2Q20 Part 1 of 1

RNS Number : 0047V

BP PLC

04 August 2020

FOR IMMEDIATE RELEASE	Top of page 1
London 4 August 2020
BP p.l.c. Group results
Second quarter and half year 2020 _(a)

For a printer friendly copy of this announcement, please click on the link below to open a PDF version

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Highlights

Resetting for the future in face of difficult conditions

- Underlying replacement cost loss for the quarter was $6.7 billion, compared with a profit of $2.8 billion for the same period a year earlier. The result was driven primarily by non-cash Upstream exploration write-offs - $6.5 billion after tax - principally resulting from a review of BP's long-term strategic plans and revisions to long-term price assumptions, combined with the impact of lower oil and gas prices and very weak refining margins, reduced oil and gas production and much lower demand for fuels and lubricants. Oil trading delivered an exceptionally strong result.

- Reported loss for the quarter was $16.8 billion, compared with a profit of $1.8 billion for the same period a year earlier, including a net post-tax charge of $10.9 billion for non-operating items. This included $9.2 billion in post-tax non-cash impairments across the group largely arising from the revisions to its long-term price assumptions and $1.7 billion of post-tax non-cash exploration write-offs treated as non-operating items.

- Operating cash flow for the quarter, excluding Gulf of Mexico oil spill payments, was $4.8 billion, including a $1.5 billion working capital release (after adjusting for net inventory holding gains). Gulf of Mexico oil spill payments in the quarter of $1.1 billion on a post-tax basis included the scheduled annual payment.

- Proceeds from divestments and other disposals received in the quarter were $1.1 billion. This included the first payment from the agreed sale of BP's petrochemicals business to INEOS, which delivered BP's plans for $15 billion of announced transactions a year earlier than expected. The sale of the upstream portion of BP's Alaska business also completed at the end of the quarter.

- Organic capital expenditure in the first half of 2020 was $6.6 billion, on track to meet BP's revised full year expectation of around $12 billion, announced in April.

- BP's redesign of its organization to become leaner, faster moving and lower cost, including the announced reduction of around 10,000 jobs, is expected to make a significant contribution to the planned $2.5 billion reduction in annual cash costs by the end of 2021, relative to 2019. Restructuring costs of around $1.5 billion are expected to be recognized in 2020.

- During the quarter BP issued $11.9 billion in hybrid bonds - a significant step in diversifying its capital structure, supporting its investment grade credit rating, and strengthening its finances.

- Net debt at the end of the quarter was $40.9 billion, $10.5 billion lower than in the first quarter. Gearing at the end of the quarter was 33.1% compared with 36.2% at the end of the previous quarter. This reflected the increase in equity associated with the issuance of hybrid bonds and the lower net debt, partly offset by the reduction in equity associated with the second-quarter loss.

- A dividend of 5.25 cents per share was announced for the quarter, compared to 10.5 cents per share for the previous quarter. This dividend decision is aligned with BP's new distribution policy announced separately today.

Second quarter ($ billion)

Underlying RC profit (loss)

Profit (loss) for the period

Operating cash flow excluding Gulf of Mexico oil spill payments

See chart on PDF

Helge Lund - chairman :

Together with our results, we are today announcing BP's new strategy to deliver our net zero ambition, and a new investor proposition underpinned by a coherent financial frame. Our investor proposition includes a new distribution policy, which is designed to reward our investors with committed distributions, and which has informed the board's decision on the dividend declared today for the second quarter of 2020.

Financial summary	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Profit (loss) for the period attributable to BP shareholders	(16,848	)	(4,365	)	1,822		(21,213	)	4,756
Inventory holding (gains) losses, net of tax	(809	)	3,737		(47	)	2,928		(886	)
RC profit (loss)	(17,657	)	(628	)	1,775		(18,285	)	3,870
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	10,975		1,419		1,036		12,394		1,299
Underlying RC profit (loss)	(6,682	)	791		2,811		(5,891	)	5,169
RC profit (loss) per ordinary share (cents)	(87.32	)	(3.11	)	8.72		(90.52	)	19.10
RC profit (loss) per ADS (dollars)	(5.24	)	(0.19	)	0.52		(5.43	)	1.15
Underlying RC profit (loss) per ordinary share (cents)	(33.05	)	3.92		13.82		(29.17	)	25.51
Underlying RC profit (loss) per ADS (dollars)	(1.98	)	0.24		0.83		(1.75	)	1.53

(a) This results announcement also represents BP's half-yearly financial report (see page 12).

RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments, working capital, 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, underlying production, major project, Upstream plant reliability and refining availability are defined in the Glossary on page 35.

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Bernard Looney - chief executive officer :

"These headline results have been driven by another very challenging quarter, but also by the deliberate steps we have taken as we continue to reimagine energy and reinvent bp. In particular, our reset of long-term price assumptions and the related impairment and exploration write-off charges had a major impact. Beneath these, however, our performance remained resilient, with good cash flow and - most importantly - safe and reliable operations."

COVID-19 Update

Outlook:

- The ongoing severe impacts of the COVID-19 pandemic continue to create a volatile and challenging trading environment.

- Looking ahead, the outlook for commodity prices and product demand remains challenging and uncertain.

- Global GDP is expected to contract this year by 4-5%.

- Global oil demand is expected to be around 8-9 million barrels of oil per day lower than 2019, with OECD oil stocks above their five-year range, and gas markets are likely to remain materially oversupplied. There is also a risk of the pandemic having an enduring impact on the global economy, with the potential for weaker demand for energy for a sustained period.

- In July, refining margins remained under pressure, with RMM at $6.3/barrel due to lower product demand and high inventories, while BP refining utilization improved to above 80%. Retail fuel demand recovered in July to 10-15% lower than a year earlier, however, aviation fuel demand continued to be over 70% lower.

- The pandemic is not expected to result in Upstream oil and gas outages but has impacted development of the Mad Dog 2, Tangguh Expansion, Trinidad Cassia Compression and Greater Tortue Ahmeyin Phase 1 major projects.

- 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.

Strengthening finances:

- BP continues to take deliberate steps to strengthen its finances and drive down its cash balance point.

- These steps include issuing around $7 billion of bonds in April, issuing $12 billion in hybrid bonds in June, agreeing the $5 billion divestment of its petrochemicals business, and completing the sale of the upstream Alaska business. BP also reset its long-term price assumptions.

- BP will continue to review these actions, and any further actions that may be appropriate, in response to changes in prevailing market conditions.

- Organic capital expenditure was limited to $6.6 billion in the first half.

- Net debt fell to $40.9 billion at quarter-end. BP had around $47 billion of liquidity, including cash and undrawn revolving credit facilities, at quarter end.

- Costs that are directly attributable to COVID-19 were around $200 million for the quarter.

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 third quarter.

- In the second quarter, Upstream production was curtailed as a result of market demand and OPEC+ restrictions, and refinery utilization was more than 10% below normal levels due to COVID-19 demand impacts.

- Despite the significant challenges of the environment, BP's operations continued safely and reliably in the quarter. BP-operated Upstream plant reliability was 95.5% and BP-operated refining availability was strong at 95.6%.

- BP continues to take steps to protect and support its staff through the pandemic, including: reduced manning levels, changing working patterns, and deploying appropriate personal protective equipment (PPE), enhanced cleaning and social distancing measures at plants and retail sites. The great majority of BP staff who are able to work from home have done so since mid-March. Decisions on repopulating offices are 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.

Supporting communities:

- BP continues to offer support in response to the pandemic in communities in which it operates.

- Recent actions include: providing discounts to emergency service and health workers in the UK and US; donating PPE to health services; campaigning to promote the wearing of masks in Africa; and supporting staff in volunteering efforts, including matching employee donations to charities.

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

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Group headlines

Results

For the half year, underlying replacement cost (RC) loss* was $5,891 million, compared with a profit of $5,169 million in 2019. Underlying RC loss is after adjusting RC loss* for a net charge for non-operating items* of $12,248 million and net adverse fair value accounting effects* of $146 million (both on a post-tax basis).

RC loss was $18,285 million for the half year, compared with a profit of $3,870 million in 2019.

For the second quarter, underlying RC loss was $6,682 million, compared with a profit of $2,811 million in 2019. Underlying RC loss is after adjusting RC loss for a net charge for non-operating items of $10,857 million and net adverse fair value accounting effects of $118 million (both on a post-tax basis).

RC loss was $17,657 million for the second quarter, compared with a profit of $1,775 million in 2019.

Loss for the second quarter and half year attributable to BP shareholders was $16,848 million and $21,213 million respectively, compared with a profit of $1,822 million and $4,756 million for the same periods in 2019.

See further information on pages 4, 29 and 30.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $3.9 billion in the quarter and $8.0 billion in the half year, compared with $4.6 billion and $9.0 billion for the same periods in 2019. BP now expects the 2020 full-year charge to be around 10% lower than 2019.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the second quarter and half year was 19% and 15% respectively, compared with 39% and 41% for the same periods in 2019. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the second quarter and half year was 9% and -3% respectively, compared with 34% and 37% for the same periods a year ago. The lower underlying ETR for the second quarter and half year reflects the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition. The underlying ETR in the second half of the year remains sensitive to the volatility in the current environment. 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 25 September 2020. The corresponding amount in sterling will be announced on 14 September 2020. See page 26 for more information.

