UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

for the period ended 30 September 2020
Commission File Number 1-06262

BP p.l.c.
(Translation of registrant’s name into English)

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F 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. 333-226485, 333-226485-01 AND 333-226485-02) 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., 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.

1

BP p.l.c. and subsidiaries
Form 6-K for the period ended 30 September 2020(a)
(a)In this Form 6-K, references to the nine months 2020 and nine months 2019 refer to the nine-month periods ended 30 September 2020 and 30 September 2019 respectively. References to the third quarter 2020 and third quarter 2019 refer to the three-month periods ended 30 September 2020 and 30 September 2019 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 2019.

2

Group results third quarter and nine months 2020
Highlights
Performance improving despite difficult environment
Financial results and progress
Loss for the quarter attributable to BP shareholders was $0.5 billion, compared with losses of $16.8 billion for the previous quarter of 2020, reflecting absence of significant exploration write-offs and impairment charges, and $0.7 billion for the third quarter of 2019.
Underlying replacement cost profit for the quarter was $0.1 billion, compared with a loss of $6.7 billion for the second quarter of 2020 and $2.3 billion profit for the third quarter of 2019. Compared to the previous quarter, the result benefitted from the absence of significant exploration write-offs and recovering oil and gas prices and demand. This was partly offset by a significantly lower oil trading result. Compared to the third quarter of 2019, the result was impacted by lower oil and gas prices and an extremely weak refining environment.
Operating cash flow for the quarter was $5.2 billion including the impact of Gulf of Mexico oil spill payments(a). Gulf of Mexico oil spill payments in the quarter were $0.1 billion post-tax.
Total capital expenditure in the nine months of 2020 was $10.6 billion, compared with $15.3 billion for the same period in 2019. Organic capital expenditure in the first three quarters of 2020 was $9.1 billion, in line with the full-year target of around $12 billion.
BP continues to make progress towards its target of $2.5 billion in annual cash cost savings by end-2021 compared with 2019, with its new organization on schedule to be in place by start of 2021.
Total proceeds from divestments and other disposals in the quarter were $0.6 billion. BP has already completed or agreed transactions for approaching half its target of $25 billion in proceeds by 2025, including the agreed $5 billion sale of BP’s petrochemicals business, expected to complete by year end.
Finance debt at 30 September 2020 was $72.8 billion, compared with $65.9 billion a year ago. Net debt at quarter-end was $40.4 billion, down $0.5 billion. This includes the impact of the $1.1 billion payment for the completion of the joint venture with Reliance. Net debt is expected to fall in the fourth quarter as proceeds from divestments are received.
A dividend of 5.25 cents per share was announced for the quarter.
Performing while transforming
BP has brought two new Upstream major projects into production since mid-year: Atlantis Phase 3 in the US Gulf of Mexico and, ahead of schedule, Khazzan Phase 2 (Ghazeer) in Oman.
Operations continued to be good with refining availability of 96.2% and Upstream plant reliability of 93.0%. Upstream unit production costs for the nine months of 2020 were 10% lower than 2019, reflecting progress on cost efficiency and strategic divestments.
While refining margins remained at historical lows, driven by the extremely weak environment, BP‘s marketing businesses recovered strongly in the quarter, with fuels marketing earnings growing 3% year on year and lubricants result broadly in line with a year earlier.
BP agreed to enter the offshore wind sector through a strategic partnership with Equinor to pursue offshore wind opportunities in the US, including taking a 50% stake in two leases off the US east coast.
BP announced plans for a network of ultra-fast chargers in Germany and BP Chargemaster won a contract to deliver over 1,000 charging points for Police Scotland.
BP also announced a partnership with Microsoft under which the two companies will co-operate to progress their sustainability aims. As part of this, BP has agreed to supply Microsoft with renewable energy and to extend its use of Microsoft’s cloud-based services.

(a)     Operating cash flow excluding Gulf of Mexico oil spill payments is a measure used by management and BP believes it is useful as it allows for meaningful comparisons between reporting periods. It is not however disclosed in this SEC filing because SEC regulations do not permit the inclusion of this non-GAAP metric.

Financial summary
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Profit (loss) for the period attributable to BP shareholders (450) (749) (21,663) 4,007 
Inventory holding (gains) losses, before tax (233) 512  3,563  (657)
Taxation charge (credit) on inventory holding gains and losses 39  (114) (829) 169 
RC profit (loss) (644) (351) (18,929) 3,519 
Net (favourable) adverse impact of non-operating items and fair value accounting effects, before tax
714  3,291  16,644  4,981 
Taxation charge (credit) on non-operating items and fair value accounting effects
16  (686) (3,520) (1,077)
Underlying RC profit (loss) 86  2,254  (5,805) 7,423 
Profit (loss) per ordinary share (cents) (2.22) (3.68) (107.15) 19.74 
Profit (loss) per ADS (dollars) (0.13) (0.22) (6.43) 1.18 
RC profit (loss) per ordinary share (cents) (3.18) (1.72) (93.63) 17.33 
RC profit (loss) per ADS (dollars) (0.19) (0.10) (5.62) 1.04 
Underlying RC profit (loss) per ordinary share (cents) 0.42  11.06  (28.72) 36.57 
Underlying RC profit (loss) per ADS (dollars) 0.03  0.66  (1.72) 2.19 







RC profit (loss), underlying RC profit, organic capital expenditure, net debt and gearing are non-GAAP measures. These measures and inventory holding gains and losses, non-operating items, fair value accounting effects, major project, Upstream plant reliability and refining availability are defined in the Glossary on page 35.
3

COVID-19 Update
Strengthening finances:
BP has continued to take deliberate steps to strengthen its finances.
Organic capital expenditure is on track for the revised full-year target of around $12 billion, announced in April. Total for the first nine months was $9.1 billion.
BP has continued to progress its divestment programme towards delivery of $25 billion of proceeds by 2025. The $5 billion sale of its petrochemicals business is expected to complete by year end. In the quarter, BP also sold an interest in a portfolio of UK retail properties for $0.5 billion.
BP’s headcount has reduced by a total of around 2,800 so far during 2020, including around 300 who have already left the organization as part of the reinvent bp programme. A further 2,100 have elected to leave under the programme, which is expected to result in a total reduction of around 10,000 positions, the majority by the end of this year. BP expects to incur people-related costs associated with the reinvent programme, including redundancy payments, of around $1.4 billion over the next 1-2 years, primarily in 2020.
Net debt was $40.4 billion at quarter-end and is expected to fall further in the fourth quarter as divestment proceeds are received. BP also continues to actively manage the profile of its debt portfolio, buying back/retiring $4.0 billion of shorter-term debt in the quarter. At quarter end BP had around $44 billion of liquidity, including cash and undrawn revolving credit facilities.
BP will continue to review these actions, and any further actions that may be appropriate, in response to changes in prevailing market conditions.
BP's future financial performance, including cash flows, net debt and gearing, will be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. It is difficult to predict when current supply and demand imbalances will be resolved and what the ultimate impact of COVID-19 will be.
Costs that are directly attributable to COVID-19 were around $0.1 billion for the quarter (second quarter 2020 $0.2 billion).
Protecting our people and operations:
BP continues to monitor the impact of COVID-19 on global operations and to date there has been no direct significant operational impact, although this could change through the rest of the fourth quarter.
Refinery utilization in the quarter was around 10% below 2019 levels, driven by COVID-19 impacts. Year-on-year, demand for retail fuels was lower by 7% and for aviation by around 60%. However fuels marketing earnings grew, benefitting from continued growth in convenience sales.
Despite the significant challenges of the environment, BP’s operations performed safely and reliably in the quarter. BP-operated Upstream plant reliability was 93.0% and BP-operated refining availability 96.2%.
BP continues to take steps to protect and support its staff through the pandemic. The great majority of BP staff who are able to work from home are still doing so. Precautions in operations and offices include: reduced manning levels, changing working patterns, deploying appropriate personal protective equipment (PPE), enhanced cleaning and social distancing measures at plants and retail sites. Decisions on repopulating offices are being taken with caution and in compliance with local and national guidelines and regulations.
BP is providing enhanced support and guidance to staff on safety, health and hygiene, homeworking and mental health.
Outlook:
The ongoing impacts of the COVID-19 pandemic continue to create a volatile and challenging trading environment. There have been some early signs of global economic recovery as countries move to more regional or localised restrictions on movement and governments continue to offer monetary and fiscal policy stimulus. However, the shape and pace of the recovery is uncertain, as it depends on the further spread of the pandemic.
The gradual recovery in oil demand seen since the spring looks set to continue, led by strengthening demand in Asia. The IEA estimates an increase of around six million barrels a day in 2021, as economies continue to open up. OPEC+ production cuts have played a major role in stabilising the market and there is already a reduction in crude and product inventories. Inventories are likely to reduce through 2021, although the pace at which they normalise will depend on the strength of economic recovery and the degree of continued OPEC+ compliance.
US gas supply is expected to continue on a declining trend in 2021, largely due to a drop in associated gas production. Tightening gas balances have caused the prompt price to rise, and the futures curve for Henry Hub now averages above $3 for 2021. This would be expected to provide some support to pricing in Europe and Asia until more gas comes to market.
The refining margin outlook remains challenging, given record high inventory levels and a levelling off in demand recovery for gasoline and jet fuel due to COVID-19.

