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.
(a)In this Form 6-K, references to the second quarter 2021 and second quarter 2020 refer to the three-month periods ended 30 June 2021 and 30 June 2020 respectively.
(b)This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in bp’s Annual Report on Form 20-F for the year ended 31 December 2020.
Profit (loss) for the period attributable to bp shareholders
3,116
(16,848)
7,783
(21,213)
Inventory holding (gains) losses*, before tax
(953)
(1,088)
(2,683)
3,796
Taxation charge (credit) on inventory holding gains and losses
217
279
605
(868)
Replacement cost (RC) profit (loss)*
2,380
(17,657)
5,705
(18,285)
Net (favourable) adverse impact of adjusting items*(a), before tax
(8)
14,566
(704)
15,930
Taxation charge (credit) on adjusting items
426
(3,591)
427
(3,536)
Underlying RC profit (loss)*
2,798
(6,682)
5,428
(5,891)
Operating cash flow*
5,411
3,737
11,520
4,689
Capital expenditure*
(2,514)
(3,067)
(6,312)
(6,928)
Divestment and other proceeds(b)
215
1,135
5,054
1,816
Net issue (repurchase) of shares
(500)
—
(500)
(776)
Finance debt
68,247
76,003
68,247
76,003
Net debt*(c)
32,706
40,920
32,706
40,920
Announced dividend per ordinary share (cents per share)
5.46
5.25
10.71
15.75
Profit (loss) per ordinary share (cents)
15.37
(83.32)
38.36
(105.02)
Profit (loss) per ADS (dollars)
0.92
(5.00)
2.30
(6.30)
Underlying RC profit (loss) per ordinary share* (cents)
13.80
(33.05)
26.75
(29.17)
Underlying RC profit (loss) per ADS (dollars)
0.83
(1.98)
1.61
(1.75)
(a)Prior to 2021 adjusting items were reported under two different headings – non-operating items and fair value accounting effects*. See page 32 for more information.
(b)Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. Other proceeds were $675 million from the sale of a 49% interest in a controlled affiliate holding certain refined product and crude logistics assets onshore US in the first half 2021 and $455 million in relation to TANAP pipeline refinancing in the second quarter and first half 2020. There are no other proceeds in the second quarter 2021.
(c)See Note 9 for more information.
RC profit (loss), underlying RC profit (loss) and net debt are non-GAAP measures. Inventory holding (gains) losses and adjusting items are non-GAAP adjustments.
* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 38.
Strong results and continued net debt reduction in an improving environment
•Operating performance was resilient in the second quarter with four major project* start-ups, strong momentum in the customers business, including material growth in convenience gross margin*, and delivery of $2.5 billion of cash costs* savings on a run-rate basis relative to 2019, around six months earlier than targeted.
•Profit for the quarter attributable to bp shareholders was $3.1 billion, compared with $4.7 billion for the first quarter 2021 and a loss of $16.8 billion for the second quarter of 2020.
•Underlying replacement cost (RC) profit* was $2.8 billion, compared with $2.6 billion for the previous quarter. This result was driven by higher oil prices and margins offset by a lower result in gas marketing and trading. The underlying RC loss for the second quarter of 2020 was $6.7 billion.
•Operating cash flow* of $5.4 billion for the quarter includes $1.2 billion pre-tax of Gulf of Mexico oil spill payments.
•Finance debt at 30 June 2021 was $68.2 billion, compared with $66.1 billion at 31 March 2021 and $76.0 billion at 30 June 2020. Net debt* fell to $32.7 billion at the end of the second quarter.
•Following the annual review of price assumptions used for investment appraisal and value-in-use impairment testing, bp's Brent oil price assumption to 2030 is increased to reflect expected supply constraints, while longer-term assumptions are lowered as bp expects an acceleration of the pace of transition to a low carbon economy.
•As a result of these changed assumptions, the reported result includes a pre-tax net impairment reversal of $3.0 billion.
Distribution growth within disciplined financial frame
•A resilient dividend is bp's first priority within its disciplined financial frame.
•Reflecting the underlying performance of the business, an improving outlook for the environment, confidence in our balance sheet and commencement of the share buyback programme, the board has announced an increase in the second quarter dividend of 4% to 5.46 cents per ordinary share. This increase is accommodated within a 2021-5 average cash balance point* of around $40 per barrel Brent, $11 per barrel RMM and $3 per mmBtu Henry Hub (all 2020 real).
•bp generated surplus cash flow* in the second quarter and first half after having reached its net debt target of $35 billion. Taking into account surplus cash flow generated in the first half of the year, bp intends to execute a share buyback of $1.4 billion prior to announcing its third quarter 2021 results. For 2021, and subject to maintaining a strong investment grade credit rating, the board remains committed to using 60% of surplus cash flow for share buybacks and plans to allocate the remaining 40% to continue strengthening the balance sheet. See page 33 for the components of our sources of cash and uses of cash in the second quarter and half year of 2021.
•On average, based on bp’s current forecasts, at around $60 per barrel Brent and subject to the board's discretion each quarter, bp expects to be able to deliver buybacks of around $1.0 billion per quarter and have capacity for an annual increase in the dividend per ordinary share of around 4%, through 2025. Other elements of the financial frame are unchanged.
•The board will take into account factors including the cumulative level of and outlook for surplus cash flow, the cash balance point and the maintenance of a strong investment grade credit rating in setting the dividend per ordinary share and the buyback each quarter.
•bp expects to outline plans for the fourth-quarter share buyback at the time of its third quarter results.
Strong progress in our transformation to an integrated energy company
•Since outlining its new strategy a year ago, bp has made strong progress in its transformation to an IEC. It has delivered 8 major projects*, built a 21GW renewable pipeline, grown convenience and electrification, reorganized, reached over $10 billion of divestment proceeds, strengthened the financial frame and begun share buybacks.
•Four major projects began production in the second quarter – in India, Egypt, Angola and the Gulf of Mexico.
•bp has continued to significantly expand its renewables pipeline, buying a 9GW solar development pipeline in the US. Lightsource bp also continued to expand, growing in Portugal, Spain, Greece and Australia. bp confirmed its intention to bid for offshore wind leases in Scotland with EnBW and in Norway with Statkraft and Aker.
•bp opened the UK’s first fleet-dedicated EV rapid charging hub in London, the first of a series intended for cities across Europe. In the US, bp agreed to take full ownership of the Thorntons business, which is expected to complete in the third quarter of 2021, positioning bp to be a leading convenience operator in the Midwest US.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.
At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft. From the first quarter of 2021, the group's reportable segments are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see note 1 Basis of preparation - Change in segmentation.
In addition to the highlights on page 4:
–During the quarter, $500 million of share buybacks were complete to offset the expected full-year dilution from the vesting of awards under employee share schemes.
–Adjusting items* in the second quarter and half year were a favourable pre-tax impact of $8 million and $704 million respectively compared with an adverse impact of $14,566 million and $15,930 million in the same periods of 2020. The 2020 charges were driven by impairment charges of $11,848 million in the second quarter. Pre-tax net impairment reversals of $2,964 million were recorded in the second quarter of 2021 following the annual review of price assumptions used for investment appraisal and value-in-use impairment testing, offset by fair value accounting effects* of $1,377 million, increases in provisions of $856 million and a $415-million charge relating to a remeasurement of deferred tax balances in our equity-accounted entity in Argentina.
–Capital expenditure* in the second quarter and half year was $2.5 billion and $6.3 billion respectively, compared with $3.1 billion and $6.9 billion in the same periods of 2020.
–Finance debt was $68.2 billion at the end of the second quarter, compared to $66.1 billion at the end of the first quarter and $76.0 billion at the end of the second quarter 2020. At the end of the second quarter, net debt* was $32.7 billion, compared to $33.3 billion at the end of the first quarter and $40.9 billion at the end of the second quarter 2020.
–Operating cash flow* was $5.4 billion for the second quarter, including $1.2 billion pre-tax Gulf of Mexico oil spill payments and $0.2 billion of cash flow relating to severance costs associated with the reinvent programme, and $11.5 billion for the half year, compared with $3.7 billion and $4.7 billion for the same periods of 2020.
–The effective tax rate (ETR) on the profit or loss for the second quarter and half year was 35% and 29% respectively, compared with 19% and 16% for the same periods in 2020. The ETR on RC profit* for the second quarter and half year was 37% and 31% respectively, compared with 19% and 15% for the same periods in 2020. Excluding adjusting items*, the underlying ETR* for the second quarter and half year was 27% and 29% respectively, compared with 9% and -3% for the same periods a year ago. In 2020 the underlying ETRs were lower as they reflected the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition. The underlying ETRs for 2021 include a benefit for the reassessment of deferred tax asset recognition. ETR on RC profit or loss and underlying ETR are non-GAAP measures.
–A dividend of 5.46 cents per ordinary share was announced for the quarter.
Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
RC profit (loss) before interest and tax
gas & low carbon energy
927
(7,752)
4,357
(6,682)
oil production & operations
3,118
(14,314)
4,597
(14,493)
customers & products
640
594
1,574
1,258
Rosneft
643
(124)
1,006
(141)
other businesses & corporate
(425)
(259)
(1,103)
(825)
Consolidation adjustment – UPII*
(31)
(46)
(18)
132
4,872
(21,901)
10,413
(20,751)
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(687)
(791)
(1,416)
(1,581)
Taxation on a RC basis
(1,567)
4,361
(2,821)
3,353
Non-controlling interests
(238)
674
(471)
694
RC profit (loss) attributable to bp shareholders*
2,380
(17,657)
5,705
(18,285)
Inventory holding gains (losses)*
953
1,088
2,683
(3,796)
Taxation (charge) credit on inventory holding gains and losses
(217)
(279)
(605)
868
Profit (loss) for the period attributable to bp shareholders
Analysis of underlying RC profit (loss) before interest and tax
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Underlying RC profit (loss) before interest and tax
gas & low carbon energy
1,240
(814)
3,510
33
oil production & operations
2,242
(7,713)
3,807
(6,818)
customers & products
827
1,405
1,483
2,326
Rosneft
689
(61)
1,052
(78)
other businesses & corporate
(305)
(220)
(475)
(652)
Consolidation adjustment – UPII
(31)
(46)
(18)
132
4,662
(7,449)
9,359
(5,057)
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(485)
(677)
(1,066)
(1,345)
Taxation on an underlying RC basis
(1,141)
770
(2,394)
(183)
Non-controlling interests
(238)
674
(471)
694
Underlying RC profit (loss) attributable to bp shareholders*
2,798
(6,682)
5,428
(5,891)
Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-17 for the segments.