Share buybacks

BP repurchased 120 million ordinary shares at a cost of $776 million (including fees and stamp duty) in the first half year 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 excluding Gulf of Mexico oil spill payments* was $4.8 billion for the second quarter and $6.1 billion for the half year. These amounts include a working capital* release of $1.5 billion in the second quarter and a working capital build of $2.2 billion in the half year, after adjusting for net inventory holding gains or losses* and working capital effects of the Gulf of Mexico oil spill. The comparable amount for the same periods in 2019 was $8.2 billion and $14.2 billion.

Operating cash flow as reported in the group cash flow statement was $3.7 billion for the second quarter and $4.7 billion for the half year, including a working capital build of $0.6 billion and a working capital release of $0.1 billion respectively, compared with $6.8 billion and $12.1 billion for the same periods in 2019.

See page 32 and Glossary for further information on Gulf of Mexico oil spill cash flows and on working capital.

Capital expenditure*

Organic capital expenditure* for the second quarter and half year was $3.0 billion and $6.6 billion respectively, compared with $3.7 billion and $7.3 billion for the same periods in 2019.

Inorganic capital expenditure* for the second quarter and half year was $33 million and $0.4 billion respectively, compared with $2.0 billion and $4.0 billion for the same periods in 2019.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 28 for further information.

Divestment and other proceeds

Divestment and other proceeds were $1.1 billion for the second quarter, including the first tranche of petrochemicals disposal proceeds and TANAP pipeline refinancing, and $1.8 billion for the half year, compared with $0.1 billion and $0.7 billion for the same periods in 2019.

Net debt* and gearing*

Net debt at 30 June 2020 was $40.9 billion, compared with $46.5 billion a year ago. Gearing at 30 June 2020 was 33.1%, compared with 31.0% a year ago. Gearing including leases* at 30 June 2020 was 37.7%, compared with 35.3% a year ago. Net debt, gearing and gearing including leases are non-GAAP measures. See pages 27 and 31 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.

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Analysis of underlying RC profit (loss)* before interest and tax

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Underlying RC profit (loss) before interest and tax
Upstream	(8,487	)	1,871		3,413		(6,616	)	6,341
Downstream	1,405		921		1,365		2,326		3,098
Rosneft	(61	)	(17	)	638		(78	)	1,205
Other businesses and corporate	(260	)	(561	)	(290	)	(821	)	(708	)
Consolidation adjustment - UPII*	(46	)	178		34		132		21
Underlying RC profit (loss) before interest and tax	(7,449	)	2,392		5,160		(5,057	)	9,957
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(677	)	(668	)	(752	)	(1,345	)	(1,506	)
Taxation on an underlying RC basis	770		(953	)	(1,515	)	(183	)	(3,135	)
Non-controlling interests	674		20		(82	)	694		(147	)
Underlying RC profit (loss) attributable to BP shareholders	(6,682	)	791		2,811		(5,891	)	5,169

Reconciliations of underlying RC profit or loss attributable to BP shareholders to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-11 for the segments.

Analysis of RC profit (loss)* before interest and tax and reconciliation to profit (loss) for the period

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
RC profit (loss) before interest and tax
Upstream	(22,008	)	1,023		2,469		(20,985	)	5,353
Downstream	594		664		1,288		1,258		3,053
Rosneft	(124	)	(17	)	525		(141	)	1,011
Other businesses and corporate	(317	)	(698	)	(381	)	(1,015	)	(927	)
Consolidation adjustment - UPII	(46	)	178		34		132		21
RC profit (loss) before interest and tax	(21,901	)	1,150		3,935		(20,751	)	8,511
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(791	)	(790	)	(868	)	(1,581	)	(1,750	)
Taxation on a RC basis	4,361		(1,008	)	(1,210	)	3,353		(2,744	)
Non-controlling interests	674		20		(82	)	694		(147	)
RC profit (loss) attributable to BP shareholders	(17,657	)	(628	)	1,775		(18,285	)	3,870
Inventory holding gains (losses)*	1,088		(4,884	)	81		(3,796	)	1,169
Taxation (charge) credit on inventory holding gains and losses	(279	)	1,147		(34	)	868		(283	)
Profit (loss) for the period attributable to BP shareholders	(16,848	)	(4,365	)	1,822		(21,213	)	4,756

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Operational updates

Upstream

Upstream production, which excludes Rosneft, for the first half of the year averaged 2,552mboe/d, 3.3% lower than a year earlier. Underlying production*, was 1.0% higher than 2019 mainly due to ramp up of major projects*.

The sale of the upstream portion of BP's Alaska business completed on 30 June. Hilcorp Energy and BP continue to work with regulators and subject to approvals, expect to complete the sale of the midstream portion, including BP's interest in the Trans Alaska Pipeline, during 2020. BP and Premier Oil signed sale and purchase agreements, reflecting final agreed terms, for the divestment of the Andrew Area and Shearwater assets in the UK North Sea. Subject to approvals, the transaction is expected to complete by the end of the third quarter of 2020.

Upstream has delayed exploration and appraisal activities and curtailed development activities in lower margin areas, as well as rephasing or minimizing spend on projects in the early phases of development. These interventions are expected to reduce 2020 reported production by around 70mboe/d.

Downstream

The second quarter saw the weakest industry refining environment in over 15 years, and an unprecedented fall in product demand driven by COVID-19. While refining operations in the quarter were strong, with BP-operated refining availability of 95.6%, demand destruction resulted in lower utilization.

In June BP announced the sale of its petrochemicals business to INEOS for a total consideration of $5 billion. Subject to approvals, the transaction is expected to complete before the end of the year.

In July BP and Reliance Industries completed the formation of the new fuel and mobility joint venture that will operate across India under the Jio-bp brand.

Low carbon

BP entered into an agreement with China's ENN to work together to supply 300,000 tonnes a year of regasified LNG to ENN's customers in Guangdong province. BP also agreed with Enágas in Spain to jointly promote LNG and CNG for transport and the use of renewable gas.

In July BP announced plans to work with JinkoPower, a leading Chinese solar power company, to offer integrated decarbonized energy solutions and services to customers in China. It also announced plans to invest $70 million in India's Green Growth Equity Fund to support the growing renewable energy sector in India.

Petrofac and BP extended their partnership with a new metering contract for four years. BP has invested in Satelytics whose technology is expected to aid in the deployment of a suite of methane detecting techniques across new and existing major facilities.

Financial framework

Operating cash flow excluding Gulf of Mexico oil spill payments* was $6.1 billion for the half year of 2020, compared with $14.2 billion for the same period in 2019.

Organic capital expenditure * for the half year of 2020 was $6.6 billion. BP expects 2020 organic capital expenditure to be around $12 billion.

Divestment and other proceeds were $1.8 billion for the half year of 2020.

Gulf of Mexico oil spill payments on a post-tax basis were $1.4 billion in the half year of 2020. BP now expects the post-tax payments to be around $1.5 billion in 2020.

Gearing * at 30 June 2020 was 33.1%, in part reflecting the recent hybrid bond issue. See page 27 for more information.

Operating metrics	First half 2020	Financial metrics	First half 2020
Operating metrics	(vs. First half 2019)	Financial metrics	(vs. First half 2019)
Tier 1 and tier 2 process safety events	47	Underlying RC profit (loss)*	$(5.9)bn
Tier 1 and tier 2 process safety events	(-2)	Underlying RC profit (loss)*	(-$11.1bn)
Reported recordable injury frequency*	0.131	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	$6.1bn
Reported recordable injury frequency*	(-29.8%)		(-$8.1bn)
Group production	3,655mboe/d	Organic capital expenditure	$6.6bn
Group production	(-3.5%)	Organic capital expenditure	(-$0.8bn)
Upstream production (excludes Rosneft segment)	2,552mboe/d	Gulf of Mexico oil spill payments (post-tax)	$1.4bn
Upstream production (excludes Rosneft segment)	(-3.3%)	Gulf of Mexico oil spill payments (post-tax)	(-$0.7bn)
Upstream unit production costs* _(a)	$6.13/boe	Divestment proceeds*	$1.4bn
Upstream unit production costs* _(a)	(-12.6%)	Divestment proceeds*	(+$0.7bn)
BP-operated Upstream plant reliability*	94.2%	Gearing	33.1%
BP-operated Upstream plant reliability*	(-0.7)	Gearing	(+2.1)
BP-operated refining availability*	95.9%	Dividend per ordinary share _(b)	5.25 cents
BP-operated refining availability*	(+2.0)	Dividend per ordinary share _(b)	(-48.8%)

(a) Reflecting divestment impacts and lower costs.

(b) Represents dividend announced in the quarter (vs. prior year quarter).

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

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Upstream

	Second		First	Second	First		First
	quarter		quarter	quarter	half		half
$ million	2020		2020	2019	2020		2019
Profit (loss) before interest and tax	(21,951	)	955	2,459	(20,996	)	5,345
Inventory holding (gains) losses*	(57	)	68	10	11		8
RC profit (loss) before interest and tax	(22,008	)	1,023	2,469	(20,985	)	5,353
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	13,521		848	944	14,369		988
Underlying RC profit (loss) before interest and tax*_(a)	(8,487	)	1,871	3,413	(6,616	)	6,341

(a) See page 7 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost loss before interest and tax for the second quarter and half year was $22,008 million and $20,985 million respectively, compared with a profit of $2,469 million and $5,353 million for the same periods in 2019. The second quarter and half year included a net non-operating charge of $13,454 million and $14,525 million respectively, which principally relate to impairments associated with revisions to long-term price assumptions, compared with a net charge of $766 million and $770 million for the same periods in 2019. Fair value accounting effects in the second quarter and half year had an adverse impact of $67 million and a favourable impact of $156 million respectively, compared with an adverse impact of $178 million and $218 million in the same periods of 2019.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost loss before interest and tax for the second quarter and half year was $8,487 million and $6,616 million respectively, compared with a profit of $3,413 million and $6,341 million for the same periods in 2019. The results for the second quarter and half year mainly reflect the impact of writing down certain exploration intangible carrying values, and lower liquids and gas realizations.