The commentary above and following should be read in conjunction with the cautionary statement on page 39.
4

Group headlines
Results
Loss for the third quarter and nine months attributable to BP shareholders was $450 million and $21,663 million respectively, compared with a loss of $749 million and a profit of $4,007 million for the same periods in 2019.
For the nine months, replacement cost (RC) loss* was $18,929 million, compared with a profit of $3,519 million in 2019. Underlying RC loss* was $5,805 million, compared with a profit of $7,423 million in 2019. Underlying RC loss is after adjusting RC loss for a net charge for non-operating items* of $13,357 million and net favourable fair value accounting effects* of $233 million (both on a post-tax basis).
For the third quarter, RC loss was $644 million, compared with $351 million in 2019. Underlying RC profit was $86 million, compared with $2,254 million in 2019. Underlying RC profit is after adjusting RC loss for a net charge for non-operating items of $1,109 million and net favourable fair value accounting effects of $379 million (both on a post-tax basis).
See further information on pages 6, 30 and 31.
Depreciation, depletion and amortization
The charge for depreciation, depletion and amortization was $3.5 billion in the quarter and $11.5 billion in the nine months, compared with $4.3 billion and $13.3 billion for the same periods in 2019. BP now expects the 2020 full-year charge to be around 15% lower than 2019.
Effective tax rate
The effective tax rate (ETR) on the profit or loss for the third quarter and nine months was 305% and 14% respectively, compared with -2,824% and 47% for the same periods in 2019.
The ETR on RC profit or loss* for the third quarter and nine months was -504% and 13% respectively, compared with 168% and 49% for the same periods in 2019. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the third quarter and nine months was 64% and -10% respectively, compared with 40% and 38% for the same periods a year ago. The higher underlying ETR for the third quarter reflects changes in the mix of profits and losses. The lower underlying ETR for the nine months mainly reflects the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition in the second quarter. ETR on RC profit or loss and underlying ETR are non-GAAP measures.
Dividend
BP today announced a quarterly dividend of 5.25 cents per ordinary share ($0.315 per ADS), which is expected to be paid on 18 December 2020. The corresponding amount in sterling will be announced on 7 December 2020. See page 27 for more information.
Share buybacks
BP repurchased 120 million ordinary shares at a cost of $776 million (including fees and stamp duty) in the nine months of 2020, all of which was completed in the first quarter. In January 2020, the share dilution buyback programme had fully offset the impact of scrip dilution since the third quarter 2017.
Operating cash flow*
Operating cash flow was $5.2 billion for the third quarter and $9.9 billion for the nine months, including the impact of Gulf of Mexico oil spill payments of $0.1 billion and $1.5 billion respectively, compared with $6.1 billion and $18.2 billion for the same periods in 2019.
Capital expenditure*
Total capital expenditure for the third quarter and nine months was $3.6 billion and $10.6 billion respectively, compared with $4.0 billion and $15.3 billion for the same periods in 2019.
Organic capital expenditure* for the third quarter and nine months was $2.5 billion and $9.1 billion respectively, compared with $3.9 billion and $11.3 billion for the same periods in 2019.
Inorganic capital expenditure* for the third quarter and nine months was $1.1 billion and $1.5 billion respectively, compared with $0.1 billion and $4.0 billion for the same periods in 2019.
BP expects total capital expenditure for 2021 to be at the lower end of a $13-15 billion range.
Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 29 for further information.
Divestment and other proceeds
Divestment proceeds* were $0.1 billion for the third quarter and $1.5 billion for the nine months, compared with $0.7 billion and $1.4 billion for the same periods in 2019. In addition, $0.5 billion was received in the third quarter of 2020 in relation to the sale of an interest in BP's UK retail property portfolio.
Debt
Finance debt at 30 September 2020 was $72.8 billion, compared with $65.9 billion a year ago. Finance debt ratio* at 30 September 2020 was 47.0%, compared with 39.7% a year ago. Net debt* at 30 September 2020 was $40.4 billion, compared with $46.5 billion a year ago. Gearing* at 30 September 2020 was 33.0%, compared with 31.7% a year ago, reflecting the reduction in equity in the period. Gearing including leases* at 30 September 2020 was 37.7%, compared with 35.9% a year ago. Net debt, gearing and gearing including leases are non-GAAP measures. See pages 27 and 32 for more information.








* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 35.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.
5

Analysis of underlying RC profit (loss)* before interest and tax
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Underlying RC profit (loss) before interest and tax
Upstream 878  2,139  (5,738) 8,480 
Downstream 636  1,883  2,962  4,981 
Rosneft (177) 802  (255) 2,007 
Other businesses and corporate (130) (322) (951) (1,030)
Consolidation adjustment – UPII* 34  30  166  51 
Underlying RC profit (loss) before interest and tax 1,241  4,532  (3,816) 14,489 
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(610) (754) (1,955) (2,260)
Taxation on an underlying RC basis (402) (1,506) (585) (4,641)
Non-controlling interests (143) (18) 551  (165)
Underlying RC profit (loss) attributable to BP shareholders 86  2,254  (5,805) 7,423 
Reconciliations of underlying RC profit or loss attributable to BP shareholders to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 9-14 for the segments.
Analysis of RC profit (loss)* before interest and tax and reconciliation to profit (loss) for the period
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
RC profit (loss) before interest and tax
Upstream 30  (1,050) (20,955) 4,303 
Downstream 915  2,016  2,173  5,069 
Rosneft (278) 802  (419) 1,813 
Other businesses and corporate 24  (412) (991) (1,339)
Consolidation adjustment – UPII 34  30  166  51 
RC profit (loss) before interest and tax 725  1,386  (20,026) 9,897 
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(808) (899) (2,389) (2,649)
Taxation on a RC basis (418) (820) 2,935  (3,564)
Non-controlling interests (143) (18) 551  (165)
RC profit (loss) attributable to BP shareholders (644) (351) (18,929) 3,519 
Inventory holding gains (losses)* 233  (512) (3,563) 657 
Taxation (charge) credit on inventory holding gains and losses (39) 114  829  (169)
Profit (loss) for the period attributable to BP shareholders (450) (749) (21,663) 4,007 




6

Operational updates
Upstream
Upstream production, which excludes Rosneft, for the nine months of the year averaged 2,448mboe/d, 6.4% lower than a year earlier. Underlying production*, for the nine months was slightly lower than 2019 reflecting adverse weather, primarily in the US Gulf of Mexico.
For the first nine months of 2020, BP-operated Upstream plant reliability* was 93.8% and Upstream unit production costs of $6.30/boe were more than 10% lower than in 2019 reflecting ongoing progress on cost efficiency in operations, and strategic divestments.
Since mid-year, BP has started production on the Atlantis Phase 3 project in the Gulf of Mexico, followed by the Ghazeer gas project, the second phase of development on Block 61 in Oman, that began production three months ahead of schedule. These are the first of five Upstream major projects* expected to begin production in 2020. BP also brought the Galeota expansion project in Trinidad into operation during the quarter.
In September, BP confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt.
The Trans Adriatic Gas pipeline (TAP) has completed construction and is expected to soon commence gas exports from Azerbaijan to customers in Europe.
Downstream
Fuels marketing earnings for the third quarter were 3% higher than in 2019, benefiting from continued growth in store gross margin, despite COVID-driven fuel demand impacts.
BP-operated refining availability continued to be strong, at 96.2% in the quarter. However, refining margins were extremely weak and refinery utilization was around 10% below 2019 levels.
Lubricants saw strong demand recovery in the third quarter, including year-on-year growth in key markets such as India and China.
The sale of BP’s petrochemicals business to INEOS, agreed in June, remains on track to complete by the end of 2020.
Strategic progress
In September, BP agreed to enter into a strategic partnership with Equinor to develop offshore wind projects in the US. This includes the purchase of a 50% interest in two existing wind leases and associated projects off the east coast of the US. Subject to customary regulatory and other approvals, the transaction is expected to close in early 2021.
BP continued to progress electrification in the quarter with plans announced in July to build a network of ultra-fast charging points across Germany, including more than 100 charging points at Aral retail sites over the next 12 months. BP Chargemaster was recently awarded a contract by Police Scotland, to deliver more than 1,000 charging points over the next four years.
BP announced a strategic partnership with Microsoft under which the two companies will co-operate to progress their sustainability aims. As part of this, BP has agreed to supply Microsoft with renewable energy and to extend its use of Microsoft’s cloud-based services.
BP announced an agreement to partner with Aberdeen City Council to help it achieve the goals of its Net Zero Vision to reduce emissions and become a climate positive city. This follows the partnership with the City of Houston that BP announced in July.
Financial framework
Operating cash flow* was $9.9 billion for the nine months of 2020, including Gulf of Mexico oil spill payments of $1.5 billion, compared with $18.2 billion for the same period in 2019.
Organic capital expenditure* for the nine months of 2020 was $9.1 billion. BP expects 2020 organic capital expenditure to be around $12 billion.
Total divestment and other proceeds were $2.4 billion for the nine months of 2020.
Gulf of Mexico oil spill payments on a post-tax basis were $1.5 billion in the nine months of 2020. Payments for the full year are expected to be around $1.5 billion on a post-tax basis.
Gearing* at 30 September 2020 was 33.0%, in part reflecting the recent hybrid bond issue. See page 27 for more information.

Operating metrics Nine months 2020 Financial metrics Nine months 2020
(vs. Nine months 2019) (vs. Nine months 2019)
Tier 1 and tier 2 process safety events
66
Underlying RC profit (loss)*i
$(5.8)bn
(-7)
(-$13.2bn)
Reported recordable injury frequency*
0.127
Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)
(b)
(-29.2%)
Group production
3,542mboe/d
Organic capital expenditureii
$9.1bn
(-5.7%) (-$2.2bn)
Upstream production (excludes Rosneft segment)
2,448mboe/d Gulf of Mexico oil spill payments (post-tax) $1.5bn
(-6.4%) (-$1.0bn)
Upstream unit production costs(a)
$6.30/boe
Divestment proceeds* $1.5bn
(-10.3%)
(+$0.1bn)
BP-operated Upstream plant reliability
93.8%
Gearingiii
33.0%
(-0.6)
(+1.3)
BP-operated refining availability* 96.0%
Dividend per ordinary share(c)
5.25 cents
(+1.4) (-48.8%)
(a)Reflecting lower costs and divestment impacts.
(b)SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax payments relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the nine months, net cash provided by operating activities was $9.9 billion and post-tax Gulf of Mexico oil spill payments were $1.5 billion.
(c)Represents dividend announced in the quarter (vs. prior year quarter).
7

Nearest GAAP equivalent measures
i (Loss) for the period att. to BP shareholders: $(21.7)bn
ii Capital expenditure*: $10.6bn
iii Finance debt ratio*: 47.0%

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.
8

Upstream
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Profit (loss) before interest and tax 38  (1,050) (20,958) 4,295 
Inventory holding (gains) losses* (8) —  3 
RC profit (loss) before interest and tax 30  (1,050) (20,955) 4,303 
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
848  3,189  15,217  4,177 
Underlying RC profit (loss) before interest and tax*(a)
878  2,139  (5,738) 8,480 
(a)See page 10 for a reconciliation to segment RC profit before interest and tax by region.