Operating Metrics
Operating metrics
First half 2021
vs First half 2020
Tier 1 and tier 2 process safety events*
30
-20
Reported recordable injury frequency*
0.168
+32.5%
Group production (mboe/d)(a)
3,242
-11.3%
upstream* production (mboe/d) (excludes Rosneft segment)
2,169
-15.0%
upstream unit production costs*(b) ($/boe)
7.33
+19.5%
bp-operated hydrocarbon plant reliability*
93.7%
-0.5
bp-operated refining availability*(a)
94.1%
-1.8
(a)See Operational updates on pages 8, 11 and 13.
(b)Reflecting lower volumes and higher costs due to phasing and seasonal maintenance activities.
–The oil market is expected to continue its rebalancing process. Global stocks are expected to decline and reach historical levels (in terms of days of forward cover) in the first half of 2022.
–Oil demand is expected to recover in 2021 on the back of a bright macroeconomic outlook, increasing vaccination roll-out and gradual lifting of COVID-19 restrictions around the world. The expectation is that demand reaches pre-Covid levels sometime in the second half of 2022.
–OPEC+ decision making on production levels is a key factor in oil prices and market rebalancing.
–Global gas demand is expected to recover to above 2019 levels by end 2021, and LNG demand to increase as a result of higher Asian imports.
–Industry refining margins are expected to be broadly flat compared to the second quarter, with recovery in demand offset by growth in net refining capacity. In lubricants, industry base oil and additive supply shortages are expected to continue in the second half.
3Q21 guidance
–Looking ahead, we expect third quarter reported upstream* production to be higher than the second quarter reflecting the completion of seasonal maintenance activity and the ramp-up of major projects. Within this, we expect production from oil production & operations to be higher.
–If COVID restrictions continue to ease, we expect higher product demand across our customer business in the third quarter. Realized refining margins are expected to improve slightly supported by stronger demand and wider North American heavy crude oil differentials. In Castrol, industry base oil and additive supply shortages are expected to continue.
2021 Guidance
In addition to the guidance on page 4:
–We continue to expect divestment and other proceeds for the year to reach $5-6 billion during the latter stages of 2021. As a result of the first half year divestments, our target of $25 billion of divestment and other proceeds between the second half of 2020 and 2025 is now underpinned by agreed or completed transactions of around $14.9 billion with over $10 billion of proceeds received.
–bp continues to expect capital expenditure*, including inorganic capital expenditure*, of around $13 billion in 2021.
–Depreciation, depletion and amortization is expected to be at a similar level to 2020 ($14.9 billion).
–Gulf of Mexico oil spill payments for the year are expected to be around $1.5 billion pre-tax.
–The other businesses & corporate underlying annual charge is expected to be in the range of $1.2-1.4 billion for 2021. The quarterly charges may vary from quarter to quarter.
–The underlying ETR* for 2021 is now expected to be around 35% but is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group’s profits and losses.
–For full year 2021 we expect reported upstream production to be lower than 2020 due to the impact of the ongoing divestment programme. However, underlying production* should be slightly higher than 2020 with the ramp-up of major projects, primarily in gas regions, partly offset by the impacts of reduced capital investment and decline in lower-margin gas assets.
COVID-19 Update
–bp's future financial performance, including cash flows and net debt, will be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. It is difficult to predict when all current supply and demand imbalances will be resolved and what the ultimate impact of COVID-19 will be.
–bp continues to take steps to protect and support its staff through the pandemic. Precautions in operations and offices together with enhanced support and guidance to staff continue with a focus on safety, health and hygiene, homeworking and mental health. Decisions on working practices and return to office based working are being taken with caution and in compliance with local and national guidelines and regulations.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.
•Sales and other operating revenues for the second quarter and half year were $5.7 billion and $13.7 billion respectively, compared with $3.2 billion and $8.8 billion for the corresponding periods in 2020. For the second quarter and half year, revenues were higher mainly due to higher gas marketing and trading revenues and higher realizations.
•The replacement cost profit before interest and tax for the second quarter and half year was $927 million and $4,357 million respectively, compared with a loss of $7,752 million and $6,682 million for the same periods in 2020. The second quarter and half year included a net adjusting charge of $313 million and gain of $847 million respectively, compared with a net adjusting charge of $6,938 million and $6,715 million for the same periods in 2020.
•After excluding adjusting items*, the underlying replacement cost profit before interest and tax* for the second quarter and half year was $1,240 million and $3,510 million respectively, compared with a loss of $814 million and a profit of $33 million for the same periods in 2020.
•The underlying replacement cost profit for the second quarter, compared with the same period in 2020, reflects significantly lower exploration write-offs, higher realizations, and significantly stronger gas marketing and trading performance, offset by a higher depreciation, depletion and amortization charge as a result of major project ramp-ups in Egypt and India. For the half year, compared with the same period in 2020, the underlying replacement cost profit mainly reflects the exceptionally strong gas marketing and trading result in the first quarter, higher realizations, and significantly lower exploration write-offs.
Operational update
•Reported production for the quarter was 875mboe/d, slightly higher compared to the same period in 2020 due to the partial divestment in Oman offset by growth in underlying production. Underlying production* was 3% higher, mainly due to major project ramp-ups, partially offset by base decline.
•Reported production for the half year was 892mboe/d, slightly higher compared to the same period in 2020. Underlying production* was flat, mainly due to major project ramp-ups, partially offset by base decline.
•Renewables pipeline* at the end of the quarter was 21GW (bp net). The renewables pipeline grew by 7GW (bp net) in the quarter and 10GW (bp net) in the half year, as a result of acquisition of a solar pipeline in the US, Lightsource bp's (LSbp) net pipeline growth, and our selection as preferred bidder for two major leases in the UK Offshore Wind Round 4 with our partner EnBW in the first quarter.
Strategic progress
gas
•On 6 July 2021 bp announced commencement of production from the East South flank of Shah Deniz 2.
•On 11 June, bp agreed to establish a joint venture with the Beijing Gas Group to supply downstream gas to northern China, expanding its role in the Chinese gas market.
•On 9 June, bp signed a long-term LNG sale and purchase agreement with Pavilion Energy Trading & Supply Pte. Ltd.for the supply of approximately 0.8 million tonnes of LNG per year to Singapore for 10 years from 2024.
•These events build on the progress announced in our first-quarter results, which comprised the following: bp announced completion of bp's sale of a 20% interest in Oman Block 61 (bp operator 40%, OQ 30%, PTTEP 20%, Petronas 10%); bp announced gas production from the Raven field in Egypt (bp operator 82.75%); bp and Reliance Industries Limited (RIL) announced the start of production from the Satellites Cluster gas field in India (bp 33.33%, RIL operator 66.67%); India Gas Solutions, a 50:50 joint venture between bp and RIL secured gas supply from block KG D6; bp received its first LNG cargo to directly supply gas to customers in China.
low carbon energy
•Solar – executing strategy and growing the pipeline
◦On 1 June, bp reached an agreement to purchase 9GW of solar development projects in the US and 1GW of safe harbour equipment from independent US solar developer 7X Energy for $220 million. The acquisition closed on 7 July.
◦Lightsource bp continued its expansion in Europe in the second quarter in Portugal, where it entered a co-development partnership with local company INSUN for five utility scale solar projects; entered the Greek market through award of capacity in solar and wind auctions alongside local developer KieferTEK; added to their Spanish pipeline through an acquisition from Grupo Jorge's energy arm; and began commercial operations at its five-project Vendimia cluster in Zaragoza, Spain.
•Offshore wind – progressing strategy
◦On 19 July, bp and EnBW submitted a bid in the ScotWind leasing round for offshore wind acreage in the UK North Sea that could support projects with 2.9GW generating capacity (1.45GW bp net).
◦On 14 June, bp agreed to join Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership – in which bp, Statkraft and Aker Offshore Wind will each hold a 33.3% share – will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area.
•These events build on the progress announced in our first-quarter results, which included the following: bp and Equinor completed the formation of their strategic US offshore wind partnership to initially develop four projects in two existing leases located offshore New York and Massachusetts; bp and partner EnBW were announced as the preferred bidder for two highly advantaged 60-year leases in the UK’s first offshore wind leasing round in a decade; bp announced that it is developing plans for the UK’s largest blue hydrogen production facility, targeting 1GW of blue hydrogen production by 2030; and LSbp acquired from Iberia Solar a 845MW solar portfolio in Spain; LSbp acquired a 1.06GW portfolio from the global photovoltaic (PV) project developer RIC Energy, together they will develop 14 sites in Spain; on 9 March, LSbp announced it has agreed to provide 88 bp service stations in New South Wales, Australia with 100% solar power, starting in January 2023.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Sales and other operating revenues(a)
5,739
3,227
13,741
8,752
Profit (loss) before interest and tax
931
(7,741)
4,383
(6,680)
Inventory holding (gains) losses*
(4)
(11)
(26)
(2)
RC profit (loss) before interest and tax
927
(7,752)
4,357
(6,682)
Net (favourable) adverse impact of adjusting items
313
6,938
(847)
6,715
Underlying RC profit (loss) before interest and tax
1,240
(814)
3,510
33
Taxation on an underlying RC basis
(244)
(111)
(779)
(372)
Underlying RC profit (loss) before interest
996
(925)
2,731
(339)
(a)Includes sales to other segments.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Depreciation, depletion and amortization
Total depreciation, depletion and amortization
1,115
952
1,969
1,990
Exploration write-offs
Exploration write-offs(b)
21
1,631
27
1,634
Adjusted EBITDA*(c)
Total adjusted EBITDA
2,376
1,101
5,506
2,989
Capital expenditure*
gas
705
1,009
1,516
2,191
low carbon energy(d)
42
10
1,116
12
Total capital expenditure
747
1,019
2,632
2,203
(b)Second quarter and first half 2020 include a write-off of $668 million which has been classified within the ‘other’ category of adjusting items.
