and optimization activities are presented gross within other operating revenues and purchases respectively. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues. See also Other significant accounting policy changes - IFRIC agenda decision on IFRS 9 'Financial instruments' below.
bp Annual Report and Form 20-F 2020
32
1. Significant accounting policies, judgements, estimates and assumptions – continued
Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.
Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded.
Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Updates to significant accounting policies
Impact of new International Financial Reporting Standards
bp adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments: Disclosures’’ with effect from 1 January 2020. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the consolidated financial statements.
'Interest Rate Benchmark Reform – Phase I’
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.
This first phase of amendments to IFRS 9 provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by interest rate benchmark reforms.
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 have been applied to new hedging relationships designated after that date.
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.
See Note 29 Financial instruments and financial risk factors - interest rate risk and Note 30 Derivative financial instruments - Fair value hedges for further information.
Impact of new International Financial Reporting Standards - Not yet adopted
The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become effective for future financial reporting periods. There are no other standards, amendments or interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group.
IFRS 17 ' Insurance Contracts'
IFRS 17 'Insurance Contracts' provides a new general model for accounting for contracts where the issuer accepts significant insurance risk from another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance Contracts' and will be effective for bp for the financial reporting period commencing 1 January 2023. The standard has not yet been endorsed by the UK and the EU. bp's assessment of the impact of IFRS 17 is at an initial stage but it is not expected to have a significant effect on future financial reporting.
‘Interest Rate Benchmark Reform – Phase II’
Amendments to IFRS 9, IFRS 7, IFRS 4 and IFRS 16 ‘Leases’ were issued by the IASB in August 2020 to provide practical expedients and reliefs in relation to modifications of financial instruments and leases that arise from transition from IBORs to RFRs. Phase II also provides further reliefs to hedge accounting requirements. These amendments were effective for bp from 1 January 2021 and will be applied prospectively. The amendments have been endorsed by the UK and by the EU.
bp’s working group on interest rate benchmark reform is monitoring and managing the transition to alternative benchmark rates and is 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.
Other changes to significant accounting policies
Physically settled derivative contracts
In March 2019, 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 transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. 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.
33
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
bp changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020, as follows:
•Revenues and purchases from such contracts are measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues.
•There is no significant effect on current period or comparative information for ‘Sales and other operating revenues’ and ‘Purchases’ as presented in the group income statement, therefore no comparative information has been re-stated.
•There is no significant effect on net assets or on comparative information for ‘Profit before taxation’ or ‘Profit after taxation’ as presented in the group income statement.
In addition, bp chose to change its presentation of revenues from physically settled derivative sales contracts from 1 January 2020. Revenues from physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. In these financial statements 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 as a result of this accounting policy change to align with the current period as set out below. See also "voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts”.
$ million
2019 (previously reported)
2019 (re-presented – see note 6)
Presentational adjustments
2018 (previously reported)
2018 (re-presented – see note 6)
Presentational adjustments
Crude oil
62,130
9,141
52,989
65,276
10,331
54,945
Oil products
180,528
102,408
78,120
195,466
108,515
86,951
Natural gas, LNG and NGLs
20,167
18,909
1,258
21,745
20,494
1,251
Non-oil products and other revenues from contracts with customers
13,254
12,169
1,085
13,768
12,489
1,279
Revenue from contracts with customers
276,079
142,627
133,452
296,255
151,829
144,426
Other operating revenues
2,318
135,770
(133,452)
2,501
146,927
(144,426)
Total sales and other operating revenues
278,397
278,397
—
298,756
298,756
—
Other changes to significant accounting policies
Change in segmentation
During the first quarter of 2021, the group's reportable segments changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the chief executive officer, from that date. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment.
Customers & products comprises the group's customer-focused businesses, spanning convenience and mobility, which includes retail and fuels next-gen offers such as electrification, as well as aviation, midstream and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business is also included as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment.
The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.
The segment measure of profit or loss continues to be replacement cost profit or loss before interest and tax, which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and losses. See Note 5 for further information.
All periods have been restated in Notes 4, 5 and 14 to reflect the changes in reportable segments. References to segments have also changed in Notes 2, 8,16 and 28.
Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts
bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group previously presented revenues and purchases for such contracts on a gross basis in the income statement upon physical settlement.
These transactions have historically represented a substantial portion of the revenues and purchases reported in the group’s consolidated financial statements. The change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, resulted in the group determining that the revenue and corresponding purchases relating to such transactions should be presented net, as gains or losses within other operating revenues, from that date. Physically settled derivative contracts were previously presented on a gross basis and included in other operating revenues and purchases; however, under the new accounting policy, such contracts will be presented on a net basis within other operating revenues to the extent that they relate to trading or optimization activities.
Additionally, the group’s trading activity has continued to evolve over time from one of capturing third-party physical trades to provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which will continue under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant information for users of the accounts as the group’s revenue recognition is more closely aligned with its assessment of ‘Scope 3’ emissions from its products, its ‘Net Zero’ ambition and how management monitors and manages performance of such contracts. Comparative information for sales and other operating revenues and purchases for 2018, 2019 and 2020 has been restated as shown in the table below. There is no impact on comparative information for profit before income and tax or earnings per share.
bp Annual Report and Form 20-F 2020
34
Additionally, the group’s trading activity has continued to evolve over time from one of capturing third party physical trades to provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which will continue under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant information for users of the accounts as the group’s revenue recognition 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. Information for Sales and other operating revenues and purchases for 2018, 2019 and 2020 has been restated as shown in the table below. There is no impact on information for profit before income tax or earnings per share.
2020
2020
Impact of net
2019
2019
Impact of net
2018
2018
Impact of net
$ million
Restated
presentation(a)
Restated
presentation(a)
Restated
presentation(a)
Segment revenues (Note 5)
gas & low carbon energy
18,467
16,275
(2,192)
28,102
27,045
(1,057)
29,630
27,208
(2,422)
oil production & operations
17,234
17,234
—
28,702
28,702
—
29,675
29,675
—
customers & products
162,974
90,744
(72,230)
250,897
132,864
(118,033)
270,689
139,520
(131,169)
other businesses & corporate
1,666
1,666
—
1,418
1,418
—
1,112
1,112
—
200,341
125,919
(74,422)
309,119
190,029
(119,090)
331,106
197,515
(133,591)
Less: sales and other revenues between segments
gas & low carbon energy
2,708
2,708
—
3,097
3,097
—
3,740
3,740
—
oil production & operations
15,879
15,879
—
25,870
25,870
—
27,185
27,185
—
customers & products
158
158
—
973
973
—
574
574
—
other businesses & corporate
1,230
1,230
—
782
782
—
851
851
—
19,975
19,975
—
30,722
30,722
—
32,350
32,350
—
External sales and other operating revenues
gas & low carbon energy
15,759
13,567
(2,192)
25,005
23,948
(1,057)
25,890
23,468
(2,422)
oil production & operations
1,355
1,355
—
2,832
2,832
—
2,490
2,490
—
customers & products
162,816
90,586
(72,230)
249,924
131,891
(118,033)
270,115
138,946
(131,169)
other businesses & corporate
436
436
—
636
636
—
261
261
—
Total sales and other operating revenues
180,366
105,944
(74,422)
278,397
159,307
(119,090)
298,756
165,165
(133,591)
Sales and other operating revenues (note 6)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil
5,048
5,048
—
9,141
9,141
—
10,331
10,331
—
Oil products
63,564
63,564
—
102,408
102,408
—
108,515
108,515
—
Natural gas, LNG and NGLs
12,726
10,763
(1,963)
18,909
15,156
(3,753)
20,494
15,385
(5,109)
Non-oil products and other revenues from contracts with customers
9,840
9,778
(62)
12,169
10,838
(1,331)
12,489
11,970
(519)
Revenues from contracts with customers
91,178
89,153
(2,025)
142,627
137,543
(5,084)
151,829
146,201
(5,628)
Other operating revenues
89,188
16,791
(72,397)
135,770
21,764
(114,006)
146,927
18,964
(127,963)
Total sales and other operating revenues
180,366
105,944
(74,422)
278,397
159,307
(119,090)
298,756
165,165
(133,591)
Purchases
132,104
57,682
(74,422)
209,672
90,582
(119,090)
229,878
96,287
(133,591)
35
bp Annual Report and Form 20-F 2020
Financial statements
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 (2019 $7,465 million), with associated liabilities of $46 million (2019 $1,393 million).
gas & low carbon energy segment
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 were completed by 31 December 2020, are described below.
customers & products segment
On 29 June 2020 bp announced that it had agreed to sell its global petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary closing adjustments. The assets and liabilities of the business were classified as held for sale from that date until the disposal completed on 31 December 2020. Under the terms of the agreement, INEOS paid bp a deposit of $400 million and a further $3.6 billion on completion less $0.1 billion of third-party indebtedness remaining in petrochemicals on completion. The remaining $1 billion was received in February 2021. The business had interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. See note 4 for further information.
oil production & operations segment
On 27 August 2019, bp announced that it had agreed to sell its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to customary closing adjustments. The sale included bp’s upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owned all of 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 TAPS completed on 18 December 2020.
bp received $800 million prior to or on completion of the disposals and has recognized a loan note with a principal amount of $2,100 million receivable from Hilcorp. The group has also recognized other assets totalling $1,722 million as at 31 December 2020, principally in relation to the ‘earn-out’ provisions of the agreement. See note 4 for information on impairment charges relating to the Alaska business.
bp retained decommissioning liability relating to the TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp when incurred.
In November 2019, bp agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The transaction completed on 28 February 2020.
The total assets and liabilities held for sale at 31 December 2020 (which are all in the gas & low carbon energy segment) and 2019 (which are mainly in the oil production & operations segment), are set out in the table below.
$ million
2020
2019
Property, plant and equipment
1,099
6,359
Goodwill
199
—
Intangible assets
—
610
Investments in associates
—
43
Inventories
—
318
Trade and other receivables
28
135
Assets classified as held for sale
1,326
7,465
Trade and other payables
(36)
(33)
Lease liabilities
—
(280)
Provisions
(10)
(1,012)
Defined benefit pension plan and other post-retirement benefit plan deficits
—
(68)
Liabilities directly associated with assets classified as held for sale
(46)
(1,393)
3. Business combinations and other significant transactions
Business combinations
2020
The group undertook a number of business combinations during 2020. The fair value of the net assets (including goodwill) and non-controlling interests recognized were $617 million and $574 million, respectively. These principally related to an acquisition in our US Fuels business.
2019
As agreed as part of the original transaction, $3,480 million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy Corporation from BHP Billiton. A number of other individually insignificant business combinations were also undertaken by bp in 2019.
bp Annual Report and Form 20-F 2020
36
4. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments a.
$ million
2020
2019
2018
Gains on sale of businesses and fixed assets
gas & low carbon energy
—
—
51
oil production & operations
360
143
386
customers & products
2,320
50
15
other businesses and corporate
194
—
4
2,874
193
456
$ million
2020
2019
2018
Losses on sale of businesses and fixed assets, and closures
gas & low carbon energy
9
884
27
oil production & operations
375
409
687
customers & products
296
57
59
other businesses and corporate
1
9
4
681
1,359
777
Impairment losses
gas & low carbon energy
6,214
387
400
oil production & operations
6,723
6,365
254
customers & products
840
65
12
other businesses and corporate
12
30
—
13,789
6,847
666
Impairment reversals
gas & low carbon energy
(3)
—
(1)
oil production & operations
(86)
(131)
(580)
customers & products
—
—
(2)
other businesses and corporate
—
—
—
(89)
(131)
(583)
Impairment and losses on sale of businesses and fixed assets, and closures
14,381
8,075
860
Disposals
Disposal proceeds and principal gains and losses on disposals by segment are described below.
$ million
2020
2019
2018
Proceeds from disposals of fixed assets
491
500
940
Proceeds from disposals of businesses, net of cash disposed
4,989
1,701
1,911
5,480
2,201
2,851
By business
gas & low carbon energy
38
565
112
oil production & operations
1,157
1,472
2,107
customers & products
3,959
152
120
other businesses and corporate
326
12
512
5,480
2,201
2,851
a Information for 2018 to 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Significant accounting policies, judgements, estimates and assumptions - Change in segmentation.
Proceeds from disposals of business in 2020 includes $3,888 million in respect of the disposal of the Petrochemical business and $347 million in respect of the disposal of the Alaska business. At 31 December 2020, deferred consideration relating to disposals amounted to $1,291 million receivable within one year (2019 $159 million and 2018 $35 million) and $2,402 million receivable after one year (2019 $125 million and 2018 $304 million). The deferred consideration principally relates to the disposals of our Petrochemical and Alaskan businesses. In addition, contingent consideration receivable relating to disposals amounted to $1,999 million at 31 December 2020 (2019 $598 million and 2018 $893 million). The contingent consideration at 31 December 2020 relates to the disposal of our Alaskan business and prior period disposals in the North Sea. These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.
Gains and losses on sale of businesses and fixed assets, and closures
gas & low carbon energy
In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge Bioenergia.
In 2018 proceeds from disposals were principally in respect of wind farms within our US wind business.
37
bp Annual Report and Form 20-F 2020
Financial statements
4. Disposals and impairment – continued
oil production & operations
In 2020, gains principally resulted from adjustments to disposals in prior periods. Gains include $130 million from the disposal of our Alaska operations and interests and $166 million fair value movements in relation to deferred and contingent consideration in relation to the Alaska disposal and prior disposals in the North Sea. Losses included $134 million fair value movements in relation to deferred and contingent consideration arising from prior period disposals in the North Sea, $120 million in relation to the likely disposal of an exploration asset, and $78 million from the disposal of certain properties in the US.
In 2019, losses included $191 million fair value movements in relation to contingent consideration arising from the prior period disposal of the Bruce, Keith and Devenick assets and $171 million in relation to severance costs associated with the divestment of our Alaskan business.
In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of certain properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our interest in the Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk Area in the US, and adjustments to disposals in prior periods.
customers & products
In 2020, gains principally resulted from the $2.3 billion gain recognised on the disposal of our Petrochemicals business which completed in December 2020. Losses included $229 million in relation to cessation of manufacturing operations at the Kwinana Refinery following the decision to cease fuel production.
other businesses and corporate
In 2020 the gain on disposal of businesses and fixed assets was principally in respect of the sale and leaseback of our St James's Square London headquarters - see Note 28 for further information.
In 2018 proceeds from disposals were principally in respect of life insurance policies in the US.
Summarized financial information relating to the sale of businesses is shown in the table below.
The principal transactions categorized as a business disposal in 2020 were the sales of our Petrochemical and Alaskan businesses. See Note 2 for further information.
The principal transaction categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt.
The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US.
$ million
2020
2019
2018
Alaska
Petrochemicals
Other
Total
Non-current assets
5,143
2,592
1,357
9,092
1,653
3,274
Current assets
693
846
—
1,539
507
173
Non-current liabilities
(923)
(178)
(538)
(1,639)
(257)
(250)
Current liabilities
(344)
(425)
(13)
(782)
(108)
(97)
Total carrying amount of net assets disposed
4,569
2,835
806
8,210
1,795
3,100
Recycling of foreign exchange on disposal
—
(331)
3
(328)
880
—
Costs on disposal
(6)
(25)
44
13
190
3
4,563
2,479
853
7,895
2,865
3,103
Gains (losses) on sale of businesses
260
2,414
(104)
2,570
(1,190)
(221)
Total consideration
4,823
4,893
749
10,465
1,675
2,882
Non-cash consideration
(219)
—
—
(219)
(938)
(282)
Consideration received (receivable)a
(4,257)
(1,005)
5
(5,257)
964
(689)
Proceeds from the sale of businesses, net of cash disposedb
347
3,888
754
4,989
1,701
1,911
a In 2019 $633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business.
b Proceeds are stated net of cash and cash equivalents disposed of $101 million (2019 $30 million and 2018 $15 million).
Impairments
Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12, and Note 15 for further information on impairments by asset category.
gas & low carbon energy
Impairment losses and reversals in all years relate primarily to producing and midstream assets.
The 2020 impairment loss of $6,214 million primarily relates to losses incurred in respect of producing and development assets in Trinidad ($2,416 million), Mauritania and Senegal ($1,909 million) and India ($1,313 million). Impairment losses were primarily driven by a reduction in bp’s future oil and gas price assumptions and, to a lesser extent, certain technical reserves revisions. The recoverable amount of the impaired CGUs in total is $13,563 million.
The principal CGUs on which significant impairment losses were incurred in 2020 were $1,909 million for Tortue in Mauritania and Senegal; $1,313 million for KGD6 in India; $1,044 million for Mahogany in Trinidad and $960 million for Cassia in Trinidad. The recoverable amount for each of these CGUs was their value in use, which in total was $4,394 million.
The 2019 impairment losses of $387 million related to a number of different assets, with the most significant charges arising in Egypt and Trinidad.
The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets.
bp Annual Report and Form 20-F 2020
38
4. Disposals and impairment – continued
oil production & operations
Impairment losses and reversals in all years relate primarily to producing and midstream assets.
The 2020 impairment loss of $6,723 million primarily relates to losses incurred in respect of producing and development assets in the UK North Sea ($2,796 million), the US ($2,744 million) and Canada ($865 million). Impairment losses were primarily driven by a reduction in bp’s future oil and gas price assumptions and, to a lesser extent, certain technical reserves revisions. The recoverable amount of the impaired CGUs in total is $19,852 million.
The principal CGUs on which significant impairment losses were incurred in 2020 were $1,181 million for Schiehallion in the UK North Sea; $1,011 million for Hawkville in BPX Energy; $747 million for ETAP in the UK North Sea and $742 million for Sunrise in Canada. The recoverable amount for each of these CGUs was their value in use, which in total was $8,806 million. In addition, impairment losses of $939 million were incurred relating to the disposal of bp’s business in Alaska. The recoverable amount of the Alaska business was its fair value less costs of disposal; see note 2 for further information.
The 2019 impairment losses of $6,365 million related to various assets, with the most significant charges arising in the US. Impairment losses arose primarily as a result of the decision to dispose of certain assets, including $4,703 million in relation to completed and expected disposals in BPX Energy and $1,264 million relating to the expected disposal of our Alaskan business; of these amounts $355 million primarily relates to impairment of associated goodwill.
The 2018 impairment losses of $254 million related to a number of different assets, with the most significant charges arising in the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets. The 2018 impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the North Sea and Angola following a change to decommissioning cost estimates.
customers & products
Impairment losses totalling $840 million, $65 million, and $12 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2020 principally relates to portfolio changes in the fuels business, including the conversion of Kwinana refinery to an import terminal. None of the impairment charges were individually material.
other businesses and corporate
Impairment losses totalling $32 million, $30 million, and $254 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2018 is in respect of assets within our US wind business in advance of their disposal in December 2018.
39
bp Annual Report and Form 20-F 2020
Financial statements
5. Segmental analysis
During the first quarter of 2021, the group's reportable segments were changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the chief executive officer from that date. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment.