Financial results
The replacement cost result before interest and tax for the third quarter and nine months was a profit of $30 million and a loss of $20,955 million respectively, compared with a loss of $1,050 million and a profit of $4,303 million for the same periods in 2019. The third quarter and nine months included a net non-operating charge of $631 million and $15,156 million respectively, compared with a net charge of $3,454 million and $4,224 million for the same periods in 2019. The net non-operating charge for the nine months is principally related to impairments associated with revisions to long-term price assumptions. Fair value accounting effects in the third quarter and nine months had an adverse impact of $217 million and $61 million respectively, compared with a favourable impact of $265 million and $47 million in the same periods of 2019.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost result before interest and tax for the third quarter and nine months was a profit of $878 million and a loss of $5,738 million respectively, compared with a profit of $2,139 million and $8,480 million for the same periods in 2019. The result for the third quarter mainly reflects lower liquids and gas realizations, partly offset by lower depreciation, depletion and amortization. The result for the nine months mainly reflects lower liquids and gas realizations and the impact of writing down certain exploration intangible carrying values.

Production
Production for the quarter was 2,243mboe/d, 12.7% lower than the third quarter of 2019 mainly due to divestments in BPX Energy, Alaska and Gulf of Suez oil concessions in Egypt. Underlying production* for the quarter decreased by 3.0% mainly due to decline associated with reduced capital investment levels and significant weather impacts from hurricanes in the US Gulf of Mexico.
For the nine months, production was 2,448mboe/d, 6.4% lower than the nine months of 2019. Underlying production for the nine months was slightly lower than 2019 reflecting adverse weather, primarily in the US Gulf of Mexico.

Key events
During the third quarter, BP was awarded eight operated and three non-operated blocks in the North Sea as part of the UK Oil & Gas Authority 32nd offshore licensing round.
On 25 August, BP confirmed it started production on Atlantis Phase 3 in the US Gulf of Mexico (BP operator 56%, BHP Billiton 44%).
On 16 September, BP confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt (Eni operator 75%, BP 25%).
On 28 September, BP Trinidad and Tobago LLC started up the Galeota expansion project in Trinidad.
On 1 October, BP confirmed force majeure was lifted on the Greater Tortue Ahmeyim (GTA) project offshore Mauritania and Senegal (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%).
On 6 October, BP confirmed the planned divestment to Premier Oil of its interests in the Andrew area and Shearwater assets, both located in the UK North Sea, will not proceed following the announcement of a proposed merger between Chrysaor and Premier Oil.
On 12 October, BP announced the start-up of production from Block 61 Phase 2 Ghazeer gas field in Oman (BP operator 60%, Makarim Gas Development Limited 30%, PC Oman Ventures Limited 10%).

Outlook
Looking ahead, we expect fourth-quarter 2020 reported production to be slightly lower than the third quarter due to maintenance activity.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

9

Upstream (continued)
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Underlying RC profit (loss) before interest and tax
US 125  552  (2,296) 2,025 
Non-US 753  1,587  (3,442) 6,455 
878  2,139  (5,738) 8,480 
Non-operating items(a)(b)
US (114) (3,338) (2,868) (3,814)
Non-US (517) (116) (12,288) (410)
(631) (3,454) (15,156) (4,224)
Fair value accounting effects
US 57  19  94  (299)
Non-US (274) 246  (155) 346 
(217) 265  (61) 47 
RC profit (loss) before interest and tax
US 68  (2,767) (5,070) (2,088)
Non-US (38) 1,717  (15,885) 6,391 
30  (1,050) (20,955) 4,303 
Exploration expense
US 40  53  2,620  147 
Non-US 150  132  7,446  551 
190  185  10,066  698 
Of which: Exploration expenditure written off(b)
50  115  9,766  476 
Production (net of royalties)(c)(d)
Liquids* (mb/d)
US 363  449  446  470 
Europe 143  118  152  138 
Rest of World 623  657  668  667 
1,129  1,224  1,266  1,274 
Of which equity-accounted entities 142  136  145  135 
Natural gas (mmcf/d)
US 1,419  2,396  1,671  2,372 
Europe 265  188  269  155 
Rest of World 4,774  5,211  4,915  5,254 
6,457  7,795  6,855  7,782 
Of which equity-accounted entities 489  466  482  460 
Total hydrocarbons* (mboe/d)
US 608  862  735  879 
Europe 188  151  198  165 
Rest of World 1,446  1,555  1,516  1,573 
2,243  2,568  2,448  2,616 
Of which equity-accounted entities 226  217  228  214 
Average realizations*(e)
Total liquids(e) ($/bbl)
38.17  55.68  35.51  58.38 
Natural gas ($/mcf) 2.56  3.11  2.65  3.49 
Total hydrocarbons ($/boe)
26.42  35.48  25.68  38.55 
(a)Nine months 2020 principally relates to impairments in a number of our businesses resulting from the revisions to BP’s long-term price assumptions. Nine months 2020 also includes impairment charges and loss principally related to the disposal of our Alaska business, BPX Energy assets and oil price impacts in the UK North Sea. Third quarter and nine months 2019 include impairment charges related to the disposal of heritage BPX Energy assets, Alaska and GUPCO divestment. See Note 3 for further information.
(b)Nine months 2020 includes the write-off of $1,969 million relating to value ascribed to certain licences as part of the accounting for the acquisition of upstream assets in Brazil, India and the Gulf of Mexico. This has been classified within the ‘other’ category of non-operating items. See Note 4 for further information.
(c)Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(d)Because of rounding, some totals may not agree exactly with the sum of their component parts.
(e)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(f)Includes condensate, natural gas liquids and bitumen.


10

Downstream
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Profit (loss) before interest and tax 1,106  1,583  (1,273) 5,775 
Inventory holding (gains) losses* (191) 433  3,446  (706)
RC profit before interest and tax 915  2,016  2,173  5,069 
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
(279) (133) 789  (88)
Underlying RC profit before interest and tax*(a)
636  1,883  2,962  4,981 
(a)See page 12 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results
The replacement cost profit before interest and tax for the third quarter and nine months was $915 million and $2,173 million respectively, compared with $2,016 million and $5,069 million for the same periods in 2019.
The third quarter and nine months include a net non-operating charge of $146 million and $924 million respectively, compared with a charge of $14 million and $49 million for the same periods in 2019. The charge for the quarter mainly relates to restructuring, while the charge for the nine months primarily reflects impairments. Fair value accounting effects in the third quarter and nine months had a favourable impact of $425 million and $135 million respectively, compared with a favourable impact of $147 million and $137 million in the same periods in 2019.
After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $636 million and $2,962 million respectively, compared with $1,883 million and $4,981 million for the same periods in 2019.
Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 12.
Fuels
The fuels business reported an underlying replacement cost profit before interest and tax of $222 million for the third quarter and $2,206 million for the nine months, compared with $1,438 million and $3,691 million for the same periods in 2019.
Across fuels marketing we saw earnings growth of 3% year on year primarily driven by increased store gross margin. This growth is despite continued COVID-19 demand impacts with retail volumes in the quarter 7% lower than last year. The result for the nine months, however, remained impacted by COVID-19, with year to date retail volumes 15% lower than 2019, and aviation volumes down by 50%.
The refining result for the quarter and nine months continued to be impacted by an extremely weak environment with refining margins remaining at historical lows. Utilization of 83% for the quarter improved compared with the second quarter, albeit still around 10% lower than 2019, driven by continued COVID-19 demand impacts. These factors were partially offset by a lower level of turnaround activity and strong refining availability.
The quarterly result also reflects a weaker contribution from supply and trading, although the contribution for the nine months remains higher year on year.
We continued to progress our advanced mobility agenda in the quarter with plans announced in July to build a network of ultra-fast charging across Germany, beginning with the roll out of more than 100 charging points at Aral retail sites over the next 12 months. In addition, BP Chargemaster was recently awarded the UK’s largest ever EV infrastructure contract by Police Scotland, to deliver more than 1,000 charging points over the next four years.
Lubricants
The lubricants business saw significant recovery in the third quarter as volumes improved to levels similar to 2019, supported by growth of more than 5% in China and India. The result for the nine months, however, continued to reflect significant COVID-19 demand destruction seen in the first half of 2020.
Underlying replacement cost profit before interest and tax was $326 million for the third quarter and $556 million for the nine months, compared with $332 million and $925 million for the same periods in 2019.
Petrochemicals
The petrochemicals business reported an underlying replacement cost profit before interest and tax of $88 million for the third quarter and $200 million for the nine months, compared with $113 million and $365 million for the same periods in 2019. The result for the quarter and nine months reflects a significantly weaker margin environment and the demand impact of COVID-19.
As previously reported, in the second quarter we announced the sale of BP’s petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary adjustments. The transaction remains on track and, subject to approvals, is expected to complete by the end of the year.
Outlook
Looking to the fourth quarter of 2020, we expect continued pressure on industry refining margins and for marketing volumes to remain impacted by COVID-19 restrictions.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.
11

Downstream (continued)
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Underlying RC profit before interest and tax - by region
US 96  537  1,372  1,634 
Non-US 540  1,346  1,590  3,347 
636  1,883  2,962  4,981 
Non-operating items
US (27) (5) (90) (2)
Non-US (119) (9) (834) (47)
(146) (14) (924) (49)
Fair value accounting effects(a)
US 78  116  152  185 
Non-US 347  31  (17) (48)
425  147  135  137 
RC profit before interest and tax
US 147  648  1,434  1,817 
Non-US 768  1,368  739  3,252 
915  2,016  2,173  5,069 
Underlying RC profit before interest and tax - by business(b)(c)
Fuels 222  1,438  2,206  3,691 
Lubricants 326  332  556  925 
Petrochemicals 88  113  200  365 
636  1,883  2,962  4,981 
Non-operating items and fair value accounting effects(a)
Fuels 288  135  (717) 73 
Lubricants (7) —  (58) 18 
Petrochemicals (2) (2) (14) (3)
279  133  (789) 88 
RC profit before interest and tax(b)(c)
Fuels 510  1,573  1,489  3,764 
Lubricants 319  332  498  943 
Petrochemicals 86  111  186  362 
915  2,016  2,173  5,069 
BP average refining marker margin (RMM)* ($/bbl)
6.2  14.7  7.0  13.4 
Refinery throughputs (mb/d)
US 701  781  687  730 
Europe 699  815  750  766 
Rest of World 187  217  189  221 
1,587  1,813  1,626  1,717 
BP-operated refining availability* (%)
96.2  96.1  96.0  94.6 
Marketing sales of refined products (mb/d)
US 1,083  1,172  997  1,141 
Europe 849  1,157  830  1,081 
Rest of World 422  459  435  500 
2,354  2,788  2,262  2,722 
Trading/supply sales of refined products 2,618  3,157  3,054  3,183 
Total sales volumes of refined products 4,972  5,945  5,316  5,905 
Petrochemicals production (kte)
US 541  564  1,562  1,749 
Europe 1,325  1,187  3,942  3,573 
Rest of World 1,211  1,325  3,635  3,780 
3,077  3,076  9,139  9,102 
(a)For Downstream, fair value accounting effects arise solely in the fuels business. See page 31 for further information.
(b)Segment-level overhead expenses are included in the fuels business result.
(c)Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany are reported in the fuels business.