(c)A reconciliation to RC profit before interest and tax is provided on page 35.
(d)First half 2021 includes $712 million in respect of the remaining payment to Equinor for our investment in our strategic US offshore wind partnership and $326 million as a lease option fee deposit paid to The Crown Estate in connection with our participation in the UK Round 4 Offshore Wind Leasing together with our partner EnBW.
Second
Second
First
First
quarter
quarter
half
half
2021
2020
2021
2020
Production (net of royalties)(e)
Liquids* (mb/d)
109
99
111
97
Natural gas (mmcf/d)
4,440
4,463
4,531
4,564
Total hydrocarbons* (mboe/d)
875
869
892
884
Of which equity-accounted entities:
Liquids* (mb/d)
3
2
3
2
Natural gas (mmcf/d)
—
—
—
—
Total hydrocarbons* (mboe/d)
3
2
3
2
Average realizations*(f)
Liquids ($/bbl)
61.69
22.59
58.61
34.30
Natural gas ($/mcf)
4.14
3.12
4.04
3.32
Total hydrocarbons* ($/boe)
28.97
18.63
27.89
20.99
(e)Includes bp’s share of production of equity-accounted entities in the gas & low carbon energy segment.
(f)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
•Sales and other operating revenues for the second quarter and half year were $5.6 billion and $10.8 billion respectively, compared with $3.3 billion and $9.1 billion for the corresponding periods in 2020. For the second quarter and half year, revenues were higher mainly due to higher realizations, partly offset by lower volumes.
•The replacement cost profit before interest and tax for the second quarter and half year was $3,118 million and $4,597 million respectively, compared with a loss of $14,314 million and $14,493 million for the same periods in 2020. The second quarter and half year included a net adjusting gain of $876 million and $790 million respectively, compared with a net adjusting charge of $6,601 million and $7,675 million for the same periods in 2020.
•After excluding adjusting items*, the underlying replacement cost profit before interest and tax* for the second quarter and half year was $2,242 million and $3,807 million respectively, compared with a loss of $7,713 million and $6,818 million for the same periods in 2020.
•The underlying replacement cost profit for the second quarter and half year, compared with the same periods in 2020 primarily reflects significantly lower exploration write-offs and higher oil and gas realizations.
Operational update
•Reported production for the quarter was 1,245mboe/d, 24.8% lower than the second quarter of 2020. This includes price impacts on PSA* and TSC* entitlement volumes and the impact of divestments, mainly in Alaska and BPX Energy. Underlying production* for the quarter decreased by 9.0% mainly due to impacts from reduced capital investment, seasonal maintenance activity and decline.
•Reported production for the half year was 1,277mboe/d, 23.4% lower than the same period in 2020. This includes price impacts on PSA* and TSC* entitlement volumes and the impact of divestments in Alaska and BPX Energy. Underlying production* for the half year decreased by 8.5% mainly due to impacts from reduced capital investment and seasonal maintenance activity.
Strategic progress
•On 6 May, bp confirmed the start of production from the Zinia Phase 2 project in Block 17, Angola (Total 38% operator, Equinor 22.16%, ExxonMobil 19%, bp 15.84%, Sonangol P&P 5%).
•On 19 May, bp and Eni announced that they have entered into a non-binding memorandum of understanding to progress detailed discussions on combining their upstream portfolios in Angola, including all their oil, gas and LNG interests in the country.
•On 23 June, bp announced the start-up of the Manuel project at the Na Kika platform in the deepwater Gulf of Mexico (bp 50% operator, Shell 50%).
•These events build on the progress announced in our first-quarter results, which comprised the following: bp signed an agreement to transfer its participating interests in six blocks located in Foz do Amazonas basin off northern Brazil to Petróleo Brasileiro S.A. (Petrobras). Subject to regulatory approval, the transaction is expected to complete in 2021; bp announced the safe arrival in Texas US of the Argos floating production platform, a major milestone for the Mad Dog 2 project in the deepwater Gulf of Mexico (bp operator 60.5%, BHP 23.9%, Union Oil Company of California 15.6%). While in Texas, Argos will undergo final preparatory work and regulatory inspections before moving offshore; bp announced an oil discovery in a high-quality Miocene reservoir at the Puma West prospect in the US deepwater Gulf of Mexico (bp operator 50%, Chevron U.S.A. Inc. 25%, Talos Energy 25%). Evaluation is ongoing.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Sales and other operating revenues(a)
5,597
3,304
10,752
9,135
Profit (loss) before interest and tax
3,112
(14,268)
4,606
(14,506)
Inventory holding (gains) losses*
6
(46)
(9)
13
RC profit (loss) before interest and tax
3,118
(14,314)
4,597
(14,493)
Net (favourable) adverse impact of adjusting items
(876)
6,601
(790)
7,675
Underlying RC profit (loss) before interest and tax
•Sales and other operating revenues for the second quarter and half year were $31.2 billion and $58.3 billion respectively, compared with $17.8 billion and $43.6 billion for the corresponding periods in 2020. The increase in the second quarter and half year was mainly due to higher oil prices. The second quarter also benefited from higher volumes as COVID-19 restrictions eased and demand recovered.
•The replacement cost profit before interest and tax for the second quarter and half year was $640 million and $1,574 million respectively, compared with $594 million and $1,258 million for the same periods in 2020. The second quarter and half year included a net adjusting charge of $187 million and a net gain of $91 million respectively, compared with a net charge of $811 million and $1,068 million for the same periods in 2020.
•After excluding adjusting items*, the underlying replacement cost profit before interest and tax* for the second quarter and half year was $827 million and $1,483 million respectively, compared with $1,405 million and $2,326 million for the same periods in 2020.
•The customers & products result for the second quarter and half year reflects a stronger customers performance, more than offset by a significantly weaker products result and absence of earnings from our divested petrochemicals business, compared to the same periods last year.
•customers – convenience and mobility results for the quarter and first half demonstrated continued strong performance, with higher earnings than the same periods last year. This result was supported by higher volumes in both retail fuel and aviation, as well as a material growth in convenience gross margin*.
Castrol results for both the quarter and half year were materially higher than last year. This was despite industry base oil and additive shortages, and COVID impacts in key markets, such as India, in the second quarter.
•products – the products result was weaker for the quarter and the half year due to a lower trading performance compared to an exceptionally strong performance in the second quarter of 2020, and a higher level of turnaround and maintenance activity in refining. Refining margins in the quarter were materially higher compared to last year, however the increasing cost of US renewable fuels credits and relatively weaker distillate demand growth in comparison to gasoline resulted in a smaller improvement in realized margins.
Operational update
•bp-operated refining availability* for the second quarter and half year was 93.5% and 94.1% respectively, lower compared with 95.6% and 95.9% for the same periods last year, due to a higher level of planned and unplanned maintenance. Utilization for the quarter was around 8 percentage points higher than the same period last year due to lower COVID related demand impacts.
Strategic progress
•We continued to progress our strategic agenda in redefining convenience, adding further strategic convenience sites* to our network. We also:
◦announced an agreement to take full ownership of the Thorntons business in the US, positioning bp to be a leading convenience operator in the Midwest US. Completion of the transaction is expected in the third quarter, subject to regulatory approvals;
◦expanded our convenience partnership model with Marks & Spencer, a leading UK retailer, piloting it in our UK franchise network;
◦extended our partnership with PAYBACK, Europe’s largest multi-partner loyalty programme, which has over 30 million customers, to become the first provider in Germany to exclusively offer PAYBACK loyalty rewards to electric vehicle drivers.
•In next-gen mobility:
◦bp pulse opened the UK’s first fleet-dedicated rapid EV charging hub in London;
◦Air bp expanded the rollout of sustainable aviation fuel (SAF), adding the offer to Munich Airport. We now supply SAF at more than 20 airports worldwide.
•In growth markets:
◦Castrol signed an exclusive three-year deal with Ki Mobility solutions in India for supply of premium lubricants across their multi-brand workshops and online service provider platform which has around 10,000 retailers and 20,000 garage owners as customers.
•In refining we continue to focus on creating a more resilient and high-performing portfolio:
◦bp’s Cherry Point refinery in Washington state was recognized as the “Best site in the industry” for its project planning and execution, for a record fifth time by research and benchmarking firm Independent Project Analysis (IPA).
•These events build on the progress announced in our first-quarter results:
◦bp pulse announced the rollout of new EV-only ultra-fast charging hubs across the UK;
◦bp agreed to take a stake alongside Daimler and BMW in Digital Charging Solutions (DCS), a leading developer of digital charging software. Completion of the transaction is subject to regulatory approvals;
◦Castrol launched a range of advanced e-fluids, Castrol ON, designed for improved electric vehicle performance, with more than half of the world’s major vehicle manufacturers(a) now using them as part of their factory fill;
◦we ceased production at our Kwinana refinery in preparation to convert it to an import terminal;
◦we received the final instalment of $1 billion for the sale of our petrochemicals business to INEOS.
(a)Based on LMCA data for top 20 selling OEMs (total new car sales) in 2019.
Net (favourable) adverse impact of adjusting items*
187
811
(91)
1,068
Underlying RC profit before interest and tax*
827
1,405
1,483
2,326
Of which:(b)
customers – convenience & mobility
951
432
1,609
1,120
Castrol – included in customers
265
63
599
230
products – refining & trading
(124)
926
(126)
1,094
petrochemicals
—
47
—
112
Taxation on an underlying RC basis
(123)
(221)
(256)
(586)
Underlying RC profit before interest
704
1,184
1,227
1,740
(a)Includes sales to other segments.
(b)A reconciliation to RC profit before interest and tax by business is provided on page 34.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Adjusted EBITDA*(c)
customers – convenience & mobility
1,280
715
2,262
1,690
Castrol – included in customers
304
106
677
311
products – refining & trading
301
1,345
720
1,923
petrochemicals
—
97
—
212
1,581
2,157
2,982
3,825
Depreciation, depletion and amortization
Total depreciation, depletion and amortization
754
752
1,499
1,499
Capital expenditure*
customers – convenience & mobility
255
150
571
490
Castrol – included in customers
42
23
83
71
products – refining & trading
264
196
480
458
petrochemicals
—
23
—
78
Total capital expenditure
519
369
1,051
1,026
(c)A reconciliation to RC profit before interest and tax by business is provided on page 34.
