Edgar Filing: BP PLC

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

for the period ended 30 June 2011

Commission File Number 1-06262

BP p.l.c.

(Translation of registrant’s name into English)

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-157906) OF BP CAPITAL MARKETS p.l.c. AND BP p.l.c.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-102583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

BP p.l.c. AND SUBSIDIARIES

FORM 6-K FOR THE PERIOD ENDED 30 JUNE 2011(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2011(b)		3 –13, 20 –22

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2011		14 – 19, 23 – 38

3.	Cautionary statement		13

4.	Principal risks and uncertainties		39 – 45

5.	Legal proceedings		46 – 49

6.	Signatures		50

7.	Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges		51

	Exhibit 99.2: Capitalization and Indebtedness		52

(a)	In this Form 6-K, references to the first half 2011 and first half 2010 refer to the six-month periods ended 30 June 2011 and 30 June 2010 respectively. References to second quarter 2011 and second quarter 2010 refer to the three-month periods ended 30 June 2011 and 30 June 2010 respectively.

(b)

This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2010.

Group results second quarter and half year 2011


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
	73,725		101,364		Sales and other operating revenues		186,693			146,796

	(17,150)		5,620		Profit (loss) for the period(a)		12,744			(11,071	)
	177		(311	)	Inventory holding (gains) losses, net of tax		(1,954	)		(304	)

	(16,973)		5,309		Replacement cost profit (loss)(b)		10,790			(11,375	)

	(91.29)		29.75		– Profit (loss) per ordinary share (cents)		67.60			(58.96	)
	(5.48)		1.79		– Profit (loss) per ADS (dollars)		4.06			(3.54	)
	(90.35)		28.10		– Replacement cost profit (loss) per ordinary share (cents)		57.23			(60.58	)
	(5.42)		1.69		– Replacement cost profit (loss) per ADS (dollars)		3.43			(3.63	)

•

BP’s profit for the second quarter was $5,620 million, compared with a loss of $17,150 million a year ago. For the half year, the profit was $12,744 million, compared with a loss of $11,071 million a year ago. BP’s second quarter replacement cost profit was $5,309 million, compared with a loss of $16,973 million a year ago. For the half year, replacement cost profit was $10,790 million, compared with a loss of $11,375 million a year ago. Replacement cost profit or loss for the group is a non-GAAP measure. For further information see pages 6 and 19.

•

The group income statement for the second quarter and half year includes pre-tax credits related to the Gulf of Mexico oil spill of $0.6 billion and $0.2 billion respectively. All amounts relating to the incident have been treated as non-operating items. For further information on the Gulf of Mexico oil spill and its consequences see pages 4 – 5, Note 2 on pages 23 – 28, Principal risks and uncertainties on pages 39 – 45 and Legal proceedings on pages 46 – 49.

•

Non-operating items (including amounts relating to the Gulf of Mexico oil spill) and fair value accounting effects for the second quarter, on a post-tax basis, had a net unfavourable impact of $298 million compared with a net unfavourable impact of $21,953 million in the second quarter of 2010. For the half year, the respective amounts were $191 million and $22,002 million unfavourable. Information on fair value accounting effects is non-GAAP and further details are provided on page 21.

•

Finance costs and net finance income or expense relating to pensions and other post-retirement benefits were $249 million for the second quarter, compared with $214 million for the same period last year. For the half year, the respective amounts were $488 million and $442 million.

•

The effective tax rate on the profit for the second quarter and half year was 35% and 36% respectively, compared with 30% and 27% on the loss for the equivalent periods in 2010. Excluding the impact of the Gulf of Mexico oil spill, the effective tax rate on the loss a year ago was 35% for the quarter and 34% for the half year. The effective tax rate on replacement cost profit for the second quarter and half year was 35% and 36% respectively, compared with 30% and 27% a year ago. Excluding the impact of the Gulf of Mexico oil spill, the effective tax rate on replacement cost loss a year ago was 35% for the quarter and 34% for the half year.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and half year was $7.8 billion and $10.3 billion, compared with $6.8 billion and $14.4 billion in the same periods of last year. The amounts for the quarter and half year of 2011 included net cash outflows of $1.9 billion and $4.7 billion respectively relating to the Gulf of Mexico oil spill.