Customers & products comprises the group’s customer-focused businesses, spanning convenience and mobility, which includes fuels retail and next-gen offers such as electrification, as well as aviation, midstream, and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business will also be reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment.
The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.
All periods have been restated in Notes 4 and 14 to reflect the changes in reportable segments. References to segments have also changed in Notes 2, 8,16 and 28.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss continues to be replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of customers & products.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country of domicile.
a 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.
bp Annual Report and Form 20-F 2020
40
5. Segmental analysis – continued
$ million
2020
By business
gas & low carbon energy
oil production & operations
customers & products
Rosneft
other businesses & corporate
Consolidation adjustment and eliminations
Total group
Segment revenues
Sales and other operating revenues
16,275
17,234
90,744
—
1,666
(19,975)
105,944
Less: sales and other operating revenues between segments
(2,708)
(15,879)
(158)
—
(1,230)
19,975
—
Third party sales and other operating revenues
13,567
1,355
90,586
—
436
—
105,944
Earnings from joint ventures and associates – after interest and tax
(45)
(327)
214
(229)
(16)
—
(403)
Segment results
Replacement cost profit (loss) before interest and taxation
(7,068)
(14,583)
3,418
(149)
(579)
89
(18,872)
Inventory holding gains (losses)a
19
(2)
(2,796)
(89)
—
—
(2,868)
Profit (loss) before interest and taxation
(7,049)
(14,585)
622
(238)
(579)
89
(21,740)
Finance costs
(3,115)
Net finance expense relating to pensions and other post-retirement benefits
(33)
Profit before taxation
(24,888)
Other income statement items
Depreciation, depletion and amortization
US
96
3,700
1,359
—
39
—
5,194
Non-US
3,361
4,087
1,631
—
616
—
9,695
Charges for provisions, net of write-back of unused provisions, including change in discount rate
(2)
58
1,903
—
543
—
2,502
Segment assets
Investments in joint ventures and associates
3,663
8,154
3,671
11,808
41
—
27,337
Additions to non-current assetsb
3,507
5,321
5,359
—
570
—
14,757
a See explanation of inventory holding gains and losses on page 40 of this report.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
41
bp Annual Report and Form 20-F 2020
Financial statements
5. Segmental analysis – continued
$ million
2019
By business
gas & low carbon energy
oil production & operations
customers & products
Rosneft
other businesses & corporate
Consolidation adjustment and eliminations
Total group
Segment revenues
Sales and other operating revenues
27,045
28,702
132,864
—
1,418
(30,722)
159,307
Less: sales and other operating revenues between segments
(3,097)
(25,870)
(973)
—
(782)
30,722
—
Third party sales and other operating revenues
23,948
2,832
131,891
—
636
—
159,307
Earnings from joint ventures and associates – after interest and tax
81
518
374
2,295
(11)
—
3,257
Segment results
Replacement cost profit (loss) before interest and taxation
2,945
1,049
6,502
2,316
(1,848)
75
11,039
Inventory holding gains (losses)a
(6)
(2)
685
(10)
—
—
667
Profit (loss) before interest and taxation
2,939
1,047
7,187
2,306
(1,848)
75
11,706
Finance costs
(3,489)
Net finance expense relating to pensions and other post-retirement benefits
(63)
Profit before taxation
8,154
Other income statement items
Depreciation, depletion and amortization
US
79
4,614
1,335
—
34
—
6,062
Non-US
5,067
4,552
1,586
—
513
—
11,718
Charges for provisions, net of write-back of unused provisions, including change in discount rate
(9)
127
507
—
560
—
1,185
Segment assets
Investments in joint ventures and associates
4,695
9,038
3,609
12,927
56
—
30,325
Additions to non-current assetsb
7,609
9,705
4,011
—
1,288
—
22,613
a See explanation of inventory holding gains and losses on page 40 of this report.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
bp Annual Report and Form 20-F 2020
42
5. Segmental analysis – continued
$ million
2018
By business
gas & low carbon energy
oil production & operations
customers & products
Rosneft
other businesses & corporate
Consolidation adjustment and eliminations
Total group
Segment revenues
Sales and other operating revenues
27,208
29,675
139,520
—
1,112
(32,350)
165,165
Less: sales and other operating revenues between segments
(3,740)
(27,185)
(574)
—
(851)
32,350
—
Third party sales and other operating revenues
23,468
2,490
138,946
—
261
—
165,165
Earnings from joint ventures and associates – after interest and tax
124
774
589
2,283
(17)
—
3,753
Segment results
Replacement cost profit (loss) before interest and taxation
4,214
9,690
6,940
2,221
(3,097)
211
20,179
Inventory holding gains (losses)a
(7)
1
(862)
67
—
—
(801)
Profit (loss) before interest and taxation
4,207
9,691
6,078
2,288
(3,097)
211
19,378
Finance costs
(2,528)
Net finance expense relating to pensions and other post-retirement benefits
(127)
Profit before taxation
16,723
Other income statement items
Depreciation, depletion and amortization
US
62
4,183
900
—
25
—
5,170
Non-US
4,403
4,616
1,177
—
91
—
10,287
Charges for provisions, net of write-back of unused provisions, including change in discount rate
114
242
834
—
1,556
—
2,746
Segment assets
Investments in joint ventures and associates
3,777
9,606
2,772
10,074
91
—
26,320
Additions to non-current assetsb c
5,778
18,841
3,609
—
129
—
28,352
a See explanation of inventory holding gains and losses on page 40 of this report.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
c Amounts have been restated to include acquisitions.
$ million
2020
By geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
27,413
78,531
105,944
Other income statement items
Production and similar taxes
57
638
695
Non-current assets
Non-current assetsb c
52,493
108,786
161,279
a Non-US region includes UK $13,836 million
b Non-US region includes UK $19,583 million
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
$ million
2019
By geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
47,951
111,356
159,307
Other income statement items
Production and similar taxes
315
1,232
1,547
Non-current assets
Non-current assetsb c
57,757
133,398
191,155
a Non-US region includes UK $17,169 million.
b Non-US region includes UK $22,881 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
43
bp Annual Report and Form 20-F 2020
Financial statements
5. Segmental analysis – continued
$ million
2018
By geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
48,593
116,572
165,165
Other income statement items
Production and similar taxes
369
1,167
1,536
Non-current assets
Non-current assetsb c
68,188
124,060
192,248
a Non-US region includes UK $16,903 million.
b Non-US region includes UK $19,426 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
6. Sales and other operating revenues
$ million
2020
2019
2018
Crude oil
5,048
9,141
10,331
Oil products
63,564
102,408
108,515
Natural gas, LNG and NGLs
10,762
15,156
15,385
Non-oil products and other revenues from contracts with customers
9,779
10,838
11,970
Revenue from contracts with customers
89,153
137,543
146,201
Other operating revenuesa
16,791
21,764
18,964
Total sales and other operating revenues
105,944
159,307
165,165
a Principally relates to physically settled derivative sales contracts.
Amounts have been restated as a result of changes to the presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. See Note 1 - Voluntary change in accounting policy - Net presentation of revenues and purchases relating to physically settled derivative contracts.
An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5.
The group’s sales to customers of crude oil and oil products were substantially all made by the customers & products segment. The group’s sales to customers of natural gas, LNG and NGLs were made by the gas & low carbon energy segment. A significant majority of the group’s sales of non-oil products and other revenues from contracts with customers were made by the customers & products segment.
Amounts shown for revenue from contracts with customers and other operating revenues for 2018 and 2019 have been represented to align with the current period. See Note 1 - Other changes to significant accounting policies - Physically settled derivative contracts for further information.
7. Income statement analysis
$ million
2020
2019
2018
Interest and other income
Interest income from
Financial assets measured at amortized cost
215
371
421
Financial assets measured at fair value through profit or loss
25
49
39
Other income
423
349
313
663
769
773
Currency exchange losses charged to the income statementa
38
37
368
Expenditure on research and development
332
364
429
Costs relating to the Gulf of Mexico oil spill (pre-interest and tax)b
255
319
714
Finance costs
Interest expense on lease liabilitiesc
337
379
51
Interest expense on other liabilities measured at amortized costd
2,166
2,410
2,147
Capitalized at 2.75% (2019 3.50% and 2018 3.56%)e
(345)
(374)
(419)
Unwinding of discount on provisionsf
437
505
210
Unwinding of discount on other payables measured at amortized cost
520
569
539
3,115
3,489
2,528
a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
b Included within production and manufacturing expenses.
c Interest payable on lease liabilities in 2018 comparative period relates to leases previously classified as finance leases under IAS 17.
d 2020 includes a loss of $158 million associated with the buyback of finance debt.
e Tax relief on capitalized interest is approximately $83 million (2019 $51 million and 2018 $55 million).
f From 1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates.
bp Annual Report and Form 20-F 2020
44
8. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the gas & low carbon energy and oil production & operations segments.
For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.
$ million
2020
2019
2018
Exploration and evaluation costs
Exploration expenditure written offa
9,920
631
1,085
Other exploration costs
360
333
360
Exploration expense for the year
10,280
964
1,445
Impairment losses
156
2
137
Intangible assets – exploration and appraisal expenditureb c
4,113
14,091
15,989
Liabilities
71
73
60
Net assets
4,042
14,018
15,929
Cash used in operating activities
360
333
360
Cash used in investing activities
674
1,215
1,119
a 2020 includes $2,643 million in the Gulf of Mexico primarily relating to the Paleogene assets, $2,539 million in Canada primarily relating to Terre de Grace, $2,141 million in Brazil, $952 million in Egypt and $832 million in Angola. 2018 included $447 million in the deepwater Gulf of Mexico principally relating to licence expiries.
b 2019 includes approximately $2.5 billion relating to Canadian oil sands.
c Amount capitalized at 31 December 2020 relates to assets in various regions. The largest of these is $0.7 billion capitalised in the Middle East region.
9. Taxation
Tax on profit
$ million
2020
2019
2018
Current tax
Charge for the year
2,095
5,316
6,217
Adjustment in respect of prior yearsa
50
(68)
(221)
2,145
5,248
5,996
Deferred taxb
Origination and reversal of temporary differences in the current year
(7,826)
(1,190)
907
Adjustment in respect of prior years
1,522
(94)
242
(6,304)
(1,284)
1,149
Tax charge (credit) on profit or loss
(4,159)
3,964
7,145
a The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year.
b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. The adjustments in respect of prior years reflect the reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year; 2020 includes charges for the reassessment of deferred tax asset recognition in light of revisions to price assumptions.
In 2020, the total tax charge recognized within other comprehensive income was $39 million (2019 $227 million charge and 2018 $714 million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit liability or asset. See Note 32 for further information.
The total tax charge recognized directly in equity was $154 million (2019 $37 million charge and 2018 $17 million charge). 2020 principally relates to a non-controlling interest transaction entered into by Rosneft.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the group on profit or loss before taxation.
45
bp Annual Report and Form 20-F 2020
Financial statements
9. Taxation – continued
$ million
2020
2019
2018
Profit (loss) before taxation
(24,888)
8,154
16,723
Tax charge (credit) on profit or loss
(4,159)
3,964
7,145
Effective tax rate
17%
49%
43%
%
Tax rate computed at the weighted average statutory ratea
31
52
43
Increase (decrease) resulting from
Tax reported in equity-accounted entities
—
(7)
(5)
Adjustments in respect of prior years
(6)
(2)
—
Deferred tax not recognized
(3)
(2)
1
Tax incentives for investment
1
(3)
(2)
Foreign exchange
(1)
1
3
Items not deductible for tax purposes
(3)
4
1
Other
(2)
6
2
Effective tax rate
17
49
43
a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries.
Deferred tax
$ million
Analysis of movements during the year in the net deferred tax (asset) liability
2020
2019
At 31 December
5,190
6,106
Adjustment on adoption of IFRS 16
—
(75)
At 1 January
5,190
6,031
Exchange adjustments
55
72
Credit for the year in the income statement
(6,304)
(1,284)
Charge for the year in other comprehensive income
48
233
Charge for the year in equity
154
37
Acquisitions and disposals
(56)
101
At 31 December
(913)
5,190
The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:
$ million
Income statementa
Balance sheet
2020
2019
2018
2020
2019
Deferred tax liability
Depreciation
(7,295)
(1,436)
(1,297)
15,361
22,627
Pension plan surpluses
69
(31)
65
2,691
2,290
Derivative financial instruments
33
29
(36)
63
29
Other taxable temporary differences
(32)
159
(57)
1,562
1,496
(7,225)
(1,279)
(1,325)
19,677
26,442
Deferred tax asset
Depreciation
(849)
—
—
(849)
—
Lease liabilities
286
264
8
(1,122)
(1,380)
Pension plan and other post-retirement benefit plan deficits
2
62
(6)
(1,548)
(1,367)
Decommissioning, environmental and other provisions
438
(472)
1,505
(7,155)
(7,579)
Derivative financial instruments
—
63
(31)
(25)
(24)
Tax credits
310
(336)
123
(3,652)
(3,964)
Loss carry forward
543
12
559
(5,319)
(5,834)
Other deductible temporary differences
191
402
316
(920)
(1,104)
921
(5)
2,474
(20,590)
(21,252)
Net deferred tax charge (credit) and net deferred tax (asset) liabilityb
(6,304)
(1,284)
1,149
(913)
5,190
Of which – deferred tax liabilities
6,831
9,750
– deferred tax assets
7,744
4,560
a The 2018 income statement is impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.
b Included within the net deferred tax (asset) liability is a deferred tax asset balance of $5,471 million (2019 $5,526 million) related to the Gulf of Mexico oil spill.
bp Annual Report and Form 20-F 2020
46
9. Taxation – continued
Of the $7,744 million of deferred tax assets recognised on the group balance sheet at 31 December 2020 (2019 $4,560 million), $7,659 million (2019 $2,421 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by forecasts that indicate sufficient future taxable profits will be available to utilize such assets. For 2020, $3,906 million relates to the US, $707 million relates to India, $637 million relates to Australia and $588 million relates to Trinidad & Tobago (2019 $2,421 million relates to the US).
A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table below.
$ billion
At 31 December
2020
2019
Unused US state tax lossesa
2.4
2.3
Unused tax losses – other jurisdictionsb
6.0
3.5
Unused tax credits
26.9
25.4
of which – arising in the UKc
23.0
21.5
– arising in the USd
3.9
3.9
Deductible temporary differencese
46.1
40.4
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities
0.8
1.5
a For 2020 these losses expire in the period 2021-2040 with applicable tax rates ranging from 3% to 10%.
b The majority of the unused tax losses have no fixed expiry date.
c The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax. These tax credits have no fixed expiry date.
d For 2020 the US unused tax credits expire in the period 2021-2030.
e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date.
$ million
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge
2020
2019
2018
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets
46
272
83
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets
11
96
—
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets
—
364
112
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
1,622
73
169
10. Dividends
The quarterly dividend which is expected to be paid on 26 March 2021 in respect of the fourth quarter 2020 is 5.25 cents per ordinary share ($0.315 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 15 March 2021.
Pence per share
Cents per share
$ million
2020
2019
2018
2020
2019
2018
2020
2019
2018
Dividends announced and paid in cash
Preference shares
1
1
1
Ordinary shares
March
8.1558
7.7382
7.1691
10.50
10.25
10.00
2,102
1,435
1,828
June
8.3421
8.0655
7.4435
10.50
10.25
10.00
2,119
1,779
1,727
September
4.0433
8.3475
7.9296
5.25
10.25
10.25
1,059
1,656
1,409
December
3.9169
7.8250
8.0251
5.25
10.25
10.25
1,059
2,075
1,734
24.4581
31.9762
30.5673
31.50
41.00
40.50
6,340
6,946
6,699
Dividend announced, paid in March 2021
5.25
1,067
The amount of unclaimed dividends recognised as a liability at 31 December 2020 is $50 million (2019 $22 million).
The details of the scrip dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of any dividends announced since the third quarter 2019, including the fourth quarter 2020 dividend expected to be paid on 26 March 2021.
2020
2019
2018
Number of shares issued (thousand)
—
208,927
195,305
Value of shares issued ($ million)
—
1,387
1,381
The financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 and paid in March 2021; this will be treated as an appropriation of profit in the year ending 31 December 2021.
47
bp Annual Report and Form 20-F 2020
Financial statements
11. Earnings per share
Cents per share
Per ordinary share
2020
2019
2018
Basic earnings per share
(100.42)
19.84
46.98
Diluted earnings per share
(100.42)
19.73
46.67
Dollars per share
Per American Depositary Share (ADS)a
2020
2019
2018
Basic earnings per share
(6.03)
1.19
2.82
Diluted earnings per share
(6.03)
1.18
2.80
a One ADS is equivalent to six ordinary shares.
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.
The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number of shares that are potentially issuable in connection with employee share-based payment plans. 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.
$ million
2020
2019
2018
Profit attributable to bp shareholders
(20,305)
4,026
9,383
Less: dividend requirements on preference shares
1
1
1
Profit for the year attributable to bp ordinary shareholders
(20,306)
4,025
9,382
Shares thousand
2020
2019
2018
Basic weighted average number of ordinary shares
20,221,514
20,284,859
19,970,215
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans
—
114,811
132,278
Weighted average number of ordinary shares outstanding used to calculate diluted earnings per share
20,221,514
20,399,670
20,102,493
Shares thousand
2020
2019
2018
Basic weighted average number of ordinary shares – ADS equivalent
3,370,252
3,380,809
3,328,369
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based payment plans
—
19,136
22,046
Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate diluted earnings per share
3,370,252
3,399,945
3,350,415
The number of ordinary shares outstanding at 31 December 2020, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 20,264,027,711. Between 31 December 2020 and 25 February 2021, the latest practicable date before the completion of these financial statements, there was a net increase of 66,249,231 in the number of ordinary shares outstanding primarily as a result of share issues in relation to employee share-based payment plans.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on pages 103-126 of bp Annual Report and Form 20-F 2020.
The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of these plans at 31 December is also shown.
Share options
2020
2019
Number of optionsa b
thousand
Weighted average exercise price $
Number of optionsa b
thousand
Weighted average exercise price $
Outstanding
28,171
3.79
17,112
4.91
Exercisable
1,874
5.02
1,067
3.97
Dilutive effect
2,497
n/a
3,990
n/a
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2020 the quoted market price of one bp ordinary share was £2.55 (2019 £4.72).
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.
bp Annual Report and Form 20-F 2020
48
11. Earnings per share – continued
Share plans
2020
2019
Number of sharesa
Number of sharesa
Vesting
thousand
thousand
Within one year
87,517
91,105
1 to 2 years
85,720
89,939
2 to 3 years
147,097
80,844
3 to 4 years
749
725
Over 4 years
349
576
321,432
263,189
Dilutive effect
104,068
92,343
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 29,718,486 in the number of potential ordinary shares relating to employee share-based payment plans between 31 December 2020 and 25 February 2021.