Production

Production for the quarter was 2,525mboe/d, 3.8% lower than the second quarter of 2019. Underlying production* for the quarter increased by 0.6% mainly due to ramp up of major projects*.

For the half year, production was 2,552mboe/d, 3.3% lower than the first half of 2019. Underlying production for the half year was 1.0% higher than 2019 mainly due to ramp up of major projects.

Key events

On 30 June, BP completed the sale of its upstream Alaska business to Hilcorp. BP and Hilcorp continue to work with regulators to complete the sale of midstream assets, including BP's interest in the Trans Alaska Pipeline System (TAPS).

On 1 July, BP confirmed the Bashrush gas discovery, located offshore Egypt. Evaluation is ongoing (Eni operator 37.5%, BP 37.5%, Total 25%).

On 20 July, BP signed sale and purchase agreements, reflecting final agreed terms, for the divestment of its interests in the Andrew Area and Shearwater assets, both located in the UK North Sea, to Premier Oil. Subject to approvals, the transaction is expected to complete by the end of the third quarter of 2020.

These events follow the announcements in our first-quarter results, which comprised the following: BP executed a gas sale and purchase agreement with partners in the Greater Tortue Ahmeyim (GTA) project. GTA operations are severely affected by COVID-19 and the 2020 weather window for installation works can no longer be met resulting in a delay of around one year (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%); BP confirmed notification from the Brazilian National Petroleum Agency (ANP) of its approvals to postpone the deadline for declaring commerciality of the Wahoo (BP operator 35.7%, IBV Brasil Petróleo 35.7% Total 20%, Anadarko 8.6%) and Itaipu (BP operator 60%, Total 26.7%, Anadarko 13.3%) pre-salt discoveries offshore Brazil in the Campos basin, until June 2022; BP confirmed completion of the restructuring of contractual arrangements for the Petrojari Foinaven floating production, storage and offloading vessel on the Foinaven field to the west of the Shetlands (BP operator 72%, RockRose Energy 28%); BP relocated personnel from the remote Tangguh expansion project in Indonesia, as part of a COVID-19 response plan and anticipates a delay to start-up (BP operator 40.22%, MI Berau B.V. 16.30%, CNOOC Muturi Ltd. 13.90%, Nippon Oil Exploration (Berau) Ltd. 12.23%, KG Berau Petroleum Ltd 8.60%, Indonesia Natural Gas Resources Muturi Inc 7.35%, KG Wiriagar Overseas Ltd 1.40%).

Outlook

Looking ahead, we expect third-quarter 2020 reported production to be lower than the second quarter reflecting price impacts on TSC* entitlement volumes, divestment of the Alaska business, and seasonal maintenance activities.

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

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Upstream (continued)

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Underlying RC profit (loss) before interest and tax
US	(2,960	)	539		861		(2,421	)	1,473
Non-US	(5,527	)	1,332		2,552		(4,195	)	4,868
	(8,487	)	1,871		3,413		(6,616	)	6,341
Non-operating items _(a)(b)
US	(2,122	)	(632	)	(446	)	(2,754	)	(476	)
Non-US	(11,332	)	(439	)	(320	)	(11,771	)	(294	)
	(13,454	)	(1,071	)	(766	)	(14,525	)	(770	)
Fair value accounting effects
US	39		(2	)	(225	)	37		(318	)
Non-US	(106	)	225		47		119		100
	(67	)	223		(178	)	156		(218	)
RC profit (loss) before interest and tax
US	(5,043	)	(95	)	190		(5,138	)	679
Non-US	(16,965	)	1,118		2,279		(15,847	)	4,674
	(22,008	)	1,023		2,469		(20,985	)	5,353
Exploration expense
US	2,560		20		69		2,580		94
Non-US	7,114		182		77		7,296		419
	9,674		202		146		9,876		513
Of which: Exploration expenditure written off_(b)	9,618		98		77		9,716		361
Production (net of royalties)_(c)(d)
Liquids* (mb/d)
US	472		505		506		488		480
Europe	166		147		137		156		148
Rest of World	728		655		658		691		672
	1,366		1,306		1,301		1,336		1,300
Natural gas (mmcf/d)
US	1,549		2,050		2,410		1,799		2,360
Europe	298		244		132		271		139
Rest of World	4,878		5,093		5,138		4,985		5,276
	6,725		7,387		7,680		7,056		7,775
Total hydrocarbons* (mboe/d)
US	739		858		921		799		887
Europe	217		189		160		203		172
Rest of World	1,569		1,533		1,544		1,551		1,581
	2,525		2,579		2,625		2,552		2,640
Average realizations* _(e)
Total liquids_(f) ($/bbl)	22.75		47.47		62.63		34.39		59.61
Natural gas ($/mcf)	2.53		2.83		3.35		2.69		3.68
Total hydrocarbons ($/boe)	19.06		31.80		40.64		25.36		40.02

(a) Second quarter 2020 principally relates to impairments in a number of our businesses resulting from the revisions to BP's long-term price assumptions. First quarter 2020 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. Second quarter and first half 2019 include impairment charges related to the disposal of BPX Energy assets and GUPCO divestment. See Note 3 for further information.

(b) Second quarter 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.

(d) Because of rounding, some totals may not agree exactly with the sum of their component parts.

(e) Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

(f) Includes condensate, natural gas liquids and bitumen.

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Downstream

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Profit (loss) before interest and tax	1,572		(3,951	)	1,381		(2,379	)	4,192
Inventory holding (gains) losses*	(978	)	4,615		(93	)	3,637		(1,139	)
RC profit before interest and tax	594		664		1,288		1,258		3,053
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	811		257		77		1,068		45
Underlying RC profit before interest and tax*_(a)	1,405		921		1,365		2,326		3,098

(a) See page 9 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 second quarter and half year was $594 million and $1,258 million respectively, compared with $1,288 million and $3,053 million for the same periods in 2019.

The second quarter and half year include a net non-operating charge of $780 million and $778 million respectively, mainly relating to impairments, compared with a charge of $31 million and $35 million for the same periods in 2019. Fair value accounting effects in the second quarter and half year had an adverse impact of $31 million and $290 million respectively, compared with an adverse impact of $46 million and $10 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 second quarter and half year was $1,405 million and $2,326 million respectively, compared with $1,365 million and $3,098 million for the same periods in 2019.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 9.

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,295 million for the second quarter and $1,984 million for the half year, compared with $961 million and $2,253 million for the same periods in 2019. The result for the quarter was primarily driven by an exceptionally strong contribution from supply and trading.

The refining result for the quarter and half year reflects the weakest industry refining environment in over 15 years. In addition, utilization was more than 10% below normal levels at around 80%, driven by COVID-19 demand impacts. These factors were partially offset by lower turnaround activity and continued strong availability.

The fuels marketing result was significantly impacted by COVID-19 related fuels demand destruction with retail fuels volumes in the quarter around 30% lower than last year. In addition, aviation fuels volumes were more than 70% lower than the same period in 2019. Despite these demand impacts, store sales at our retail sites increased year on year on a like for like basis, demonstrating the strength and resilience of our convenience retail offer.

In July we announced the start of our new fuels and mobility joint venture in India, Reliance BP Mobility Limited. Operating under the "Jio-bp" brand, the joint venture aims to become a leading player in India's growing fuels and mobility markets, expanding from its current retail network of over 1,400 retail sites to up to 5,500 over the next five years.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $63 million for the second quarter and $230 million for the half year, compared with $321 million and $593 million for the same periods in 2019. The result for the quarter and half year reflects significant COVID-19 related demand destruction, with lubricants volumes in Europe, North America and India 40-50% lower in the quarter compared with the same period last year. In China, where we experienced significant impacts in the first quarter, we have seen strong volume recovery in the second quarter.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $47 million for the second quarter and $112 million for the half year, compared with $83 million and $252 million for the same periods in 2019. The result for the quarter and half year reflects a weaker margin environment and the impact of COVID-19, partly offset by lower turnaround activity.

In the quarter we announced the sale of BP's petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary adjustments. As a result, the net assets have been classified as held for sale in the group balance sheet at 30 June 2020. Subject to approvals, the transaction is expected to complete before the end of the year.

Outlook

Looking to the third quarter of 2020, we expect higher product demand, albeit still significantly below last year's levels. We also expect significant continued pressure on industry refining margins into the third quarter.