•

Gross debt at the end of the quarter was $46.9 billion compared with $30.6 billion a year ago. The ratio of gross debt to gross debt plus equity was 30%, compared with 26% a year ago. Net debt at the end of the quarter was $27.0 billion, compared with $23.2 billion a year ago. The ratio of net debt to net debt plus equity was 20% compared with 21% a year ago. Net debt information is non-GAAP and is defined on page 7.

•

Total capital expenditure for the second quarter and half year was $8.2 billion and $12.2 billion respectively. Organic capital expenditure(c) in the second quarter and half year was $4.2 billion and $8.2 billion respectively. Disposal proceeds were $1.6 billion for the quarter and $2.6 billion for the half year. As at 30 June 2011, we had entered into agreements for disposals with a total value of $25 billion, against our objective of $30 billion by the end of 2011.

•

The quarterly dividend expected to be paid on 20 September 2011 is 7 cents per share ($0.42 per ADS). The corresponding amount in sterling will be announced on 6 September 2011. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the scrip dividend programme are available at www.bp.com/scrip.

(a)	Profit (loss) attributable to BP shareholders.

(b)

Replacement cost profit or loss reflects the replacement cost of supplies and is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS), as explained in more detail on page 19. The replacement cost profit or loss for the period is arrived at by excluding from profit or loss inventory holding gains and losses and their associated tax effect. Replacement cost profit or loss for the group is not a recognized GAAP measure. Management believes this information 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 principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil 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 information.

(c)	Organic capital expenditure excludes acquisitions and asset exchanges (see page 18).

The commentaries above and following should be read in conjunction with the cautionary statement on page 13.

Gulf of Mexico oil spill

Completing the response

The majority of the shoreline clean-up phase of the incident response was completed during the first quarter. During the second quarter, limited work continued to clean impacted marshes and barrier islands, and access to some areas was restricted due to wildlife breeding seasons. Patrolling is ongoing to respond to any further residual tar balls. Monitoring against established criteria continues, with the aim of assigning cleaned shorelines to a status in which no further treatment (NFT) is required. The majority of impacted shoreline has already been transitioned to NFT. Further shoreline surveys are scheduled for the fourth quarter of 2011, after the hurricane season, to identify any remaining clean-up needs.

The pilot project to retrieve remaining boom anchors from the coastal waters of Louisiana was completed and the Federal On-Scene Coordinator (FOSC) has confirmed that further action is not warranted.

Following the completion of the majority of the subsea work during the first quarter, decontamination of the Enterprise drilling rig and seabed survey work were completed during the second quarter. No further activity is planned at the well site.

The phased transition from the Gulf Coast incident management team (GC-IMT) to BP’s Gulf Coast Restoration Organization (GCRO) continues, and the response organization continues to maintain resources in line with operational requirements.

Economic restoration

A total of $6.8 billion has been paid out to fund economic and environmental restoration of the Gulf of Mexico. These payments are for claims from individuals, businesses and government entities. $0.3 billion of this is for natural resource damage assessment.

Trust update

During the first half, BP made two scheduled contributions totalling $2.5 billion to the Deepwater Horizon Oil Spill Trust fund. The Trust was established in 2010 to satisfy legitimate individual and business claims administered by the Gulf Coast Claims Facility (GCCF), state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages (NRD) and related costs. In early July, BP received a $1.1 billion settlement payment from MOEX which was also paid into the Trust.

Payments from the Trust during the second quarter and half year respectively totalled $1.0 billion and $2.1 billion, of which in the second quarter $873 million was paid through the GCCF to individual and business claimants, $87 million for NRD assessment costs, $17 million in relation to state and local government claims, and $33 million for other resolved items. As of 30 June 2011, the cumulative amount paid from the Trust since its inception was $5.1 billion and BP’s cumulative contributions to the Trust were $7.5 billion.

On 21 April 2011, BP announced a commitment of up to $1 billion for projects that will restore injured natural resources in the Gulf at the earliest opportunity. These projects will undergo public review before they are funded.