Retail(d)
Second
Second
First
First
quarter
quarter
half
half
2021
2020
2021
2020
bp retail sites* – total (#)
20,300
18,900
20,300
18,900
bp retail sites in growth markets*
2,700
1,300
2,700
1,300
Strategic convenience sites*
2,000
1,650
2,000
1,650
(d)Reported to the nearest 50.
Marketing sales of refined products (mb/d)
Second
Second
First
First
quarter
quarter
half
half
2021
2020
2021
2020
US
1,131
872
1,074
955
Europe
838
685
772
820
Rest of World
469
364
455
441
2,438
1,921
2,301
2,216
Trading/supply sales of refined products(e)
415
403
376
430
Total sales volume of refined products
2,853
2,324
2,677
2,646
(e)Comparative information for 2020 has been restated for the changes to net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 basis of preparation - Voluntary change in accounting policy. The amounts previously presented for the first quarter 2021 have been amended from 314mb/d to 336mb/d.
(a)In 2021 the RMM has been updated to reflect changes in bp’s portfolio, and the update of crude reference for Mediterranean region. On this basis the second quarter and half year 2020 RMM would be $6.1/bbl and $7.5/bbl respectively.
•The replacement cost (RC) profit before interest and tax for the second quarter and half year was $643 million and $1,006 million respectively, compared with a loss of $124 million and $141 million for the same periods in 2020. The second quarter and half year included a net adjusting charge of $46 million, compared with $63 million for the same periods in 2020.
•After excluding adjusting items, the underlying RC profit before interest and tax* for the second quarter and half year was $689 million and $1,052 million respectively, compared with a loss of $61 million and $78 million for the same periods in 2020.
•Compared with the same periods in 2020, the result for the second quarter primarily reflects higher oil prices partially offset by adverse foreign exchange effects whilst the result for the half year was primarily affected by higher oil prices, favourable foreign exchange and duty lag effects.
•bp's two nominees, Bernard Looney and Bob Dudley, were re-elected to Rosneft's board at Rosneft's annual general meeting (AGM) on 1 June 2021. At the AGM, shareholders also approved a resolution to pay dividends of 6.94 roubles per ordinary share, which constitutes 50% of the company’s IFRS net profit for 2020. bp received a payment of $176 million after a deduction of withholding tax on 14 July.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021(a)
2020
2021
2020
Profit (loss) before interest and tax(b)(c)
711
(71)
1,162
(289)
Inventory holding (gains) losses*
(68)
(53)
(156)
148
RC profit (loss) before interest and tax
643
(124)
1,006
(141)
Net (favourable) adverse impact of adjusting items
46
63
46
63
Underlying RC profit (loss) before interest and tax
689
(61)
1,052
(78)
Taxation on an underlying RC basis
(68)
8
(103)
11
Underlying RC profit (loss) before interest
621
(53)
949
(67)
Second
Second
First
First
quarter
quarter
half
half
2021(a)
2020
2021(a)
2020
Production: Hydrocarbons (net of royalties, bp share)
Liquids* (mb/d)
858
856
842
886
Natural gas (mmcf/d)
1,374
1,248
1,335
1,261
Total hydrocarbons* (mboe/d)
1,095
1,071
1,073
1,103
(a)The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the three months and six months ended 30 June 2021. Actual results may differ from these amounts. Amounts reported for the second quarter are based on bp’s 22.03% average economic interest for the quarter (second quarter 2020 21.2%).
(b)The Rosneft segment result includes equity-accounted earnings arising from bp’s economic interest in Rosneft as adjusted for accounting required under IFRS relating to bp’s purchase of its interest in Rosneft, and the amortization of the deferred gain relating to the divestment of bp’s interest in TNK-BP.
(c)bp’s adjusted share of Rosneft’s earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the bp group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.
Other businesses & corporate comprises our innovation & engineering business including bp ventures and Launchpad, regions, cities & solutions, our corporate activities & functions, and any residual costs of the Gulf of Mexico oil spill.
Financial results
•The replacement cost loss before interest and tax for the second quarter and half year was $425 million and $1,103 million respectively, compared with $259 million and $825 million for the same periods in 2020. The second quarter and half year included a net adjusting charge of $120 million and $628 million respectively, including $73 million of favourable and $374 million of adverse fair value accounting effects* respectively, compared with a net charge of $39 million and $173 million, including $41 million of adverse fair value accounting effects, for the same periods in 2020.
•After excluding adjusting items*, the underlying replacement cost loss before interest and tax* for the second quarter and half year was $305 million and $475 million respectively, compared with $220 million and $652 million for the same periods in 2020.
Strategic progress
•bp and CEMEX signed a memorandum of understanding on 13 May to explore solutions to help decarbonize the production and distribution of CEMEX’s products and develop lower carbon offers for CEMEX and bp customers worldwide.
•bp and the Mærsk Mc-Kinney Møller Center for Zero Carbon Shipping signed a partnership agreement on 23 July committing to a long-term collaboration on the development of new alternative fuels and low carbon solutions for the shipping industry.
•On 25 May, bp ventures invested $7 million into electric vehicle (EV) charging firm IoTecha, which uses Internet of Things technology to connect EV charge points with the electricity grid, homes, and buildings. bp plans to integrate IoTecha’s products into its EV ecosystem to help accelerate mainstream adoption of EVs and support the transition to more sustainable mobility.
•bp ventures portfolio company Lightning eMotors became a public listed company on the New York Stock Exchange on 7 May. Lightning eMotors designs and manufactures electric vehicles (EVs) for commercial fleets, including school buses and ambulances, as well as offering charging technologies for commercial and government vehicles. bp, which has supported the company since 2014, owns approximately 30% of the company. The listing is expected to provide Lightning eMotors with growth capital to help accelerate its business.
•Open Energi became Launchpad’s 6th portfolio company on 28 June. Open Energi is an advanced software technology company that uses AI algorithms to optimize distributed commercial and industrial power assets at scale.
•These events build on the progress announced in our first-quarter results, which comprised the following: bp and Qantas signed a memorandum of understanding on 15 January to collaborate on opportunities to reduce carbon emissions in the aviation sector and contribute to the development of a sustainable aviation fuel industry in Australia; bp signed a memorandum of understanding with the Ministry of Energy of the Republic of Azerbaijan to co-operate in assessing the potential and conditions required for large-scale decarbonized and integrated energy and mobility systems, including renewable energy projects in the regions and cities of Azerbaijan; bp and Infosys signed a memorandum of understanding to explore the development of a digitally-enabled Energy as a Service offer at Infosys campuses in India, which could be scaled to industrial parks and cities in the future; bp divested its holding in Palantir for $443 million.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Profit (loss) before interest and tax
(425)
(259)
(1,103)
(825)
Inventory holding (gains) losses*
—
—
—
—
RC profit (loss) before interest and tax
(425)
(259)
(1,103)
(825)
Net (favourable) adverse impact of adjusting items
120
39
628
173
Underlying RC profit (loss) before interest and tax
Earnings from joint ventures – after interest and tax
(57)
(567)
103
(589)
Earnings from associates – after interest and tax
856
(100)
1,457
(344)
Interest and other income
82
107
164
247
Gains on sale of businesses and fixed assets
250
74
1,355
90
Total revenues and other income
37,598
20,776
74,090
51,639
Purchases(a)
21,241
8,364
36,897
28,565
Production and manufacturing expenses
6,562
5,211
13,420
11,310
Production and similar taxes
295
124
548
327
Depreciation, depletion and amortization (Note 6)
3,631
3,937
6,998
7,996
Impairment and losses on sale of businesses and fixed assets (Note 3)
(2,937)
11,770
(2,564)
12,919
Exploration expense
107
9,674
206
9,876
Distribution and administration expenses
2,874
2,509
5,489
5,193
Profit (loss) before interest and taxation
5,825
(20,813)
13,096
(24,547)
Finance costs
682
783
1,405
1,566
Net finance expense relating to pensions and other post-retirement benefits
5
8
11
15
Profit (loss) before taxation
5,138
(21,604)
11,680
(26,128)
Taxation
1,784
(4,082)
3,426
(4,221)
Profit (loss) for the period
3,354
(17,522)
8,254
(21,907)
Attributable to
bp shareholders
3,116
(16,848)
7,783
(21,213)
Non-controlling interests
238
(674)
471
(694)
3,354
(17,522)
8,254
(21,907)
Earnings per share (Note 7)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic
15.37
(83.32)
38.36
(105.02)
Diluted
15.30
(83.32)
38.16
(105.02)
Per ADS (dollars)
Basic
0.92
(5.00)
2.30
(6.30)
Diluted
0.92
(5.00)
2.29
(6.30)
(a)2020 numbers have been restated as a result of changes to the net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 Basis of preparation - Voluntary change in accounting policy.
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off
3,659
13,555
7,087
17,712
Impairment and (gain) loss on sale of businesses and fixed assets
(3,187)
11,696
(3,919)
12,829
Earnings from equity-accounted entities, less dividends received
(539)
860
(1,172)
1,365
Net charge for interest and other finance expense, less net interest paid
300
17
329
154
Share-based payments
228
351
182
345
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
(371)
(34)
(391)
(54)
Net charge for provisions, less payments
1,172
(365)
2,074
(424)
Movements in inventories and other current and non-current assets and liabilities
26
(609)
(2,767)
74
Income taxes paid
(1,015)
(130)
(1,583)
(1,184)
Net cash provided by operating activities
5,411
3,737
11,520
4,689
Investing activities
Expenditure on property, plant and equipment, intangible and other assets
(2,435)
(3,018)
(5,468)
(6,807)
Acquisitions, net of cash acquired
—
—
(1)
(17)
Investment in joint ventures
(47)
(8)
(789)
(26)
Investment in associates
(32)
(41)
(54)
(78)
Total cash capital expenditure
(2,514)
(3,067)
(6,312)
(6,928)
Proceeds from disposal of fixed assets
93
10
644
20
Proceeds from disposal of businesses, net of cash disposed
122
670
3,735
1,341
Proceeds from loan repayments
67
543
128
606
Cash provided from investing activities
282
1,223
4,507
1,967
Net cash used in investing activities
(2,232)
(1,844)
(1,805)
(4,961)
Financing activities
Net issue (repurchase) of shares (Note 7)
(500)
—
(500)
(776)
Lease liability payments
(514)
(664)
(1,074)
(1,233)
Proceeds from long-term financing
1,985
6,846
3,941
9,530
Repayments of long-term financing
(67)
(964)
(7,096)
(4,681)
Net increase (decrease) in short-term debt
(33)
(215)
189
2,302
Issue of perpetual hybrid bonds
—
11,861
—
11,861
Payments on perpetual hybrid bonds
(328)
—
(383)
—
Payments relating to transactions involving non-controlling interests (other)
—
(8)
—
(8)
Receipts relating to transactions involving non-controlling interests (other)
3
—
671
9
Dividends paid - BP shareholders
(1,062)
(2,119)
(2,126)
(4,221)
- non-controlling interests
(107)
(74)
(158)
(105)
Net cash provided by (used in) financing activities
(623)
14,663
(6,536)
12,678
Currency translation differences relating to cash and cash equivalents
24
(42)
(34)
(225)
Increase (decrease) in cash and cash equivalents
2,580
16,514
3,145
12,181
Cash and cash equivalents at beginning of period
31,676
18,139
31,111
22,472
Cash and cash equivalents at end of period(a)
34,256
34,653
34,256
34,653
(a) Second quarter and first half 2020 includes $436 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.