49
bp Annual Report and Form 20-F 2020
Financial statements
12. Property, plant and equipment (PP&E)
$ million
Land and land improvements
Buildings
Oil and gas propertiesa
Plant, machinery and equipment
Fittings, fixtures and office equipment
Transportation
Oil depots, storage tanks and service stations
Total
Cost - owned PP&E
At 1 January 2020
3,609
1,422
214,352
46,724
2,532
3,474
8,694
280,807
Exchange adjustments
219
6
—
801
33
8
603
1,670
Additions
101
63
6,922
1,539
586
49
864
10,124
Acquisitions
89
—
—
35
5
9
376
514
Transfers from intangible assets
—
—
605
—
—
—
—
605
Reclassified as assets held for sale
—
—
(1,425)
—
—
—
—
(1,425)
Deletions
(146)
(281)
(6,131)
(6,185)
(738)
(491)
(261)
(14,233)
At 31 December 2020
3,872
1,210
214,323
42,914
2,418
3,049
10,276
278,062
Depreciation - owned PP&E
At 1 January 2020
581
697
124,766
21,527
2,006
2,744
4,865
157,186
Exchange adjustments
35
6
—
424
26
9
379
879
Charge for the year
113
46
10,068
1,312
170
77
740
12,526
Impairment losses
8
9
11,705
744
2
4
3
12,475
Impairment reversals
—
(1)
(83)
—
—
(5)
—
(89)
Reclassified as assets held for sale
—
—
(326)
—
—
—
—
(326)
Deletions
(45)
(126)
(5,579)
(3,976)
(359)
(448)
(201)
(10,734)
At 31 December 2020
692
631
140,551
20,031
1,845
2,381
5,786
171,917
Owned PP&E - net book amount at 31 December 2020
3,180
579
73,772
22,883
573
668
4,490
106,145
Right-of-use assets - net book amount at 31 December 2020b
—
1,254
77
792
21
2,855
3,692
8,691
Total PP&E - net book amount at 31 December 2020
3,180
1,833
73,849
23,675
594
3,523
8,182
114,836
Cost - owned PP&E
At 1 January 2019
3,562
1,502
232,684
45,721
2,747
10,183
8,866
305,265
Exchange adjustments
(22)
5
—
(158)
15
(3)
(69)
(232)
Additions
88
93
13,237
2,433
172
274
644
16,941
Acquisitions
51
—
—
—
—
—
8
59
Transfers from intangible assets
—
—
1,885
—
—
—
—
1,885
Reclassified as assets held for sale
(26)
—
(22,602)
—
(76)
(6,708)
—
(29,412)
Deletions
(44)
(178)
(10,852)
(1,272)
(326)
(272)
(755)
(13,699)
At 31 December 2019
3,609
1,422
214,352
46,724
2,532
3,474
8,694
280,807
Depreciation - owned PP&E
At 1 January 2019
626
697
133,687
20,512
2,041
7,819
5,146
170,528
Exchange adjustments
(4)
5
—
(63)
12
(3)
(45)
(98)
Charge for the year
44
59
13,012
1,705
168
173
420
15,581
Impairment losses
1
1
5,871
64
1
404
4
6,346
Impairment reversals
—
—
(129)
—
—
(2)
—
(131)
Reclassified as assets held for sale
—
—
(17,764)
—
(69)
(5,478)
—
(23,311)
Deletions
(86)
(65)
(9,911)
(691)
(147)
(169)
(660)
(11,729)
At 31 December 2019
581
697
124,766
21,527
2,006
2,744
4,865
157,186
Owned PP&E - net book amount at 31 December 2019
3,028
725
89,586
25,197
526
730
3,829
123,621
Right-of-use assets - net book amount at 31 December 2019b
—
1,196
128
1,241
16
3,385
3,055
9,021
Total PP&E - net book amount at 31 December 2019
3,028
1,921
89,714
26,438
542
4,115
6,884
132,642
Assets under construction included above
At 31 December 2020
17,259
At 31 December 2019
23,897
Depreciation charge for the year on right-of-use assets
2020
192
43
637
10
829
579
2,290
2019
220
31
671
9
784
526
2,241
a For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.
b $284 million (2019 $653 million) of drilling rig right-of-use assets and $2,521 million (2019 $2,929 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment and Transportation respectively.
bp Annual Report and Form 20-F 2020
50
13. Capital commitments
Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts had been signed at 31 December 2020 amounted to $8,009 million (2019 $11,382 million, 2018 $8,319 million). bp has contracted capital commitments amounting to $1,087 million (2019 $77 million, 2018 $25 million) in relation to joint ventures and $183 million (2019 $787 million, 2018 $1,227 million) in relation to associates. bp’s share of contracted capital commitments of joint ventures amounted to $900 million (2019 $1,024 million, 2018 $619 million).
14. Goodwill and impairment review of goodwill
$ million
2020
2019
Cost
At 1 January
12,865
12,815
Exchange adjustments
184
79
Acquisitions and other additionsa
632
26
Reclassified as assets held for sale
(199)
—
Deletions
(389)
(55)
At 31 December
13,093
12,865
Impairment losses
At 1 January
997
611
Exchange adjustments
1
—
Impairment losses for the year
1
386
Deletions
(386)
—
At 31 December
613
997
Net book amount at 31 December
12,480
11,868
Net book amount at 1 January
11,868
12,204
a 2020 principally relates to an acquisition in the US Fuels business.
Impairment review of goodwill
$ million
Goodwill at 31 December
2020
2019
gas & low carbon energy
2,152
2,345
oil production & operations
5,613
5,613
customers & products
4,660
3,904
other businesses & corporate
55
6
12,480
11,868
Information for 2018 to 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Significant accounting policies, judgements, estimates and assumptions - Change in segmentation.
Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies of the acquisition. For upstream assets, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For customers & products, goodwill has been allocated to Lubricants, US Fuels, European Fuels and Other.
For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangible assets and goodwill in Note 1.
gas & low carbon energy and oil production & operations
As a result of the change in bp’s reporting segments on 1st January 2021, a reassessment of the oil and gas properties CGUs and the level at which goodwill is allocated and monitored for impairment testing purposes was required. Oil and gas properties CGUs were allocated to the new segments based on whether they predominantly produce oil or gas. No oil and gas property individual CGUs were split between the new segments and the existing CGUs remained unchanged. Legacy upstream goodwill was allocated to the two groups of CGUs allocated to the new segments based on the relative aggregate recoverable value of each group. An impairment test was performed on the goodwill balances allocated to the oil production & operations and the gas & low carbon energy segments at 1 January 2021 after the change in segments; no impairment of either goodwill balance was identified as a result thereof.
$ million
$ million
gas & low carbon energy
oil production & operations
2020
2019
2020
2019
Goodwill
2,152
2,345
5,613
5,613
Excess of recoverable amount over carrying amount
3,991
22,570
27,758
70,680
The table above shows the carrying amount of goodwill for the segments at the period end and the excess of the recoverable amount, based on a pre-tax value-in-use calculation, over the carrying amount (headroom) at the date of the most recent test. The reduction in headroom since the prior period principally relates to the impact of changes to price assumptions.
No impairment of the goodwill balance was recognized during 2020 (2019 $386 million relating to oil, production & operations).
51
bp Annual Report and Form 20-F 2020
Financial statements
14. Goodwill and impairment review of goodwill – continued
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, as they do not represent part of the grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for internal management purposes. Where such activities form part of a wider upstream cash-generating unit, they are reflected in the test. As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of each field is computed using appropriate individual economic models and key assumptions agreed by bp management.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource volumes approved as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources. Oil and gas price assumptions and discount rate assumptions used were as disclosed in Note 1. The average production for the purposes of goodwill impairment testing over the next 15 years is 877 mmboe per year (2019 829 mmboe per year). The weighted average pre-tax discount rate used in the test is 11% (2019 12%).
The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. The value-in-use calculation has been prepared solely for the purposes of determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. Due to economic developments, regulatory change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the calculations.
Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different result.
Adverse changes in input assumptions applied in respect to assets carried at or close to their value in use, primarily being those assets previously impaired, would have a limited effect on goodwill headroom, instead resulting in a direct impairment of the particular cash-generating unit's net book value. Conversely, a reduction in the value in use of those assets carried at a value below their respective values in use would result in an adverse impact on the goodwill headroom. It is estimated that a 21% reduction in revenue throughout each year of the remaining life of those assets, either as a result of adverse price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.
It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.
customers & products
$ million
2020
2019
Lubricants
US Fuels
European Fuels
Other
Total
Lubricants
US Fuels
European Fuels
Other
Total
Goodwill
2,865
606
913
276
4,660
2,779
—
858
267
3,904
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.
Lubricants
As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2018 was used as the basis for the tests in 2020 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount is remote.
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period are extrapolated using a nominal 2.8% growth rate.
bp Annual Report and Form 20-F 2020
52
15. Intangible assets
$ million
2020
2019
Exploration and appraisal expenditurea
Other intangibles
Total
Exploration and appraisal expenditurea
Other intangibles
Total
Cost
At 1 January
15,306
4,900
20,206
17,053
4,504
21,557
Exchange adjustments
—
138
138
—
2
2
Acquisitions
—
318
318
—
35
35
Additions
703
645
1,348
1,268
457
1,725
Transfers to property, plant and equipment
(605)
—
(605)
(1,885)
—
(1,885)
Reclassified as assets held for sale
—
—
—
(671)
—
(671)
Deletions
(987)
(379)
(1,366)
(459)
(98)
(557)
At 31 December
14,417
5,622
20,039
15,306
4,900
20,206
Amortization
At 1 January
1,215
3,452
4,667
1,064
3,209
4,273
Exchange adjustments
—
93
93
—
4
4
Exploration expenditure written off
9,920
—
9,920
631
—
631
Charge for the year
—
372
372
—
331
331
Impairment losses
156
9
165
2
2
4
Reclassified as assets held for sale
—
—
—
(61)
—
(61)
Deletions
(987)
(284)
(1,271)
(421)
(94)
(515)
At 31 December
10,304
3,642
13,946
1,215
3,452
4,667
Net book amount at 31 December
4,113
1,980
6,093
14,091
1,448
15,539
Net book amount at 1 January
14,091
1,448
15,539
15,989
1,295
17,284
a For further information see Intangible assets within Note 1 and Note 8.
16. Investments in joint ventures
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
$ million
2020
2019a
2018
Sales and other operating revenues
10,545
14,139
13,258
Profit before interest and taxation
(151)
976
1,396
Finance costs
201
109
85
Profit before taxation
(352)
867
1,311
Taxation
(51)
289
414
Non-controlling interest
1
2
—
Profit for the year
(302)
576
897
Other comprehensive income
(5)
(6)
6
Total comprehensive income
(307)
570
903
Non-current assets
12,646
13,457
Current assets
3,424
3,738
Total assets
16,070
17,195
Current liabilities
2,644
2,514
Non-current liabilities
5,023
4,676
Total liabilities
7,667
7,190
Net assets
8,403
10,005
Less: non-controlling interests
39
49
8,364
9,956
Group investment in joint ventures
Group share of net assets (as above)
8,364
9,956
Loans made by group companies to joint ventures
(2)
35
8,362
9,991
a 2019 has been restated to include non-controlling interest
53
bp Annual Report and Form 20-F 2020
Financial statements
16. Investments in joint ventures – continued
Transactions between the group and its joint ventures are summarized below.
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
bp's share of impairment charges taken by joint ventures in 2020 was $433 million (2019 $25 million reversal) of which $336 million (2019 $25 million reversal) was in the oi production & operations segment.
17. Investments in associates
The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the group income statement and on the group balance sheet.
$ million
Income statement
Balance sheet
Earnings from associates - after interest and tax
Investments in associates
2020
2019
2018
2020
2019
Rosneft
(229)
2,295
2,283
11,808
12,927
Other associates
128
386
573
7,167
7,407
(101)
2,681
2,856
18,975
20,334
The associate that is material to the group at both 31 December 2020 and 2019 is Rosneft.
bp owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed on the London Stock Exchange. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019 50.0% plus one share) of the voting shares of Rosneft.
bp classifies its investment in Rosneft as an associate because, in management’s judgement, bp has significant influence over Rosneft; see Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional currency is the Russian rouble. The decrease in the group's equity-accounted investment balance for Rosneft at 31 December 2020 compared with 31 December 2019 principally relates to adverse foreign exchange effects, which have been recognized in other comprehensive income, and dividends, partially offset by bp's share of Rosneft’s changes in equity.
During 2020 Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, Rosneft received shares equal to a 9.6% share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also entered into share buyback transactions during the year. These are also accounted for as treasury shares. bp retains 19.75% of the voting rights at meetings of Rosneft shareholders and will continue to be entitled to dividends based on its current shareholding. bp’s economic interest, however, increased as a result of its indirect interest in the shares held by the subsidiary of Rosneft. bp’s share of profit or loss of Rosneft reflects its economic interest. At 31 December 2020, bp's economic interest was 22.03%.
On 28 December 2020 Rosneft completed the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10% interest in LLC Vostok Oil. A preliminary assessment of the fair values of the assets and liabilities acquired and the consideration transferred in respect of the acquisitions has been undertaken and the further impact, if any, on bp’s accounting for its equity-accounted investment in Rosneft will be updated once this has been finalised.
The value of bp’s 19.75% shareholding in Rosneft based on the quoted market share price of $5.64 per share (2019 $7.21 per share) was $11,804 million at 31 December 2020 (2019 $15,090 million). The value of bp's 22.03% economic interest based on the quoted market share price was $13,167 million at 31 December 2020.
The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects adjustments made by bp to Rosneft’s own results in applying the equity method of accounting. bp adjusts Rosneft’s results for the accounting required under IFRS relating to bp’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of bp’s interest in TNK-BP.
bp Annual Report and Form 20-F 2020
54
17. Investments in associates – continued
$ million
Gross amount
2020
2019
2018
Sales and other operating revenues
82,786
134,046
131,322
Profit before interest and taxation
1,270
17,473
18,886
Finance costs
1,742
1,281
2,785
Profit (loss) before taxation
(472)
16,192
16,101
Taxation
208
3,058
2,957
Non-controlling interests
482
1,514
1,585
Profit (loss) for the year
(1,162)
11,620
11,559
Other comprehensive income
1,653
572
2,086
Total comprehensive income
491
12,192
13,645
Non-current assets
175,978
161,327
Current assets
42,459
38,657
Total assets
218,437
199,984
Current liabilities
49,781
44,459
Non-current liabilities
96,727
79,327
Total liabilities
146,508
123,786
Net assets
71,929
76,198
Less: non-controlling interests
10,897
10,744
61,032
65,454
The group received dividends, net of withholding tax, of $480 million from Rosneft in 2020 (2019 $785 million and 2018 $620 million).
Summarized financial information for the group’s share of associates is shown below.
$ million
bp share
2020
2019
2018
Rosnefta
Other
Total
Rosnefta
Other
Total
Rosnefta
Other
Total
Sales and other operating revenues
17,535
5,946
23,481
26,474
7,934
34,408
25,936
9,134
35,070
Profit before interest and taxation
295
276
571
3,451
788
4,239
3,730
1,150
4,880
Finance costs
372
80
452
253
87
340
550
78
628
Profit (loss) before taxation
(77)
196
119
3,198
701
3,899
3,180
1,072
4,252
Taxation
51
67
118
604
315
919
584
499
1,083
Non-controlling interests
101
1
102
299
—
299
313
—
313
Profit (loss) for the year
(229)
128
(101)
2,295
386
2,681
2,283
573
2,856
Other comprehensive income
336
(19)
317
113
(25)
88
412
(1)
411
Total comprehensive income
107
109
216
2,408
361
2,769
2,695
572
3,267
Non-current assets
33,754
11,449
45,203
31,862
11,504
43,366
Current assets
8,238
1,749
9,987
7,635
1,924
9,559
Total assets
41,992
13,198
55,190
39,497
13,428
52,925
Current liabilities
9,535
1,346
10,881
8,781
1,908
10,689
Non-current liabilities
18,558
4,709
23,267
15,667
4,577
20,244
Total liabilities
28,093
6,055
34,148
24,448
6,485
30,933
Net assets
13,899
7,143
21,042
15,049
6,943
21,992
Less: non-controlling interests
2,091
—
2,091
2,122
—
2,122
11,808
7,143
18,951
12,927
6,943
19,870
Group investment in associates
Group share of net assets (as above)
11,808
7,143
18,951
12,927
6,943
19,870
Loans made by group companies to associates
—
24
24
—
464
464
11,808
7,167
18,975
12,927
7,407
20,334
a In 2014-2019, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars. Foreign exchange gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments were recognized initially in other comprehensive income, and were reclassified to the income statement as the hedged revenue was recognized.
During the year, bp and Reliance Industries completed the formation of a new fuels and mobility venture, Reliance BP Mobility Limited, that will operate across India under the Jio-bp brand. bp invested $1 billion to acquire a 49% stake in the company.
Transactions between the group and its associates are summarized below.
55
bp Annual Report and Form 20-F 2020
Financial statements
17. Investments in associates – continued
$ million
Sales to associates
2020
2019
2018
Product
Sales
Amount receivable at 31 December
Sales
Amount receivable at 31 December
Sales
Amount receivable at 31 December
LNG, crude oil and oil products, natural gas
855
169
1,544
243
2,064
393
$ million
Purchases from associates
2020
2019
2018
Product
Purchases
Amount payable at 31 December
Purchases
Amount payable at 31 December
Purchases
Amount payable at 31 December
Crude oil and oil products, natural gas, transportation tariff
4,926
1,280
9,503
1,641
14,112
2,069
In addition to the transactions shown in the table above, in 2018 bp acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary, which develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. bp’s interest in LLC Kharampurneftegaz is accounted for as an associate.
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to various entities.
bp has commitments amounting to $10,777 million (2019 $11,198 million), primarily in relation to contracts with its associates for the purchase of transportation capacity. For information on capital commitments in relation to associates see Note 13.
bp's share of impairment charges taken by associates in 2020 was $414 million (2019 $152 million).
bp Annual Report and Form 20-F 2020
56
18. Other investments
$ million
2020
2019
Current
Non-current
Current
Non-current
Equity investmentsa
—
913
—
571
Contingent consideration
317
1,682
122
476
Other
16
151
47
229
333
2,746
169
1,276
a Approximately half of the group's equity investments are unlisted.
Contingent consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount rate used is based on a risk-free rate adjusted for asset-specific risks. The contingent consideration principally relates to the disposal of our Alaskan business.
19. Inventories
$ million
2020
2019
Crude oil
4,498
5,610
Natural gas
265
222
Emissions allowancesa
1,297
1,193
Refined petroleum and petrochemical products
8,791
11,714
14,851
18,739
Trading inventories
292
182
15,143
18,921
Supplies
1,730
1,959
16,873
20,880
Cost of inventories expensed in the income statement
132,104
209,672
a Comparative period has been re-presented to align with the current period.
The inventory valuation at 31 December 2020 is stated net of a provision of $584 million (2019 $650 million) to write down inventories to their net realizable value, of which $216 million (2019 $290 million) relates to hydrocarbon inventories. The net credit to the income statement in the year in respect of inventory net realizable value provisions was $17 million (2019 $348 million credit), of which $71 million credit (2019 $309 million credit) related to hydrocarbon inventories.
Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are predominantly categorized within level 2 of the fair value hierarchy.
20. Trade and other receivables
$ million
2020
2019
Current
Non-current
Current
Non-current
Financial assets
Trade receivables
12,926
19
19,424
22
Amounts receivable from joint ventures and associates
339
10
672
2
Receivables related to disposalsa
1,291
2,402
159
125
Other receivables
2,628
637
3,166
701
17,184
3,068
23,421
850
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asset
32
—
201
—
Sales taxes and production taxes
557
504
640
538
Other receivables
175
779
180
759
764
1,283
1,021
1,297
17,948
4,351
24,442
2,147
a For further information see Note 4 - Disposals and Impairment.
In both 2020 and 2019 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk.
Trade and other receivables, other than certain receivables related to disposals, are predominantly non-interest bearing. See Note 29 for further information.
57
bp Annual Report and Form 20-F 2020
Financial statements
21. Valuation and qualifying accounts
$ million
2020
2019
2018
Trade and other receivables
Fixed asset investments
Trade and other receivables
Fixed asset investments
Trade and other receivables
Fixed asset investments
At 1 January – IAS 39
509
249
416
235
335
314
Adjustment on adoption of IFRS 9
—
—
—
—
115
(85)
At 1 January – IFRS 9
509
249
416
235
450
229
Charged to costs and expenses
214
103
206
28
30
10
Charged to other accountsa
2
—
(2)
—
(12)
(1)
Deductions
(170)
(166)
(111)
(14)
(52)
(3)
At 31 December
555
186
509
249
416
235
a Principally exchange adjustments.
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The adjustment on adoption of IFRS 9 relates to the additional loss allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $456 million (2019 $414 million, 2018 $327 million) relating to receivables that were credit-impaired at the end of the year and $99 million (2019 $95 million, 2018 $89 million) relating to receivables that were not credit-impaired at the end of the year. 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 during the year.
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit or loss under IFRS 9.
In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost totalled $11 million (2019 $11 million). For further information on the group's credit risk management policies and how the group recognizes and measures expected losses see Note 29.
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.
22. Trade and other payables
$ million
2020
2019
Current
Non-current
Current
Non-current
Financial liabilities
Trade payables
23,157
—
30,538
—
Amounts payable to joint ventures and associates
1,364
—
1,866
—
Payables for capital expenditure and acquisitions
2,297
1,033
3,868
1,196
Payables related to the Gulf of Mexico oil spill
1,399
9,988
1,617
10,863
Other payables
5,041
681
5,810
133
33,258
11,702
43,699
12,192
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security
2,103
73
2,381
33
Other payables
653
337
749
401
2,756
410
3,130
434
36,014
12,112
46,829
12,626
Materially all of bp's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows.
Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further information.
Payables related to the Gulf of Mexico oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the amounts included in payables related to the Gulf of Mexico oil spill for these elements of the agreements are $4,837 million payable over 12 years, $2,584 million payable over 13 years and $3,549 million payable over 12 years respectively at 31 December 2020. Reported within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $1,786 million (2019 outflow of $2,694 million, 2018 outflow of $3,531 million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018 payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also included. For full details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings.
Payables related to the Gulf of Mexico oil spill at 31 December 2020 also include amounts payable for settled economic loss and property damage claims which are payable over a period of up to seven years.
bp Annual Report and Form 20-F 2020
58
23. Provisions
$ million
Decommissioning
Environmental
Litigation and claims
Emissions
Other
Total
At 1 January 2020
15,110
1,620
1,281
919
2,021
20,951
Exchange adjustments
96
9
1
25
84
215
Increase (decrease) in existing provisions
(686)
297
260
1,429
974
2,274
Write-back of unused provisions
(11)
(88)
(12)
(17)
(341)
(469)
Unwinding of discount
369
39
18
—
11
437
Utilization
(7)
(246)
(508)
(687)
(378)
(1,826)
Reclassified to other payables
(245)
—
(129)
—
(86)
(460)
Reclassified as liabilities directly associated with assets held for sale
(10)
—
—
—
—
(10)
Deletions
(140)
(2)
(1)
—
(8)
(151)
At 31 December 2020
14,476
1,629
910
1,669
2,277
20,961
Of which – current
428
273
260
1,621
1,179
3,761
– non-current
14,048
1,356
650
48
1,098
17,200
The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. The emissions provision relates to the group’s obligation to transfer emissions allowances under relevant regulations. The provision will principally be settled through allowances already held as inventory in the group balance sheet. Included within the other category at 31 December 2020 are reinvent bp restructuring provisions for employee termination payments of $428 million.
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
Gulf of Mexico oil spill
The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that occurred in 2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33.
Litigation and claims
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's Steering Committee (PSC) provides for a court-supervised settlement programme, the Deepwater Horizon Court Supervised Settlement Programme (DHCSSP), which commenced operation on 4 June 2012. 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 DHCSSP. 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. Amounts payable for settled economic and property damage claims are reported within payables - see Note 22 for further information.
A separate claims administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 88 of this report.
The litigation and claims provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts payable may differ from the amount provided and the timing of payments is uncertain.
24. Pensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts.
For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits in Note 1.
The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, one independent director and one independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The UK plan is closed to new joiners and is currently under consultation for closure to future accrual. As at 31 December 2020, it remained open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a defined contribution plan.
In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are overseen by a fiduciary Investment Committee. During 2020 the committee was composed of seven bp employees appointed by the president of bp Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions. In the US, group companies also provide post-retirement healthcare to most retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits is usually based on the employee remaining in service until a specified age and completion of a minimum period of service.
59
bp Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average plan with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional contributions made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between bp and the works council or between bp and the trade union.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2020 the aggregate level of contributions was $325 million (2019 $349 million and 2018 $610 million). The aggregate level of contributions in 2021 is expected to be approximately $400 million, and includes contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance for discretionary funding.
For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,014 million at 31 December 2020, all of which relates to future service. This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 307 of bp Annual Report and Form 20-F 2020.
The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan.
Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made into the primary US pension plan in 2020 and no statutory funding requirement is expected in the next 12 months.
The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus through a reduction in future contributions.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December 2020.
The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2020. The UK plans are subject to a formal actuarial valuation every three years; valuations are required more frequently in many other countries.The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2017, and a valuation as at 31 December 2020 is currently underway. A valuation of the US plan and largest Eurozone plans are carried out annually.
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following year.
%
Financial assumptions used to determine benefit obligation
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Discount rate for plan liabilities
1.4
2.1
2.9
2.2
3.1
4.1
1.0
1.3
2.0
Rate of increase in salaries
3.6
3.4
3.8
4.1
3.9
3.9
2.9
3.1
3.1
Rate of increase for pensions in payment
2.8
2.7
3.0
—
—
—
1.3
1.5
1.5
Rate of increase in deferred pensions
2.8
2.7
3.0
—
—
—
0.5
0.5
0.5
Inflation for plan liabilities
2.9
2.7
3.1
1.7
1.5
1.5
1.5
1.7
1.7
%
Financial assumptions used to determine benefit expense
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Discount rate for plan service cost
2.1
3.0
2.6
3.2
4.2
3.6
1.8
2.5
2.4
Discount rate for plan other finance expense
2.1
2.9
2.5
3.1
4.1
3.5
1.3
2.0
1.9
Inflation for plan service cost
2.6
3.1
3.1
1.5
1.5
1.7
1.7
1.7
1.6
The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth. These include an allowance for promotion-related salary growth, of up to 0.8% depending on country.
bp Annual Report and Form 20-F 2020
60
24. Pensions and other post-retirement benefits – continued
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp’s most substantial pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows:
Years
Mortality assumptions
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Life expectancy at age 60 for a male currently aged 60
26.9
27.3
27.4
24.7
24.9
25.1
25.7
25.7
25.6
Life expectancy at age 60 for a male currently aged 40
28.4
28.9
28.9
26.4
26.7
26.9
28.2
28.3
28.1
Life expectancy at age 60 for a female currently aged 60
28.8
28.7
28.8
27.7
28.0
28.5
29.0
29.1
29.0
Life expectancy at age 60 for a female currently aged 40
30.4
30.5
30.6
29.2
29.7
30.1
31.2
31.2
31.2
Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.
A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below.
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2020, the UK plan switched 11% of plan assets from equities to bonds (2019 2%). There is a similar agreement in place for the primary US plan, although no switches have taken place in 2019 or 2020.
The current asset allocation policy for the major plans at 31 December 2020 was as follows:
UK
US
Asset category
%
%
Total equity (including private equity)
17
40
Bonds/cash (including LDI)
76
60
Property/real estate
7
—
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $4,217 million (2019 $4,804 million) of government-issued nominal bonds and $24,576 million (2019 $19,462 million) of index-linked bonds.
Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the level of risk. The fair value of these instruments is included in other assets in the table below.
The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 63 of this report.
61
bp Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
$ million
UKa
USb
Eurozone
Other
Total
Fair value of pension plan assets
At 31 December 2020
Listed equities – developed markets
5,008
1,112
542
318
6,980
– emerging markets
418
115
68
70
671
Private equityc
2,899
1,604
—
4
4,507
Government issued nominal bondsd
4,303
1,839
1,111
616
7,869
Government issued index-linked bondsd
24,576
—
107
—
24,683
Corporate bondsd
8,906
2,398
587
279
12,170
Propertye
2,553
—
110
28
2,691
Cash
1,392
267
51
163
1,873
Other
795
131
104
30
1,060
Debt (repurchase agreements) used to fund liability driven investments
(9,387)
—
—
—
(9,387)
41,463
7,466
2,680
1,508
53,117
At 31 December 2019
Listed equities – developed markets
6,285
1,290
495
371
8,441
– emerging markets
1,096
124
61
64
1,345
Private equityc
2,675
1,474
—
3
4,152
Government issued nominal bondsd
4,884
2,100
959
572
8,515
Government issued index-linked bondsd
19,462
—
100
—
19,562
Corporate bondsd
6,132
2,304
569
256
9,261
Propertye
2,507
—
96
27
2,630
Cash
426
289
33
93
841
Other
98
74
30
26
228
Debt (repurchase agreements) used to fund liability driven investments
(7,436)
—
—
—
(7,436)
36,129
7,655
2,343
1,412
47,539
At 31 December 2018
Listed equities – developed markets
5,191
1,238
413
306
7,148
– emerging markets
950
63
65
56
1,134
Private equityc
2,792
1,495
—
4
4,291
Government issued nominal bondsd
4,263
2,072
895
533
7,763
Government issued index-linked bondsd
17,491
—
102
—
17,593
Corporate bondsd
4,606
2,184
506
243
7,539
Propertye
2,311
6
57
25
2,399
Cash
376
73
42
83
574
Other
116
64
32
40
252
Debt (repurchase agreements) used to fund liability driven investments
(6,011)
—
—
—
(6,011)
32,085
7,195
2,112
1,290
42,682
a Bonds held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom.
b Bonds held by the US pension plans are denominated in US dollars.
c Private equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable inputs.
d Bonds held by pension plans are valued using quoted prices in active markets.
e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of significant unobservable inputs.
bp Annual Report and Form 20-F 2020
62
24. Pensions and other post-retirement benefits – continued
$ million
2020
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current service costa
250
292
103
38
683
Past service costb
(48)
(66)
12
(20)
(122)
Settlementb
—
(23)
10
(1)
(14)
Operating charge relating to defined benefit plans
202
203
125
17
547
Payments to defined contribution plans
49
183
2
38
272
Total operating charge
251
386
127
55
819
Interest income on plan assetsa
(725)
(210)
(33)
(40)
(1,008)
Interest on plan liabilities
596
289
97
59
1,041
Other finance (income) expense
(129)
79
64
19
33
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
4,108
1,041
104
38
5,291
Change in financial assumptions underlying the present value of the plan liabilities
(4,207)
(1,178)
(143)
(42)
(5,570)
Change in demographic assumptions underlying the present value of the plan liabilities
585
29
56
(4)
666
Experience gains and losses arising on the plan liabilities
54
(101)
(178)
8
(217)
Remeasurements recognized in other comprehensive income
540
(209)
(161)
—
170
Movements in benefit obligation during the year
Benefit obligation at 1 January
29,780
10,119
7,353
1,826
49,078
Exchange adjustments
1,303
—
720
64
2,087
Operating charge relating to defined benefit plans
202
203
125
17
547
Interest cost
596
289
97
59
1,041
Contributions by plan participantsc
21
—
2
11
34
Benefit payments (funded plans)d
(1,291)
(1,441)
(81)
(86)
(2,899)
Benefit payments (unfunded plans)d
(8)
(197)
(265)
(34)
(504)
Reclassified as assets held for sale
—
(1)
(55)
—
(56)
Disposals
—
(35)
—
—
(35)
Remeasurements
3,568
1,250
265
38
5,121
Benefit obligation at 31 Decembera e
34,171
10,187
8,161
1,895
54,414
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
36,129
7,655
2,343
1,412
47,539
Exchange adjustments
1,582
—
235
64
1,881
Interest income on plan assetsa f
725
210
33
40
1,008
Contributions by plan participantsc
21
—
2
11
34
Contributions by employers (funded plans)
189
8
99
29
325
Benefit payments (funded plans)d
(1,291)
(1,441)
(81)
(86)
(2,899)
Reclassified as assets held for sale
—
(7)
(55)
—
(62)
Remeasurementsf
4,108
1,041
104
38
5,291
Fair value of plan assets at 31 Decemberg
41,463
7,466
2,680
1,508
53,117
Surplus (deficit) at 31 December
7,292
(2,721)
(5,481)
(387)
(1,297)
Represented by
Asset recognized
7,567
269
59
62
7,957
Liability recognized
(275)
(2,990)
(5,540)
(449)
(9,254)
7,292
(2,721)
(5,481)
(387)
(1,297)
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
7,564
269
(109)
(58)
7,666
Unfunded
(272)
(2,990)
(5,372)
(329)
(8,963)
7,292
(2,721)
(5,481)
(387)
(1,297)
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
(33,899)
(7,197)
(2,789)
(1,566)
(45,451)
Unfunded
(272)
(2,990)
(5,372)
(329)
(8,963)
(34,171)
(10,187)
(8,161)
(1,895)
(54,414)
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service credits represent curtailment gains arising from restructuring programmes in the UK, US and other countries, whilst past service costs and settlements in the Eurozone represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlement costs in the US resulted from a pension risk transfer to an external carrier for a group of small benefit retirees.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,935 million benefits and $428 million settlements, plus $40 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,728 million for pension liabilities and $2,459 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $5,060 million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 61 of this report.
63
bp Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
$ million
2019
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current service costa
227
263
81
38
609
Past service costb
2
—
5
(1)
6
Settlementb
—
(13)
8
—
(5)
Operating charge relating to defined benefit plans
229
250
94
37
610
Payments to defined contribution plans
42
188
7
38
275
Total operating charge
271
438
101
75
885
Interest income on plan assetsa
(909)
(285)
(43)
(46)
(1,283)
Interest on plan liabilities
757
387
133
69
1,346
Other finance (income) expense
(152)
102
90
23
63
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
2,945
1,079
220
97
4,341
Change in financial assumptions underlying the present value of the plan liabilities
(2,294)
(1,036)
(748)
(92)
(4,170)
Change in demographic assumptions underlying the present value of the plan liabilities
136
91
3
(4)
226
Experience gains and losses arising on the plan liabilities
(57)
(22)
6
4
(69)
Remeasurements recognized in other comprehensive income
730
112
(519)
5
328
Movements in benefit obligation during the year
Benefit obligation at 1 January
26,830
9,696
6,906
1,686
45,118
Exchange adjustments
942
—
(142)
26
826
Operating charge relating to defined benefit plans
229
250
94
37
610
Interest cost
757
387
133
69
1,346
Contributions by plan participantsc
20
—
2
6
28
Benefit payments (funded plans)d
(1,207)
(830)
(76)
(75)
(2,188)
Benefit payments (unfunded plans)d
(6)
(205)
(273)
(15)
(499)
Reclassified as assets held for sale
—
(146)
—
—
(146)
Disposals
—
—
(30)
—
(30)
Remeasurements
2,215
967
739
92
4,013
Benefit obligation at 31 Decembera e
29,780
10,119
7,353
1,826
49,078
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
32,085
7,195
2,112
1,290
42,682
Exchange adjustments
1,141
—
(43)
24
1,122
Interest income on plan assetsa f
909
285
43
46
1,283
Contributions by plan participantsc
20
—
2
6
28
Contributions by employers (funded plans)
236
4
85
24
349
Benefit payments (funded plans)d
(1,207)
(830)
(76)
(75)
(2,188)
Reclassified as assets held for sale
—
(78)
—
—
(78)
Remeasurementsf
2,945
1,079
220
97
4,341
Fair value of plan assets at 31 Decemberg
36,129
7,655
2,343
1,412
47,539
Surplus (deficit) at 31 December
6,349
(2,464)
(5,010)
(414)
(1,539)
Represented by
Asset recognized
6,588
387
27
51
7,053
Liability recognized
(239)
(2,851)
(5,037)
(465)
(8,592)
6,349
(2,464)
(5,010)
(414)
(1,539)
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
6,588
387
(136)
(87)
6,752
Unfunded
(239)
(2,851)
(4,874)
(327)
(8,291)
6,349
(2,464)
(5,010)
(414)
(1,539)
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
(29,541)
(7,268)
(2,479)
(1,499)
(40,787)
Unfunded
(239)
(2,851)
(4,874)
(327)
(8,291)
(29,780)
(10,119)
(7,353)
(1,826)
(49,078)
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,304 million benefits and $346 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,789 million for pension liabilities and $2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,567 million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 61 of this report.
bp Annual Report and Form 20-F 2020
64
24. Pensions and other post-retirement benefits – continued
$ million
2018
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current service costa
295
299
84
43
721
Past service costb
15
—
9
4
28
Settlement
—
—
17
—
17
Operating charge relating to defined benefit plans
310
299
110
47
766
Payments to defined contribution plans
38
178
5
40
261
Total operating charge
348
477
115
87
1,027
Interest income on plan assetsa
(868)
(262)
(44)
(45)
(1,219)
Interest on plan liabilities
774
369
136
67
1,346
Other finance (income) expense
(94)
107
92
22
127
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
(722)
(256)
(69)
(36)
(1,083)
Change in financial assumptions underlying the present value of the plan liabilities
1,770
945
14
65
2,794
Change in demographic assumptions underlying the present value of the plan liabilities
123
(9)
(42)
7
79
Experience gains and losses arising on the plan liabilities
520
41
(43)
9
527
Remeasurements recognized in other comprehensive income
1,691
721
(140)
45
2,317
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs have arisen from restructuring programmes and represent charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone.
Sensitivity analysis
The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2020 for the group’s pensions and other post-retirement benefit expense would have had the effects shown in the tables below. The effects shown for the expense in 2021 comprise the total of current service cost and net finance income or expense.