Claims update

As of 30 June 2011, a total of $6.3 billion had been paid for individual, business and government claims. This includes amounts paid directly by BP prior to the establishment of the Trust.

During the emergency advance phase in 2010, the GCCF paid 169,172(a) claimants amounts totalling $2.6 billion. In the first quarter of 2011, the GCCF issued its protocol for the resolution and finalization of claims allowing claimants submitting legitimate claims to elect to (i) receive interim payments for substantiated past losses, or (ii) receive an offer for full and final settlement payment and release, with certain exceptions, their right to sue all potentially liable entities including BP. During the second quarter, an additional 40,152 claimants filed claims at this second and final phase, taking the total number of claimants in this phase to 308,112 as of 30 June 2011. Of these, 150,672 claims have been paid and finalized for $1.7 billion, 88,873 have been denied by the GCCF, 8,776 have been determined to have no loss and 559 claims were withdrawn. The claims of the remaining 59,232 claimants have not yet been finalized and are at various stages of the GCCF’s claims review process. Claimants electing to receive interim payments have been paid $208 million. As of 30 June 2011, $5.0 billion had been paid either by the GCCF or by BP to individual and business claimants.

BP received 76 new claims from government entities during the second quarter, and has processed 88% of the total 965 claims filed. Government entities have received $1.3 billion in payments for 797 claims since the incident occurred. The remaining government claims are at various stages of the claims process.

Following the first-quarter agreement with the state of Alabama to provide $16 million for tourism promotion, BP completed similar agreements during the second quarter with the states of Florida and Mississippi for $30 million and $16 million respectively. Discussions are currently under way with the state of Mississippi regarding contributions for seafood testing and marketing.

(a)

Number of claimants updated from 169,005 as published in our first-quarter results announcement, reflecting a small number of payments made in the second quarter 2011 as a result of the resolution of outstanding claims from the emergency advance phase. At the end of the second quarter 2011, 273 emergency advance phase claims remained unresolved.

Gulf of Mexico oil spill (continued)

Environmental restoration

Last year, BP announced the creation of the independent Gulf of Mexico Research Initiative (GRI), a ten-year, $500-million scientific research programme directed at studying the potential environmental and public health impacts of the Deepwater Horizon accident. The master research agreement was signed in March 2011 and three Requests for Proposals (RFPs) from research consortia or individual researchers are planned for this year, two of which were issued during the second quarter.

Financial update

In the second quarter we recognized a $0.6 billion reduction in the pre-tax charge for the incident. This reflects the settlements with MOEX USA Corporation, the parent company of one of our partners in the MC252 exploration block, and Weatherford, a contractor on the Macondo well, partially offset by an incremental charge for spill response costs including provisioning for shoreline patrolling and maintenance costs, plus a charge for the ongoing quarterly expenses of the Gulf Coast Restoration Organization. For the half year, the reduction in the pre-tax charge was $0.2 billion. In 2010, the pre-tax charge recognized was $40.9 billion, which included the $20-billion Trust commitment.

Under the above settlement agreements, MOEX USA Corporation paid BP $1.1 billion in early July, which was subsequently paid to the Trust, and Weatherford have paid BP $75 million which will also be contributed to the $20-billion Trust.

The total amounts that will be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty as described further in Note 2 on pages 23 – 28. Also see Note 2, on page 28 under Contingent assets, for information on partner recovery.

Legal proceedings and investigations

See Gulf of Mexico oil spill on pages 34 – 39 of BP’s Annual Report and Form 20-F 2010 and Legal proceedings on pages 46 – 49 herein for details of legal proceedings, including external investigations relating to the incident.

Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) for the period


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
	6,244		6,614		Exploration and Production		15,034			14,536
	2,075		1,338		Refining and Marketing		3,417			2,804
	(70)		(598	)	Other businesses and corporate		(1,076	)		(398	)
	(32,192)		617		Gulf of Mexico oil spill response(a)		233			(32,192	)
	98		515		Consolidation adjustment		(27	)		306

	(23,845)		8,486		RC profit (loss) before interest and tax(b)		17,581			(14,944	)

	(214)		(249	)	Finance costs and net finance income or expense relating to pensions and other post-retirement benefits		(488	)		(442	)
	7,188		(2,858	)	Taxation on a replacement cost basis		(6,172	)		4,222
	(102)		(70	)	Minority interest		(131	)		(211	)

	(16,973)		5,309		Replacement cost profit (loss) attributable to BP shareholders		10,790			(11,375	)

	(284)		493		Inventory holding gains (losses)		2,905			421
	107		(182	)	Taxation (charge) credit on inventory holding gains and losses		(951	)		(117	)

	(17,150)		5,620		Profit (loss) for the period attributable to BP shareholders		12,744			(11,071	)

(a)	See Note 2 on pages 23 – 28 for further information on the accounting for the Gulf of Mexico oil spill response.

(b)	Replacement cost profit or loss reflects the replacement cost of supplies. Replacement cost profit for the group is a non-GAAP measure. For further information see page 19.

Total of non-operating items and fair value accounting effects(a)(b)


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
	(61)		(699	)	Exploration and Production		40			43
	351		(54	)	Refining and Marketing		(171	)		291
	71		(263	)	Other businesses and corporate		(444	)		(47	)
	(32,192)		617		Gulf of Mexico oil spill response		233			(32,192	)

	(31,831)		(399	)	Total before interest and taxation		(342	)		(31,905	)
	—		(15	)	Finance costs(c)		(31	)		—

	(31,831)		(414	)	Total before taxation		(373	)		(31,905	)
	9,878		116		Taxation credit (charge)(d)		182			9,903

	(21,953)		(298	)	Total after taxation for the period		(191	)		(22,002	)

(a)	An analysis of non-operating items by type is provided on page 20 and an analysis by region is shown on pages 9, 11 and 12.

(b)	Information on fair value accounting effects is non-GAAP. For further details, see page 21.

(c)	Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 23 – 28 for further details.

(d)

Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill and, for the first quarter 2011, the impact of a $683-million one-off deferred tax adjustment in respect of the recently enacted increase in the supplementary charge on UK oil and gas production) on group profit or loss. However, the US statutory tax rate has been used for expenditures relating to the Gulf of Mexico oil spill that qualify for tax relief.

Per share amounts

Second
quarter

Second

quarter

First half

2010

2011

2010

Per ordinary share (cents)(a)

(91.29)

29.75

Profit (loss) for the period

67.60

(58.96

)

(90.35)

28.10

RC profit (loss) for the period

57.23

(60.58

)

Per ADS (dollars)(a)

(5.48)

1.79

Profit (loss) for the period

4.06

(3.54

)

(5.42)

1.69

RC profit (loss) for the period

3.43

(3.63

)

(a)	See Note 6 on page 31 for details of the calculation of earnings per share.

Net debt ratio – net debt: net debt + equity

Second

quarter

Second

quarter

First half

2010

2011

2010

$ million

30,580

46,890

Gross debt

46,890

30,580

1,173

Less: fair value asset of hedges related to finance debt

1,173

30,527

45,717

30,527

7,310

18,749

Cash and cash equivalents

18,749

7,310

23,217

26,968

Net debt

26,968

23,217

86,362

108,408

Equity

108,408

86,362

21%

20%

Net debt ratio

20%

21%

See Note 7 on page 32 for further details on finance debt.

Net debt and net debt ratio are non-GAAP measures. Net debt includes the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. We believe that net debt and net debt ratio provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders.

Dividends

Dividends payable

BP today announced a dividend of 7 cents per ordinary share expected to be paid in September. The corresponding amount in sterling will be announced on 6 September 2011, calculated based on the average of the market exchange rates for the four dealing days commencing on 31 August 2011. Holders of American Depositary Shares (ADSs) will receive $0.42 per ADS. The dividend is due to be paid on 20 September 2011 to shareholders and ADS holders on the register on 5 August 2011. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the scrip dividend programme including the second-quarter dividend and timetable are available at www.bp.com/scrip.