The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2020 included in BP Annual Report and Form 20-F 2020.
The directors consider it appropriate to adopt the going concern basis of accounting in preparing the interim financial statements. The ongoing impact of COVID-19 and the current economic environment has been considered as part of the going concern assessment. Forecast liquidity has been assessed under a number of stressed scenarios to support this assertion. Reverse stress tests indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the interim financial statements even if the Brent price fell to zero.
bp prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. As a result of the UK's withdrawal from the EU, with effect from 1 January 2021, the consolidated financial statements are also prepared in accordance with IFRS as adopted by the UK. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the EU and UK differ in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented.
The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2021 which are the same as those used in preparing BP Annual Report and Form 20-F 2020 with the exception of the changes described in the 'Updates to significant accounting policies' section below. There are no other new or amended standards or interpretations adopted from 1 January 2021 onwards that have a significant impact on the financial information.
Considerations in respect of COVID-19 and the current economic environment
bp's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 2020. These have been subsequently considered at the end of each quarter to determine if any changes were required to those judgements and estimates as a result of current market conditions. The conditions also result in the valuation of certain assets and liabilities remaining subject to more uncertainty, including those set out below.
Impairment testing assumptions
The group’s price assumption for Brent oil was revised during the second quarter. The assumption up to 2030 was increased to reflect near-term supply constraints whereas the long-term assumption was decreased reaching $55 per barrel by 2040 and $45 per barrel by 2050 (in real 2020 terms) as bp's management expects an acceleration of the pace of transition to a lower carbon economy. The price assumption for Henry Hub gas are unchanged from those disclosed in BP Annual Report and Form 20-F 2020. A summary of the group’s price assumptions, in real 2020 terms, is provided below:
Second half 2021
2025
2030
2040
2050
Brent oil ($/bbl)
60
60
60
55
45
Henry Hub gas ($/mmBtu)
3.00
3.00
3.00
3.00
2.75
The group has identified upstream oil and gas properties with carrying amounts totalling approximately $33 billion where the headroom, based on the most recent impairment tests performed, was less than or equal to 20% of the carrying value. A change in price or other assumptions within the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a significant risk of impairment reversals or charges in that period.
Impairment reversals for the second quarter of 2021 primarily relate to the changes to price assumptions. For further information see Note 3.
The discount rates used in value-in-use impairment testing as disclosedin BP Annual Report and Form 20-F 2020, are unchanged.
Provisions
The nominal risk-free discount rate applied to provisions is reviewed on a quarterly basis. The discount rate applied to the group's provisions was revised in the second quarter to 2.0% (31 December 2020 2.5%) to reflect lower recent US Treasury yields. The principal impact of this rate reduction was a $1.3 billion increase in the decommissioning provision with a corresponding increase in the carrying amount of property, plant and equipment of $1.0 billion.
During the second quarter, the group assessed that a decommissioning provision should be recognized for certain assets previously sold to a third party where the decommissioning obligation transferred may revert to bp due to the financial condition of the current owner. No other significant decommissioning provisions of this nature have been identified however bp continues to review and monitor the risk of reversion of decommissioning obligations.
The group's defined benefit pension plans are reviewed quarterly to determine any changes to the fair value of the plan assets or present value of the defined benefit obligations. As a result of the review during the second quarter of 2021, the group's total net defined benefit pension plan surplus as at 30 June 2021 is $2.0 billion, compared to a deficit of $1.3 billion at 31 December 2020.
The movement for the six months principally reflects net actuarial gains reported in other comprehensive income arising from increases in the UK, US and Eurozone discount rates partly offset by increases in inflation rates and negative asset performance. Also reflected in the second quarter is a reduction in the liability of the UK funded final salary pension plan which was closed to future accrual on 30 June 2021. A curtailment gain of $0.3 billion has been recognized in the income statement. For active members of the scheme at 30 June 2021, benefits payable are now linked to salary as at that date rather than to salary on retirement.The current environment is likely to continue to affect the values of the plan assets and obligations resulting in potential volatility in the amount of the net defined benefit pension plan surplus/deficit recognized.
Impairment of financial assets measured at amortized cost
The estimate of the loss allowance recognized on financial assets measured at amortized cost using an expected credit loss approach was determined not to be a significant accounting estimate in preparing BP Annual Report and Form 20-F 2020. Expected credit loss allowances are, however, reviewed and updated quarterly. Allowances are recognized on assets where there is evidence that the asset is credit-impaired and on a forward-looking expected credit loss basis for assets that are not credit-impaired. The current economic environment and future credit risk outlook have been considered in updating the estimate of loss allowances with no significant impact in the quarter.
The group continues to believe that the calculation of expected credit loss allowances is not a significant accounting estimate. The group continues to apply its credit policy as disclosed in BP Annual Report and Form 20-F 2020 - Financial statements - Note 29 Financial instruments and financial risk factors - credit risk.
Other accounting judgements and estimates
All other significant accounting judgements and estimates disclosed in BP Annual Report and Form 20-F 2020 remain applicable and no new significant accounting judgements or estimates have been identified specifically arising from the impact of COVID-19.
Updates to significant accounting policies
Change in accounting policy - Interest Rate Benchmark Reform - Phase II
Financial authorities have announced the timing of interest rate benchmark transitions with market discussions continuing around benchmark application. The replacement of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with alternative benchmarks in the US, UK, EU and other territories is expected at the end of 2021 for most benchmarks, with remaining USD tenors expected to cease in 2023. bp is primarily exposed to USD LIBORs that will be available until June 2023.
Amendments to IFRS 9 'Financial instruments', IFRS 16 ‘Leases’ and other IFRSs were issued by the IASB in August 2020 to provide practical expedients and reliefs when changes are made to contractual cash flows or hedging relationships because of the transition from Inter-bank Offered Rates to alternative risk-free rates. bp adopted these amendments from 1 January 2021 and they will be applied prospectively.
bp has set up an internal working group on interest rate benchmark reform to monitor market developments and manage the transition to alternative benchmark rates. The impacts on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts have been assessed and transition plans are being developed. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform.
Change in segmentation
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 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 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.
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 4 for further information.
Comparative information for 2020 has been restated in Notes 4, 5 and 6 to reflect the changes in reportable segments.
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.
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 2020 has been restated as shown in the table below. There is no significant impact on comparative information for profit before income and tax or earnings per share.
In addition, as disclosed in the group's 2020 financial statements, in 2020 revenues from physically settled derivative contracts were reclassified as other operating revenues and were no longer presented together with revenues from contracts with customers. In these financial statements certain other similar contracts have been reclassified as other operating revenues and then been subject to net presentation as described above. Comparative information for natural gas, LNG and NGLs, and non-oil products and other revenue from contracts with customers in Note 5 has been amended to align with current period presentation as shown in the table below.
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil
1,062
1,062
—
2,497
2,497
—
Oil products
10,452
10,452
—
30,706
30,706
—
Natural gas, LNG and NGLs
2,992
2,072
(920)
6,630
5,250
(1,379)
Non-oil products and other revenues from contracts with customers
2,118
2,092
(26)
4,608
4,569
(39)
Revenues from contracts with customers
16,624
15,678
(946)
44,441
43,022
(1,419)
Other operating revenues
15,052
5,584
(9,468)
46,885
9,213
(37,672)
Total sales and other operating revenues
31,676
21,262
(10,414)
91,326
52,235
(39,091)
(a) Total purchases for the second quarter and first half 2020 have been re-stated by the equal and opposite amount as total sales and other operating revenues.
The carrying amount of assets classified as held for sale at 30 June 2021 is $34 million, with associated liabilities of $31 million.
At 31 December 2020 the balance consists primarily of a 20% participating interest from BP’s 60% participating interest in Block 61 in Oman, which is reported in the gas & low carbon energy segment. As announced on 1 February 2021, BP agreed to sell this interest to PTT Exploration and Production Public Company Limited (PTTEP) of Thailand for a total consideration of up to $2.6 billion, subject to final adjustments. On 28 March, a royal decree was published approving the sale and $2.4 billion was received in March 2021.
Note 3. Impairment and losses on sale of businesses and fixed assets(a)
Impairment reversals net of losses on sale of businesses and fixed assets for the second quarter and first half 2021 were $2,937 million and $2,564 million respectively (charges of $11,770 million and $12,919 million for the comparative periods in 2020) and include net impairment reversals for the second quarter and first half 2021 of $2,964 million and $2,744 million respectively (charges of $11,848 million and $12,646 million for the comparative periods in 2020). Impairment charges included within the 2021 numbers are immaterial.
gas & low carbon energy segment
Net impairment reversals in the gas & low carbon energy segment were $1,270 million and $1,148 million for the second quarter and first half 2021 respectively (charges of $6,111 million and $6,112 million for the comparative periods in 2020).
Impairment reversals for the second quarter and first half 2021 mainly relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. They include amounts in Azerbaijan, India and Trinidad. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.
oil production & operations segment
Net impairment reversals in the oil production & operations segment were $1,756 million and $1,657 million for the second quarter and first half 2021 (charges of $5,008 million and $5,792 million for the comparative periods in 2020).