12

Rosneft
Third Third Nine Nine
quarter quarter months months
$ million
2020(a)
2019
2020(a)
2019
Profit (loss) before interest and tax(b)(c)
(244) 723  (533) 1,772 
Inventory holding (gains) losses* (34) 79  114  41 
RC profit (loss) before interest and tax (278) 802  (419) 1,813 
Net charge (credit) for non-operating items* 101  —  164  194 
Underlying RC profit (loss) before interest and tax* (177) 802  (255) 2,007 

Financial results
Replacement cost (RC) loss before interest and tax for the third quarter and nine months was $278 million and $419 million respectively, compared with a profit of $802 million and $1,813 million for the same periods in 2019.
After adjusting for non-operating items, the underlying RC loss before interest and tax for the third quarter and nine months was $177 million and $255 million respectively, compared with a profit of $802 million and $2,007 million for the same periods in 2019.
Compared with the same periods in 2019, the results for the third quarter and nine months primarily reflects lower oil prices and adverse foreign exchange effects and lower production as a result of OPEC+ agreement.
Third Third Nine Nine
quarter quarter months months
2020(a)
2019
2020(a)
2019
Production (net of royalties) (BP share)
Liquids* (mb/d) 858  920  877  923 
Natural gas (mmcf/d) 1,260  1,236  1,261  1,271 
Total hydrocarbons* (mboe/d) 1,075  1,133  1,094  1,142 
(a)The operational and financial information of the Rosneft segment for the third quarter and nine months is based on preliminary operational and financial results of Rosneft for the three months and nine months ended 30 September 2020. Actual results may differ from these amounts. Amounts reported for the third quarter are based on BP’s 21.96% average economic interest for the quarter (second quarter 2020 21.20%, first quarter 2020 and 2019 19.75%).
(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.

13

Other businesses and corporate
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Profit (loss) before interest and tax 24  (412) (991) (1,339)
Inventory holding (gains) losses*   —    — 
RC profit (loss) before interest and tax 24  (412) (991) (1,339)
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
(154) 90  40  309 
Underlying RC profit (loss) before interest and tax* (130) (322) (951) (1,030)
Underlying RC profit (loss) before interest and tax
US (65) (249) (318) (628)
Non-US (65) (73) (633) (402)
(130) (322) (951) (1,030)
Non-operating items
US (62) (85) (172) (291)
Non-US (50) (5) (93) (18)
(112) (90) (265) (309)
Fair value accounting effects
US   —    — 
Non-US 266  —  225  — 
266  —  225  — 
RC profit (loss) before interest and tax
US (127) (334) (490) (919)
Non-US 151  (78) (501) (420)
24  (412) (991) (1,339)
Other businesses and corporate comprises our alternative energy business, shipping, treasury, BP ventures and corporate activities including centralized functions, and any residual costs of the Gulf of Mexico oil spill.
Financial results
The replacement cost result before interest and tax for the third quarter and nine months was a profit of $24 million and a loss of $991 million respectively, compared with a loss of $412 million and $1,339 million for the same periods in 2019.
The results included a net non-operating charge of $112 million for the third quarter and $265 million for the nine months, compared with a charge of $90 million and $309 million for the same periods in 2019. Fair value accounting effects in the third quarter and nine months had a favourable impact of $266 million and $225 million. See page 28 for further information.
After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $130 million and $951 million respectively, compared with $322 million and $1,030 million for the same periods in 2019.
Alternative Energy
BP's net ethanol-equivalent production* for the third quarter and nine months of the year averaged 36.5kb/d and 22.1kb/d respectively, compared with 24.4kb/d and 14.4kb/d for the 100% BP-owned business for the same periods in 2019.
Net wind generation capacity* was 1,072MW at 30 September 2020, compared with 926MW at 30 September 2019. BP’s net share of wind generation for the third quarter and nine months was 454GWh and 1,904GWh respectively, compared with 506GWh and 1,967GWh for the same periods in 2019. In September BP acquired the remaining 50% interest in the BP-operated Fowler Ridge 1 wind asset. The asset increased net wind capacity by 150MW to 1,072MW.
In September BP and Equinor announced the formation of a new strategic partnership to develop four assets in two existing offshore wind leases located offshore New York and Massachusetts. Subject to customary regulatory and other approvals, the transaction is expected to close in early 2021 and will mark BP’s first entry into the offshore wind sector, one of the fastest growing energy sectors.
Lightsource BP has developed 637MW for the nine months of the year to 30 September 2020. In September Lightsource BP reached financial close and mobilized construction for the 300MW Bighorn Solar project in the US, which will deliver energy to the EVRAZ North America steel mill in Pueblo, Colorado. In October they completed construction on three solar sites in Franklin County, Pennsylvania in the US. The sites will deliver electricity to Penn State University under the 70MW Power Purchase Agreement (PPA) to provide over 100 million kilowatt-hours of electricity in year one.
BP has developed a total of 3GW net renewable energy generating capacity by 30 September 2020 across our businesses. We intend to continue building our renewable energy businesses and to have developed 20GW by 2025.
Outlook
Other businesses and corporate average quarterly charges, excluding non-operating items, fair value accounting effects and foreign exchange volatility impact, are expected to be around $350 million although this will fluctuate quarter to quarter.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.
14

Financial statements
Group income statement
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Sales and other operating revenues (Note 6) 44,251  68,291  135,577  207,288 
Earnings from joint ventures – after interest and tax 73  90  (516) 413 
Earnings from associates – after interest and tax (332) 784  (676) 2,041 
Interest and other income 183  126  430  559 
Gains on sale of businesses and fixed assets 27  117  145 
Total revenues and other income 44,202  69,292  134,932  210,446 
Purchases 31,645  52,273  99,301  156,228 
Production and manufacturing expenses 5,073  5,259  16,383  16,006 
Production and similar taxes (Note 8) 140  340  467  1,135 
Depreciation, depletion and amortization (Note 7) 3,467  4,297  11,463  13,346 
Impairment and losses on sale of businesses and fixed assets (Note 3) 294  3,416  13,213  4,418 
Exploration expense (Note 4) 190  185  10,066  698 
Distribution and administration expenses 2,435  2,648  7,628  8,061 
Profit (loss) before interest and taxation 958  874  (23,589) 10,554 
Finance costs 800  883  2,366  2,603 
Net finance expense relating to pensions and other post-retirement benefits 8  16  23  46 
Profit (loss) before taxation 150  (25) (25,978) 7,905 
Taxation 457  706  (3,764) 3,733 
Profit (loss) for the period (307) (731) (22,214) 4,172 
Attributable to
BP shareholders
(450) (749) (21,663) 4,007 
Non-controlling interests
143  18  (551) 165 
(307) (731) (22,214) 4,172 
Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic (2.22) (3.68) (107.15) 19.74 
Diluted (2.22) (3.68) (107.15) 19.63 
Per ADS (dollars)
Basic (0.13) (0.22) (6.43) 1.18 
Diluted (0.13) (0.22) (6.43) 1.18 



15

Condensed group statement of comprehensive income
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Profit (loss) for the period (307) (731) (22,214) 4,172 
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences(a)
(166) (986) (3,437) 134 
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets
  —  4  — 
Cash flow hedges and costs of hedging (90) (17) 63  135 
Share of items relating to equity-accounted entities, net of tax 308  119  417  39 
Income tax relating to items that may be reclassified (16) 12  64  (31)
36  (872) (2,889) 277 
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset(b)
78  (260) (163) (1,152)
Cash flow hedges that will subsequently be transferred to the balance sheet
8  (10) (2) (9)
Income tax relating to items that will not be reclassified (16) 27  (16) 302 
70  (243) (181) (859)
Other comprehensive income 106  (1,115) (3,070) (582)
Total comprehensive income (201) (1,846) (25,284) 3,590 
Attributable to
BP shareholders (364) (1,848) (24,723) 3,434 
Non-controlling interests 163  (561) 156 
(201) (1,846) (25,284) 3,590 
(a)Nine months 2020 was principally affected by movements in the Russian rouble against the US dollar.
(b)See Note 1 for further information.

16

Condensed group statement of changes in equity
BP shareholders’ Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
At 1 January 2020 98,412    2,296  100,708 
Total comprehensive income (24,723) 133  (694) (25,284)
Dividends (5,305)   (163) (5,468)
Cash flow hedges transferred to the balance sheet, net of tax
7      7 
Repurchase of ordinary share capital (776)     (776)
Share-based payments, net of tax 547      547 
Share of equity-accounted entities’ changes in equity, net of tax
       
Issue of perpetual hybrid bonds (48) 11,909    11,861 
Payments on perpetual hybrid bonds   (27)   (27)
Tax on issue of perpetual hybrid bonds 1      1 
Transactions involving non-controlling interests, net of tax
(160)   746  586 
At 30 September 2020 67,955  12,015  2,185  82,155 
BP shareholders’ Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
At 31 December 2018 99,444  —  2,104  101,548 
Adjustment on adoption of IFRS 16, net of tax(a)
(329) —  (1) (330)
At 1 January 2019 99,115  —  2,103  101,218 
Total comprehensive income 3,434  —  156  3,590 
Dividends (4,857) —  (166) (5,023)
Cash flow hedges transferred to the balance sheet, net of tax
18  —  —  18 
Repurchase of ordinary share capital (340) —  —  (340)
Share-based payments, net of tax 544  —  —  544 
Share of equity-accounted entities’ changes in equity, net of tax
—  — 
At 30 September 2019 97,922  —  2,093  100,015 
(a)    See Note 1 in BP Annual Report and Form 20-F 2019 for further information.