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

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Downstream (continued)

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Underlying RC profit before interest and tax - by region
US	719		557		566		1,276		1,097
Non-US	686		364		799		1,050		2,001
	1,405		921		1,365		2,326		3,098
Non-operating items
US	(69	)	6		2		(63	)	3
Non-US	(711	)	(4	)	(33	)	(715	)	(38	)
	(780	)	2		(31	)	(778	)	(35	)
Fair value accounting effects_(a)
US	(71	)	145		8		74		69
Non-US	40		(404	)	(54	)	(364	)	(79	)
	(31	)	(259	)	(46	)	(290	)	(10	)
RC profit before interest and tax
US	579		708		576		1,287		1,169
Non-US	15		(44	)	712		(29	)	1,884
	594		664		1,288		1,258		3,053
Underlying RC profit before interest and tax - by business _(b)(c)
Fuels	1,295		689		961		1,984		2,253
Lubricants	63		167		321		230		593
Petrochemicals	47		65		83		112		252
	1,405		921		1,365		2,326		3,098
Non-operating items and fair value accounting effects _(a)
Fuels	(748	)	(257	)	(99	)	(1,005	)	(62	)
Lubricants	(51	)	-		22		(51	)	18
Petrochemicals	(12	)	-		-		(12	)	(1	)
	(811	)	(257	)	(77	)	(1,068	)	(45	)
RC profit before interest and tax _(b)(c)
Fuels	547		432		862		979		2,191
Lubricants	12		167		343		179		611
Petrochemicals	35		65		83		100		251
	594		664		1,288		1,258		3,053

BP average refining marker margin (RMM)* ($/bbl)	5.9		8.8		15.2		7.4		12.7

Refinery throughputs (mb/d)
US	614		748		673		681		703
Europe	716		835		715		776		741
Rest of World	157		223		209		190		223
	1,487		1,806		1,597		1,647		1,667
BP-operated refining availability* (%)	95.6		96.1		93.4		95.9		93.9

Marketing sales of refined products (mb/d)
US	872		1,038		1,174		955		1,126
Europe	685		954		1,091		820		1,042
Rest of World	364		519		520		441		520
	1,921		2,511		2,785		2,216		2,688
Trading/supply sales of refined products	3,172		3,377		3,099		3,274		3,197
Total sales volumes of refined products	5,093		5,888		5,884		5,490		5,885

Petrochemicals production (kte)
US	410		611		584		1,021		1,185
Europe	1,246		1,371		1,226		2,617		2,386
Rest of World	1,271		1,153		1,156		2,424		2,455
	2,927		3,135		2,966		6,062		6,026

(a) For Downstream, fair value accounting effects arise solely in the fuels business. See page 30 for further information.

(b) Segment-level overhead expenses are included in the fuels business result.

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Rosneft

	Second		First		Second	First		First
	quarter		quarter		quarter	half		half
$ million	2020 _(a)		2020		2019	2020 _(a)		2019
Profit (loss) before interest and tax_(b)(c)	(71	)	(218	)	523	(289	)	1,049
Inventory holding (gains) losses*	(53	)	201		2	148		(38	)
RC profit (loss) before interest and tax	(124	)	(17	)	525	(141	)	1,011
Net charge (credit) for non-operating items*	63		-		113	63		194
Underlying RC profit (loss) before interest and tax*	(61	)	(17	)	638	(78	)	1,205

Financial results

Replacement cost (RC) loss before interest and tax for the second quarter and half year was $124 million and $141 million respectively, compared with a profit of $525 million and $1,011 million for the same periods in 2019.

After adjusting for non-operating items, the underlying RC loss before interest and tax for the second quarter and half year was $61 million and $78 million respectively, compared with a profit of $638 million and $1,205 million for the same periods in 2019.

Compared with the same periods in 2019, the result for the second quarter primarily reflects lower oil prices partially offset by favourable foreign exchange, whilst the result for the half year was primarily affected by lower oil prices.

Key events

BP's two nominees, Bob Dudley and Bernard Looney, were elected to Rosneft's board at Rosneft's annual general meeting (AGM) on 2 June 2020. At the AGM, shareholders also approved a resolution to pay a dividend of 18.07 roubles per ordinary share, which brings the total dividend for 2019 to 33.41 roubles per ordinary share, constituting 50% of the company's IFRS net profit. BP received a payment of $480 million, after the deduction of withholding tax, on 14 July.

On 30 April 2020, Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, Rosneft received shares equal to a 9.6% share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also has an approved programme of share buybacks under which shares are being repurchased. Those shares are also accounted for as treasury shares.

BP retains 19.75% of the voting rights at meetings of Rosneft shareholders and continues to be entitled to dividends based on that shareholding. BP's economic interest as of 30 June, however, has increased to 21.93% as a result of its indirect interest in the shares held by the subsidiaries of Rosneft. BP's share of profit or loss of Rosneft reflects its economic interest.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2020 _(a)	2020	2019	2020 _(a)	2019
Production (net of royalties) (BP share)
Liquids* (mb/d)	856	916	912	886	924
Natural gas (mmcf/d)	1,248	1,275	1,250	1,261	1,288
Total hydrocarbons* (mboe/d)	1,071	1,136	1,127	1,103	1,146

(a) The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the three months and six months ended 30 June 2020. Actual results may differ from these amounts. Amounts reported for the second quarter are based on BP's 21.2% average economic interest for the quarter and include adjustments to reflect the finalization of Rosneft's first quarter results. Amounts reported for the first quarter and all comparative periods are based on BP's 19.75% economic interest.

(b) The Rosneft segment result includes equity-accounted earnings arising from BP's economic interest in Rosneft for the second quarter 2020 as adjusted for accounting required under IFRS relating to BP's purchase of its interest in Rosneft, and the amortization of the deferred gain relating to the divestment of BP's interest in TNK-BP.

(c) BP's adjusted share of Rosneft's earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.

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Other businesses and corporate

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Profit (loss) before interest and tax	(317	)	(698	)	(381	)	(1,015	)	(927	)
Inventory holding (gains) losses*	-		-		-		-		-
RC profit (loss) before interest and tax	(317	)	(698	)	(381	)	(1,015	)	(927	)
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	57		137		91		194		219
Underlying RC profit (loss) before interest and tax*	(260	)	(561	)	(290	)	(821	)	(708	)
Underlying RC profit (loss) before interest and tax
US	(129	)	(124	)	(224	)	(253	)	(379	)
Non-US	(131	)	(437	)	(66	)	(568	)	(329	)
	(260	)	(561	)	(290	)	(821	)	(708	)
Non-operating items
US	(62	)	(48	)	(78	)	(110	)	(206	)
Non-US	46		(89	)	(13	)	(43	)	(13	)
	(16	)	(137	)	(91	)	(153	)	(219	)
Fair value accounting effects
US	-		-		-		-		-
Non-US	(41	)	-		-		(41	)	-
	(41	)	-		-		(41	)	-
RC profit (loss) before interest and tax
US	(191	)	(172	)	(302	)	(363	)	(585	)
Non-US	(126	)	(526	)	(79	)	(652	)	(342	)
	(317	)	(698	)	(381	)	(1,015	)	(927	)

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 loss before interest and tax for the second quarter and half year was $317 million and $1,015 million respectively, compared with $381 million and $927 million for the same periods in 2019.

The results included a net non-operating charge of $16 million for the second quarter and $153 million for the half year, compared with a charge of $91 million and $219 million for the same periods in 2019. Fair value accounting effects in the second quarter and half year had an adverse impact of $41 million. See page 30 for further information.

Alternative Energy

BP's net ethanol-equivalent production* for the first half of the year averaged 14.4kb/d, compared with 9.3kb/d for the 100% BP-owned business for the same period in 2019.

Net wind generation capacity* was 923MW at 30 June 2020, compared with 926MW at 30 June 2019. BP's net share of wind generation for the second quarter and half year was 673GWh and 1,450GWh respectively, compared with 688GWh and 1,461GWh for the same periods in 2019. In July, BP agreed to acquire the remaining 50% interest in the BP-operated Fowler Ridge 1 wind asset from its current partner, Dominion Energy. Located in central Indiana, the asset includes 162 wind turbines with a generating capacity of 300MW and will increase BP's net wind generation capacity to 1,073MW.

Lightsource BP has developed assets of 2.2GW to date and has an ambition to reach 10GW of developed assets by the end of 2023.

In April, Lightsource BP and Conway Corp signed a 20-year purchase power agreement for the development of a 132MW solar energy project in White County, Arkansas, US. In the same month Lightsource BP and the Southeastern Pennsylvania Transportation Authority (SEPTA) in the US signed a long-term power contract. The agreement will provide SEPTA with 67,029MWh of electricity from two solar power plants in Franklin county - about 20% of the transportation agency's annual electricity usage. Lightsource BP also acquired the Wellington North solar project in New South Wales, Australia in July. It will be sited adjacent to Lightsource BP's existing 200MW Wellington solar asset, which is currently in construction, creating a combined total capacity of 550MW.

This builds on the progress announced in our first-quarter results, which comprised the following: Lightsource BP signed a multi-year module supply agreement with Canadian Solar Inc. to deliver 1.2GW of high-efficiency polycrystalline solar modules for projects in the US and Australia; and Lightsource BP closed on a $250 million financing package for its Impact Solar project located in Lamar County, Texas, USA.

In early July BP signed a memorandum of understanding (MOU) with Chinese solar firm, JinkoPower Technologies, to provide integrated decarbonized energy solutions and services to customers in China.

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.

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This results announcement also represents BP's half-yearly financial report for the purposes of the Disclosure Guidance and Transparency Rules made by the UK Financial Conduct Authority. In this context: (i) the condensed set of financial statements can be found on pages 14-27; (ii) pages 1-11, and 28-39 comprise the interim management report; and (iii) the directors' responsibility statement and auditors' independent review report can be found on pages 12-13.

Statement of directors' responsibilities

The directors confirm that, to the best of their knowledge, the condensed set of financial statements on pages 14-27 has been prepared in accordance with IAS 34 'Interim Financial Reporting', and that the interim management report on pages 1-11 and 28-39 includes a fair review of the information required by the Disclosure Guidance and Transparency Rules.