Dividends paid

Second
quarter

Second

quarter

First half

2010

2011

2010

Dividends paid per ordinary share

—

7.000

cents

14.000

14.000

—

4.2809

pence

8.6181

8.679

—

42.00

Dividends paid per ADS (cents)

84.00

84.00

Scrip dividends

—

72.8

Number of shares issued (millions)

139.4

—

525

Value of shares issued ($ million)

1,035

—

Exploration and Production

Second
quarter

Second

quarter

First half

2010

2011

2010

$ million

15,215

18,418

Sales and other operating revenues

36,823

33,295

6,189

6,619

Profit before interest and tax

15,154

14,505

)

Inventory holding (gains) losses

(120

)

6,244

6,614

Replacement cost profit before interest and tax(a)

15,034

14,536

By region

1,798

731

2,606

4,560

4,446

5,883

Non-US

12,428

9,976

6,244

6,614

15,034

14,536

(a)	See page 19 for information on replacement cost reporting for operating segments.

Sales and other operating revenues for the second quarter and half year were $18 billion and $37 billion respectively, compared with $15 billion and $33 billion for the corresponding periods in 2010. The increases for both the quarter and half year were primarily due to higher realizations, partly offset by lower volumes. In addition, there were improved gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $6,614 million and $15,034 million respectively, increases of 6% and 3% compared with the same periods in 2010. The second quarter was impacted by net non-operating charges of $664 million, mainly comprising impairment and other related charges in North America, partially offset by gains on disposals and fair value gains on embedded derivatives. The half year included a net non-operating gain of $46 million, with disposal gains more than offsetting impairment and other non-operating charges. In the second quarter and half year, fair value accounting effects had unfavourable impacts of $35 million and $6 million respectively compared with unfavourable impacts of $122 million and $59 million in the same periods of last year.

The primary additional factors impacting replacement cost profit for both periods, compared with a year ago, were higher realizations partially offset by lower production volumes including the impact of divestments. In addition, there were higher earnings from equity-accounted entities (mainly TNK-BP) and an improved contribution from gas marketing and trading, partly offset by higher costs including rig standby costs in the Gulf of Mexico, higher turnaround and related maintenance expenditure, higher exploration write-offs, and certain other one-off charges. In the third quarter, we expect costs to continue to be impacted by rig standby costs, and by turnaround and related maintenance expenditure.

Production for the quarter was 3,433mboe/d, 11% lower than the second quarter of 2010. After adjusting for the effect of acquisitions and divestments and entitlement impacts in our production-sharing agreements (PSAs), the decrease was 7%. This primarily reflects lower Gulf of Mexico production, as a result of ongoing decline owing to the suspension of drilling activity and also the impact of turnaround and maintenance activity, and continuing maintenance and turnaround activity weighted towards other higher-margin areas, including the Greater Plutonio turnaround in Angola and the North Sea. This was partly offset by Iraq production.

For the first half of the year, production was 3,505mboe/d, also 11% lower than in the same period last year. After adjusting for the effect of acquisitions and divestments and PSA entitlement impacts, first-half production was 7% lower than in 2010.

Looking ahead, production in the third quarter is expected to reflect the continuation of the divestment programme, ongoing seasonal turnaround activity across the portfolio and the ongoing decline in the Gulf of Mexico. We continue to expect production in 2011 to be in line with our February guidance of around 3.4 million barrels of oil equivalent per day, with the exact outcome depending on the timing of acquisitions and divestments and PSA entitlement impacts.

We continue to make strategic progress. In May, we received final regulatory approval and completed the purchase of ten exploration and production blocks in Brazil from Devon Energy, announced in March last year.

BP agreed in May to sell its interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd for up to $610 million in cash.

Also in May, the Republic of Azerbaijan ratified the new PSA between BP and SOCAR on joint exploration and development of the Shafag-Asiman structure in the Azerbaijan sector of the Caspian Sea, which was originally signed in October 2010. Under the 30-year PSA, BP will be the operator with a 50% interest while SOCAR will hold the remaining 50% equity.

On 6 July, BP sold half of the 3.29% interest in the ACG development in the Caspian Sea, which had been acquired from Devon Energy last year, to Azerbaijan (ACG) Limited (an affiliate wholly owned and controlled by the State Oil Company of the Republic of Azerbaijan) for $585 million subject to completion adjustments.