17

Group balance sheet
30 September 31 December
$ million 2020 2019
Non-current assets
Property, plant and equipment 116,580  132,642 
Goodwill 12,457  11,868 
Intangible assets 6,293  15,539 
Investments in joint ventures 7,953  9,991 
Investments in associates 16,929  20,334 
Other investments 2,439  1,276 
Fixed assets 162,651  191,650 
Loans 711  630 
Trade and other receivables 4,239  2,147 
Derivative financial instruments 7,705  6,314 
Prepayments 497  781 
Deferred tax assets 6,816  4,560 
Defined benefit pension plan surpluses 6,806  7,053 
189,425  213,135 
Current assets
Loans 555  339 
Inventories 13,840  20,880 
Trade and other receivables 15,954  24,442 
Derivative financial instruments 3,562  4,153 
Prepayments 645  857 
Current tax receivable 681  1,282 
Other investments 298  169 
Cash and cash equivalents 30,749  22,472 
66,284  74,594 
Assets classified as held for sale (Note 2) 4,541  7,465 
70,825  82,059 
Total assets 260,250  295,194 
Current liabilities
Trade and other payables 33,823  46,829 
Derivative financial instruments 3,088  3,261 
Accruals 3,822  5,066 
Lease liabilities 1,907  2,067 
Finance debt 11,013  10,487 
Current tax payable 804  2,039 
Provisions 2,563  2,453 
57,020  72,202 
Liabilities directly associated with assets classified as held for sale (Note 2) 1,057  1,393 
58,077  73,595 
Non-current liabilities
Other payables 11,908  12,626 
Derivative financial instruments 4,761  5,537 
Accruals 908  996 
Lease liabilities 7,375  7,655 
Finance debt 61,796  57,237 
Deferred tax liabilities 6,634  9,750 
Provisions 17,892  18,498 
Defined benefit pension plan and other post-retirement benefit plan deficits 8,744  8,592 
120,018  120,891 
Total liabilities 178,095  194,486 
Net assets 82,155  100,708 
Equity
BP shareholders’ equity 67,955  98,412 
Non-controlling interests 14,200  2,296 
Total equity 82,155  100,708 


18

Condensed group cash flow statement
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Operating activities
Profit (loss) before taxation 150  (25) (25,978) 7,905 
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off
3,517  4,412  21,229  13,822 
Impairment and (gain) loss on sale of businesses and fixed assets
267  3,415  13,096  4,273 
Earnings from equity-accounted entities, less dividends received
1,018  (236) 2,383  (1,220)
Net charge for interest and other finance expense, less net interest paid
60  257  214  407 
Share-based payments
199  149  544  563 
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
(46) (50) (100) (195)
Net charge for provisions, less payments
293  (132) (131) (446)
Movements in inventories and other current and non-current assets and liabilities
556  141  630  (2,612)
Income taxes paid
(810) (1,875) (1,994) (4,330)
Net cash provided by operating activities 5,204  6,056  9,893  18,167 
Investing activities
Expenditure on property, plant and equipment, intangible and other assets (2,577) (3,954) (9,384) (11,482)
Acquisitions, net of cash acquired (10) 13  (27) (3,529)
Investment in joint ventures (12) (60) (38) (80)
Investment in associates (1,037) (22) (1,115) (221)
Total cash capital expenditure (3,636) (4,023) (10,564) (15,312)
Proceeds from disposal of fixed assets 32  171  52  476 
Proceeds from disposal of businesses, net of cash disposed 84  536  1,425  909 
Proceeds from loan repayments 50  63  656  182 
Net cash used in investing activities (3,470) (3,253) (8,431) (13,745)
Financing activities
Net issue (repurchase) of shares (Note 9)   (215) (776) (340)
Lease liability payments (578) (594) (1,811) (1,806)
Proceeds from long-term financing 2,587  213  12,117  6,718 
Repayments of long-term financing (4,307) (516) (8,988) (6,758)
Net increase (decrease) in short-term debt (2,630) (852) (328) 118 
Issue of perpetual hybrid bonds   —  11,861  — 
Payments on perpetual hybrid bonds (27) —  (27) — 
Payments relating to transactions involving non-controlling interests (other)   —  (8) — 
Receipts relating to transactions involving non-controlling interests (other) 483  —  492  — 
Dividends paid - BP shareholders (1,060) (1,656) (5,281) (4,870)
 - non-controlling interests
(58) (47) (163) (166)
Net cash provided by (used in) financing activities (5,590) (3,667) 7,088  (7,104)
Currency translation differences relating to cash and cash equivalents 268  (118) 43  (94)
Increase (decrease) in cash and cash equivalents (3,588) (982) 8,593  (2,776)
Cash and cash equivalents at beginning of period 34,653  20,674  22,472  22,468 
Cash and cash equivalents at end of period(a)
31,065  19,692  31,065  19,692 

(a)    Third quarter and nine months 2020 include $316 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.


19

Notes
Note 1. Basis of preparation

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 2019 included in BP Annual Report and Form 20-F 2019.
The directors consider it appropriate to adopt the going concern basis of accounting in preparing the interim financial information. The impact of COVID-19 and the current economic environment has been considered as part of the going concern assessment. Forecast liquidity has been assessed under a number of stressed scenarios and a reverse stress test performed to support this assertion.
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 IFRS. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented.
The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2020 which are the same as those used in preparing BP Annual Report and Form 20-F 2019 with the exception of the changes described in the 'Updates to significant accounting policies' section below. There are no other new or amended standards or interpretations adopted from 1 January 2020 onwards that have a significant impact on the interim financial information.
Considerations in respect of COVID 19 (coronavirus) and the current economic environment
BP's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 2019. These have been subsequently reviewed at the end of each quarter to determine if any changes were required to those judgements and estimates as a result of current market conditions. The valuation of certain assets and liabilities is subject to a greater level of uncertainty than when reported in BP Annual Report and Form 20-F 2019, including those set out below.
Impairment testing assumptions
BP now sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for energy for a sustained period. BP’s management also has a growing expectation that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of all the above, during the second quarter, BP revised its price assumptions for value-in-use impairment testing, lowering them and extending the period covered to 2050. The price assumption for the remainder of 2020 for Henry Hub gas was subsequently increased during the third quarter to reflect improving observed market prices. A summary of the group’s revised price assumptions, in real 2020 terms, is provided below:
4Q20 2021 2025 2030 2040 2050
Brent oil ($/bbl) 40  50  50  60  60  50 
Henry Hub gas ($/mmBtu) 2.75 3.00 3.00 3.00 3.00 2.75
As disclosed in BP Annual Report and Form 20-F 2019 - Note 1, the majority of BP’s reserves and resources that support the carrying amount of the group’s oil and gas properties are expected to be produced over the next ten years. The revised assumptions for Brent oil and Henry Hub gas for the next 10 years are lower by approximately 30% and 15% respectively than the average prices used to estimate cash flows over this period as disclosed in BP Annual Report and Form 20-F 2019 - Note 1. The revised impairment testing price assumptions are lower, on average, by approximately 27% and 31% respectively for the period from 2020 to 2050, than the prices referenced in BP Annual Report and Form 20-F 2019 - Note 1.
The group has identified oil and gas properties with carrying amounts totalling $40 billion where the headroom, based on the most recent impairment tests performed, was less than or equal to 20% of the carrying value. The significant majority of these assets have nil headroom. A change in price or other assumptions within the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a significant risk of impairment reversals or charges in that period.
The discount rates used in value-in-use impairment testing were also reviewed. As these are set using a number of parameters that are applicable to longer-term assets, a revision of the discount rate assumption was determined not to be appropriate and therefore the rates, as disclosed in BP Annual Report and Form 20-F 2019, remain unchanged.

20

Note 1. Basis of preparation (continued)
Provisions
The nominal risk-free discount rate applied to provisions is reviewed on a quarterly basis. Recent changes in long-dated US government bond yields have not affected the group's overall assessment of the discount rate applied to the group's provisions and therefore the rate, as disclosed in BP Annual Report and Form 20-F 2019, remains unchanged. The timing and amount of cash flows relating to the group's existing provisions are not currently expected to change significantly as a result of the current environment. The detailed annual review will take place later in 2020.
In addition, the group has recognized provisions for restructuring costs for plans that were formalized during the third quarter.
Pensions and other post-retirement benefits
The group's defined benefit pension plans are reviewed quarterly to determine any changes to the fair value of the plan assets or present value of the defined benefit obligations. As a result of the review during the third quarter of 2020, the group's total net defined benefit pension plan deficit as at 30 September 2020 is $1.9 billion, an increase in the deficit of $0.4 billion from 31 December 2019. The movement for the nine months principally reflects actuarial losses reported in other comprehensive income arising from decreasing discount rates and higher inflation assumptions increasing the plan obligations partially offset by increases in the valuation of plan assets. The current environment is likely to continue to affect the values of the plan assets and obligations resulting in potential volatility in the amount of the net defined benefit pension plan surplus/deficit recognized.
Impairment of financial assets measured at amortized cost
The estimate of the loss allowance recognized on financial assets measured at amortized cost using an expected credit loss approach was determined not to be a significant accounting estimate in preparing BP Annual Report and Form 20-F 2019. Expected credit loss allowances are, however, reviewed and updated quarterly. Allowances are recognized on assets where there is evidence that the asset is credit-impaired and on a forward-looking expected credit loss basis for assets that are not credit-impaired. The current economic environment and future credit risk outlook have been considered in updating the estimate of loss allowances although the full economic impact of COVID-19 on the forward-looking expected credit loss is subject to significant uncertainty due to the limited forward-looking information currently available.
Whilst credit risk has increased since 31 December 2019, there has also been a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 30 September 2020 have not significantly increased from the amounts disclosed in BP Annual Report and Form 20-F 2019 - Financial statements - Note 21 Valuation and qualifying accounts.
The group continues to believe that the calculation of expected credit loss allowances is not a significant accounting estimate. The group continues to apply its credit policy as disclosed in BP Annual Report and Form 20-F 2019 - Financial statements - Note 29 Financial instruments and financial risk factors - credit risk.
Income taxes
None of the group's deferred tax assets in BP Annual Report and Form 20-F 2019 were determined to be a significant accounting estimate. The carrying amounts are, however, reviewed and updated quarterly to the extent that there are changes in the probability of sufficient taxable profits being available to utilize the reported deferred tax assets. The group has recognized deferred tax assets as at 30 September 2020 of $6.8 billion, an increase of $2.3 billion from 31 December 2019. The group continues to believe that the measurement of its deferred tax assets is not a significant accounting estimate.
Other accounting judgements and estimates
All other significant accounting judgements and estimates disclosed in BP Annual Report and Form 20-F 2019 remain applicable and no new significant accounting judgements or estimates have been identified.
Updates to significant accounting policies
Hybrid bond issuance
On 17 June 2020, a group subsidiary issued perpetual subordinated hybrid bonds in EUR, GBP and USD for a US dollar equivalent amount of $11.9 billion. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests in the condensed consolidated financial statements. The contractual terms of these instruments allow the group to defer coupon payments and the repayment of principal indefinitely, however their terms and conditions stipulate that any deferred payments must be made in the event of an announcement of an ordinary share or parity equity dividend distribution or certain share repurchases or redemptions.
Change in accounting policy - Interest Rate Benchmark Reform: Amendments to IFRS 9 'Financial instruments'
Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. Uncertainty around the method and timing of transition from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to certain hedging relationships.
BP is significantly exposed to benchmark interest rate components e.g. USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. All of the group's existing fair value hedge relationships are directly affected by interest rate benchmark reform as they all manage interest rate risk. Further information about the group’s fair value hedges is included in BP Annual Report and Form 20-F 2019 - Financial statements - Note 30 Derivative financial instruments - Fair value hedges.
BP adopted the amendments to IFRS 9 and IFRS 7 ‘Financial Instruments: Disclosures’ relating to interest rate benchmark reform with effect from 1 January 2020. This first phase of amendments provides temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by interest rate benchmark reforms.