The directors of BP p.l.c. are listed on pages 74-77 of BP Annual Report and Form 20-F 2019, with the following exceptions: Brian Gilvary retired on 30 June 2020 and Murray Auchincloss joined the board on 1 July 2020.

By order of the board

Bernard Looney	Murray Auchincloss
Chief Executive Officer	Chief Financial Officer
3 August 2020	3 August 2020

Top of page 13

Independent review report to BP p.l.c.

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2020 which comprises the group income statement, condensed group statement of comprehensive income, condensed group statement of changes in equity, group balance sheet, condensed group cash flow statement and related notes 1 to 13. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Directors' responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

As disclosed in Note 1, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting" as adopted by the European Union.

Our responsibility

Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2020 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Deloitte LLP

Statutory Auditor

London

United Kingdom

3 August 2020

The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the review work carried out by the statutory auditors does not involve consideration of these matters and, accordingly, the statutory auditors accept no responsibility for any changes that may have occurred to the financial information since it was initially presented on the website.

Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

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Financial statements

Group income statement

	Second		First		Second	First		First
	quarter		quarter		quarter	half		half
$ million	2020		2020		2019	2020		2019

Sales and other operating revenues (Note 6)	31,676		59,650		72,676	91,326		138,997
Earnings from joint ventures - after interest and tax	(567	)	(22	)	138	(589	)	323
Earnings from associates - after interest and tax	(100	)	(244	)	608	(344	)	1,257
Interest and other income	107		140		270	247		433
Gains on sale of businesses and fixed assets	74		16		55	90		144
Total revenues and other income	31,190		59,540		73,747	90,730		141,154
Purchases	18,778		48,878		55,683	67,656		103,955
Production and manufacturing expenses	5,211		6,099		5,391	11,310		10,747
Production and similar taxes (Note 8)	124		203		371	327		795
Depreciation, depletion and amortization (Note 7)	3,937		4,059		4,588	7,996		9,049
Impairment and losses on sale of businesses and fixed assets (Note 3)	11,770		1,149		906	12,919		1,002
Exploration expense (Note 4)	9,674		202		146	9,876		513
Distribution and administration expenses	2,509		2,684		2,646	5,193		5,413
Profit (loss) before interest and taxation	(20,813	)	(3,734	)	4,016	(24,547	)	9,680
Finance costs	783		783		853	1,566		1,720
Net finance expense relating to pensions and other post-retirement benefits	8		7		15	15		30
Profit (loss) before taxation	(21,604	)	(4,524	)	3,148	(26,128	)	7,930
Taxation	(4,082	)	(139	)	1,244	(4,221	)	3,027
Profit (loss) for the period	(17,522	)	(4,385	)	1,904	(21,907	)	4,903
Attributable to
BP shareholders	(16,848	)	(4,365	)	1,822	(21,213	)	4,756
Non-controlling interests	(674	)	(20	)	82	(694	)	147
	(17,522	)	(4,385	)	1,904	(21,907	)	4,903

Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	(83.32	)	(21.63	)	8.95	(105.02	)	23.47
Diluted	(83.32	)	(21.63	)	8.92	(105.02	)	23.35
Per ADS (dollars)
Basic	(5.00	)	(1.30	)	0.54	(6.30	)	1.41
Diluted	(5.00	)	(1.30	)	0.54	(6.30	)	1.40

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Condensed group statement of comprehensive income

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019

Profit (loss) for the period	(17,522	)	(4,385	)	1,904		(21,907	)	4,903
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences_(a)	1,371		(4,642	)	131		(3,271	)	1,120
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	3		1		-		4		-
Cash flow hedges and costs of hedging	68		85		133		153		152
Share of items relating to equity-accounted entities, net of tax	(333	)	442		(30	)	109		(80	)
Income tax relating to items that may be reclassified	(37	)	117		(9	)	80		(43	)
	1,072		(3,997	)	225		(2,925	)	1,149
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset_(b)	(1,960	)	1,719		(39	)	(241	)	(892	)
Cash flow hedges that will subsequently be transferred to the balance sheet	(2	)	(8	)	(7	)	(10	)	1
Income tax relating to items that will not be reclassified	623		(623	)	2		-		275
	(1,339	)	1,088		(44	)	(251	)	(616	)
Other comprehensive income	(267	)	(2,909	)	181		(3,176	)	533
Total comprehensive income	(17,789	)	(7,294	)	2,085		(25,083	)	5,436
Attributable to
BP shareholders	(17,142	)	(7,217	)	2,001		(24,359	)	5,282
Non-controlling interests	(647	)	(77	)	84		(724	)	154
	(17,789	)	(7,294	)	2,085		(25,083	)	5,436

(a) First and second quarter 2020 was principally affected by movements in the Russian rouble against the US dollar.

(b) See Note 1 for further information.

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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	(24,359	)	-	(724	)	(25,083	)
Dividends	(4,242	)	-	(105	)	(4,347	)
Cash flow hedges transferred to the balance sheet, net of tax	6		-	-		6
Repurchase of ordinary share capital	(776	)	-	-		(776	)
Share-based payments, net of tax	342		-	-		342
Share of equity-accounted entities' changes in equity, net of tax	-		-	-		-
Issue of perpetual hybrid bonds	(48	)	11,909	-		11,861
Transactions involving non-controlling interests, net of tax	(471	)	-	571		100
At 30 June 2020	68,864		11,909	2,038		82,811

	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	5,282		-	154		5,436
Dividends	(3,200	)	-	(119	)	(3,319	)
Cash flow hedges transferred to the balance sheet, net of tax	12		-	-		12
Repurchase of ordinary share capital	(125	)	-	-		(125	)
Share-based payments, net of tax	398		-	-		398
Share of equity-accounted entities' changes in equity, net of tax	3		-	-		3
At 30 June 2019	101,485		-	2,138		103,623

(a) See Note 1 in BP Annual Report and Form 20-F 2019 for further information.

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Group balance sheet

	30 June	31 December
$ million	2020	2019
Non-current assets
Property, plant and equipment	117,208	132,642
Goodwill	12,352	11,868
Intangible assets	5,987	15,539
Investments in joint ventures	8,015	9,991
Investments in associates	16,982	20,334
Other investments	2,559	1,276
Fixed assets	163,103	191,650
Loans	724	630
Trade and other receivables	4,270	2,147
Derivative financial instruments	7,381	6,314
Prepayments	495	781
Deferred tax assets	6,891	4,560
Defined benefit pension plan surpluses	6,346	7,053
	189,210	213,135
Current assets
Loans	370	339
Inventories	12,504	20,880
Trade and other receivables	16,522	24,442
Derivative financial instruments	4,751	4,153
Prepayments	679	857
Current tax receivable	637	1,282
Other investments	122	169
Cash and cash equivalents	34,217	22,472
	69,802	74,594
Assets classified as held for sale (Note 2)	4,169	7,465
	73,971	82,059
Total assets	263,181	295,194
Current liabilities
Trade and other payables	32,134	46,829
Derivative financial instruments	3,678	3,261
Accruals	3,670	5,066
Lease liabilities	1,958	2,067
Finance debt	11,452	10,487
Current tax payable	1,159	2,039
Provisions	2,074	2,453
	56,125	72,202
Liabilities directly associated with assets classified as held for sale (Note 2)	948	1,393
	57,073	73,595
Non-current liabilities
Other payables	11,777	12,626
Derivative financial instruments	5,652	5,537
Accruals	936	996
Lease liabilities	7,373	7,655
Finance debt	64,527	57,237
Deferred tax liabilities	6,585	9,750
Provisions	17,986	18,498
Defined benefit pension plan and other post-retirement benefit plan deficits	8,461	8,592
	123,297	120,891
Total liabilities	180,370	194,486
Net assets	82,811	100,708
Equity
BP shareholders' equity	68,864	98,412
Non-controlling interests	13,947	2,296
Total equity	82,811	100,708

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Condensed group cash flow statement