$ million
One percentage point
UK
US
Eurozone
Increase
Decrease
Increase
Decrease
Increase
Decrease
Discount ratea
Effect on expense in 2021
(274)
198
(51)
36
(2)
(11)
Effect on obligation at 31 December 2020
(5,658)
7,690
(1,272)
1,556
(1,149)
1,452
Inflation rateb
Effect on expense in 2021
145
(116)
10
(8)
35
(28)
Effect on obligation at 31 December 2020
5,337
(4,482)
66
(55)
1,025
(870)
Salary growth
Effect on expense in 2021
31
(27)
12
(10)
7
(7)
Effect on obligation at 31 December 2020
670
(585)
82
(69)
91
(89)
a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
$ million
One year increase
UK
US
Eurozone
Longevity
Effect on expense in 2021
28
5
8
Effect on obligation at 31 December 2020
1,406
150
333
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted average duration of the defined benefit obligations at 31 December 2020 are as follows:
$ million
Estimated future benefit payments
UK
US
Eurozone
Other
Total
2021
1,072
1,568
357
112
3,109
2022
1,086
612
346
109
2,153
2023
1,120
593
339
107
2,159
2024
1,141
575
332
108
2,156
2025
1,135
583
328
107
2,153
2026-2030
5,939
2,696
1,521
528
10,684
Years
Weighted average duration
19.2
13.8
16.1
12.7
65
bp Annual Report and Form 20-F 2020
Financial statements
25. Cash and cash equivalents
$ million
2020
2019
Cash
6,235
6,462
Triparty repos and term bank deposits
17,368
10,296
Cash equivalents (excluding triparty repos and term bank deposits)
7,508
5,714
31,111
22,472
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits of three months or less with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash, triparty repos and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2020 includes $1,917 million (2019 $1,676 million) that is restricted. The restricted cash balances include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.
The group holds $3,890 million (2019 $4,678 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise on repatriation.
26. Finance debt
$ million
2020
2019
Current
Non-current
Total
Current
Non-current
Total
Borrowings
9,359
63,305
72,664
10,487
57,237
67,724
The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $8,122 million (2019 $8,166 million) and issued commercial paper of $1,004 million (2019 $2,279 million). Finance debt does not include accrued interest, which is reported within other payables. As part of actively managing its debt portfolio, during the year the group bought back $4.0 billion equivalent (2019 $nil) of euro and sterling bonds and terminated derivatives associated with the debt bought back. In addition on 18 December 2020 the group exercised its option to redeem finance debt with an outstanding aggregate principal amount of $2.0 billion on 22 January 2021. On 19 March 2021 the group bought back a further $1.9 billion equivalent of euro and sterling bonds and terminated associated derivatives. These transactions have no significant impact on net debt or gearing.
The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures.
Fixed rate debt
Floating rate debt
Total
Weighted average interest rate %
Weighted average time for which rate is fixed Years
Amount $ million
Weighted average interest rate %
Amount $ million
Amount $ million
2020
US dollar
3
8
39,452
2
32,891
72,343
Other currencies
6
9
178
5
143
321
39,630
33,034
72,664
2019
US dollar
4
5
25,634
3
41,871
67,505
Other currencies
6
10
183
7
36
219
25,817
41,907
67,724
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2020, whereas in the group balance sheet the amount is reported within current finance debt.
The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of the significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such measurements are therefore categorized in level 2 of the fair value hierarchy.
$ million
2020
2019
Fair value
Carrying amount
Fair value
Carrying amount
Short-term borrowings
1,237
1,237
2,321
2,321
Long-term borrowings
74,855
71,427
67,055
65,403
Total finance debt
76,092
72,664
69,376
67,724
bp Annual Report and Form 20-F 2020
66
27. Capital disclosures and net debt
The group defines capital as total equity plus net debt. We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a secure financial base.
The group monitors capital on basis of gearing, that is, the ratio of net debt to net debt plus equity. 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 exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and gearing are non-GAAP measures. 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’. All components of equity are included in the denominator of the calculation.
At 31 December 2020, gearing was 31.3% (2019 31.1%).
$ million
At 31 December
2020
2019
Finance debt
72,664
67,724
Less: fair value asset (liability) of hedges related to finance debta
2,612
(190)
70,052
67,914
Less: cash and cash equivalents
31,111
22,472
Net debt
38,941
45,442
Total equityb
85,568
100,708
Gearing
31.3
%
31.1
%
a 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 (2019 liability of $601 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.
b Total equity in 2020 includes perpetual hybrid bonds issued on 17 June 2020. See Note 32 for further information.
An analysis of changes in liabilities arising from financing activities is provided below.
$ million
Finance debt
Currency swapsa
Lease liabilities
Net partner payable for leases entered into on behalf of joint operations
Total liabilities arising from financing activities
At 1 January 2020
67,724
918
9,722
290
78,654
Exchange adjustments
349
—
181
4
534
Net financing cash flow
1,589
(226)
(2,442)
(40)
(1,119)
Fair value (gains) losses
2,612
(3,734)
—
—
(1,122)
New and remeasured leases/joint operation payables
—
—
1,579
20
1,599
Other movements
390
77
222
(7)
682
At 31 December 2020
72,664
(2,965)
9,262
267
79,228
At 1 January 2019
65,132
1,486
667
—
67,285
Adjustment on adoption of IFRS16
—
—
9,233
217
9,450
Exchange adjustments
(62)
—
(4)
8
(58)
Net financing cash flow
1,671
2
(2,372)
(14)
(713)
Fair value (gains) losses
924
(570)
—
—
354
New and remeasured leases/joint operations payables
—
—
2,614
82
2,696
Other movements
59
—
(416)
(3)
(360)
At 31 December 2019
67,724
918
9,722
290
78,654
a Previously reported in this column were hedge accounted derivatives related to finance debt. This has been updated in 2020 as described below and comparatives provided on a consistent basis. Currency swaps include cross currency interest rate swaps.
The balances above do not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. The currency swaps are reported on the balance sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for trading and derivatives designated in fair value hedge relationships as detailed in Note 30. When hedge accounting is applied to these derivatives they are included in the calculation of net debt shown above.
67
bp Annual Report and Form 20-F 2020
Financial statements
28. Leases
The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the gas & low carbon energy and oil production & operations segments and retail service stations, oil depots and storage tanks in the customers & products segment as well as office accommodation and vessel charters across the group. The weighted-average remaining lease term for the total lease portfolio is around 8 years (2019 9 years). Some leases will have payments that vary with market interest or inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market values have significantly declined at the conclusion of the lease.
The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.
$ million
2020
2019
Undiscounted lease liability cash flows due:
Within 1 year
2,262
2,514
1 to 2 years
1,672
1,839
2 to 3 years
1,340
1,364
3 to 4 years
1,025
1,105
4 to 5 years
878
876
5 to 10 years
2,192
2,427
Over 10 years
1,515
1,174
10,884
11,299
Impact of discounting
(1,622)
(1,577)
Lease liabilities at 31 December
9,262
9,722
Of which – current
1,933
2,067
– non-current
7,329
7,655
The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December 2020 is $5,309 million (2019 $5,688 million). The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue Ahmeyim project from 2023.
$ million
2020
2019
Total cash outflow for amounts included in lease liabilitiesa
2,779
2,709
Expense for variable payments not included in the lease liability
41
67
Short-term lease expense
621
331
Additions to right-of-use assets in the period
1,714
2,542
Gain on sale and leaseback transactions
187
—
a The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above.
An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.
29. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments and their carrying amounts are set out below.
$ million
At 31 December 2020
Note
Measured at amortized cost
Mandatorily measured at fair value through profit or loss
Derivative hedging instruments
Total carrying amount
Financial assets
Other investments
18
—
3,079
—
3,079
Loans
929
369
—
1,298
Trade and other receivables
20
20,252
—
—
20,252
Derivative financial instruments
30
—
10,049
2,698
12,747
Cash and cash equivalents
25
24,905
6,206
—
31,111
Financial liabilities
Trade and other payables
22
(44,960)
—
—
(44,960)
Derivative financial instruments
30
—
(8,320)
(82)
(8,402)
Accruals
(5,502)
—
—
(5,502)
Lease liabilities
28
(9,262)
—
—
(9,262)
Finance debt
26
(72,664)
—
—
(72,664)
(86,302)
11,383
2,616
(72,303)
bp Annual Report and Form 20-F 2020
68
29. Financial instruments and financial risk factors – continued
$ million
At 31 December 2019
Note
Measured at amortized cost
Mandatorily measured at fair value through profit or loss
Derivative hedging instruments
Total carrying amount
Financial assets
Other investments
18
—
1,445
—
1,445
Loans
906
63
—
969
Trade and other receivables
20
24,271
—
—
24,271
Derivative financial instruments
30
—
9,984
483
10,467
Cash and cash equivalents
25
18,183
4,289
—
22,472
Financial liabilities
Trade and other payables
22
(55,891)
—
—
(55,891)
Derivative financial instruments
30
—
(8,122)
(676)
(8,798)
Accruals
(6,062)
—
—
(6,062)
Lease liabilities
28
(9,722)
—
—
(9,722)
Finance debt
26
(67,724)
—
—
(67,724)
(96,039)
7,659
(193)
(88,573)
The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair value, or approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as measured at fair value through profit or loss totalled a net gain of $367 million (2019 net loss of $129 million). Dividend income of $17 million (2019 $20 million) from investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7.
Interest income and expenses arising on financial instruments are disclosed in Note 7.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.
The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function. Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function. All other foreign exchange and interest rate activities within financial markets are performed within the integrated supply and trading function and are also underpinned by the compliance, control and risk management infrastructure common to the activities of bp’s integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and material commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below.
(i) Commodity price risk
The group’s integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas swaps, options and futures.
The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented by stress testing and scenario analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity occurring in liquid periods is
69
bp Annual Report and Form 20-F 2020
Financial statements
29. Financial instruments and financial risk factors – continued
subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board has delegated a limit of $100 million (2019 $100 million) value at risk in support of this trading activity. Alternative measures are used to monitor exposures which are outside liquid periods and for which value-at-risk techniques are not appropriate.
(ii) Foreign currency exchange risk
Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because bp’s major product, oil, is priced internationally in US dollars. bp’s foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then managing any material residual foreign currency exchange risks.
Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2020, the total foreign currency borrowings not swapped into US dollars amounted to $321 million (2019 $219 million). During the year the group issued perpetual subordinated hybrid bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the repayment of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods.
The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit. A continuous assessment is made in respect to the group’s foreign currency exposures to capture hedging requirements.
During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the exposures are in sterling, euro, Australian dollar and Korean won. At 31 December 2020 the most significant open contracts in place were for $124 million sterling (2019 $106 million sterling).
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained in (i) commodity price risk above.
(iii) Interest rate risk
bp is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2020 was 45% of total finance debt outstanding (2019 62%). The weighted average interest rate on finance debt at 31 December 2020 was 3% (2019 3%) and the weighted average maturity of fixed rate debt was eight years (2019 five years).
The group’s earnings are sensitive to changes in interest rates on the element of the group’s finance debt that has been swapped to floating rates. If the interest rates applicable to these floating rate instruments were to have changed by one percentage point on 1 January 2021, it is estimated that the group’s finance costs for 2021 would change by approximately $330 million (2019 $419 million).
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. bp is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. Following the completion of consultation processes, these financial authorities have begun to announce the timing of both benchmark transitions and continued publication of synthetic benchmarks.
In October 2020 the International Swaps and Derivatives Association (ISDA) published its fallback protocol containing clauses to amend derivative contracts on the cessation of LIBOR should an entity and its counterparties adhere to the protocol. The protocol’s pricing mechanism is at fair market value and bp has signed up to the protocol as this removes transition uncertainty for any interest rate and cross-currency interest rate swap contracts of the Group without fall-back clauses. The ISDA fallback protocol is expected to increase market activity and certainty such that corporates can finalize their plans for implementation of the transition. bp continues to monitor regulatory and market developments over the course of the transition.
In response to the cessation of the interbank offered rates (IBORs), bp has set up an internal working group to monitor market developments and manage the transition to alternative benchmark rates and is 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.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2020 was $1,405 million (2019 $692 million) in respect of liabilities of joint ventures and associates and $661 million (2019 $523 million) in respect of liabilities of other third parties.
The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions. Standing credit controls and processes were augmented intra-year given heightened uncertainty from increased oil price volatility and the evolving COVID-19 pandemic. Constraints on incoming credit risks were tightened, credit reporting and frequency was enhanced from the operational to board level, and key credit risk strategies were reviewed and vetted.
bp Annual Report and Form 20-F 2020
70
29. Financial instruments and financial risk factors – continued
For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses. Expected loss allowances for financial guarantee contracts are typically lower than their initial fair value less, where appropriate, amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off.
The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the event of default are reflected in the calculation when they are considered integral to the related asset.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2020, the group had in place credit enhancements designed to mitigate approximately $5.4 billion (2019 $7.0 billion) of credit risk, of which substantially all relates to assets in the scope of IFRS 9's impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related receivables. Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.
Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial assets which are subject to review for impairment under IFRS 9 is as set out below.
%
As at 31 December
2020
2019
AAA to AA-
11
%
16
%
A+ to A-
59
%
51
%
BBB+ to BBB-
8
%
13
%
BB+ to BB-
6
%
7
%
B+ to B-
13
%
11
%
CCC+ and below
3
%
2
%
Movements in the impairment provision for trade and other receivables are shown in Note 21.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the balance sheet.
Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group.
$ million
Gross amounts of recognized financial assets (liabilities)
Amounts set off
Net amounts presented on the balance sheet
Related amounts not set off in the balance sheet
Net amount
At 31 December 2020
Master netting arrangements
Cash collateral (received) pledged
Derivative assets
14,765
(2,019)
12,746
(2,075)
(386)
10,285
Derivative liabilities
(10,414)
2,019
(8,395)
2,075
—
(6,320)
Trade and other receivables
7,667
(3,679)
3,988
(693)
(122)
3,173
Trade and other payables
(7,862)
3,679
(4,183)
693
—
(3,490)
At 31 December 2019
Derivative assets
13,191
(2,724)
10,467
(1,971)
(206)
8,290
Derivative liabilities
(11,445)
2,724
(8,721)
1,971
—
(6,750)
Trade and other receivables
10,661
(5,211)
5,450
(961)
(190)
4,299
Trade and other payables
(10,266)
5,211
(5,055)
961
—
(4,094)
71
bp Annual Report and Form 20-F 2020
Financial statements
29. Financial instruments and financial risk factors – continued
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.
The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms. bp utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of receivables and, in the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days.
It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be significant. In common with the industry, bp routinely provides LCs to some of its suppliers.
The group has committed LC facilities totalling $11,325 million (2019 $12,175 million), allowing LCs to be issued for a maximum 24-month duration. There were also uncommitted secured LC facilities in place at 31 December 2020 for $3,460 million (2019 $4,440 million), which are secured against inventories or receivables when utilized. The facilities are held with over 25 international banks. The uncommitted secured LC facilities can only be terminated by either party giving a stipulated termination notice to the other.
In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their exposure. bp’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31 December 2020, $5,250 million (2019 $4,755 million) of the group’s trade payables subject to these arrangements were payable to LC providers, with no material exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that settlement periods were shorter.
Standard & Poor’s Ratings long-term credit rating for bp is A- (negative outlook) and Moody’s Investors Service rating is A1 (negative outlook) and the Fitch Ratings' long-term credit rating is A (stable).
During 2020, $14 billion (2019 $8 billion) of long-term taxable bonds were issued with terms ranging from two to thirty years. In addition the group issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion. Commercial paper is issued at competitive rates to meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $31.1 billion at 31 December 2020 (2019 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At 31 December 2020, the group had substantial amounts of undrawn borrowing facilities available, consisting of an undrawn committed $10.0 billion credit facility and $7.6 billion (2019 $7.6 billion) of standby facilities. On 1st March 2021, following an assessment of liquidity requirements, the group replaced these with new facility agreements, consisting of an undrawn committed $8.0 billion credit facility and $4.0 billion of standby facilities. The facilities are available for three and five years respectively at pre-agreed margins and are with 27 international banks, and borrowings under them would be at pre-agreed rates.
For further information on the group's sources and uses of cash see Liquidity and capital resources on page 306 of bp Annual Report and Form 20-F 2020.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below, that could be of a significantly different amount or could occur earlier than the expected maturity analysis provided.
The table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided. As a result of the 19 March 2021 debt buy back (see Note 26 for further information) $1.9 billion equivalent of cash outflows relating to finance debt that are presented in the table with maturities of 2-8 years have occurred within one year of the balance sheet date.
$ million
2020
2019
Trade and
other
payablesa
Accruals
Finance debt
Interest on finance debt
Trade and
other
payablesa
Accruals
Finance
debtb
Interest on finance debt
Within one year
33,290
4,650
9,119
1,778
43,699
5,066
10,065
2,037
1 to 2 years
1,728
157
6,292
1,477
1,937
261
6,726
1,641
2 to 3 years
1,590
184
7,031
1,305
1,465
146
7,949
1,409
3 to 4 years
1,332
87
8,047
1,110
1,409
181
7,022
1,172
4 to 5 years
1,335
217
6,652
919
1,332
108
7,554
942
5 to 10 years
4,570
108
22,156
2,408
5,863
231
23,540
1,970
Over 10 years
4,419
99
10,008
1,037
3,957
69
2,497
249
48,264
5,502
69,305
10,034
59,662
6,062
65,353
9,420
a 2020 includes $14,569 million (2019 $16,129 million) in relation to the Gulf of Mexico oil spill, of which $13,160 million (2019 $14,501 million) matures in greater than one year.
bp Annual Report and Form 20-F 2020
72
29. Financial instruments and financial risk factors – continued
The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $33,704 million at 31 December 2020 (2019 $24,787 million) to be received on the same day as the related cash outflows. As a result of the termination of derivatives associated with the 19 March 2021 debt buy back (see Note 26 for further information) $1.8 billion of cash outflows that are presented in the table with maturities of 2-8 years and $1.9 billion equivalent of cash inflows on the receive legs have occurred within one year of the balance sheet date.
$ million
Cash outflows for derivative financial instruments at 31 December
2020
2019
Within one year
2,384
1,678
1 to 2 years
1,976
2,384
2 to 3 years
2,017
2,838
3 to 4 years
3,074
2,906
4 to 5 years
2,582
3,321
5 to 10 years
15,263
10,633
Over 10 years
4,483
2,224
31,779
25,984
For further information on our derivative financial instruments, see Note 30.
30. Derivative financial instruments
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within Note 1.
The fair values of derivative financial instruments at 31 December are set out below.
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of variation margin.
Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy.
73
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Financial statements
30. Derivative financial instruments – continued
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the fair value hierarchy.