21

Note 1. Basis of preparation (continued)
The reliefs provided by the amendments allow BP, in the event that significant uncertainty around the reforms arise, to assume that:
the interest rate benchmark component of fair value hedges only needs to be assessed as separately identifiable at initial designation; and
the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the hedging instrument for fair value hedges.
In accordance with the transition provisions, the amendments have been adopted retrospectively to hedging relationships that existed at the start of the current reporting period and will be applied to new hedging relationships designated after that date.
The reliefs have meant that the uncertainty over the interest rate benchmark reforms has not resulted in discontinuation of hedge accounting for any of BP’s fair value hedges.
The second phase of IFRS amendments were issued by the IASB in August 2020 to address the financial reporting impacts of transitioning from IBORs to RfRs. These amendments will be effective for BP from 1 January 2021.The amendments are not yet endorsed by the EU or the UK. BP has set up an internal working group to monitor and manage the transition to alternative benchmark rates and are currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts. BP is also participating on external committees and task forces dedicated to interest rate benchmark reform.
Change in accounting policy - physically settled derivative contracts
In March 2019, the IFRS Interpretations Committee (“IFRIC”) issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item, such as commodities, that are not accounted for as 'own-use' contracts. IFRIC concluded that such contracts are settled by the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability.
BP regularly enters into forward sale and purchase contracts. As described in the group's accounting policy for revenue in BP Annual Report and Form 20-F 2019, revenue recognized at the time such contracts were physically settled was measured at the contractual transaction price and was presented together with revenue from contracts with customers in those financial statements.
BP changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020, as follows:
Revenues and purchases from such contracts are measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues.
There is no significant effect on current period or comparative information for ‘Sales and other operating revenues’ and ‘Purchases’ as presented in the group income statement, therefore no comparative information has been re-stated.
There is no significant effect on net assets or on comparative information for ‘Profit before taxation’ or ‘Profit after taxation’ as presented in the group income statement.
In addition, BP chose to change its presentation of revenues from physically settled derivative sales contracts from first quarter 2020. Revenues from physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. They are now presented as other revenues. Comparative information in Note 6 for revenue from contracts with customers and other revenues have been re-presented to align with the current period.



22

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 September 2020 is $4,541 million, with associated liabilities of $1,057 million. These principally relate to two transactions.
Downstream segment
On 29 June 2020 BP announced that it had agreed to sell its global petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary closing adjustments. Under the terms of the agreement, INEOS paid BP a deposit of $400 million and will pay a further $3.6 billion on completion. An additional $1 billion will be deferred and paid in three separate instalments of $100 million in March, April and May 2021 with the remaining $700 million payable by the end of June 2021. The business has interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. Subject to regulatory and other approvals, the transaction is expected to complete by the end of 2020. Assets of $3,963 million and associated liabilities of $745 million have been classified as held for sale in the group balance sheet at 30 September 2020. Accumulated foreign exchange differences will be reclassified from the foreign currency translation reserve to the income statement when the sale transaction completes. At 30 September 2020 these foreign exchange differences amounted to a gain of approximately $375 million.
Upstream segment
On 27 August 2019, BP announced that it had agreed to sell all of its Alaska operations and interests to Hilcorp Energy (‘Hilcorp’), including its ownership interests in BP Exploration (Alaska) Inc, which owned all of BP’s upstream oil and gas interests in Alaska, and the assets of BP Pipelines (Alaska) Inc., including a 49% interest in the Trans Alaska Pipeline System (TAPS), for up to $5.6 billion, subject to customary closing adjustments. Assets of $6,518 million and associated liabilities of $969 million relating to this transaction were classified as held for sale at 31 December 2019. Deposit payments totalling $500 million in cash were received in 2019.
On 30 June 2020, BP completed the sale of BP Exploration (Alaska) Inc. On completion, BP received $209 million in cash and recognized a loan note with a principal amount of $2,100 million receivable from Hilcorp. The group also recognized other assets totalling $1,689 million, including amounts in relation to the ‘earn-out’ provisions of the agreement.
The sale of BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS) and other midstream assets, which is subject to regulatory approvals, is expected to complete during the fourth quarter of 2020. On completion of the sale, BP will retain its decommissioning liability relating to TAPS, which will be partially offset by a 30% cost reimbursement from Harvest Alaska LLC, an affiliate of Hilcorp. Assets of $499 million and associated liabilities of $279 million relating to this transaction continue to be classified as held for sale at 30 September 2020.

Note 3. Impairment and losses on sale of businesses and fixed assets
Impairment and losses on sale of businesses and fixed assets for the third quarter and nine months were $294 million and $13,213 million and include net impairment charges of $277 million and $12,923 million respectively. Impairment charges also arose in certain equity-accounted entities in the nine months. The BP shares of these charges, amounting to $978 million for the nine months, are reported in the line items 'Earnings from joint ventures' and 'Earnings from associates' in the group income statement.
Upstream segment
Net Impairment charges in the Upstream segment were $272 million and $12,157 million for the third quarter and nine months respectively.
Impairment charges for the nine months mainly relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. They include amounts in Azerbaijan, BPX Energy, Canada, Egypt, India, Mauritania & Senegal, the North Sea, and Trinidad. The recoverable amounts of the cash generating units within these businesses were based on value-in-use calculations.
Impairment charges for the nine months also include amounts relating to the disposal of the group’s interests in its Alaska business. See Note 2 for further information.
The BP share of impairment charges arising in equity-accounted entities reported in the Upstream segment in the nine months was $742 million.
Downstream segment
Impairment charges in the Downstream segment were $736 million for the nine months, principally relating to anticipated portfolio changes in the fuels business. Materially all of the impairment charges arose in the second quarter.

Note 4. Exploration expense
Exploration expense in the third quarter and nine months was $190 million and $10,066 million and includes exploration expenditure write-offs of $50 million and $9,766 million respectively. All exploration expenditure is recorded within the Upstream segment.
The exploration write-offs principally arose following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's price assumptions. The exploration write-offs for the nine months principally arose in Angola, Brazil, Canada, Egypt, India and the Gulf of Mexico.

23

Note 5. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Upstream 30  (1,050) (20,955) 4,303 
Downstream 915  2,016  2,173  5,069 
Rosneft (278) 802  (419) 1,813 
Other businesses and corporate 24  (412) (991) (1,339)
691  1,356  (20,192) 9,846 
Consolidation adjustment – UPII* 34  30  166  51 
RC profit (loss) before interest and tax* 725  1,386  (20,026) 9,897 
Inventory holding gains (losses)*
Upstream 8  —  (3) (8)
Downstream 191  (433) (3,446) 706 
Rosneft (net of tax) 34  (79) (114) (41)
Profit (loss) before interest and tax 958  874  (23,589) 10,554 
Finance costs 800  883  2,366  2,603 
Net finance expense relating to pensions and other post-retirement benefits 8  16  23  46 
Profit (loss) before taxation 150  (25) (25,978) 7,905 
RC profit (loss) before interest and tax*
US 105  (2,425) (3,995) (1,156)
Non-US 620  3,811  (16,031) 11,053 
725  1,386  (20,026) 9,897 

24

Note 6. Sales and other operating revenues
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
By segment
Upstream 7,797  12,396  26,455  40,546 
Downstream 40,256  61,834  121,461  186,646 
Other businesses and corporate 391  461  1,294  1,250 
48,444  74,691  149,210  228,442 
Less: sales and other operating revenues between segments
Upstream 3,647  6,406  13,167  20,211 
Downstream 124  (59) (328) 589 
Other businesses and corporate 422  53  794  354 
4,193  6,400  13,633  21,154 
Third party sales and other operating revenues
Upstream 4,150  5,990  13,288  20,335 
Downstream 40,132  61,893  121,789  186,057 
Other businesses and corporate (31) 408  500  896 
Total sales and other operating revenues 44,251  68,291  135,577  207,288 
By geographical area
US 16,513  23,413  47,849  71,347 
Non-US 32,328  51,030  101,059  153,581 
48,841  74,443  148,908  224,928 
Less: sales and other operating revenues between areas 4,590  6,152  13,331  17,640 
44,251  68,291  135,577  207,288 
Revenues from contracts with customers(a)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil 1,366  2,194  3,863  7,261 
Oil products 16,301  26,547  47,007  76,462 
Natural gas, LNG and NGLs 2,844  4,387  9,474  14,038 
Non-oil products and other revenues from contracts with customers 2,965  2,970  7,573  9,291 
Revenue from contracts with customers 23,476  36,098  67,917  107,052 
Other operating revenues(b)
20,775  32,193  67,660  100,236 
Total sales and other operating revenues 44,251  68,291  135,577  207,288 
(a)    Amounts shown for revenue from contracts with customers and other operating revenues for third quarter and nine months 2019 have been represented to align with the current period. See Note 1 for further information.
(b)    Principally relates to physically settled derivative sales contracts.