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Operating activities
Profit (loss) before taxation	(21,604	)	(4,524	)	3,148		(26,128	)	7,930
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	13,555		4,157		4,665		17,712		9,410
Impairment and (gain) loss on sale of businesses and fixed assets	11,696		1,133		851		12,829		858
Earnings from equity-accounted entities, less dividends received	860		505		(395	)	1,365		(984	)
Net charge for interest and other finance expense, less net interest paid	17		137		62		154		150
Share-based payments	351		(6	)	117		345		414
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(34	)	(20	)	(68	)	(54	)	(145	)
Net charge for provisions, less payments	(365	)	(59	)	(198	)	(424	)	(314	)
Movements in inventories and other current and non-current assets and liabilities	(609	)	683		(58	)	74		(2,753	)
Income taxes paid	(130	)	(1,054	)	(1,309	)	(1,184	)	(2,455	)
Net cash provided by operating activities	3,737		952		6,815		4,689		12,111
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,018	)	(3,789	)	(3,833	)	(6,807	)	(7,528	)
Acquisitions, net of cash acquired	-		(17	)	(1,747	)	(17	)	(3,542	)
Investment in joint ventures	(8	)	(18	)	(20	)	(26	)	(20	)
Investment in associates	(41	)	(37	)	(54	)	(78	)	(199	)
Total cash capital expenditure	(3,067	)	(3,861	)	(5,654	)	(6,928	)	(11,289	)
Proceeds from disposal of fixed assets	10		10		70		20		305
Proceeds from disposal of businesses, net of cash disposed	670		671		8		1,341		373
Proceeds from loan repayments	543		63		64		606		119
Net cash used in investing activities	(1,844	)	(3,117	)	(5,512	)	(4,961	)	(10,492	)
Financing activities
Net issue (repurchase) of shares (Note 9)	-		(776	)	(80	)	(776	)	(125	)
Lease liability payments	(664	)	(569	)	(595	)	(1,233	)	(1,212	)
Proceeds from long-term financing	6,846		2,684		4,381		9,530		6,505
Repayments of long-term financing	(964	)	(3,717	)	(3,602	)	(4,681	)	(6,242	)
Net increase (decrease) in short-term debt	(215	)	2,517		(119	)	2,302		970
Issue of perpetual hybrid bonds	11,861		-		-		11,861		-
Payments relating to transactions involving non-controlling interests (other)	(8	)	-		-		(8	)	-
Receipts relating to transactions involving non-controlling interests (other)	-		9		-		9		-
Dividends paid - BP shareholders	(2,119	)	(2,102	)	(1,779	)	(4,221	)	(3,214	)
- non-controlling interests	(74	)	(31	)	(83	)	(105	)	(119	)
Net cash provided by (used in) financing activities	14,663		(1,985	)	(1,877	)	12,678		(3,437	)
Currency translation differences relating to cash and cash equivalents	(42	)	(183	)	(8	)	(225	)	24
Increase (decrease) in cash and cash equivalents	16,514		(4,333	)	(582	)	12,181		(1,794	)
Cash and cash equivalents at beginning of period	18,139		22,472		21,256		22,472		22,468
Cash and cash equivalents at end of period_(a)	34,653		18,139		20,674		34,653		20,674

(a) Second quarter and first half 2020 includes $436 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.

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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

With the COVID-19 pandemic having continued during the second quarter of 2020, BP now sees the prospect of an enduring impact on the global economy, 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, BP has revised its price assumptions used in value-in-use impairment testing, lowering them and extending the period covered to 2050. A summary of the group's revised price assumptions, in real 2020 terms, is provided below:

	Second half 2020	2021	2025	2030	2040	2050
Brent oil ($/bbl)	40	50	50	60	60	50
Henry Hub gas ($/mmBtu)	2.00	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 16% 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 identified oil and gas properties with carrying amounts totalling $43 billion where the headroom, after the impairment tests performed in the second quarter, was less than or equal to 20% of the carrying value. A change in price or other assumptions within the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount.

Impairment charges for the second quarter of 2020 relate to the changes to price assumptions, the group's ongoing disposal programme and other factors. For further information see Note 3.

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.

Exploration and appraisal intangible assets

As a result of the revised price assumptions and a review of the long-term strategic plan, management reviewed BP's exploration prospects and the carrying value of the associated intangible assets. The outcome of the review has resulted in revised judgements over the expectations to extract value from certain prospects, thereby leading to write-offs of the associated exploration and appraisal intangible assets in the second quarter of 2020. For further information see Note 4.

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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 expects to recognize provisions for restructuring costs as plans are formalized from the second half of 2020.

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 second quarter of 2020, the group's total net defined benefit pension plan deficit as at 30 June 2020 is $2.1 billion, an increase in the deficit by $2.0 billion and $0.6 billion from 31 March 2020 and 31 December 2019 respectively. This 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 recognised 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 June 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 June 2020 of $6.9 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 USD 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.

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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 is expected to be issued by the IASB later in 2020 to address the financial reporting impacts of transitioning from IBORs to RfRs. BP has set up an internal working group to monitor and manage the transition to alternative benchmark rates and are currently assessing the population of contracts and arrangements that are linked to existing interest rate benchmarks, for example, 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 has 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, including the first quarter 2020, 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.

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 30 June 2020 is $4,169 million, with associated liabilities of $948 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 before the end of 2020. Assets of $3,647 million and associated liabilities of $637 million have been classified as held for sale in the group balance sheet at 30 June 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 June 2020 these foreign exchange differences amounted to a gain of approximately $300 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.

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Note 2. Non-current assets held for sale (continued)

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 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 June 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 second quarter and half year were $11,770 million and $12,919 million and include net impairment charges of $11,848 million ($8,540 million after tax) and $12,646 million ($9,111 million after tax) respectively. Impairment charges also arose in certain equity-accounted entities in the second quarter. The BP shares of these charges, amounting to $648 million for the second quarter ($635 million after tax), are reported in the line items 'Earnings from joint ventures' and 'Earnings from associates' in the group income statement.

Upstream segment

Impairment charges in the Upstream segment were $11,100 million and $11,885 million for the second quarter and half year respectively.

Impairment charges for the second quarter 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 second quarter and half year also include amounts relating to the disposal of the group's interests in its Alaska business. For the second quarter these principally relate to revisions to the fair value of the consideration recognized following changes to oil and gas price assumptions. For the first half they additionally relate to completion adjustments, changes to structure and phasing of consideration and discounting impacts. The recoverable amount of the Alaska business was based on its fair value less costs of disposal. See Note 2 for further information.

The BP share of impairment charges arising in equity-accounted entities reported in the Upstream segment in the second quarter was $585 million.

Downstream segment

Impairment charges in the Downstream segment were $729 million for the second quarter, principally relating to anticipated portfolio changes in the fuels business. There were no other significant impairment charges in the Downstream segment for the half year.

Note 4. Exploration expense

Exploration expense in the second quarter and half year was $9,674 million and $9,876 million and includes exploration expenditure write-offs of $9,618 million ($8,128 million after tax) and $9,716 million ($8,202 million after tax) 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 long-term price assumptions. The exploration write-offs for the second quarter principally arose in Angola, Brazil, Canada, Egypt, India and the Gulf of Mexico.

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Note 5. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Upstream	(22,008	)	1,023		2,469		(20,985	)	5,353
Downstream	594		664		1,288		1,258		3,053
Rosneft	(124	)	(17	)	525		(141	)	1,011
Other businesses and corporate	(317	)	(698	)	(381	)	(1,015	)	(927	)
	(21,855	)	972		3,901		(20,883	)	8,490
Consolidation adjustment - UPII*	(46	)	178		34		132		21
RC profit (loss) before interest and tax*	(21,901	)	1,150		3,935		(20,751	)	8,511
Inventory holding gains (losses)*
Upstream	57		(68	)	(10	)	(11	)	(8	)
Downstream	978		(4,615	)	93		(3,637	)	1,139
Rosneft (net of tax)	53		(201	)	(2	)	(148	)	38
Profit (loss) before interest and tax	(20,813	)	(3,734	)	4,016		(24,547	)	9,680
Finance costs	783		783		853		1,566		1,720
Net finance expense relating to pensions and other post-retirement benefits	8		7		15		15		30
Profit (loss) before taxation	(21,604	)	(4,524	)	3,148		(26,128	)	7,930

RC profit (loss) before interest and tax*
US	(4,695	)	595		498		(4,100	)	1,269
Non-US	(17,206	)	555		3,437		(16,651	)	7,242
	(21,901	)	1,150		3,935		(20,751	)	8,511

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Note 6. Sales and other operating revenues

	Second	First		Second	First		First
	quarter	quarter		quarter	half		half
$ million	2020	2020		2019	2020		2019
By segment
Upstream	7,194	11,464		13,556	18,658		28,150
Downstream	27,241	53,964		66,396	81,205		124,812
Other businesses and corporate	450	453		433	903		789
	34,885	65,881		80,385	100,766		153,751

Less: sales and other operating revenues between segments
Upstream	2,613	6,907		7,481	9,520		13,805
Downstream	330	(782	)	62	(452	)	648
Other businesses and corporate	266	106		166	372		301
	3,209	6,231		7,709	9,440		14,754

Third party sales and other operating revenues
Upstream	4,581	4,557		6,075	9,138		14,345
Downstream	26,911	54,746		66,334	81,657		124,164
Other businesses and corporate	184	347		267	531		488
Total sales and other operating revenues	31,676	59,650		72,676	91,326		138,997

By geographical area
US	10,117	21,219		26,086	31,336		47,934
Non-US	24,776	43,955		52,933	68,731		102,551
	34,893	65,174		79,019	100,067		150,485
Less: sales and other operating revenues between areas	3,217	5,524		6,343	8,741		11,488
	31,676	59,650		72,676	91,326		138,997

Revenues from contracts with customers_(a)
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	1,062	1,435		2,577	2,497		5,067
Oil products	10,452	20,254		27,211	30,706		49,915
Natural gas, LNG and NGLs	2,992	3,638		4,294	6,630		9,651
Non-oil products and other revenues from contracts with customers_(b)	2,118	2,490		3,258	4,608		6,321
Revenue from contracts with customers	16,624	27,817		37,340	44,441		70,954
Other operating revenues_(b)(c)	15,052	31,833		35,336	46,885		68,043
Total sales and other operating revenues	31,676	59,650		72,676	91,326		138,997

(a) Amounts shown for revenue from contracts with customers and other operating revenues for second quarter and first half 2019 have been represented to align with the current period. See Note 1 for further information.

(b) Comparative information for the first quarter 2020 for non-oil products and other revenues from contracts with customers and other operating revenues have been amended from those previously presented with no overall effect on total sales and other operating revenues. The previously disclosed amount for non-oil products and other revenues from contracts was $2,853 million. The previously disclosed amount for other operating revenues was $31,470 million.