$ million
2020
2019
Fair value asset
Fair value liability
Fair value asset
Fair value liability
Derivatives held for trading
Currency derivatives
858
(694)
81
(744)
Oil price derivatives
1,519
(1,093)
1,918
(1,478)
Natural gas price derivatives
6,406
(5,489)
6,569
(4,871)
Power price derivatives
1,258
(1,037)
1,306
(952)
Other derivatives
7
—
110
—
10,048
(8,313)
9,984
(8,045)
Embedded derivatives
Other embedded derivatives
1
(7)
—
(77)
1
(7)
—
(77)
Cash flow hedges
Currency forwards
4
—
1
(4)
Gas price futures
—
—
—
—
4
—
1
(4)
Fair value hedges
Currency swaps
2,614
(82)
344
(637)
Interest rate swaps
80
—
138
(35)
2,694
(82)
482
(672)
12,747
(8,402)
10,467
(8,798)
Of which – current
2,992
(2,998)
4,153
(3,261)
– non-current
9,755
(5,404)
6,314
(5,537)
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 29.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
$ million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
153
9
3
2
2
689
858
Oil price derivatives
1,159
197
90
63
7
3
1,519
Natural gas price derivatives
1,210
731
596
525
476
2,868
6,406
Power price derivatives
425
223
161
107
76
266
1,258
Other derivatives
—
—
7
—
—
—
7
2,947
1,160
857
697
561
3,826
10,048
$ million
2019
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
48
23
9
1
—
—
81
Oil price derivatives
1,619
114
76
53
45
11
1,918
Natural gas price derivatives
1,889
824
615
489
433
2,319
6,569
Power price derivatives
556
269
146
94
67
174
1,306
Other derivatives
33
—
—
77
—
—
110
4,145
1,230
846
714
545
2,504
9,984
bp Annual Report and Form 20-F 2020
74
30. Derivative financial instruments – continued
Derivative liabilities held for trading have the following fair values and maturities.
$ million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
(502)
(117)
(11)
(1)
—
(63)
(694)
Oil price derivatives
(1,000)
(83)
(9)
(1)
—
—
(1,093)
Natural gas price derivatives
(1,095)
(595)
(479)
(422)
(348)
(2,550)
(5,489)
Power price derivatives
(345)
(184)
(126)
(81)
(68)
(233)
(1,037)
(2,942)
(979)
(625)
(505)
(416)
(2,846)
(8,313)
$ million
2019
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
(166)
(283)
(201)
(1)
(23)
(70)
(744)
Oil price derivatives
(1,405)
(56)
(14)
(2)
(1)
—
(1,478)
Natural gas price derivatives
(1,070)
(522)
(446)
(399)
(363)
(2,071)
(4,871)
Power price derivatives
(395)
(165)
(104)
(76)
(51)
(161)
(952)
(3,036)
(1,026)
(765)
(478)
(438)
(2,302)
(8,045)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
$ million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Fair value of derivative assets
Level 1
48
9
15
3
5
1
81
Level 2
3,342
858
367
212
100
709
5,588
Level 3
739
546
552
520
493
3,548
6,398
4,129
1,413
934
735
598
4,258
12,067
Less: netting by counterparty
(1,182)
(253)
(77)
(38)
(37)
(432)
(2,019)
2,947
1,160
857
697
561
3,826
10,048
Fair value of derivative liabilities
Level 1
(55)
(9)
(13)
(3)
(5)
(1)
(86)
Level 2
(3,577)
(809)
(263)
(136)
(41)
(79)
(4,905)
Level 3
(492)
(414)
(426)
(404)
(407)
(3,198)
(5,341)
(4,124)
(1,232)
(702)
(543)
(453)
(3,278)
(10,332)
Less: netting by counterparty
1,182
253
77
38
37
432
2,019
(2,942)
(979)
(625)
(505)
(416)
(2,846)
(8,313)
Net fair value
5
181
232
192
145
980
1,735
$ million
2019
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Fair value of derivative assets
Level 1
63
6
2
—
2
1
74
Level 2
5,344
1,014
439
210
120
42
7,169
Level 3
779
501
485
540
452
2,708
5,465
6,186
1,521
926
750
574
2,751
12,708
Less: netting by counterparty
(2,041)
(291)
(80)
(36)
(29)
(247)
(2,724)
4,145
1,230
846
714
545
2,504
9,984
Fair value of derivative liabilities
Level 1
(49)
(8)
(4)
(1)
(2)
(1)
(65)
Level 2
(4,522)
(932)
(458)
(146)
(113)
(101)
(6,272)
Level 3
(506)
(377)
(383)
(367)
(352)
(2,447)
(4,432)
(5,077)
(1,317)
(845)
(514)
(467)
(2,549)
(10,769)
Less: netting by counterparty
2,041
291
80
36
29
247
2,724
(3,036)
(1,026)
(765)
(478)
(438)
(2,302)
(8,045)
Net fair value
1,109
204
81
236
107
202
1,939
75
bp Annual Report and Form 20-F 2020
Financial statements
30. Derivative financial instruments – continued
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy.
$ million
Oil price
Natural gas price
Power price
Currency and other
Total
Fair value contracts at 1 January 2020
71
28
(125)
110
84
Gains (losses) recognized in the income statement
250
184
162
(66)
530
Sales
—
—
—
(32)
(32)
Settlements
(135)
(22)
(189)
—
(346)
Transfers out of level 3
5
(43)
(21)
(1)
(60)
Net fair value of contracts at 31 December 2020
191
147
(173)
11
176
Deferred day-one gains (losses)
881
Derivative asset (liability)
1,057
$ million
Oil price
Natural gas price
Power price
Other
Total
Fair value contracts at 1 January 2019
23
(13)
(148)
107
(31)
Gains (losses) recognized in the income statement
128
82
244
2
456
Gains (losses) recognized in other comprehensive income
—
—
(18)
—
(18)
Settlements
(79)
(21)
(179)
—
(279)
Transfers out of level 3
(1)
(20)
(24)
1
(44)
Net fair value of contracts at 31 December 2019
71
28
(125)
110
84
Deferred day-one gains (losses)
949
Derivative asset (liability)
1,033
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2020 was a $315-million gain (2019 $250-million gain related to derivatives still held at 31 December 2019).
Derivative gains and losses
The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these items was a net gain of $2,808 million. This number does not include gains and losses on the change in value of contracts which are not recognized under IFRS such as transportation and storage contracts, but does include the associated financially settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
The group also enters into derivative contracts relating to foreign currency risk management activities including contracts that the group has entered into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. Gains and losses on these contracts are included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a net gain of $829 million (2019 $160 million net gain and 2018 $351 million net loss), however where these gains and losses arise on derivatives hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
Cash flow hedges
(i) Foreign currency risk of highly probable forecast capital expenditure
At 31 December 2020, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed asset section of the balance sheet.
The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to the income statement.
The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality counterparties; and
bp Annual Report and Form 20-F 2020
76
30. Derivative financial instruments – continued
•differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Korean won/US dollar). The group's cash flow hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness.
The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.
(ii) Commodity price risk of highly probable forecast sales
During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to be cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of each day.
The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a percentage of future gas sales from its BPX Energy business.
The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with the notional amount designated on the forecast transaction.
The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did not designate any net positions as hedged items in cash flow hedges of commodity price risk.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period.
$ million
Change in fair value of hedging instrument used to calculate ineffectiveness
Change in fair value of hedged item used to calculate ineffectiveness
Hedge ineffectiveness recognized in profit or (loss)
At 31 December 2020
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
4
(4)
—
Commodity price risk
Highly probable forecast sales
78
(78)
—
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
(1)
1
—
Commodity price risk
Highly probable forecast sales
(100)
100
—
The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge relationships.
Carrying amount of hedging instrument
Nominal amounts of hedging instruments
Assets
Liabilities
At 31 December 2020
$ million
$ million
$ million
mmBtu
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
4
—
162
Commodity price risk
Highly probable forecast sales
—
—
(175)
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
1
(4)
150
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
All of the nominal amount of hedging instruments at 31 December 2020 and 2019 relating to highly probably forecast capital expenditure matures within 12 months of the relevant balance sheet date. Of the nominal amount of hedging instruments at 31 December 2020 relating to highly probably forecast sales 135 mmBtu matures within 12 months and 40 mmBtu within one to two years.
77
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Financial statements
30. Derivative financial instruments – continued
The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as hedging instruments in cash flow hedge relationships at 31 December.
Weighted average price/rate
2020
2019
At 31 December
Forecast capital expenditure
Forecast sales
Forecast capital expenditure
Sterling/US dollar
1.35
1.35
Euro/US dollar
—
1.11
Korean won/US dollar
1,174.47
1,115.66
Henry Hub $/mmBtu
2.88
Fair value hedges
At 31 December 2020, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group’s approach to interest rate and foreign currency exchange risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Canadian dollar and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge ineffectiveness. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and reliably measurable component of interest rate risk.
All of the fair value hedge accounting relationships currently in place are directly affected by the interest rate benchmark reform which will replace interbank offered rates (IBORs) with alternative benchmark rates as they all manage interest rate risk. The Group is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. The nominal amounts of the applicable hedging instruments represent the extent of the risk exposure bp manages for financial derivatives designated in fair value hedge relationships that is directly affected by the interest rate benchmark reform. These are disclosed in the table below. 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. However, the temporary reliefs provided by IFRS 9 allow bp to assume that in the event that significant uncertainty around the reform arises:
•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.
Judgement will be required to determine when the uncertainty arising from interest rate benchmark reform is no longer present and when the temporary reliefs no longer apply. However, at 31 December 2020 the reliefs apply and bp continues to monitor regulatory and market developments as it manages the contractual transition.
For foreign currency exposures, the group excludes from the designation the foreign currency basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the group’s policy on costs of hedging.
The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only with high credit quality counterparties; and
•sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the instrument and the bond.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.
$ million
Change in fair value of hedging instrument used to calculate ineffectiveness
Change in fair value of hedged item used to calculate ineffectiveness
Hedge ineffectiveness recognized in profit or (loss)
At 31 December 2020
Fair value hedges
Interest rate risk on finance debt
(258)
258
—
Interest rate and foreign currency risk on finance debt
(2,743)
2,549
194
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
(764)
737
27
Interest rate and foreign currency risk on finance debt
(336)
286
50
bp Annual Report and Form 20-F 2020
78
30. Derivative financial instruments – continued
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
$ million
Carrying amount of hedging instrument
Nominal amounts of hedging instruments
At 31 December 2020
Assets
Liabilities
Fair value hedges
Interest rate risk on finance debt
80
—
4,104
Interest rate and foreign currency risk on finance debt
2,614
(82)
23,313
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
138
(35)
13,442
Interest rate and foreign currency risk on finance debt
344
(637)
21,296
All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value hedges is included within the production and manufacturing expenses section of the income statement.
The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
$ million
At 31 December 2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
5-10 years
Over 10 years
Total
Fair value hedges
Interest rate risk on finance debt
2,705
996
—
227
—
176
—
4,104
Interest rate and foreign currency risk on finance debt
737
1,056
2,039
3,175
2,804
8,587
4,915
23,313
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
3,000
2,576
4,039
1,200
206
2,421
—
13,442
Interest rate and foreign currency risk on finance debt
882
672
1,400
2,777
3,109
10,216
2,240
21,296
The table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
At 31 December
2020
2019
Interest rate swaps
Cross-currency interest rate swaps
Interest rate swaps
Cross-currency interest rate swaps
Interest rate
0.58
%
1.88
%
2.36
%
3.27
%
Sterling/US dollar
1.33
1.32
Euro/US dollar
1.14
1.15
Canadian dollar/US dollar
0.78
0.87
The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged items designated in fair value hedge relationships at 31 December.
$ million
Carrying amount of hedged item
Accumulated fair value adjustment included in the carrying amount of hedged items
At 31 December 2020
Assets
Liabilities
Assets
Liabilities
Discontinued hedges
Fair value hedges
Interest rate risk on finance debt
—
(4,196)
—
(81)
(775)
Interest rate and foreign currency risk on finance debt
—
(23,253)
—
(938)
—
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
—
(13,441)
—
(100)
(714)
Interest rate and foreign currency risk on finance debt
—
(21,240)
—
(525)
—
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
79
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Financial statements
30. Derivative financial instruments – continued
Movement in reserves related to hedge accounting
The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage convention of this table is consistent with that presented in Note 32.
$ million
Cash flow hedge reserve
Costs of hedging reserve
Highly probable forecast capital expenditure
Highly probable forecast sales
Purchase of equitya
Interest rate and foreign currency risk on finance debt
Total
At 1 January 2020
(1)
—
(651)
(170)
(822)
Recognized in other comprehensive income
Cash flow hedges marked to market
7
78
—
—
85
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss
—
(37)
—
—
(37)
Costs of hedging marked to market
—
—
—
42
42
Costs of hedging reclassified to the income statement
—
—
—
22
22
7
41
—
64
112
Cash flow hedges transferred to the balance sheet
6
—
—
—
6
At 31 December 2020
12
41
(651)
(106)
(704)
$ million
Cash flow hedge reserve
Costs of hedging reserve
Highly probable forecast capital expenditure
Highly probable forecast sales
Purchase of equitya
Interest rate and foreign currency risk on finance debt
Total
At 1 January 2019
(21)
(6)
(651)
(223)
(901)
Recognized in other comprehensive income
Cash flow hedges marked to market
(3)
(100)
—
—
(103)
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss
—
106
—
—
106
Costs of hedging marked to market
—
—
—
(4)
(4)
Costs of hedging reclassified to the income statement
—
—
—
57
57
(3)
6
—
53
56
Cash flow hedges transferred to the balance sheet
23
—
—
—
23
At 31 December 2019
(1)
—
(651)
(170)
(822)
a See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity.
Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified from the cash flow hedge reserve into profit or loss during the year relate to continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in sales and other operating revenues in the income statement.
Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency risk on debt which is a time-period related item.
bp Annual Report and Form 20-F 2020
80
31. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
2020
2019
2018
Issued
Shares thousand
$ million
Shares thousand
$ million
Shares thousand
$ million
8% cumulative first preference shares of £1 eacha
7,233
12
7,233
12
7,233
12
9% cumulative second preference shares of £1 eacha
5,473
9
5,473
9
5,473
9
21
21
21
Ordinary shares of 25 cents each
At 1 January
21,535,840
5,383
21,525,464
5,381
21,288,193
5,322
Issue of new shares for the scrip dividend programme
—
—
208,927
52
195,305
49
Issue of new shares for employee share-based payment plans
34,000
9
37,400
9
92,168
23
Issue of new shares – other
—
—
—
—
—
—
Repurchase of ordinary share capital
(120,058)
(30)
(235,951)
(59)
(50,202)
(13)
At 31 December
21,449,782
5,362
21,535,840
5,383
21,525,464
5,381
5,383
5,404
5,402
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
During 2020 the company repurchased 120 million ordinary shares for a total consideration of $776 million, including transaction costs of $4 million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.6% of ordinary share capital. The number of shares in issue is reduced when shares are repurchased.
Treasury sharesa
2020
2019
2018
Shares thousand
Nominal value $ million
Shares thousand
Nominal value $ million
Shares thousand
Nominal value $ million
At 1 January
1,296,856
323
1,426,265
356
1,482,072
370
Purchases for settlement of employee share plans
—
—
1,118
—
757
—
Issue of new shares for employee share-based payment plans
34,116
9
37,400
9
92,168
23
Shares re-issued for employee share-based payment plans
(143,322)
(36)
(167,927)
(42)
(148,732)
(37)
At 31 December
1,187,650
296
1,296,856
323
1,426,265
356
Of which – shares held in treasury by bp
1,105,157
275
1,163,077
290
1,264,732
316
– shares held in ESOP trusts
82,491
21
133,707
33
161,518
40
– shares held by bp’s US share plan administratorb
2
—
72
—
15
—
a See Note 32 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing 5.4% (2019 5.9% and 2018 6.9%) of the called-up ordinary share capital of the company.
During 2020, the movement in shares held in treasury by bp represented less than 0.3% (2019 less than 0.5% and 2018 less than 1.0%) of the ordinary share capital of the company.
81
bp Annual Report and Form 20-F 2020
Financial statements
32. Capital and reserves
Share capital
Share premium account
Capital redemption reserve
Merger reserve
Total share capital and capital reserves
At 1 January 2020
5,404
12,417
1,498
27,206
46,525
Profit (loss) for the year
—
—
—
—
—
Items that may be reclassified subsequently to profit or loss
Cash flow hedges and costs of hedging (including reclassifications)
—
—
—
—
—
Share of items relating to equity-accounted entities, net of taxa
—
—
—
—
—
Other
—
—
—
—
—
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
—
—
—
—
—
Cash flow hedges that will subsequently be transferred to the balance sheet
—
—
—
—
—
Total comprehensive income
—
—
—
—
—
Dividends
52
(52)
—
—
—
Cash flow hedges transferred to the balance sheet, net of tax
—
—
—
—
—
Repurchases of ordinary share capital
(59)
—
59
—
—
Share-based payments, net of taxb
9
164
—
—
173
Share of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
—
Transactions involving non-controlling interests, net of taxe
—
—
—
—
—
At 31 December 2019
5,404
12,417
1,498
27,206
46,525
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
c Principally relates to a non-controlling interest transaction entered into by Rosneft.
d Principally relates to the sale of interests in our UK and New Zealand retail property portfolio, for which proceeds of $0.5 billion and $0.2 billion were received respectively.
e Principally relates to the sale of a 49% interest in bp's retail property portfolio in Australia.