Note 7. Depreciation, depletion and amortization
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Upstream
US 842  1,121  2,954  3,522 
Non-US 1,713  2,295  5,768  7,189 
2,555  3,416  8,722  10,711 
Downstream
US 336  336  1,022  992 
Non-US 407  394  1,220  1,169 
743  730  2,242  2,161 
Other businesses and corporate
US 13  14  44  41 
Non-US 156  137  455  433 
169  151  499  474 
Total group 3,467  4,297  11,463  13,346 

25

Note 8. Production and similar taxes
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
US 14  66  40  226 
Non-US 126  274  427  909 
140  340  467  1,135 

Note 9. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. No share buybacks were carried out during the quarter. A total of 120 million ordinary shares were repurchased for cancellation in the nine months, as part of the share buyback programme announced on 31 October 2017. The shares had a total cost of $776 million, including transaction costs of $4 million. The number of shares in issue is reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Results for the period
Profit (loss) for the period attributable to BP shareholders (450) (749) (21,663) 4,007 
Less: preference dividend   —  1 
Profit (loss) attributable to BP ordinary shareholders (450) (749) (21,664) 4,006 
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding 20,251,199  20,371,728  20,217,559  20,295,078 
ADS equivalent 3,375,199  3,395,288  3,369,593  3,382,513 
Weighted average number of shares outstanding used to calculate diluted earnings per share
20,251,199  20,371,728  20,217,559  20,411,739 
ADS equivalent 3,375,199  3,395,288  3,369,593  3,401,957 
Shares in issue at period-end 20,254,417  20,417,220  20,254,417  20,417,220 
ADS equivalent 3,375,736  3,402,870  3,375,736  3,402,870 
(a)Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the third quarter 2020 and nine months 2020 are 81,097 thousand (ADS equivalent 13,516 thousand) and 94,302 thousand (ADS equivalent 15,717 thousand) respectively.

Issued ordinary share capital as at 30 September 2020 comprised 20,266,630,701 ordinary shares (31 December 2019 20,372,762,750 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 1,149,151,649 ordinary shares which have been bought back and are held in treasury by BP (31 December 2019 1,163,077,064 ordinary shares).
26

Note 10. Dividends
Dividends payable
BP today announced an interim dividend of 5.25 cents per ordinary share which is expected to be paid on 18 December 2020 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 6 November 2020. The corresponding amount in sterling is due to be announced on 7 December 2020, calculated based on the average of the market exchange rates for the four dealing days commencing on 1 December 2020. Holders of ADSs are expected to receive $0.315 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2020 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
Third Third Nine Nine
quarter quarter months months
2020 2019 2020 2019
Dividends paid per ordinary share
cents 5.250  10.250  26.250  30.750 
pence 4.043  8.348  20.541  24.152 
Dividends paid per ADS (cents) 31.50  61.50  157.50  184.50 
Scrip dividends
Number of shares issued (millions)   72.5    208.9 
Value of shares issued ($ million)   440    1,387 

Note 11. Net debt
Net debt* Third Third Nine Nine
quarter quarter months months Year
$ million 2020 2019 2020 2019 2019
Finance debt(a)(b)
72,828  65,867  72,828  65,867  67,724 
Fair value (asset) liability of hedges related to finance debt(c)
(1,384) 319  (1,384) 319  190 
71,444  66,186  71,444  66,186  67,914 
Less: cash and cash equivalents(b)
31,065  19,692  31,065  19,692  22,472 
Net debt 40,379  46,494  40,379  46,494  45,442 
Total equity 82,155  100,015  82,155  100,015  100,708 
Gearing* 33.0% 31.7% 33.0  % 31.7  % 31.1  %
(a)The fair value of finance debt at 30 September 2020 was $75,338 million (31 December 2019 $69,376 million).
(b)Third quarter and nine months 2020 include $316 million of cash and $19 million of finance debt included in assets and liabilities held for sale in the group balance sheet.
(c)Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $372 million (third quarter 2019 liability of $682 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

In the third quarter, the group bought back $4.0 billion equivalent of euro and sterling bonds as part of actively managing its debt portfolio. Derivatives associated with the debt bought back were also terminated. There was no significant impact on net debt as a result of these transactions.
On 17 June 2020 the group issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion. See Note 1 for further information.


27

Note 12. Inventory valuation

A provision of $544 million was held against hydrocarbon inventories at 30 September 2020 ($290 million at 31 December 2019) to write them down to their net realizable value.

Note 13. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 26 October 2020, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2020.


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Additional information
Capital expenditure*
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Capital expenditure on a cash basis
Organic capital expenditure* 2,512  3,946  9,085  11,280 
Inorganic capital expenditure*(a)(b)
1,124  77  1,479  4,032 
3,636  4,023  10,564  15,312 
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Organic capital expenditure by segment
Upstream
US
589  1,036  2,775  2,990 
Non-US
1,367  2,110  4,546  5,856 
1,956  3,146  7,321  8,846 
Downstream
US
139  197  395  655 
Non-US
345  558  1,171  1,562 
484  755  1,566  2,217 
Other businesses and corporate
US
13  66  32 
Non-US
59  37  132  185 
72  45  198  217 
2,512  3,946  9,085  11,280 
Organic capital expenditure by geographical area
US
741  1,241  3,236  3,677 
Non-US
1,771  2,705  5,849  7,603 
2,512  3,946  9,085  11,280 
(a)On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for the nine months 2019 relating to this transaction.
(b)Third quarter and nine months 2020 include $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries. Nine months 2020 and 2019 also include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.



29

Non-operating items*
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Upstream
Gains on sale of businesses and fixed assets 10  —  104  105 
Impairment and losses on sale of businesses and fixed assets(a)
(274) (3,406) (12,358) (4,318)
Environmental and other provisions (9) —  (22) — 
Restructuring, integration and rationalization costs(b)
(164) (24) (192) (76)
Other(c)(d)
(194) (24) (2,688) 65 
(631) (3,454) (15,156) (4,224)
Downstream
Gains on sale of businesses and fixed assets 16  10  44 
Impairment and losses on sale of businesses and fixed assets(a)
(20) (11) (823) (100)
Environmental and other provisions   (1)   (1)
Restructuring, integration and rationalization costs(b)
(142) (4) (111) 14 
Other   —    (6)
(146) (14) (924) (49)
Rosneft
Other (101) —  (164) (194)
(101) —  (164) (194)
Other businesses and corporate
Gains on sale of businesses and fixed assets 1  —  3  (4)
Impairment and losses on sale of businesses and fixed assets   —  (21) — 
Environmental and other provisions (32) —  (55) (28)
Restructuring, integration and rationalization costs(b)
(156) —  (202)
Gulf of Mexico oil spill (63) (84) (115) (256)
Other(e)
138  (6) 125  (28)
(112) (90) (265) (309)
Total before interest and taxation (990) (3,558) (16,509) (4,776)
Finance costs(f)
(198) (145) (434) (389)
Total before taxation (1,188) (3,703) (16,943) (5,165)
Taxation credit (charge) on non-operating items (6) 772  3,752  1,121 
Taxation – impact of foreign exchange(g)
85  —  (166) — 
Total after taxation for period (1,109) (2,931) (13,357) (4,044)
(a)See Note 3 for further information.
(b)Third quarter 2020 includes recognized provisions for restructuring costs for plans that were formalized during the quarter.
(c)Nine months 2020 includes exploration write-offs of $1,969 million relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil, India and the Gulf of Mexico and the impairment of certain intangible assets in Mauritania and Senegal.
(d)Nine months 2020 includes $585 million and $742 million of impairments reported by equity-accounted entities.
(e)From first quarter 2020, BP is presenting temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt as non-operating items. These amounts represent: (i) the impact of ineffectiveness and the amortisation of cross currency basis resulting from the application of fair value hedge accounting; and (ii) the net impact of foreign currency exchange movements on finance debt and associated derivatives where hedge accounting is not applied. Relevant amounts in the comparative periods presented were not material.
(f)All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. Third quarter and nine months 2020 also include the income statement impact associated with the buyback of finance debt. See Note 11 for further information.
(g)From first quarter 2020, BP is presenting certain foreign exchange effects on tax as non-operating items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency. Relevant amounts in the comparative periods presented were not material.
30

Non-GAAP information on fair value accounting effects
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Favourable (adverse) impact relative to management’s measure of performance
Upstream (217) 265  (61) 47 
Downstream 425  147  135  137 
Other businesses and corporate 266  —  225  — 
474  412  299  184 
Taxation credit (charge) (95) (86) (66) (44)
379  326  233  140 

Fair value accounting effects reflect differences in the way that BP manages the economic exposure and measures performance relating to certain activities and the way these activities are measured under IFRS.  They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below.
BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
BP enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas, power and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within BP’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period.
In addition, from the second quarter 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the Other businesses and corporate segment in the table above, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.