Impairment reversals for the second quarter and first half 2021 mainly relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. They include amounts in BPX Energy and the North Sea. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.
(a) All disclosures are pre-tax.
Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation(a)
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
gas & low carbon energy
927
(7,752)
4,357
(6,682)
oil production & operations
3,118
(14,314)
4,597
(14,493)
customers & products
640
594
1,574
1,258
Rosneft
643
(124)
1,006
(141)
other businesses & corporate
(425)
(259)
(1,103)
(825)
4,903
(21,855)
10,431
(20,883)
Consolidation adjustment – UPII*
(31)
(46)
(18)
132
RC profit (loss) before interest and tax*
4,872
(21,901)
10,413
(20,751)
Inventory holding gains (losses)*
gas & low carbon energy
4
11
26
2
oil production & operations
(6)
46
9
(13)
customers & products
887
978
2,492
(3,637)
Rosneft (net of tax)
68
53
156
(148)
Profit (loss) before interest and tax
5,825
(20,813)
13,096
(24,547)
Finance costs
682
783
1,405
1,566
Net finance expense relating to pensions and other post-retirement benefits
5
8
11
15
Profit (loss) before taxation
5,138
(21,604)
11,680
(26,128)
RC profit (loss) before interest and tax*
US
955
(4,695)
2,862
(4,100)
Non-US
3,917
(17,206)
7,551
(16,651)
4,872
(21,901)
10,413
(20,751)
(a)Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Change in segmentation.
Less: sales and other operating revenues between segments
gas & low carbon energy
1,063
27
2,095
1,838
oil production & operations
4,928
2,870
9,783
8,371
customers & products
112
330
222
(452)
other businesses & corporate
307
267
466
371
6,410
3,494
12,566
10,128
External sales and other operating revenues
gas & low carbon energy
4,676
3,200
11,646
6,914
oil production & operations
669
435
969
765
customers & products
31,048
17,453
58,045
44,049
other businesses & corporate
74
174
351
507
Total sales and other operating revenues
36,467
21,262
71,011
52,235
By geographical area
US
15,305
7,532
29,796
17,197
Non-US
29,700
16,946
56,583
43,778
45,005
24,478
86,379
60,975
Less: sales and other operating revenues between areas
8,538
3,216
15,368
8,740
36,467
21,262
71,011
52,235
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil
1,291
1,062
2,625
2,497
Oil products
24,651
10,452
43,929
30,706
Natural gas, LNG and NGLs(b)
4,273
2,072
8,454
5,250
Non-oil products and other revenues from contracts with customers(b)
1,603
2,092
3,001
4,569
Revenue from contracts with customers
31,818
15,678
58,009
43,022
Other operating revenues(c)
4,649
5,584
13,002
9,213
Total sales and other operating revenues
36,467
21,262
71,011
52,235
(a)Comparative information for 2020 has been restated for the changes in reportable segments and also changes to net presentation of revenues and purchases relating to physically settled derivative contracts effective 1 January 2021. For more information see Note 1 Basis of preparation - Voluntary change in accounting policy and Change in segmentation.
(b)Comparative information has been amended for certain contracts that have been reclassified to other operating revenues and then been subject to the net presentation described in Note 1 Basis of preparation - Voluntary change in accounting policy.
(c)Principally relates to commodity derivative transactions.
Note 6. Depreciation, depletion and amortization(a)
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Total depreciation, depletion and amortization by segment
gas & low carbon energy
1,115
952
1,969
1,990
oil production & operations
1,559
2,070
3,133
4,187
customers & products
754
752
1,499
1,499
other businesses & corporate
203
163
397
320
3,631
3,937
6,998
7,996
Total depreciation, depletion and amortization by geographical area
US
1,160
1,404
2,281
2,829
Non-US
2,471
2,533
4,717
5,167
3,631
3,937
6,998
7,996
(a)Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Change in segmentation.
Note 7. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the second quarter 2021 115 million of ordinary shares were repurchased for cancellation for a total cost of $500 million, including transaction costs of $3 million, as part of the share buyback programme announced on 27 April 2021. The number of shares in issue is reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Results for the period
Profit (loss) for the period attributable to bp shareholders
3,116
(16,848)
7,783
(21,213)
Less: preference dividend
—
1
1
1
Profit (loss) attributable to bp ordinary shareholders
3,116
(16,849)
7,782
(21,214)
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding
20,272,111
20,222,575
20,285,083
20,200,694
ADS equivalent(c)
3,378,685
3,370,429
3,380,847
3,366,782
Weighted average number of shares outstanding used to calculate diluted earnings per share
20,366,731
20,222,575
20,394,877
20,200,694
ADS equivalent(c)
3,394,455
3,370,429
3,399,146
3,366,782
Shares in issue at period-end
20,224,314
20,249,046
20,224,314
20,249,046
ADS equivalent(c)
3,370,719
3,374,841
3,370,719
3,374,841
(a)Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the second quarter 2020 and first half 2020 are 63,119 thousand (ADS equivalent 10,520 thousand) and 85,469 thousand (ADS equivalent 14,245 thousand) respectively.
(c)One ADS is equivalent to six ordinary shares.
Issued ordinary share capital as at 30 June 2021 comprised 20,239,233,502 ordinary shares (31 December 2020 20,344,625,660 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 1,095,305,700 ordinary shares which have been bought back and are held in treasury by BP (31 December 2020 1,105,156,692 ordinary shares).
BP today announced an interim dividend of 5.46 cents per ordinary share which is expected to be paid on 24 September 2021 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 13 August 2021. The ex-dividend date will be 12 August 2021. The corresponding amount in sterling is due to be announced on 14 September 2021, calculated based on the average of the market exchange rates over three dealing days between 8 September 2021 and 10 September 2021. Holders of ADSs are expected to receive $0.3276 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the second quarter 2021 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the second quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
Second
Second
First
First
quarter
quarter
half
half
2021
2020
2021
2020
Dividends paid per ordinary share
cents
5.250
10.500
10.500
21.000
pence
3.712
8.342
7.480
16.498
Dividends paid per ADS (cents)
31.50
63.00
63.00
126.00
Note 9. Net debt
Net debt*
Second
Second
Fourth
First
First
quarter
quarter
quarter
half
half
$ million
2021
2020
2020
2021
2020
Finance debt(a)
68,247
76,003
72,664
68,247
76,003
Fair value (asset) liability of hedges related to finance debt(b)
(1,285)
(430)
(2,612)
(1,285)
(430)
66,962
75,573
70,052
66,962
75,573
Less: cash and cash equivalents
34,256
34,653
31,111
34,256
34,653
Net debt
32,706
40,920
38,941
32,706
40,920
Total equity
93,232
82,811
85,568
93,232
82,811
Gearing*
26.0%
33.1%
31.3%
26.0%
33.1%
(a)The fair value of finance debt at 30 June 2021 was $70,589 million (31 December 2020 $76,092 million, 30 June 2020 $77,990 million).
(b)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 $308 million (fourth quarter 2020 liability of $236 million and second quarter 2020 liability of $554 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(c)Net debt does 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.
As part of actively managing its debt portfolio, on 9 June 2021 bp exercised its option to redeem finance debt with an outstanding aggregate principal amount of $2.4 billion on 13 July 2021. In the first quarter, the group bought back $3.9 billion equivalent of US dollar, euro and sterling bonds and terminated derivatives associated with the non-USD debt bought back. These transactions have no significant impact on net debt or gearing.
Note 10. Inventory valuation
A provision of $17 million was held against hydrocarbon inventories at 30 June 2021 ($289 million at 30 June 2020) to write them down to their net realizable value. As a result of the changes in strategic direction of the group and the evolution of the trading strategy set out in Note 1, from 1 January, certain inventory, totalling $11.0 billion as at 30 June 2021 is now treated as trading inventory and is valued at fair value whereas the equivalent inventory was previously valued at the lower of cost or net realisable value in prior periods.
Note 11. Statutory accounts
The financial information shown in this publication, which was approved by the Board of Directors on 2 August 2021, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2021.
(a)Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Change in segmentation.
(b)First half 2021 includes the final payment of $712 million in respect of the strategic partnership with Equinor.
Impairment and losses on sale of businesses and fixed assets(c)
1,270
(6,111)
1,147
(6,114)
Environmental and other provisions
—
—
—
—
Restructuring, integration and rationalization costs(d)
(21)
(6)
(29)
(4)
Fair value accounting effects(e)
(1,311)
(67)
(1,064)
156
Other(f)
(251)
(754)
(241)
(753)
(313)
(6,938)
847
(6,715)
oil production & operations
Gains on sale of businesses and fixed assets
216
87
384
94
Impairment and losses on sale of businesses and fixed assets(c)
1,751
(4,861)
1,542
(5,991)
Environmental and other provisions(g)
(776)
—
(841)
(13)
Restructuring, integration and rationalization costs(d)
(90)
(18)
(94)
(24)
Fair value accounting effects
—
—
—
—
Other(f)(h)
(225)
(1,809)
(201)
(1,741)
876
(6,601)
790
(7,675)
customers & products
Gains on sale of businesses and fixed assets
8
(13)
(89)
(6)
Impairment and losses on sale of businesses and fixed assets
(35)
(798)
(78)
(803)
Environmental and other provisions
(8)
—
(8)
—
Restructuring, integration and rationalization costs(d)
(10)
31
(51)
31
Fair value accounting effects(e)
(139)
(31)
320
(290)
Other
(3)
—
(3)
—
(187)
(811)
91
(1,068)
Rosneft
Other
(46)
(63)
(46)
(63)
(46)
(63)
(46)
(63)
other businesses & corporate
Gains on sale of businesses and fixed assets
—
—
—
2
Impairment and losses on sale of businesses and fixed assets
(50)
—
(51)
—
Environmental and other provisions
(72)
—
(72)
(23)
Restructuring, integration and rationalization costs(d)
(74)
(33)
(99)
(46)
Gulf of Mexico oil spill
(18)
(31)
(29)
(52)
Fair value accounting effects(e)
73
(41)
(374)
(41)
Other
21
66
(3)
(13)
(120)
(39)
(628)
(173)
Total before interest and taxation
210
(14,452)
1,054
(15,694)
Finance costs(i)(j)
(202)
(114)
(350)
(236)
Total before taxation
8
(14,566)
704
(15,930)
Taxation credit (charge) on adjusting items
(396)
3,477
(384)
3,787
Taxation – impact of foreign exchange(k)
(30)
114
(43)
(251)
Total taxation on adjusting items
(426)
3,591
(427)
3,536
Total after taxation for period
(418)
(10,975)
277
(12,394)
(a)Prior to 2021 adjusting items were reported under two different headings – non-operating items and fair value accounting effects. Comparative information for 2020 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation – Change in segmentation.