bp Annual Report and Form 20-F 2020
82
32. Capital and reserves – continued
$ million
Treasury shares
Foreign currency translation reserve
Available- for-sale investments
Cash flow hedges
Costs of hedging
Total fair value reserves
Profit and loss account
bp shareholders’ equity
Non-controlling interests
Total equity
Hybrid bonds
Other interest
(14,412)
(6,495)
—
(752)
(160)
(912)
73,706
98,412
—
2,296
100,708
—
—
—
—
—
—
(20,305)
(20,305)
256
(680)
(20,729)
—
(2,224)
—
—
—
—
—
(2,224)
—
37
(2,187)
—
—
—
31
60
91
—
91
—
—
91
—
—
—
—
—
—
312
312
—
—
312
—
—
—
—
—
—
71
71
—
—
71
—
—
—
—
—
—
65
65
—
—
65
—
—
—
7
—
7
—
7
—
—
7
—
(2,224)
—
38
60
98
(19,857)
(21,983)
256
(643)
(22,370)
—
—
—
—
—
—
(6,367)
(6,367)
—
(238)
(6,605)
—
—
—
6
—
6
—
6
—
—
6
—
—
—
—
—
—
(776)
(776)
—
—
(776)
1,188
—
—
—
—
—
(638)
726
—
—
726
—
—
—
—
—
—
1,341
1,341
—
—
1,341
—
—
—
—
—
—
(48)
(48)
11,909
—
11,861
—
—
—
—
—
—
—
—
(89)
—
(89)
—
—
—
—
—
—
3
3
—
—
3
—
—
—
—
—
—
(64)
(64)
—
827
763
(13,224)
(8,719)
—
(708)
(100)
(808)
47,300
71,250
12,076
2,242
85,568
(15,767)
(8,902)
—
(777)
(210)
(987)
78,748
99,444
—
2,104
101,548
—
—
—
—
—
—
(329)
(329)
—
(1)
(330)
(15,767)
(8,902)
—
(777)
(210)
(987)
78,419
99,115
—
2,103
101,218
—
—
—
—
—
—
4,026
4,026
—
164
4,190
—
2,407
—
—
—
—
—
2,407
—
9
2,416
—
—
—
5
50
55
—
55
—
—
55
—
—
—
—
—
—
82
82
—
—
82
—
—
—
—
—
—
(64)
(64)
—
—
(64)
—
—
—
—
—
—
171
171
—
—
171
—
—
—
(3)
—
(3)
—
(3)
—
—
(3)
—
2,407
—
2
50
52
4,215
6,674
—
173
6,847
—
—
—
—
—
—
(6,929)
(6,929)
—
(213)
(7,142)
—
—
—
23
—
23
—
23
—
—
23
—
—
—
—
—
—
(1,511)
(1,511)
—
—
(1,511)
1,355
—
—
—
—
—
(809)
719
—
—
719
—
—
—
—
—
—
5
5
—
—
5
—
—
—
—
—
—
316
316
—
233
549
(14,412)
(6,495)
—
(752)
(160)
(912)
73,706
98,412
—
2,296
100,708
83
bp Annual Report and Form 20-F 2020
Financial statements
32. Capital and reserves – continued
Share capital
Share premium account
Capital redemption reserve
Merger reserve
Total share capital and capital reserves
At 31 December 2017
5,343
12,147
1,426
27,206
46,122
Adjustment on adoption of IFRS 9, net of tax
—
—
—
—
—
At 1 January 2018
5,343
12,147
1,426
27,206
46,122
Profit (loss) for the year
—
—
—
—
—
Items that may be reclassified subsequently to profit or loss
Cash flow hedges and costs of hedging (including reclassifications)
—
—
—
—
—
Share of items relating to equity-accounted entities, net of taxa
—
—
—
—
—
Other
—
—
—
—
—
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
—
—
—
—
—
Cash flow hedges that will subsequently be transferred to the balance sheet
—
—
—
—
—
Total comprehensive income
—
—
—
—
—
Dividends
49
(49)
—
—
—
Cash flow hedges transferred to the balance sheet, net of tax
—
—
—
—
—
Repurchases of ordinary share capital
(13)
—
13
—
—
Share-based payments, net of taxb
23
207
—
—
230
Share of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
—
Transactions involving non-controlling interests, net of tax
—
—
—
—
—
At 31 December 2018
5,402
12,305
1,439
27,206
46,352
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
bp Annual Report and Form 20-F 2020
84
32. Capital and reserves – continued
$ million
Treasury shares
Foreign currency translation reserve
Available- for-sale investments
Cash flow hedges
Costs of hedging
Total fair value reserves
Profit and loss account
bp shareholders’ equity
Non-controlling interests
Total equity
Hybrid bonds
Other interest
(16,958)
(5,156)
17
(760)
—
(743)
75,226
98,491
—
1,913
100,404
—
—
(17)
—
(37)
(54)
(126)
(180)
—
—
(180)
(16,958)
(5,156)
—
(760)
(37)
(797)
75,100
98,311
—
1,913
100,224
—
—
—
—
—
—
9,383
9,383
—
195
9,578
—
(3,746)
—
—
—
—
—
(3,746)
—
(41)
(3,787)
—
—
—
(6)
(173)
(179)
—
(179)
—
—
(179)
—
—
—
—
—
—
417
417
—
—
417
—
—
—
—
—
—
7
7
—
—
7
—
—
—
—
—
—
1,599
1,599
—
—
1,599
—
—
—
(37)
—
(37)
—
(37)
—
—
(37)
—
(3,746)
—
(43)
(173)
(216)
11,406
7,444
—
154
7,598
—
—
—
—
—
—
(6,699)
(6,699)
—
(170)
(6,869)
—
—
—
26
—
26
—
26
—
—
26
—
—
—
—
—
—
(355)
(355)
—
—
(355)
1,191
—
—
—
—
—
(718)
703
—
—
703
—
—
—
—
—
—
14
14
—
—
14
—
—
—
—
—
—
—
—
—
207
207
(15,767)
(8,902)
—
(777)
(210)
(987)
78,748
99,444
—
2,104
101,548
.
85
bp Annual Report and Form 20-F 2020
Financial statements
32. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares.
Treasury shares
Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) and bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.
Available-for-sale investments
This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on these investments in profit or loss.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities.
Costs of hedging
This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging relationship.
Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
Non-controlling interests
Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-controlling interests are perpetual subordinated hybrid bonds issued by BP Capital Markets PLC, a group subsidiary, on 17 June 2020 in euro, sterling and US dollars for a US dollar equivalent amount of $11.9 billion. The hybrid bonds include redemption options exercisable at the group’s discretion from June 2025 to March 2030 (the first ‘call date’), on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or tax regime) as set out in the individual terms of each issue. Coupons are fixed for an initial period up to dates from September 2025 to June 2030 at rates of 3.25% to 4.875% and reset to rates determined by the contractual terms of each instrument on certain dates thereafter. The contractual terms of the hybrid bonds 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. 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 consolidated financial statements.
bp Annual Report and Form 20-F 2020
86
32. Capital and reserves – continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
$ million
2020
Pre-tax
Tax
Net of tax
Items that may be reclassified subsequently to profit or loss
Share of items relating to equity-accounted entities, net of tax
417
—
417
Other
—
7
7
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
2,317
(718)
1,599
Cash flow hedges that will subsequently be transferred to the balance sheet
(37)
—
(37)
Other comprehensive income
(1,266)
(714)
(1,980)
33. Contingent liabilities and legal proceedings
Contingent liabilities
There were contingent liabilities at 31 December 2020 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in Note 29.
In the normal course of the group’s business, bp group entities are subject to legal and regulatory proceedings arising out of current and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current legal and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material.
The group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain matters that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could, in aggregate, be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp does not expect there to be any material impact upon the group‘s results of operations, financial position or liquidity.
87
bp Annual Report and Form 20-F 2020
Financial statements
33. Contingent liabilities and legal proceedings – continued
The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to the group‘s results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a material impact on the group’s results of operations, financial position or liquidity.
If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations it is possible that, in certain circumstances, bp could be partially or wholly responsible for decommissioning. While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, bp is not currently aware of any such material cases that have a greater than remote chance of reverting to the group. In one current case in the US, the owner of facilities has filed for bankruptcy and submitted a proposed restructuring plan. It is considered possible that certain decommissioning costs associated with some of these facilities may in the future revert to bp in relation to assets previously disposed. No provision has been recognised and no reliable estimate of this potential exposure is available, however any amount which may revert is not expected to have a material impact on the group’s financial position. Furthermore, as described in Provisions and contingencies within Note 1, decommissioning provisions associated with customers & products facilities are not generally recognized as the potential obligations cannot be measured given their indeterminate settlement dates.
Contingent liabilities related to the Gulf of Mexico oil spill
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance.
Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
Introduction
BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico, where the semi-submersible rig Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident are discussed below.
Economic and Property Damages Settlement
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 court supervised settlement programme. That settlement programme had been established to administer claims pursuant to the Economic and Property Damages Settlement (EPD Settlement) which was entered into with the plaintiffs’ steering committee (PSC) acting on behalf of individual and business plaintiffs in the multi-district litigation proceedings in 2012 to resolve certain economic and property damage claims. The Court also ordered that all future issues concerning EPD Settlement claims would be considered time barred under the settlement programme and that the claims administrator should proceed to complete post-closure administrative wind down activities.
Medical Benefits Class Action Settlement
In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the PSC. It involves payments to qualifying class members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for qualifying class members. As of 31 December 2020, 1 claim remained pending determination. In total, 27,603 claims (comprising 22,833 SPC claims and 4,770 PMCP claims) have been approved for compensation totalling approximately $67 million and 9,623 claims have been denied.
The Medical Settlement also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). In order to seek compensation from bp for an LMPC, class members must file a notice with the Medical Claims Administrator within 4 years after the date of first diagnosis of the LMPC. As of 31 December 2020, there were 612 pending lawsuits brought by class members claiming LMPCs.
Other civil complaints – economic loss
Nearly all economic loss and property damage claims from individuals and businesses that either opted out of the EPD Settlement and/or were excluded from that settlement have been settled or dismissed.
The claims of 10 US-resident private plaintiffs remain in the multi-district litigation proceedings in federal district court in New Orleans. Those claims have been scheduled for a process of discovery and dispositive motions which is expected to conclude around mid-2021.
Other civil complaints – personal injury
The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the Medical Settlement and/or were excluded from that settlement have been dismissed.
In 2019, the federal district court in New Orleans determined in a series of proceedings that 923 plaintiffs had post-explosion clean-up, medical monitoring and personal injury claims that complied with the court’s prior order to show cause why their claims should not be dismissed. As a result of several subsequent dismissals, approximately 881 plaintiffs’ claims remained as of 31 December 2020.
On 23 February 2021, the district court issued a Case Management Order announcing its intent to sever the personal injury cases from the multi-district litigation proceedings and staying the litigation of any punitive damages claims until plaintiffs can establish a right to compensatory damages. The district court also stated that the order severing and re-allotting these cases is forthcoming. Most cases will remain in the federal district court in New Orleans and be re-allotted among the judges of that court.
Individual securities litigation
In October 2020, bp engaged with the plaintiffs in a mediation of all remaining multi-district litigation proceedings in federal district court in Houston. 28 such actions on behalf of 115 plaintiffs remained pending on 31 December 2020. The mediation resulted in settlements of all these cases and settlement agreements have now been executed with all plaintiffs.
bp Annual Report and Form 20-F 2020
88
33. Contingent liabilities and legal proceedings – continued
Canadian class actions
Following various legal proceedings, a plaintiff seeking to assert claims under Canadian law against bp on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of bp ordinary shares and ADSs appealed the motion to dismiss the case in its entirety granted on 8 November 2019. On 20 January 2021, the Court of Appeal affirmed that dismissal.
Non-US government lawsuits
On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP America Production Company (BPAPC) and other bp subsidiaries. On 27 June 2018, bp answered the complaint by seeking dismissal on various grounds including that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. There has been no material development in these proceedings during 2020 and up to the date of publication of this BP Annual Report and Form 20-F 2020 in 2021.
On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BPXP, BPAPC, and other purported bp subsidiaries. In these class actions, plaintiffs seek an order requiring the bp defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BPXP and BPAPC opposed class certification and sought dismissal, principally on the basis that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. The court certified the class on 25 September 2019 and bp appealed that decision including by way of constitutional challenge (amparo). The amparo action was denied on 8 October 2020 and on 18 January 2021, bp’s appeal of that ruling was also denied. Class notification procedures have not yet been finally determined.
These legal actions remain at a relatively early stage and while it is not possible to predict the outcome, bp believes that it has valid defences, and it intends to defend such actions vigorously.
Other legal proceedings
FERC and CFTC matters
Following an investigation by the US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) of several bp entities, the Administrative Law Judge of the FERC ruled on 13 August 2015 that bp manipulated the market by selling next-day, fixed price natural gas at Houston Ship Channel in 2008 in order to suppress the Gas Daily index and benefit its financial position. On 11 July 2016 the FERC issued an Order affirming the initial decision and directing bp to pay a civil penalty of $20.16 million and to disgorge $207,169 in unjust profits. On 10 August 2016, bp filed a request for rehearing with the FERC. On 17 December 2020, the FERC denied the rehearing request, sustaining the prior decision and ordering payment of the penalty and disgorgement amounts. bp has complied with the order but strongly disagrees with the FERC’s decision and is pursuing an appeal to the US Court of Appeals.
Lead paint matters
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary« of bp, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another company that manufactured lead pigment during the period 1920-1946. The plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that the incurrence of liability is remote. Consequently, bp believes that the impact of these lawsuits on the group’s results, financial position or liquidity will not be material.
Climate change
BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in multiple lawsuits brought in various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a variety of legal theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change and seek remedies including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the various cases could be substantial. All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, BP believes that it has valid defences, and it intends to defend such actions vigorously.
Louisiana Coastal restoration
Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas companies seeking damages for coastal erosion. bp entities are defendants in 17 of these cases. The lawsuits allege that the defendants' historical operations in oil fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted without the required coastal use permits. The plaintiffs seek unspecified statutory penalties and damages, including the costs of restoring coastal wetlands allegedly impacted by oil field operations.
In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are defendants in two of these private landowner cases.
All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, bp believes that it has valid defences, and it intends to defend such actions vigorously.
89
bp Annual Report and Form 20-F 2020
Financial statements
34. Remuneration of senior management and non-executive directors
Remuneration of directors
$ million
2020
2019
2018
Total for all directors
Emoluments
6
9
8
Amounts received under incentive schemesa
14
20
16
Total
20
29
24
a Excludes amounts relating to past directors.
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year.
Pension contributions
During 2020 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2020, one executive director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of service prior to 1 September 2016.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 103 of bp Annual Report and Form 20-F 2020. See also Related-party transactions on page 326 of bp Annual Report and Form 20-F 2020.
Remuneration of directors and senior management
$ million
2020
2019
2018
Total for all senior management and non-executive directors
Short-term employee benefits
17
30
25
Pensions and other post-retirement benefits
2
2
2
Share-based payments
52
32
32
Termination benefits
8
—
—
Total
79
64
59
Senior management comprises members of the leadership team, see pages 78-79 of bp Annual Report and Form 20-F 2020 for further information.
Short-term employee benefits
These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments.
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
Termination benefits
Termination benefits include compensation to senior management for loss of office.
bp Annual Report and Form 20-F 2020
90
35. Employee costs and numbers
$ million
Employee costs
2020
2019
2018
Wages and salariesa
7,600
7,497
7,931
Social security costs
729
733
743
Share-based paymentsb
728
694
669
Pension and other post-retirement benefit costs
852
948
1,154
9,909
9,872
10,497
2020
2019
2018
Average number of employeesc
US
Non-US
Total
US
Non-US
Total
US
Non-US
Total
Upstream
4,800
10,600
15,400
5,800
11,000
16,800
5,900
11,500
17,400
Downstreamd
5,800
37,800
43,600
5,700
37,300
43,000
6,000
36,300
42,300
Other businesses and corporatee
1,800
7,300
9,100
2,100
10,600
12,700
1,900
12,100
14,000
12,400
55,700
68,100
13,600
58,900
72,500
13,800
59,900
73,700
a Includes termination costs of $1,237 million (2019 $182 million and 2018 $493 million). Reinvent bp restructuring accruals of $714 million and provisions of $428 million for employee termination payments were held at 31 December 2020.
b The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.
c Reported to the nearest 100.
d Includes 19,100 (2019 18,100 and 2018 17,100) service station staff.
e Includes 0 (2019 2,500 and 2018 4,000) agricultural, operational and seasonal workers in Brazil.
The reduction in the average number of employees in 2020 compared to 2019 is principally a result of the reinvent bp programme and divestment activity.
This information has not been restated for the changes in reportable segments as data is not available.
36. Auditor’s remuneration
$ million
Fees
2020
2019
2018
The audit of the company annual accountsa
30
32
25
The audit of accounts of subsidiaries of the company
11
11
10
Total audit
41
43
35
Audit-related assurance servicesb
11
4
4
Total audit and audit-related assurance services
52
47
39
Non-audit and other assurance services
1
1
2
Services relating to bp pension plans
1
1
1
54
49
42
a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
b Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services. 2020 fees include audit fees relating to the Petrochemicals disposal.
With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing Ernst & Young LLP (EY).
2020 includes $0.5 million of additional fees for 2019. 2019 includes $3.6 million of additional fees for 2018. In addition to the amounts shown in the table above, in 2018 $0.75 million of additional fees were paid to EY in respect of their audit for 2017. Auditor's remuneration is included in the income statement within distribution and administration expenses.
Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods presented.
The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit committee through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender, including matters relevant to the 2020 audit, have been reviewed and challenged by the Audit Committee, before being approved. Deloitte performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit-related or assurance nature.
Under SEC regulations, the remuneration of the auditor of $54 million (2019 $49 million and 2018 $42 million) is required to be presented as follows: audit $41 million (2019 $43 million and 2018 $35 million); other audit-related $11 million (2019 $4 million and 2018 $4 million); tax $nil (2019 $nil and 2018 $nil); and all other fees $2 million (2019 $2 million and 2018 $3 million).
91
bp Annual Report and Form 20-F 2020
Financial statements
37. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2020 and the group percentage of ordinary share capital (to nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets and liabilities of the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report.
Subsidiaries
%
Country of incorporation
Principal activities
International
BP Corporate Holdings
100
England & Wales
Investment holding
BP Exploration Operating Company
100
England & Wales
Exploration and production
*BP Global Investments
100
England & Wales
Investment holding
*BP International
100
England & Wales
Integrated oil operations
BP Oil International
100
England & Wales
Integrated oil operations
*Burmah Castrol
100
Scotland
Lubricants
Angola
BP Exploration (Angola)
100
England & Wales
Exploration and production
Azerbaijan
BP Exploration (Caspian Sea)
100
England & Wales
Exploration and production
BP Exploration (Azerbaijan)
100
England & Wales
Exploration and production
Canada
*BP Holdings Canada
100
England & Wales
Investment holding
Egypt
BP Exploration (Delta)
100
England & Wales
Exploration and production
Germany
BP Europa SE
100
Germany
Refining and marketing
India
BP Exploration (Alpha)
100
England & Wales
Exploration and production
Trinidad & Tobago
BP Trinidad and Tobago
70
US
Exploration and production
UK
BP Capital Markets
100
England & Wales
Finance
US
*BP Holdings North America
100
England & Wales
Investment holding
Atlantic Richfield Company
100
US
Exploration and production, refining and marketing
BP America
100
US
BP America Production Company
100
US
BP Company North America
100
US
BP Corporation North America
100
US
BP Products North America
100
US
Standard Oil Company
100
US
BP Capital Markets America
100
US
Finance
Associates
%
Country of incorporation
Principal activities
Russia
Rosneft Oil Company
19.75
Russia
Integrated oil operations
38. Condensed consolidating information on certain US subsidiaries
On June 30, 2020, bp completed the sale of all its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy, and BP Exploration (Alaska) Inc. is therefore no longer a subsidiary of BP p.l.c. Accordingly, bp is no longer presenting condensed consolidating information on BP Exploration (Alaska) Inc. as a subsidiary issuer of registered securities pursuant to Rule 3-10 of Regulation S-X. BP p.l.c. will continue to fully and unconditionally guarantee the payment obligations under the BP Prudhoe Bay Royalty Trust. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc., which are 100%-owned finance subsidiaries of BP p.l.c.
bp Annual Report and Form 20-F 2020
92
Additional disclosures
Additional information
Capital expenditure
Information for 2018 to 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Significant accounting policies, judgements, estimates and assumptions - Change in segmentation.