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Note 7. Depreciation, depletion and amortization

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2020	2020	2019	2020	2019
Upstream
US	1,044	1,068	1,288	2,112	2,401
Non-US	1,973	2,082	2,396	4,055	4,894
	3,017	3,150	3,684	6,167	7,295
Downstream
US	344	342	333	686	656
Non-US	408	405	392	813	775
	752	747	725	1,499	1,431
Other businesses and corporate
US	16	15	14	31	27
Non-US	152	147	165	299	296
	168	162	179	330	323
Total group	3,937	4,059	4,588	7,996	9,049

Note 8. Production and similar taxes

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2020	2020	2019	2020	2019
US	13	13	79	26	160
Non-US	111	190	292	301	635
	124	203	371	327	795

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. This brings the total number of ordinary shares repurchased for cancellation in the year to 120 million for a total cost of $776 million, including transaction costs of $4 million, as part of the share buyback programme announced on 31 October 2017. The number of shares in issue is reduced when shares are repurchased.

The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.

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Note 9. Earnings per share and shares in issue (continued)

	Second		First		Second	First		First
	quarter		quarter		quarter	half		half
$ million	2020		2020		2019	2020		2019
Results for the period
Profit (loss) for the period attributable to BP shareholders	(16,848	)	(4,365	)	1,822	(21,213	)	4,756
Less: preference dividend	1		-		1	1		1
Profit (loss) attributable to BP ordinary shareholders	(16,849	)	(4,365	)	1,821	(21,214	)	4,755

Number of shares (thousand) _(a)(b)
Basic weighted average number of shares outstanding	20,222,575		20,178,803		20,336,347	20,200,694		20,256,254
ADS equivalent	3,370,429		3,363,133		3,389,391	3,366,782		3,376,042

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,222,575		20,178,803		20,421,184	20,200,694		20,368,125
ADS equivalent	3,370,429		3,363,133		3,403,530	3,366,782		3,394,687

Shares in issue at period-end	20,249,046		20,197,527		20,373,332	20,249,046		20,373,332
ADS equivalent	3,374,841		3,366,254		3,395,555	3,374,841		3,395,555

(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 first quarter 2020, second quarter 2020 and first half 2020 are 74,240 thousand (ADS equivalent 12,374 thousand), 63,119 thousand (ADS equivalent 10,520 thousand) and 85,469 thousand (ADS equivalent 14,245 thousand) respectively.

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 25 September 2020 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 14 August 2020. The corresponding amount in sterling is due to be announced on 14 September 2020, calculated based on the average of the market exchange rates for the four dealing days commencing on 8 September 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 second 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 second quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2020	2020	2019	2020	2019
Dividends paid per ordinary share
cents	10.500	10.500	10.250	21.000	20.500
pence	8.342	8.156	8.066	16.498	15.804
Dividends paid per ADS (cents)	63.00	63.00	61.50	126.00	123.00
Scrip dividends
Number of shares issued (millions)	-	-	46.3	-	136.4
Value of shares issued ($ million)	-	-	318	-	947

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Note 11. Net debt

Net debt*	Second		First	Second		First		First
	quarter		quarter	quarter		half		half
$ million	2020		2020	2019		2020		2019
Finance debt_(a)(b)	76,003		69,117	67,553		76,003		67,553
Fair value (asset) liability of hedges related to finance debt_(c)	(430	)	426	(378	)	(430	)	(378	)
	75,573		69,543	67,175		75,573		67,175
Less: cash and cash equivalents_(b)	34,653		18,139	20,674		34,653		20,674
Net debt	40,920		51,404	46,501		40,920		46,501
Total equity_(d)	82,811		90,480	103,623		82,811		103,623
Gearing*	33.1%		36.2%	31.0%		33.1%		31.0%

(a) The fair value of finance debt at 30 June 2020 was $77,990 million (30 June 2019 $68,857 million).

(b) Second quarter and first half 2020 includes $436 million of cash and $24 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 $554 million (first quarter 2020 liability of $663 million and second quarter 2019 liability of $563 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

(d) Total equity in the second quarter and first half 2020 includes $11.9 billion related to perpetual hybrid bonds issued on 17 June 2020. See Note 1 for further information.

Note 12. Inventory valuation

A provision of $289 million was held against hydrocarbon inventories at 30 June 2020 ($3,596 million at 31 March 2020 and $290 million at 31 December 2019) to write them down to their net realizable value.

Note 13. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 3 August 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. BP Annual Report and Form 20-F 2019 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

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Additional information

Capital expenditure*

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2020	2020	2019	2020	2019
Capital expenditure on a cash basis
Organic capital expenditure*	3,034	3,539	3,686	6,573	7,334
Inorganic capital expenditure*_(a)	33	322	1,968	355	3,955
	3,067	3,861	5,654	6,928	11,289

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2020	2020	2019	2020	2019
Organic capital expenditure by segment
Upstream
US	1,018	1,168	972	2,186	1,954
Non-US	1,517	1,662	1,858	3,179	3,746
	2,535	2,830	2,830	5,365	5,700
Downstream
US	135	121	271	256	458
Non-US	295	531	470	826	1,004
	430	652	741	1,082	1,462
Other businesses and corporate
US	21	32	15	53	24
Non-US	48	25	100	73	148
	69	57	115	126	172
	3,034	3,539	3,686	6,573	7,334
Organic capital expenditure by geographical area
US	1,174	1,321	1,258	2,495	2,436
Non-US	1,860	2,218	2,428	4,078	4,898
	3,034	3,539	3,686	6,573	7,334

(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 $1,748 million for the second quarter 2019 and $3,480 million for the first half 2019 relating to this transaction. First half 2020 and 2019 also include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

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Non-operating items*

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Upstream
Gains on sale of businesses and fixed assets	87		7		47		94		105
Impairment and losses on sale of businesses and fixed assets_(a)	(10,953	)	(1,131	)	(843	)	(12,084	)	(912	)
Environmental and other provisions	-		(13	)	-		(13	)	-
Restructuring, integration and rationalization costs	(24	)	(4	)	(17	)	(28	)	(52	)
Other_(b)(c)	(2,564	)	70		47		(2,494	)	89
	(13,454	)	(1,071	)	(766	)	(14,525	)	(770	)
Downstream
Gains on sale of businesses and fixed assets	(13	)	7		10		(6	)	42
Impairment and losses on sale of businesses and fixed assets_(a)	(798	)	(5	)	(61	)	(803	)	(89	)
Environmental and other provisions	-		-		-		-		-
Restructuring, integration and rationalization costs	31		-		20		31		18
Other	-		-		-		-		(6	)
	(780	)	2		(31	)	(778	)	(35	)
Rosneft
Other_(c)	(63	)	-		(113	)	(63	)	(194	)
	(63	)	-		(113	)	(63	)	(194	)
Other businesses and corporate
Gains on sale of businesses and fixed assets	-		2		(4	)	2		(4	)
Impairment and losses on sale of businesses and fixed assets	(19	)	(2	)	-		(21	)	-
Environmental and other provisions	-		(23	)	(22	)	(23	)	(28	)
Restructuring, integration and rationalization costs	(33	)	(13	)	(3	)	(46	)	7
Gulf of Mexico oil spill	(31	)	(21	)	(57	)	(52	)	(172	)
Other_(d)	67		(80	)	(5	)	(13	)	(22	)
	(16	)	(137	)	(91	)	(153	)	(219	)
Total before interest and taxation	(14,313	)	(1,206	)	(1,001	)	(15,519	)	(1,218	)
Finance costs_(e)	(114	)	(122	)	(116	)	(236	)	(244	)
Total before taxation	(14,427	)	(1,328	)	(1,117	)	(15,755	)	(1,462	)
Taxation credit (charge) on non-operating items	3,456		302		256		3,758		349
Taxation - impact of foreign exchange_(f)	114		(365	)	-		(251	)	-
Total after taxation for period	(10,857	)	(1,391	)	(861	)	(12,248	)	(1,113	)

(a) See Note 3 for further information.

(b) Second quarter and first half 2020 include the exploration write-off of $1,969 million ($1,670 million after tax) 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.

(c) Second quarter and first half 2020 include $585 million and $63 million of impairments reported by equity-accounted entities in the Upstream and Rosneft segments respectively.

(d) 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.

(e) Relates to the unwinding of discounting effects relating to Gulf of Mexico oil spill payables.

(f) From first quarter 2020, BP is presenting certain foreign exchange effects on tax as non-operating items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency. Relevant amounts in the comparative periods presented were not material.

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Non-GAAP information on fair value accounting effects

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Favourable (adverse) impact relative to management's measure of performance
Upstream	(67	)	223		(178	)	156		(218	)
Downstream	(31	)	(259	)	(46	)	(290	)	(10	)
Other businesses and corporate	(41	)	-		-		(41	)	-
	(139	)	(36	)	(224	)	(175	)	(228	)
Taxation credit (charge)	21		8		49		29		42
	(118	)	(28	)	(175	)	(146	)	(186	)

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 groups commodity, interest rate and currency risk exposures as detailed below.

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.

BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP's gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.

IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.

BP enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management's internal measure of performance. Under management's internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas, power and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management's estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.

Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within BP's risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period.

In addition, from the second quarter 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the Other businesses and corporate segment in the table above, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.