(b)First half 2021 relates to a gain from the divestment of a 20% stake in Oman Block 61.
(c)See Note 3 for further information.
(d)All periods in 2021 include recognized provisions for restructuring costs associated with the reinvent programme that was formalized in 2020.
(e)For further information, including the nature of fair value accounting effects reported in each segment, see page 39.
(f)Second quarter and first half 2020 include the exploration write-off of $668 million in gas and lower carbon energy relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of gas & low carbon assets in India and the impairment of certain intangible assets in Mauritania and Senegal and $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 oil production & operations assets in Brazil and the Gulf of Mexico.
(g)Second quarter and first half 2021 Includes adjustments relating to the change in discount rate on retained decommissioning provisions and the recognition of a decommissioning provision in relation to certain assets previously sold to a third party where the decommissioning obligation transferred may revert to bp due to the financial condition of the current owner.
(h)Second quarter and first half 2021 includes a $415 million charge relating to a remeasurement of deferred tax balances in our equity-accounted entity in Argentina following income tax rate changes partially offset by impairment reversals in equity-accounted entities.
(i)All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. Second quarter and first half 2021 also include the income statement impact associated with the buyback of finance debt. See Note 9 for further information.
(j)From first quarter 2021 bp is presenting temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt as an adjusting item within finance costs. In 2020 these amounts were presented within production and manufacturing expenses and as an 'other' adjusting item in the other business & corporate segment. Relevant amounts in the comparative periods presented were not material.
(k)bp is presenting certain foreign exchange effects on tax as adjusting 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.
Net debt including leases
Net debt including leases*
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Net debt
32,706
40,920
32,706
40,920
Lease liabilities
8,863
9,331
8,863
9,331
Net partner (receivable) payable for leases entered into on behalf of joint operations
109
(90)
109
(90)
Net debt including leases
41,678
50,161
41,678
50,161
Total equity
93,232
82,811
93,232
82,811
Gearing including leases*
30.9%
37.7%
30.9%
37.7%
Gulf of Mexico oil spill
30 June
31 December
$ million
2021
2020
Gulf of Mexico oil spill payables and provisions
(10,258)
(11,436)
Of which - current
(1,270)
(1,444)
Deferred tax asset
4,326
5,471
During the second quarter pre-tax payments of $1,199 million were made relating to the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Payables and provisions presented in the table above reflect the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. Where amounts have been provided on an estimated basis, the amounts ultimately payable may differ from the amounts provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in BP Annual Report and Form 20-F 2020 - Financial statements - Notes 7, 9, 20, 22, 23, 29, and 33.
Surplus cash flow* components
Second
First
quarter
half
$ million
2021
2021
Sources:
Net cash provided by operating activities
5,411
11,520
Cash provided from investing activities
282
4,507
Receipts relating to transactions involving non-controlling interests (other)
3
671
5,696
16,698
Uses:
Lease liability payments
(514)
(1,074)
Payments on perpetual hybrid bonds
(328)
(383)
Dividends paid – BP shareholders
(1,062)
(2,126)
– non-controlling interests
(107)
(158)
Total capital expenditure
(2,514)
(6,312)
Net repurchase of shares relating to employee share schemes
(500)
(500)
Currency translation differences relating to cash and cash equivalents
Reconciliation of customers & products RC profit before interest and tax* to underlying RC profit before interest and tax to adjusted EBITDA* by business
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
RC profit before interest and tax for customers & products
640
594
1,574
1,258
Less: Adjusting items gains (charges)
(187)
(811)
91
(1,068)
Underlying RC profit before interest and tax for customers & products
827
1,405
1,483
2,326
By business:
customers – convenience & mobility
951
432
1,609
1,120
Castrol – included in customers
265
63
599
230
products – refining & trading
(124)
926
(126)
1,094
petrochemicals
—
47
—
112
Add back: Depreciation, depletion and amortization
Reconciliation of RC profit before interest and tax* to adjusted EBITDA*
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
gas & low carbon energy
RC profit before interest and tax
927
(7,752)
4,357
(6,682)
Less: Adjusting items gains (charges)
(313)
(6,938)
847
(6,715)
Underlying RC profit before interest and tax
1,240
(814)
3,510
33
Add back: Depreciation, depletion and amortization
1,115
952
1,969
1,990
Exploration write-offs, net of adjusting items(a)
21
963
27
966
Adjusted EBITDA
2,376
1,101
5,506
2,989
oil production & operations
RC profit (loss) before interest and tax
3,118
(14,314)
4,597
(14,493)
Less: Adjusting items gains (charges)
876
(6,601)
790
(7,675)
Underlying RC profit before interest and tax
2,242
(7,713)
3,807
(6,818)
Add back: Depreciation, depletion and amortization
1,559
2,070
3,133
4,187
Exploration write-offs, net of adjusting items(b)
8
6,686
64
6,781
Adjusted EBITDA
3,809
1,043
7,004
4,150
(a)Second quarter and first half 2020 exclude a write-off of $668 million which has been classified within the ‘other’ category of adjusting items.
(b)Second quarter and first half 2020 exclude a write-off of $1,301 million which has been classified within the ‘other’ category of adjusting items.
Reconciliation of basic earnings per ordinary share to replacement cost (RC) profit (loss) per share and to underlying replacement cost profit (loss) per share
Second
Second
First
First
quarter
quarter
half
half
Per ordinary share (cents)
2021
2020
2021
2020
Profit (loss) for the period attributable to bp shareholders
15.37
(83.32)
38.36
(105.02)
Inventory holding (gains) losses*, before tax
(4.70)
(5.38)
(13.23)
18.79
Taxation charge (credit) on inventory holding gains and losses
1.07
1.38
2.99
(4.29)
11.74
(87.32)
28.12
(90.52)
Net (favourable) adverse impact of adjusting items* , before tax
(0.04)
72.03
(3.47)
78.86
Taxation charge (credit) on adjusting items
2.10
(17.76)
2.10
(17.51)
Underlying RC profit (loss)*
13.80
(33.05)
26.75
(29.17)
Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and underlying ETR
Taxation (charge) credit
Second
Second
First
First
quarter
quarter
half
half
$ million
2021
2020
2021
2020
Taxation on profit or loss
(1,784)
4,082
(3,426)
4,221
Taxation on inventory holding gains and losses
(217)
(279)
(605)
868
Taxation on a replacement cost (RC) profit or loss basis
(1,567)
4,361
(2,821)
3,353
Total taxation on adjusting items
(426)
3,591
(427)
3,536
Taxation on underlying replacement cost profit or loss
The principal risks and uncertainties affecting bp are described in the Risk factors section of bp Annual Report and Form 20-F 2020 (pages 67-70) and are summarized below. There are no material changes in those principal risks and uncertainties for the remaining six months of the financial year.
The risks and uncertainties summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.
Strategic and commercial risks
•Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.
•Access, renewal and reserves progression – inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.
•Major project* delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.
•Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.
•Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss.
•Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.
•Digital infrastructure and cyber security – breach or failure of our or third parties’ digital infrastructure or cyber security, including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.
•Climate change and the transition to a lower carbon economy – developments in policy, law, regulation, technology and markets, including societal and investor sentiment, related to the issue of climate change could increase costs, constrain our operations and affect our business plans and financial performance.
•Competition – inability to remain efficient, maintain a high-quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.
•Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business.
•Insurance – our insurance strategy could expose the group to material uninsured losses.
Safety and operational risks
•Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.
•Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities.
•Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations.
•Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.
Compliance and control risks
•Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.
•Regulation – changes in the law and regulation could increase costs, constrain our operations and affect our business plans and financial performance.
•Treasury and trading activities – ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.
•Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.
For a full discussion of the group’s material legal proceedings, see pages 226-227 of bp Annual Report and Form 20-F 2020.
Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions. Non-GAAP measures are sometimes referred to as alternative performance measures.
New metrics have been introduced in 2021 to provide transparency against key strategic value drivers.
Adjusted EBITDA is a non-GAAP measure presented for bp's operating segments and is defined as replacement cost (RC) profit before interest and tax, excluding net adjusting items*, adding back depreciation, depletion and amortization and exploration write-offs (net of adjusting items). Adjusted EBITDA by business is a further analysis of adjusted EBITDA for the customers & products businesses. bp believes it is helpful to disclose adjusted EBITDA by operating segment and by business because it reflects how the segments measure underlying business delivery. The nearest equivalent measure on an IFRS basis for the segment is RC profit or loss before interest and tax, which is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS. A reconciliation to GAAP information is provided on pages 34 and 35.
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 32. Prior to 2021 adjusting items were reported under two different headings – non-operating items and fair value accounting effects.
Bioenergy production is average thousands of barrels of biofuel production per day during the period covered, net to bp. This includes equivalent ethanol production, bp Bunge biopower for grid export, biogas and refining co-processing and standalone hydrogenated vegetable oil (HVO).
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement. Capital expenditure for the operating segments and customers & products businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil price for the quarter that would cause the sum of operating cash flow excluding Gulf of Mexico oil spill payments (assuming actual refining marker margins and Henry Hub gas prices for the quarter) and proceeds from loan repayments to equate to the sum of total cash capital expenditure, lease liability payments, dividend paid, and payments on perpetual hybrid bonds.
Cash costs is a non-GAAP measure and is defined as production and manufacturing expenses plus distribution and administration expenses and excludes costs that are classified as adjusting items and costs that are variable, primarily with volumes (such as freight costs). Management believes that cash costs is a performance measure that provides investors with useful information regarding the company’s financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Convenience gross margin is a 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.