On 22 July, the Indian Minister of Petroleum announced approval for BP’s alliance with Reliance Industries. While we await formal written approval, we understand the acquisition by BP of a 30% interest in 21 blocks, including the already producing KG-D6, have been unconditionally approved. Upon receipt of written approval, we can proceed with obtaining final regulatory approval of the Reserve Bank of India and then proceed to completion. The Sales and Purchase Agreement dated 21 February 2011 concerned 23 blocks and the Minister’s decision on the final two blocks will be taken in due course.

On 25 July, BP announced it had been awarded a 100% interest, under PSAs, in Trinidad and Tobago deepwater blocks 23(a) and TTDAA 14.

Exploration and Production


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Non-operating items
	(156)		(730	)	US		(726	)		(218	)
	217		66		Non-US		772			320

	61		(664	)			46			102

					Fair value accounting effects(a)
	(35)		(18	)	US		7			46
	(87)		(17	)	Non-US		(13	)		(105	)

	(122)		(35	)			(6	)		(59	)

					Exploration expense
	64		625		US(b)		933			133
	68		54		Non-US(c)		145			119

	132		679				1,078			252

					Production (net of royalties)(d)
					Liquids (mb/d)(e)
	581		465		US		494			623
	184		151		Europe		158			199
	859		860		Russia		858			854
	759		653		Rest of World		689			779

	2,383		2,129				2,199			2,455

	1,149		1,165		Of which equity-accounted entities		1,164			1,140

					Natural gas (mmcf/d)
	2,240		1,833		US		1,869			2,231
	551		391		Europe		382			575
	647		675		Russia		697			660
	5,046		4,664		Rest of World		4,626			5,076

	8,484		7,563				7,574			8,542

	1,080		1,101		Of which equity-accounted entities		1,114			1,086

					Total hydrocarbons (mboe/d)(f)
	968		781		US		816			1,007
	279		218		Europe		224			298
	971		976		Russia		978			968
	1,628		1,458		Rest of World		1,487			1,655

	3,846		3,433				3,505			3,928

	1,335		1,355		Of which equity-accounted entities		1,356			1,328

					Average realizations(g)
	72.90		106.99		Total liquids ($/bbl)		99.98			72.35
	3.76		4.54		Natural gas ($/mcf)		4.37			4.01
	47.08		63.23		Total hydrocarbons ($/boe)		61.05			48.16

(a)	These effects represent the favourable (unfavourable) impact relative to management’s measure of performance. Further information on fair value accounting effects is provided on page 21.

(b)	First half 2011 includes $93 million related to decommissioning of idle infrastructure, as required by BOEMRE’s Notice to Lessees No. 2010-GO5 issued in October 2010. Second quarter and first half 2011 include $395 million classified within the ‘other’ category of non-operating items.

(c)	First half 2011 includes $44 million classified within the ‘other’ category of non-operating items.

(d)	Includes BP’s share of production of equity-accounted entities.

(e)	Crude oil and natural gas liquids.

(f)	Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

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

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

Refining and Marketing

Second

quarter

Second

quarter

First half

2010

2011

2010

$ million

67,250

93,886

Sales and other operating revenues

171,319

131,536

1,850

1,820

Profit before interest and tax

6,187

3,258

225

(482

)

Inventory holding (gains) losses

(2,770

)

(454

)

2,075

1,338

Replacement cost profit before interest and tax(a)

3,417

2,804

By region

757

(17

)

623

694

1,318

1,355

Non-US

2,794

2,110

2,075

1,338

3,417

2,804

(a)	See page 19 for information on replacement cost reporting for operating segments.

Sales and other operating revenues for the second quarter and half year were $94 billion and $171 billion respectively, compared with $67 billion and $132 billion for the corresponding periods in 2010. The increases for both the quarter and half year primarily reflected higher prices, partly offset by lower volumes. Both periods also benefited from favourable foreign exchange effects.

The replacement cost profit before interest and tax for the second quarter and half year was $1,338 million and $3,417 million respectively, compared with $2,075 million and $2,804 million for the same periods last year.