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Net debt including leases

Net debt including leases*	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Net debt	40,920		51,404		46,501		40,920		46,501
Lease liabilities	9,331		9,373		10,379		9,331		10,379
Net partner (receivable) payable for leases entered into on behalf of joint operations	(90	)	(159	)	(230	)	(90	)	(230	)
Net debt including leases	50,161		60,618		56,650		50,161		56,650
Total equity_(a)	82,811		90,480		103,623		82,811		103,623
Gearing including leases*	37.7%		40.1%		35.3%		37.7%		35.3%

(a) Total equity in the second quarter and first half 2020 includes $11.9 billion related to perpetual hybrid bonds issued on 17 June 2020. See Note 1 for further information.

Readily marketable inventory* (RMI)

	30 June	31 December
$ million	2020	2019
RMI at fair value*	4,111	6,837
Paid-up RMI*	1,971	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 June		31 December
$ million	2020		2019
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	12,504		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	(8,793	)	(14,280	)
	3,711		6,600
Plus: difference between RMI at fair value and RMI on an IFRS basis	400		237
RMI at fair value	4,111		6,837
Less: unpaid RMI* at fair value	(2,140	)	(3,620	)
Paid-up RMI	1,971		3,217

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Gulf of Mexico oil spill

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2020	2020	2019	2020	2019
Net cash provided by operating activities as per condensed group cash flow statement	3,737	952	6,815	4,689	12,111
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis	1,097	281	1,413	1,378	2,062
Operating cash flow, excluding Gulf of Mexico oil spill payments*	4,834	1,233	8,228	6,067	14,173

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $1,209 million and $1,490 million in the second quarter and first half of 2020 respectively. For the same periods in 2019, the amount was an outflow of $1,472 million and $2,126 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. Included in the current quarter are payments of $1,199 million on a pre-tax basis relating to the 2016 consent decree and settlement agreement.

	30 June		31 December
$ million	2020		2019
Trade and other payables	(11,294	)	(12,480	)
Provisions	(29	)	(189	)
Gulf of Mexico oil spill payables and provisions	(11,323	)	(12,669	)
Of which - current	(1,511	)	(1,800	)

Deferred tax asset	5,456		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.

Working capital* reconciliation

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2020		2020		2019		2020		2019
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement	(609	)	683		(58	)	74		(2,753	)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill	1,120		254		1,451		1,374		2,082
Adjusted for Inventory holding gains (losses)* (Note 5)
Upstream	57		(68	)	(10	)	(11	)	(8	)
Downstream	978		(4,615	)	93		(3,637	)	1,139
Working capital release (build)	1,546		(3,746	)	1,476		(2,200	)	460

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Realizations* and marker prices

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2020	2020	2019	2020	2019
Average realizations _(a)
Liquids* ($/bbl)
US	21.63	45.96	56.98	33.80	53.91
Europe	28.91	50.71	68.73	40.30	65.04
Rest of World	22.58	48.13	66.24	33.79	63.18
BP Average	22.75	47.47	62.63	34.39	59.61
Natural gas ($/mcf)
US	0.97	1.28	1.80	1.15	2.18
Europe	1.38	3.23	3.63	2.17	4.75
Rest of World	3.12	3.51	4.12	3.32	4.40
BP Average	2.53	2.83	3.35	2.69	3.68
Total hydrocarbons* ($/boe)
US	16.05	29.94	35.94	23.37	35.08
Europe	23.00	43.97	63.40	33.46	61.02
Rest of World	20.21	31.61	41.60	25.63	41.06
BP Average	19.06	31.80	40.64	25.36	40.02
Average oil marker prices ($/bbl)
Brent	29.56	50.10	68.86	40.07	65.95
West Texas Intermediate	27.96	45.56	59.90	36.69	57.42
Western Canadian Select	22.19	28.71	47.37	25.48	46.14
Alaska North Slope	30.28	51.07	68.29	40.59	66.37
Mars	30.02	45.57	65.20	37.73	63.20
Urals (NWE - cif)	31.36	47.84	67.62	39.80	65.23
Average natural gas marker prices
Henry Hub gas price_(b) ($/mmBtu)	1.71	1.95	2.64	1.83	2.90
UK Gas - National Balancing Point (p/therm)	12.88	24.81	31.53	18.98	40.01

(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.

(b) Henry Hub First of Month Index.

Exchange rates

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2020	2020	2019	2020	2019
$/£ average rate for the period	1.24	1.28	1.29	1.26	1.29
$/£ period-end rate	1.23	1.24	1.27	1.23	1.27

$/€ average rate for the period	1.10	1.10	1.12	1.10	1.13
$/€ period-end rate	1.12	1.10	1.14	1.12	1.14

Rouble/$ average rate for the period	72.40	66.75	64.58	69.64	65.29
Rouble/$ period-end rate	71.25	78.14	63.09	71.25	63.09

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Principal risks and uncertainties

The principal risks and uncertainties affecting BP are described in the Risk factors section of BP Annual Report and Form 20-F 2019 (pages 70-71) and are summarized below. There are no material changes in those principal risks and uncertainties for the remaining six months of the financial year. See page 2 for an update in relation to COVID-19.

The risks and uncertainties summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks

• Prices and markets - our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.

• Access, renewal and reserves progression - inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.

• Major project* delivery - failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.

• Geopolitical - exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.

• Liquidity, financial capacity and financial, including credit, exposure - failure to work within our financial framework could impact our ability to operate and result in financial loss.

• Joint arrangements and contractors - varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.

• Digital infrastructure and cyber security - breach or failure of our or third parties' digital infrastructure or cyber security, including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.

• Climate change and the transition to a lower carbon economy - policy, legal, regulatory, technology and market developments related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities.

• Competition - inability to remain efficient, maintain a high-quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.

• Crisis management and business continuity - failure to address an incident effectively could potentially disrupt our business.

• Insurance - our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks

• Process safety, personal safety, and environmental risks - exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.

• Drilling and production - challenging operational environments and other uncertainties could impact drilling and production activities.

• Security - hostile acts against our staff and activities could cause harm to people and disrupt our operations.

• Product quality - supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks

• Ethical misconduct and non-compliance - ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.

• Regulation - changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth opportunities.

• Treasury and trading activities - ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.

• Reporting - failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.

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.

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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.

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 30.

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 and total equity, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.

Gearing including leases and net debt including leases are non-GAAP measures. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. BP believes these measures provide useful information to investors as they enable investors to understand the impact of the group's lease portfolio on net debt and gearing. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt including leases is provided on page 31.

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 28.

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.

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Glossary (continued)

Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP's share of equity-accounted entities.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 7, 9 and 11, and by segment and type is shown on page 29.

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 28.

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 31.

Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.

Refining availability represents Solomon Associates' operational availability for BP-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.

The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP's crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP's particular refinery configurations and crude and product slate.

Top of page 37

Glossary (continued)

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP's management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 1. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within BP's operational HSSE reporting boundary. That boundary includes BP's own operated facilities and certain other locations or situations.

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.

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 29 and 30 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 1.

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.

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.

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Glossary (continued)

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.

Working capital - Change in working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement. Change in working capital adjusted for inventory holding gains/losses is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and this therefore represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities. In the context of describing operating cash flow excluding Gulf of Mexico oil spill payments, change in working capital also excludes movements in inventories and other current and non-current assets and liabilities relating to the Gulf of Mexico oil spill. See page 32 for further details.

BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.

Top of page 39

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 the trading environment, commodity prices, global GDP; plans and expectations regarding the divestment programme including 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 to Hilcorp, BP's petrochemicals business to INEOS and BP's Andrew Area and Shearwater assets to Premier Oil); expectations for the total amount of organic capital expenditure in 2020; plans and expectations regarding new joint ventures and other agreements, including partnerships with Reliance Industries, China's ENN, Enágas in Spain, JinkoPower, and Petrofac; plans to invest in India's Green Growth Equity Fund and Satelytics; expectations regarding quarterly dividends; expectations regarding demand for BP's products in the Upstream and Downstream; expectations regarding the Downstream refining margins; expectations regarding BP's future financial performance and cash flows; plans and expectations with respect to the implementation and impact of BP's redesign of its organization, including the announced reduction of around 10,000 jobs, and plans for BP to achieve $2.5 billion in cost savings by the end of 2021 relative to 2019, and the amount and timing of associated restructuring charges; expectations regarding the full-year charge for depreciation, depletion and amortization; expectations regarding the underlying effective tax rate in the second half of 2020; plans and expectations with respect the Lightsource BP project with SEPTA in the US and Lightsource BP's ambition to reach 10GW of developed assets by the end of 2023; expectations regarding the Rosneft results; plans and expectations regarding Upstream projects, including the timing of the Mad Dog 2, Tanguuh Expansion, Trinidad Cassia Compression and Greater Tortue Ahmeyin Phase 1 major projects; expectations regarding Upstream full year and third-quarter 2020 reported production, including the expectation that interventions will reduce 2020 reported production; 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; 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, and under "Risk factors" in BP Annual Report and Form 20-F 2019 as filed with the US Securities and Exchange Commission.

This announcement includes inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014. The person responsible for arranging the release of this announcement on behalf of BP p.l.c. is Ben Mathews, Company Secretary.

Contacts

	London	Houston

Press Office	David Nicholas	Brett Clanton
	+44 (0)20 7496 4708	+1 281 366 8346

Investor Relations	Craig Marshall	Brian Sullivan
bp.com/investors	+44 (0)20 7496 4962	+1 281 892 3421

BP p.l.c.'s LEI Code 213800LH1BZH3D16G760

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

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