Convenience gross margin growth at constant foreign exchange is a non-GAAP measure. This metric requires a calculation of the comparative convenience gross margin ($ million) at current period foreign exchange rates (constant foreign exchange) and compares the current period value with the restated comparative period value, which results in the growth % at constant foreign exchange rates. bp believes the convenience gross margin and growth at constant foreign exchange are useful measures because these measures may help investors to understand and evaluate, in the same way as management, our progress against our strategic objectives of redefining convenience. The nearest GAAP measure to convenience gross margin is RC profit before interest and tax for the customer & products segment.
Developed renewables to final investment decision (FID) – Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity to FID will increase proportionately to share increase for any assets where bp held equity at the point of FID.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Taxation on a 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. 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. Taxation on a RC basis and ETR on RC profit or loss are non-GAAP measures. 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 35.
Electric vehicle charge points are defined as charge points operated by either bp or a bp joint venture.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way bp manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. 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, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis.These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period.The fair values of derivative instruments used to risk manage certain oil, gas, power and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect, which is reported in the gas and low carbon energy segment, reduces the measurement differences between that of the derivative financial instruments used to risk manage the LNG contracts and the measurement of the LNG contracts themselves, which therefore gives a better representation of performance in each period.
In addition, from the second quarter 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the other businesses & corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.
Gearing and net debt are non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt does 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. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how
significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 30.
We are unable to present reconciliations of forward-looking information for net debt or gearing to finance debt and total equity, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Gearing including leases and net debt including leases are non-GAAP measures. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group’s lease portfolio on net debt and gearing. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt including leases is provided on page 33.
Hydrocarbons– Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a 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. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis. Further information and a reconciliation to GAAP information is provided on page 31.
Installed renewables capacity is bp's share of capacity for operating assets owned by entities where bp has an equity share.
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.
Liquids – Liquids for oil production & operations, gas & low carbon energy and Rosneft comprises crude oil, condensate and natural gas liquids. For oil production & operations and gas & low carbon energy, liquids also includes bitumen.
Major projects have a bp net investment of at least $250 million, or are considered to be of strategic importance to bp or of a high degree of complexity.
Operating cash flowis net cash provided by (used in) operating activities as stated in the condensed group cash flow statement.
Organic capital expenditure is a 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. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis and a reconciliation to GAAP information is provided on page 31.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
Production-sharing agreement/contract (PSA/PSC) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the bp share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.
Refining availabilityrepresents Solomon Associates’ operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.
Renewables pipeline – Renewable projects satisfying criteria to the point they can be considered developed to final investment decision (FID): Site based projects have obtained land exclusivity rights, or for PPA based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted.
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 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. A reconciliation to GAAP information is provided on page 3. RC profit or loss before interest and tax is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS.
Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Reported incidents are investigated throughout the year and as a result there may be changes in previously reported incidents. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this this represents a more up to date reflection of the safety environment.
Retail sites include sitesoperated 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 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.
Solomon availability – See Refining availability definition.
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.
Surplus cash flow is a non-GAAP measure and refers to the net surplus of sources of cash over uses of cash, after reaching the $35 billion net debt target. Sources of cash include net cash provided by operating activities, cash provided from investing activities and cash receipts relating to transactions involving non-controlling interests (other). Uses of cash include lease liability payments, payments on perpetual hybrid bond, dividends paid, cash capital expenditure, the cash cost of share buybacks to offset the dilution from vesting of awards under employee share schemes and currency translation differences relating to cash and cash equivalents as presented on the condensed group cash flow statement. See page 33 for the components of our sources of cash and uses of cash.
Technical service contract (TSC) – Technical service contract is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, the oil and gas company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a profit margin which reflects incremental production added to the oilfield.
Tier 1 and tier 2 process safety events – Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Reported process safety events are investigated throughout the year and as a result there may be changes in previously reported events. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this this represents a more up to date reflection of the safety environment.
Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis 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 35.
Underlying production – 2021 underlying production, when compared with 2020, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract.
Underlying RC profit or loss / underlying RC profit or loss attributable to bp shareholders is a non-GAAP measure and is RC profit or loss* (as defined on page 41) after excluding net adjusting items and related taxation. See page 32 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 3 for the group and pages 8-17 for the segments.
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 35.
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.
upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities.
Trade marks
Trade marks of the bp group appear throughout this announcement. They include:
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement:
The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, the following, among other statements, are all forward looking in nature: expectations regarding the COVID-19 pandemic, including its risks, impacts, consequences, duration, continued restrictions, challenges, bp’s response, the impact on bp’s financial performance (including cash flows and net debt), operations and credit losses, and the impact on the trading environment, oil and gas prices, and global GDP; expectations regarding the shape of the COVID-19 recovery and the pace of transition to a lower-carbon economy and energy system; plans, expectations and assumptions regarding oil and gas demand, supply or prices, the timing of production of reserves, or decision making by OPEC+; expectations regarding refining margins, refinery utilization rates and product demand; expectations regarding bp’s future financial performance and cash flows; expectations regarding future upstream production and project ramp-up; expectations regarding supply shortages; expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals; expectations with regards to bp’s transformation to an IEC; plans and expectations regarding bp’s financial framework; expectations regarding quarterly dividends and share buybacks, including bp’s plan to increase the second quarter dividend by 4% per ordinary share, bp’s expectation based on its current forecasts, at an oil price of around $60 per barrel Brent and subject to the Board’s approval each quarter of being able to deliver a buyback of around $1.0 billion per quarter on average and have capacity for an annual increase in the dividend per ordinary share of around 4% through 2025, and plan to commence a buyback from first half surplus cash flow; expectations of executing a share buyback of $1.4 billion prior to announcement of third quarter 2021 results; expectations of outlining plans for the fourth-quarter share buyback at the time of bp’s third quarter results; plans and expectations of using 60% of surplus cash flow for share buybacks and plans to allocate the remaining 40% to strengthen bp’s balance sheet for 2021; expectations regarding demand for bp’s products; plans and expectations with respect to the total capital expenditure, depreciation, depletion and amortization, expected tax rate and business and corporate underlying annual charge for 2021; plans and expectations regarding net debt; plans and expectations regarding the divestment programme, including the amount and timing of proceeds in 2021, and plans and expectations in respect of reaching $25 billion of proceeds by 2025 and expectations that divestment and other proceeds for 2021 will be in the $5-6 billion range; plans and expectations regarding bp’s renewable energy and alternative energy businesses; expectations regarding reported and underlying production and related major project ramp-up, capital investments, divestment and maintenance activity; expectations regarding price assumptions used in accounting estimates; expectations regarding the underlying effective tax rate for 2021; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; plans and expectations that capital expenditure, including inorganic capital expenditure, will reach around $13 billion in 2021; plans and expectations regarding new joint ventures and other agreements, including partnerships and other collaborations with EnBW, Statkraft, Aker Offshore Wind, Equinor, Eni, Marks & Spencer, PAYBACK, Ki Mobility, Daimler, BMW, Qantas, Azerbaijan, Infosys, CEMEX and the Mærsk Mc-Kinney Møller Center for Zero Carbon Shipping as well as plans and expectations regarding LSbp’s acquisitions from Iberia Solar and RIC Energy and its activities in Australia, bp’s blue hydrogen production facility, bp’s Mad Dog 2 development in the Gulf of Mexico, the transfer by bp of its participating interests in six blocks located in Foz do Amazonas basin off northern Brazil, bp’s exploration at the Puma West prospect, bp’s announced agreement to take full ownership of the Thorntons business in the US with completion in the third quarter of 2021 and Air bp’s rollout of sustainable aviation fuel; plans and expectations regarding bp’s intention to bid with EnBW to develop offshore wind in the UK North Sea; plans and expectations regarding bp’s plans to join Statkraft and Aker to develop offshore wind power in Norway and pursue a bid in the Sørlige Nordsjø II (SN2) licence area; plans and expectations for bp’s work on EV charging, including the development of EV charging networks in the UK and Europe and bp’s investment into IoTecha; plans and expectations regarding the listing of Lightning eMotors; plans and expectations regarding Launchpad portfolio companies; and expectations regarding operational and financial results or acquisitions or divestments by Rosneft, and expectations with respect to Rosneft dividends.
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 fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America and continued base oil and additive supply shortages; OPEC+ quota restrictions; PSA and TSC effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, as well those factors discussed under “Risk factors” in bp Annual Report and Form 20-F 2020 as filed with the US Securities and Exchange Commission.
The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2021 in
accordance with IFRS:
Capitalization and indebtedness
30 June
$ million
2021
Share capital and reserves
Capital shares (1-2)
5,354
Paid-in surplus (3)
14,300
Merger reserve (3)
27,206
Treasury shares
(12,724)
Cash flow hedge reserve
(844)
Costs of hedging reserve
(193)
Foreign currency translation reserve
(8,438)
Profit and loss account
54,136
BP shareholders' equity
78,797
Hybrid bonds
11,949
Other interest
2,486
Equity attributable to non-controlling interests
14,435
Total equity
93,232
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year
1,825
Finance debt due within one year
7,622
Lease liabilities due after more than one year
7,038
Finance debt due after more than one year
60,625
Total finance debt and lease liabilities
77,110
Total (7)(8)
170,342
1.Issued share capital as of 30 June 2021 comprised 20,239,233,502 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,095,305,700 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.
2.Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.
3.Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to
shareholders.
4.Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2021.
5.Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under finance leases. This includes one hundred percent of lease liabilities for joint operations where BP is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2020– Liquidity and capital resources for further information.
6.At 30 June 2021, the parent company, BP p.l.c. had issued guarantees totalling $64,094 million relating to group finance debt issued by subsidiaries. Thus 94% of the group’s finance debt had been guaranteed by BP p.l.c.In addition, BP p.l.c. guarantees $11.9 billion of perpetual subordinated hybrid bonds issued by a subsidiary. At 30 June 2021 $568 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.
7.At 30 June 2021 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,321 million in respect of the borrowings of equity-accounted entities and $560 million in respect of the borrowings of other third parties.
8.Total capitalisation and indebtedness includes non-controlling interests of $14,435 million at 30 June 2021 which includes $11,949 million related to perpetual hybrid bonds issued on 17 June 2020.
9.There has been no material change since 30 June 2021 in the consolidated capitalization and indebtedness of BP.
44
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.