31

Net debt including leases
Net debt including leases* Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Net debt 40,379  46,494  40,379  46,494 
Lease liabilities 9,282  9,639  9,282  9,639 
Net partner (receivable) payable for leases entered into on behalf of joint operations
(41) (197) (41) (197)
Net debt including leases 49,620  55,936  49,620  55,936 
Total equity 82,155  100,015  82,155  100,015 
Gearing including leases* 37.7% 35.9% 37.7% 35.9%


Readily marketable inventory* (RMI)
30 September 31 December
$ million 2020 2019
RMI at fair value* 4,506  6,837 
Paid-up RMI* 1,474  3,217 
Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP’s integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.
See the Glossary on page 35 for a more detailed definition of RMI. RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.
30 September 31 December
$ million 2020 2019
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS 13,840  20,880 
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST
(9,474) (14,280)
4,366  6,600 
Plus: difference between RMI at fair value and RMI on an IFRS basis 140  237 
RMI at fair value 4,506  6,837 
Less: unpaid RMI* at fair value (3,032) (3,620)
Paid-up RMI 1,474  3,217 

32

Gulf of Mexico oil spill
Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $180 million and $1,670 million in the third quarter and nine months of 2020 respectively. For the same periods in 2019, the amount was an outflow of $443 million and $2,569 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2020 and 2019 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis amounted to an outflow of $142 million and $1,520 million in the third quarter and nine months of 2020. For the same periods in 2019, the amount on a post-tax basis was an outflow of $409 million and $2,471 million respectively.
30 September 31 December
$ million 2020 2019
Trade and other payables (11,298) (12,480)
Provisions (23) (189)
Gulf of Mexico oil spill payables and provisions (11,321) (12,669)
Of which - current (1,427) (1,800)
Deferred tax asset 5,449  5,526 
The provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in BP Annual Report and Form 20-F 2019 - Financial statements - Notes 7, 9, 20, 22, 23, 29, 33 and pages 319 to 320 of Legal proceedings.
Reconciliation of basic earnings per ordinary share to replacement cost (RC) profit (loss) per share and to underlying replacement cost profit (loss) per share
Third Third Nine Nine
quarter quarter months months
Per ordinary share (cents) 2020 2019 2020 2019
Profit (loss) for the period (2.22) (3.68) (107.15) 19.74 
Inventory holding (gains) losses*, before tax (1.15) 2.51  17.62  (3.24)
Taxation charge (credit) on inventory holding gains and losses 0.19  (0.55) (4.10) 0.83 
Replacement cost (RC) profit (loss)* (3.18) (1.72) (93.63) 17.33 
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax
3.53  16.15  82.32  24.54 
Taxation charge (credit) on non-operating items and fair value accounting effects 0.07  (3.37) (17.41) (5.30)
Underlying RC profit (loss)* 0.42  11.06  (28.72) 36.57 

Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and underlying ETR
Taxation (charge) credit
Third Third Nine Nine
quarter quarter months months
$ million 2020 2019 2020 2019
Taxation on profit or loss (457) (706) 3,764  (3,733)
Taxation on inventory holding gains and losses (39) 114  829  (169)
Taxation on a replacement cost (RC) profit or loss basis (418) (820) 2,935  (3,564)
Taxation on non-operating items and fair value accounting effects (16) 686  3,520  1,077 
Taxation on underlying replacement cost profit or loss (402) (1,506) (585) (4,641)
Effective tax rate
Third Third Nine Nine
quarter quarter months months
% 2020 2019 2020 2019
ETR on profit or loss 305  (2,824) 14  47 
Adjusted for inventory holding gains or losses (809) 2,992  (1)
ETR on RC profit or loss* (504) 168  13  49 
Adjusted for non-operating items and fair value accounting effects 568  (128) (23) (11)
Underlying ETR* 64  40  (10) 38 

33

Realizations* and marker prices
Third Third Nine Nine
quarter quarter months months
2020 2019 2020 2019
Average realizations(a)
Liquids* ($/bbl)
US 31.74  50.46  33.24  52.80 
Europe 43.52  61.90  41.35  64.21 
Rest of World 41.46  59.14  36.13  61.91 
BP Average 38.17  55.68  35.51  58.38 
Natural gas ($/mcf)
US 1.29  1.72  1.19  2.02 
Europe 2.34  3.03  2.22  3.98 
Rest of World 2.99  3.82  3.21  4.21 
BP Average 2.56  3.11  2.65  3.49 
Total hydrocarbons* ($/boe)
US 22.04  31.23  23.01  33.81 
Europe 36.14  52.47  34.34  58.55 
Rest of World 27.40  36.82  26.19  39.69 
BP Average 26.42  35.48  25.68  38.55 
Average oil marker prices ($/bbl)
Brent 42.94  62.00  41.06  64.59 
West Texas Intermediate 40.91  56.40  38.12  57.08 
Western Canadian Select 31.62  43.61  27.54  45.30 
Alaska North Slope 42.75  62.98  41.32  65.23 
Mars 42.01  59.19  39.18  61.85 
Urals (NWE – cif) 42.83  60.82  40.83  63.71 
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)
1.98  2.23  1.88  2.67 
UK Gas – National Balancing Point (p/therm) 21.06  27.46  19.69  35.70 
(a)Based on sales of consolidated subsidiaries only this excludes equity-accounted entities.
(b)Henry Hub First of Month Index.
Exchange rates
Third Third Nine Nine
quarter quarter months months
2020 2019 2020 2019
$/£ average rate for the period 1.29  1.23  1.27  1.27 
$/£ period-end rate 1.28  1.23  1.28  1.23 
$/€ average rate for the period 1.17  1.11  1.12  1.12 
$/€ period-end rate 1.17  1.09  1.17  1.09 
Rouble/$ average rate for the period 73.74  64.64  71.00  65.06 
Rouble/$ period-end rate 77.57  64.32  77.57  64.32 

34

Legal proceedings
For a full discussion of the group’s material legal proceedings, see pages 319-320 of BP Annual Report and Form 20-F 2019.

Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions. Non-GAAP measures are sometimes referred to as alternative performance measures.
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 33.
Ethanol-equivalent production (which includes ethanol and sugar) is converted to thousands of barrels a day at 6.289 million litres = 1 thousand barrels divided by the total number of days in the period reported.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 31.
Finance debt ratio is defined as the ratio of finance debt to the total of finance debt plus total equity.
Gearing and net debt are non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 27.
We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Gearing including leases and net debt including leases 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 32.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 29.

35

Glossary (continued)
Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.
Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.
Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities.
Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 10, 12 and 14, and by segment and type is shown on page 30.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments is a non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill from net cash provided by operating activities as reported in the condensed group cash flow statement. BP believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities.
Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 29.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
Production-sharing agreement/contract (PSA/PSC) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 32.
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.

36

Glossary (continued)
Refining availability represents Solomon Associates’ operational availability for BP-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.
Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 3. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 33.
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.
Solomon availability – See Refining availability definition.
Technical service contract (TSC) – Technical service contract is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, the oil and gas company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a profit margin which reflects incremental production added to the oilfield.
Tier 1 and tier 2 process safety events – Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.
Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 33.
We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.
Underlying production – 2020 underlying production, when compared with 2019, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract.
Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 30 and 31 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3.

37

Glossary (continued)
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 33.
Upstream plant reliability (BP-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP’s share of equity-accounted entities.

38

Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: the expectations regarding the COVID-19 pandemic including its risks, impacts, consequences and challenges and BP’s response, including the impact on financial performance (including cash flows, net debt and gearing), operations, credit losses, trading environment, oil and gas prices, global GDP, the shape of the COVID-19 recovery and the pace of transition to a lower-carbon economy and energy system; plans and expectations regarding the divestment programme, including reaching $25 billion of proceeds by 2025 and expectations with respect to completion of transactions and the timing and amount of proceeds of agreed disposals (including the expected completion of the sales of the midstream portion of BP’s Alaskan business (including TAPS) to Hilcorp and BP’s petrochemicals business to INEOS); plans and expectations with respect to the total amount of organic capital expenditure and the DD&A charge in 2020; plans and expectations with respect to the total capital expenditure for 2021; plans and expectations regarding net debt, including to deliver the target of $35 billion; plans and expectations regarding new joint ventures and other agreements, including partnerships with Equinor, Police Scotland, Microsoft, Aberdeen City and Aral in Germany; plans and expectations regarding BP’s priorities, including to focus on maintaining capital discipline, driving costs down, delivering divestments and reducing debt while bringing new major projects onstream; plans to expand the India retail business; expectations regarding quarterly dividends; expectations regarding demand for BP’s products in the Upstream and Downstream; expectations regarding the Downstream refining margins and marketing volumes; expectations regarding BP’s future financial performance and cash flows; plans and expectations with respect to the implementation and impact of BP’s strategic reinvention and redesign of its organization, including for the organization to be in place by the start of 2021, the announced reduction of up to 10,000 jobs, and plans for BP to deliver $2.5 billion in cash cost savings from 2019 to end-2021, and the amount and timing of associated people-related costs; expectations regarding the underlying effective tax rate in the fourth quarter of 2020; plans and expectations with respect the Lightsource BP Bighorn Solar project and BP’s ambition to reach 20GW of developed assets by the end of 2025; plans and expectations regarding Upstream projects, including for five Upstream major projects to begin production in 2020 and the timing of the Trans Adriatic Gas pipeline project; expectations regarding Upstream fourth-quarter 2020 reported and underlying production and maintenance activity; expectations regarding the timing of implementation of new accounting policies; expectations regarding price assumptions used in accounting estimates; expectations regarding the Other businesses and corporate average quarterly charges; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill. 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 significant drop in the oil price, 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; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA and TSC effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, under “Principal risks and uncertainties” in our results announcement for the period ended 30 June 2020 and under “Risk factors” in BP Annual Report and Form 20-F 2019 as filed with the US Securities and Exchange Commission. 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 significant drop in the oil price, 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; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA and TSC effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, under “Principal risks and uncertainties” in our results announcement for the period ended 30 June 2020 and under “Risk factors” in BP Annual Report and Form 20-F 2019 as filed with the US Securities and Exchange Commission.





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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 September 2020 in
accordance with IFRS:
Capitalization and indebtedness
30 September
$ million 2020
Share capital and reserves
Capital shares (1-2) 5,374 
Paid-in surplus (3) 14,111 
Merger reserve (3) 27,206 
Treasury shares (13,319)
Cash flow hedge reserve (753)
Costs of hedging reserve (102)
Foreign currency translation reserve (9,897)
Issue of perpetual hybrid bonds (48)
Profit and loss account 45,383 
BP shareholders' equity 67,955 
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year 1,907 
Finance debt due within one year 11,013 
Lease liabilities due after more than one year 7,375 
Finance debt due after more than one year 61,796 
Total finance debt and lease liabilities 82,091 
Total (7)(8) 150,046 

1.Issued share capital as of 30 September 2020 comprised 20,266,630,701 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,149,151,649 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 September 2020.

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 2019 – Liquidity and capital resources for further information.

6.At 30 September 2020, the parent company, BP p.l.c. had issued guarantees totalling $68,154 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 September 2020 $565 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

7.At 30 September 2020 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,251 million in respect of the borrowings of equity-accounted entities and $560 million in respect of the borrowings of other third parties.

8.Total capitalization and indebtedness does not include non-controlling interests of $14.2 billion at 30 September 2020 which includes $11.9 billion related to perpetual hybrid bonds issued on 17 June 2020. See Note 1 to the consolidated financial statements for further information.

9.There has been no material change since 30 September 2020 in the consolidated capitalization and indebtedness of BP.
40

Signatures

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


BP p.l.c.
(Registrant)


Dated: 27 October 2020 /s/ BEN MATHEWS
Ben J. S. Mathews
Company Secretary
                                        

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