$ million
2020
2019
2018
Capital expenditure
Organic capital expenditure
12,034
15,238
15,140
Inorganic capital expenditureab
2,021
4,183
9,948
14,055
19,421
25,088
$ million
2020
2019
2018
Organic capital expenditure by segment
gas & low carbon energy
US
50
31
72
Non-US
3,707
5,216
5,735
3,757
5,247
5,807
oil production & operations
US
3,330
4,004
3,431
Non-US
2,318
2,706
2,898
5,648
6,710
6,329
customers & products
US
632
913
877
Non-US
1,698
2,084
1,904
2,330
2,997
2,781
other businesses & corporate
US
41
31
33
Non-US
258
253
190
299
284
223
12,034
15,238
15,140
Organic capital expenditure by geographical area
US
4,053
4,979
4,413
Non-US
7,981
10,259
10,727
12,034
15,238
15,140
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 2019 and $6,788 million for 2018 relating to this transaction. 2018 includes $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with Conoco-Phillips in which Conoco-Philips simultaneously purchased bp's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2020, 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing agreement« in Azerbaijan.
b 2020 includes a $500 million deposit in respect of the strategic partnership with Equinor and $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries.
93
bp Annual Report and Form 20-F 2020
Adjusting items
Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the group’s reported financial performance. Prior to 2021 adjusting items were reported under two different headings – non-operating items and fair value accounting effects. Information for 2018 to 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Significant accounting policies, judgements, estimates and assumptions - Change in segmentation. An analysis of adjusting items is shown in the table below.
$ million
2020
2019
2018
gas & low carbon energy
Gain on sale of businesses and fixed assets
—
(1)
51
Impairment and losses on sale of businesses and fixed assetsa b
(6,220)
(1,271)
(427)
Environmental and other provisions
—
—
—
Restructuring, integration and rationalization costsc
(127)
(1)
(19)
Fair value accounting effects
(738)
714
60
Otherd
(672)
56
(45)
(7,757)
(503)
(380)
oil production & operations
Gain on sale of businesses and fixed assetsa
360
143
386
Impairment and losses on sale of businesses and fixed assetsa
(7,012)
(6,643)
(361)
Environmental and other provisions
(2)
(32)
(35)
Restructuring, integration and rationalization costsc
(278)
(90)
(116)
Fair value gain (loss) on embedded derivatives
—
—
17
Fair value accounting effects
—
(8)
(99)
Otherd
(1,763)
14
76
(8,695)
(6,616)
(132)
customers & products
Gain on sale of businesses and fixed assetsa e
2,320
50
15
Impairment and losses on sale of businesses and fixed assetsa
(1,136)
(122)
(69)
Environmental and other provisions
(33)
(78)
(83)
Restructuring, integration and rationalization costsc
(633)
85
(405)
Fair value accounting effects
(149)
160
95
Other
(39)
(12)
(174)
330
83
(621)
Rosneft
Other
(205)
(103)
(95)
(205)
(103)
(95)
other businesses & corporate
Gain on sale of businesses and fixed assetsa
194
—
4
Impairment and losses on sale of businesses and fixed assetsa
(1)
(38)
(4)
Environmental and other provisionsf
(177)
(231)
(640)
Restructuring, integration and rationalization costsb
(258)
8
(185)
Gulf of Mexico oil spill response
(255)
(319)
(714)
Fair value accounting effects
675
—
—
Otherg
125
(33)
(134)
303
(613)
(1,673)
Total before interest and taxation
(16,024)
(7,752)
(2,901)
Finance costsh
(625)
(511)
(479)
Total before taxation
(16,649)
(8,263)
(3,380)
Taxation credit (charge) on adjusting items
4,334
1,788
522
Taxation - impact of US tax reformi
—
—
121
Taxation - impact of foreign exchangej
(99)
—
—
Total after taxation
(12,414)
(6,475)
(2,737)
a See Financial statements – Note 4 for further information.
b 2019 includes $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP Bunge Bioenergia.
c Restructuring charges are classified as adjusting items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. 2020 includes recognized provisions for restructuring costs for plans that were formalized during the year. 2018 includes amounts related to the programme originally announced in 2014 that was completed in 2018.
d 2020 includes exploration write-offs of $673 million in gas & low carbon energy relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in India and and the impairment of certain intangible assets in Mauritania and Senegal in gas & low carbon energy and exploration write-offs of $1,301 million in oil production & operations relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil and the Gulf of Mexico. 2018 includes exploration write-offs of $124 million in oil production & operations in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.
e 2020 includes a gain of $2.3 billion on the sale of our petrochemicals business.
f All periods primarily reflect charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related legal provisions.
bp Annual Report and Form 20-F 2020
94
Additional disclosures
g From 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 amortization 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.
h All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. 2020 also includes the income statement impact associated with the buyback of finance debt. See Note 26 for further information.
ij In 2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.
j From 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.
95
bp Annual Report and Form 20-F 2020
Non-GAAP information on fair value accounting effects
Information for 2018 to 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Significant accounting policies, judgements, estimates and assumptions - Change in segmentation. The impacts of fair value accounting effects, relative to management’s internal measure of performance. Further information on fair value accounting effects is provided on page 344 of bp Annual Report and Form 20-F 2020.
$ million
2020
2019
2018
gas & low carbon energy
Unrecognized (gains) losses brought forward from previous perioda
253
(463)
(526)
Favourable (adverse) impact relative to management’s measure of performance
(738)
714
60
Exchange translation gains (losses) on fair value accounting effects
—
2
3
Unrecognized (gains) losses carried forward
(485)
253
(463)
oil production & operations
Unrecognized (gains) losses brought forward from previous period
—
8
107
Favourable (adverse) impact relative to management’s measure of performance
—
(8)
(99)
Exchange translation gains (losses) on fair value accounting effects
—
—
—
Unrecognized (gains) losses carried forward
—
—
8
customers & products
Unrecognized (gains) losses brought forward from previous perioda
104
(56)
(151)
Favourable (adverse) impact relative to management’s measure of performance
(149)
160
95
Unrecognized (gains) losses carried forward
(45)
104
(56)
other businesses & corporate
Favourable (adverse) impact relative to management’s measure of performanceb
675
—
—
Unrecognized (gains) losses carried forward
675
—
—
Favourable (adverse) impact relative to management’s measure of performance – by region
gas & low carbon energy
US
198
(171)
64
Non-US
(936)
885
(4)
(738)
714
60
oil production & operations
US
—
(8)
(99)
Non-US
—
—
—
—
(8)
(99)
customers & products
US
27
148
(155)
Non-US
(176)
12
250
(149)
160
95
other businesses & corporate
US
—
—
—
Non-US
675
—
—
675
—
—
(212)
866
56
Taxation credit (charge)
(11)
(155)
12
(223)
711
68
a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between gas & low carbon energy and customers & products as part of the transfer of the NGL business between segments.
b From 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. For further information see page 344 of bp Annual Report and Form 20-F 2020.
Net debt including leases
Net debt including leases« is shown in the table below.
$ million
At 31 December
2020
2019
Net debt«
38,941
45,442
Lease liabilities
9,262
9,722
Net partner (receivable) payable for leases entered into on behalf of joint operations«
(7)
(158)
Net debt including leases
48,196
55,006
Total equity
85,568
100,708
Gearing including leases«
36.0%
35.3%
bp Annual Report and Form 20-F 2020
96
Glossary
Abbreviations
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion cubic feet.
bcfe
Billion cubic feet equivalent.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
GtCO2
Gigatonnes of carbon dioxide.
IFRS
International Financial Reporting Standards.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
mboe/d
Thousand barrels of oil equivalent per day.
mmb/d
Million barrels per day.
mmboe/d
Million barrels of oil equivalent per day.
mmBtu
Million British thermal units.
mmcf/d
Million cubic feet per day.
Mte
Million tonnes.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
Definitions
Unless the context indicates otherwise, the definitions for the following glossary terms are given below.
Non-GAAP measures are sometimes referred to as alternative performance measures.
Adjusting items
Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors to better understand and evaluate the group’s reported financial performance. Adjusting items include gains and losses on the sale of businesses and fixed assets, impairments, environmental and other provisions, restructuring, integration and rationalization costs, fair value accounting effects, costs relating to the Gulf of Mexico oil spill and other items. Adjusting items within equity-accounted earnings are reported net
of incremental income tax reported by the equity-accounted entity. Adjusting items are used as a reconciling adjustment to derive underlying RC profit or loss and related underlying measures which are non-GAAP measures. An analysis of adjusting items by segment and type is shown on page 94 of this report. Prior to 2021 adjusting items were reported under two different headings – non-operating items and fair value accounting effects.
Associate
An entity over which the group has significant influence and that is neither a subsidiary nor a joint arrangement of the group. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
Brent
A trading classification for North Sea crude oil that serves as a major benchmark price for purchases of oil worldwide.
Capital expenditure
Total cash capital expenditure as stated in the group cash flow statement. Capital expenditure for the operating segments and customers & products businesses is presented on the same basis.
Commodity trading contracts
bp participates in regional and global commodity trading markets in order to manage, transact and hedge the crude oil, refined products and natural gas that the group either produces or consumes in its manufacturing operations. The range of contracts the group enters into in its commodity trading operations is described below. Using these contracts, in combination with rights to access storage and transportation capacity, allows the group to access advantageous pricing differences between locations, time periods and grades.
Exchange-traded commodity derivatives
Contracts that are typically in the form of futures and options traded on a recognized exchange, such as Nymex and ICE. Such contracts are traded in standard specifications for the main marker crude oils, such as Brent and West Texas Intermediate; the main product grades, such as gasoline and gasoil; and for natural gas and power. Gains and losses, otherwise referred to as variation margin, are generally settled on a daily basis with the relevant exchange. These contracts are used for the trading and risk management of crude oil, refined products, and natural gas and power. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in sales and other operating revenues for accounting purposes.
Over-the-counter (OTC) contracts
Contracts that are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties or through brokers, others may be cleared by a central clearing counterparty. These contracts can be used both for trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in sales and other operating revenues for accounting purposes. Many grades of crude oil bought and sold use standard contracts including US domestic light sweet crude oil, commonly referred to as West Texas Intermediate, and a standard North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE). Forward contracts are used in connection with the purchase of crude oil supplies for refineries and for marketing and sales of the group’s oil production and refined products. The contracts typically contain standard delivery and settlement terms. These transactions call for physical delivery of oil with consequent operational and price risk. However, various means exist and are used from time to time, to settle obligations under the contracts in cash rather than through physical delivery. Physically settled BFOE contracts delivered by cargo additionally specify a standard volume and tolerance.
Gas and power OTC markets are highly developed in North America and the UK, where commodities can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price, with delivery and settlement at a future date. Typically, the contracts specify delivery terms for the underlying commodity. Some of these transactions are not settled physically as they can be net settled by transacting offsetting sale or purchase contracts for the same location and delivery period. The
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contracts contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically, volume, price and term (e.g. daily, monthly and balance of month) are the main variable contract terms.
Swaps are typically contractual obligations to exchange cash flows between two parties. A typical swap transaction usually references a floating price and a fixed price with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell crude, oil products, natural gas or power at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry. Typically, netting agreements are used to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell a commodity at the market price prevailing on or around the delivery date when title to the inventory is taken. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. As such, these transactions result in physical delivery with operational and price risk. Spot and term contracts typically relate to purchases of crude for a refinery, products for marketing, or third-party natural gas, or sales of the group’s oil production, oil products or gas production to third parties. For accounting purposes, spot and term sales are included in sales and other operating revenues when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.
Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.
Convenience gross margin
Non-GAAP measure. Convenience gross margin is calculated as RC profit before interest and tax for the customers & products segment, excluding RC profit before interest and tax for the refining & trading and petrochemicals businesses, and adjusting items« (as defined above) for the convenience & mobility business to derive underlying RC profit before interest and tax for the convenience & mobility business; subtracting underlying RC profit before interest and tax for the Castrol business; adding back depreciation, depletion and amortization, production and manufacturing, distribution and administration expenses for convenience & mobility (excluding Castrol); subtracting earnings from equity-accounted entities in the convenience & mobility business (excluding Castrol) and gross margin for the retail fuels, next-gen, aviation, B2B and midstream businesses.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss
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. A reconciliation to GAAP information is provided on page 101 of this report.
Electric vehicle charge points
Defined as charge points operated by either bp or a bp joint venture.
Fair value accounting effects
Non-GAAP adjustments to our IFRS profit or loss. They reflect the difference between the way bp manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Fair value accounting effects are included within adjusting items. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below. Other than as noted below, the fair value accounting effects described are reported in both the gas & low carbon energy and customer & products segments.
bp uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural
gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
bp enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) 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 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 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, eliminates the fair value gains and losses of these derivative financial
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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.
Finance debt ratio
Finance debt ratio is defined as the ratio of finance debt to the total of finance debt plus total equity.
Gearing and net debt
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’. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent measure to net debt on an IFRS basis. The nearest equivalent GAAP measure to gearing on an IFRS basis is finance debt ratio.
We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, 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
Non-GAAP measure. 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. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent measure to net debt including leases on an IFRS basis. The nearest equivalent GAAP measure to gearing including leases on an IFRS basis is finance debt ratio.
Henry Hub
A distribution hub on the natural gas pipeline system in Erath, Louisiana, that lends its name to the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange and the over-the-counter swaps traded on Intercontinental Exchange.
Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure
A subset of capital expenditure on a cash basis 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 93 of this report.
Inventory holding gains and losses
Inventory holding gains and losses are non-GAAP adjustments to our IFRS profit (loss) and represent:
a.the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting of inventories other than for trading
inventories, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed as inventory holding gains and losses represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach; and
b.an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade by grade basis, during the period. This is calculated from each operation’s inventory management system on a monthly basis using the discrete monthly movement in market prices for these inventories.
The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions that are price risk-managed. See Replacement cost (RC) profit or loss definition below.
Joint arrangement
An arrangement in which two or more parties have joint control.
Joint control
Contractually agreed sharing of control over an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
Joint operation
A joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement.
Liquids
Comprises crude oil, condensate and natural gas liquids. For the oil production & operations segment, it also includes bitumen.
Operating cash flow
Net cash provided by (used in) operating activities as stated in the 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.
Organic capital expenditure
Non-GAAP measure. Organic capital expenditure comprises capital expenditure on a cash basis less inorganic capital expenditure. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 93 of this report.
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.
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
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incurred and a stipulated share of the production remaining after such cost recovery.
Realizations
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. For the gas & low carbon energy and oil production & operations segments, realizations include transfers between businesses.
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.
Refining marker margin (RMM)
The average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.
Replacement cost (RC) profit or loss / RC profit or loss attributable to bp shareholders
Reflects the replacement cost of inventories sold in the period and is is calculated as profit or loss attributable to bp shareholders, adjusting for inventory holding gains and losses (net of tax). RC profit or loss for the group is not a recognized GAAP measure. bp believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to bp shareholders. See Financial statements – Note 5. A reconciliation to GAAP information is provided on page 4 of this report.
Retail sites
Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Retail sites in growth markets
These are retail sites that are either bp branded or co-branded with our partners in China, Mexico and Indonesia and also include sites in India through our Jio-bp JV.
Strategic convenience sites
Strategic convenience sites are retail sites, within the bp portfolio, which both sell bp branded fuel and carry one of the strategic convenience brands (e.g. M&S, Rewe to Go). To be considered a strategic convenience brand the convenience offer should be a strategic differentiator in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.
Subsidiary
An entity that is controlled by the bp group. Control of an investee exists when an investor is exposed, or has rights, to variable returns from its
involvement with the investee and has the ability to affect those returns through its power over the investee.
UK National Balancing Point
A virtual trading location for sale, purchase and exchange of UK natural gas. It is the pricing and delivery point for the Intercontinental Exchange natural gas futures contract.
Underlying effective tax rate (ETR)
Non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses and total taxation on adjusting items. Information on underlying RC profit or loss is provided below. Taxation on an underlying RC basis presented for the operating segments is calculated through an allocation of taxation on an underlying RC basis to each segment. bp believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. Taxation on an underlying RC basis and underlying ETR are non-GAAP measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.
We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses and adjusting items, that are difficult to predict in advance in order to include in a GAAP estimate. A reconciliation to GAAP information is provided on page 101 of this report.
Underlying replacement cost (RC) profit or loss / underlying RC profit or loss attributable to bp shareholders
Non-GAAP measure. RC profit or loss« (as defined above) after excluding net adjusting items and related taxation. See page 94 of this report for additional information on the adjusting items that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the items and their financial impact. Underlying RC profit or loss before interest and tax for the operating segments or customers & products businesses is calculated as RC profit or loss (as defined above) including profit or loss attributable to non-controlling interests before interest and tax for the operating segments and excluding net adjusting items for the respective operating segment or business.
bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period, by adjusting for the effects of these adjusting items. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments and businesses is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 4 of this report.
upstream
upstream includes oil and natural gas field development and production within the gas & low carbon energy and oil production & operations segments. References to upstream exclude Rosneft.
West Texas Intermediate (WTI)
A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a benchmark price for purchases of oil in the US.
Working capital
Movements in inventories and other current and non-current assets and liabilities as stated in the group cash flow statement.
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Non-GAAP measures reconciliations
Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR
Taxation (charge) credit
$ million
2020
2019
2018
Taxation on profit or loss for the year
4,159
(3,964)
(7,145)
Adjusted for taxation on inventory holding gains and losses
667
(156)
198
Taxation on a RC profit or loss basis
3,492
(3,808)
(7,343)
Adjusted for taxation on adjusting items and certain foreign exchange impacts on the group’s tax charge for the period
4,235
1,788
522
Adjusted for the impact of US tax reform
—
—
121
Taxation on an underlying RC basis
(743)
(5,596)
(7,986)
Effective tax rate
%
2020
2019
2018
ETR on profit or loss for the year
17
49
43
Adjusted for inventory holding gains and losses
(1)
2
(1)
ETR on RC profit or loss
16
51
42
Adjusted for adjusting items and certain foreign exchange impacts on the group’s tax charge for the period
(30)
(15)
(5)
Adjusted for the impact of US tax reform
—
—
1
Underlying ETR
(14)
36
38
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bp Annual Report and Form 20-F 2020
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BP p.l.c.
(Registrant)
Dated:
31 January 2022
/s/ BEN MATHEWS
Ben J. S. Mathews
Company Secretary
bp Annual Report and Form 20-F 2020
102
EXHIBIT INDEX
Exhibit Number
Exhibit description
23.1
Consent of Deloitte LLP, independent registered public accounting firm, London, United Kingdom
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Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference of our report dated 22 March 2021, except for the change in accounting policy related to the presentation of revenues and purchases relating to physically settled derivative contracts disclosed in Note 1 and the change in segmentation disclosed in Notes 1 and 5, as to which the date is 31 January 2022, relating to the consolidated financial statements of BP p.l.c. (the “Company”), appearing in this Report on Form 6-K dated 31 January 2022, in the following Registration Statements:
Registration Statement Nos. 333-254751, 333-254751-01 and 333-254751-02 of the Company, BP Capital Markets p.l.c. and BP Capital Markets America Inc. on Form F-3; and Registration Statement Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-207188, 333-207189, 333-210316, 333-210318, 333-253287 and 333-254578 of the Company on Form S-8.