The 2011 results included net non-operating charges of $218 million for the second quarter and $235 million for the half year, mainly comprising impairment charges, primarily associated with our US divestment programme, partly offset by gains on disposal. A year ago, there were net non-operating gains of $232 million and $162 million respectively. Fair value accounting effects had favourable impacts of $164 million for the second quarter and $64 million for the half year. The corresponding periods in 2010 reflected favourable impacts of $119 million and $129 million respectively.

Compared with a year ago, the second-quarter result reflected an improved refining environment, which was more than offset by the swing to a small loss in supply and trading, reduced economic utilization at the Texas City refinery following the recent weather-related power outage, higher turnaround activities, and certain one-off charges. In addition to the factors mentioned above, the first half benefited from a particularly strong first-quarter supply and trading contribution, which more than offset the weak contribution in the second quarter, strong refining feedstock optimization in the US due to BP’s location advantage in accessing WTI-priced crude grades and higher petrochemicals’ aromatics margins.

In the second quarter, refining throughputs in the fuels value chains reduced by over 170mb/d compared with the same period last year primarily due to operational issues following the recent power outage at the Texas City refinery. Solomon refining availability (as defined in footnote (b) on page 11) was 94.8% for the quarter.

In the international businesses, petrochemicals production volumes were down in the second quarter by approximately 8% compared with the same period last year, driven primarily by shutdowns following the power outage at the Texas City petrochemicals site, a tornado strike at the Decatur plant and turnaround activity at the Cooper River plant.

Looking ahead, we expect a typical seasonal decline in refining margins in the third quarter. Throughput at the Texas City refinery has been largely restored and we expect the last of the impacted units to return to full capacity during August. We expect petrochemicals production volumes to improve compared with the second quarter following the recent full recovery of operations at our Decatur, Texas City and Cooper River petrochemicals sites. The planned turnaround activity in the second half of 2011 is expected to be lower than in the first half.

Early last year we announced our exit from five countries in southern Africa. The sale of BP Zambia and BP Malawi to Puma Energy was completed in the second quarter of 2011, with completion of BP Tanzania, the last piece of this disposal, to follow.

Following a strategic review, we announced earlier this year our intent to divest the Texas City refinery and the southern part of our US West Coast fuels value chain, including the Carson refinery.

In the second quarter, we also executed agreements confirming the sale of 33 refined products terminals and 992 miles of pipelines as part of the ongoing divestment programme of a number of non-strategic pipelines and terminals in the US.

Refining and Marketing


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Non-operating items
	151		(239	)	US		(255	)		148
	81		21		Non-US		20			14

	232		(218	)			(235	)		162

					Fair value accounting effects(a)
	37		71		US		23			53
	82		93		Non-US		41			76

	119		164				64			129

					Refinery throughputs (mb/d)
	1,350		1,190		US		1,192			1,358
	770		749		Europe		758			775
	309		314		Rest of World		311			295

	2,429		2,253		Total throughput		2,261			2,428

	94.6		94.8		Refining availability (%)(b)		94.3			94.9

					Sales volumes (mb/d)(c)
					Marketing sales by region
	1,466		1,407		US		1,391			1,442
	1,312		1,298		Europe		1,283			1,369
	622		613		Rest of World		611			626

	3,400		3,318		Total marketing sales		3,285			3,437
	2,544		2,729		Trading/supply sales		2,494			2,583

	5,944		6,047		Total refined product sales		5,779			6,020

					Refining Marker Margin (RMM) ($/bbl)(d)
	15.02		15.75		US West Coast		15.96			12.44
	11.24		16.81		US Gulf Coast		13.83			10.78
	7.24		13.00		US Midwest		8.31			6.13
	11.21		11.69		North West Europe		11.38			10.51
	9.59		8.49		Mediterranean		8.79			8.93
	10.48		15.00		Singapore		14.85			10.54
	11.04		13.92		BP Average RMM		12.48			10.06

					Chemicals production (kte)
	1,088		766		US		1,901			2,028
	1,067		1,050		Europe(e)		2,035			2,130
	1,846		1,846		Rest of World		3,764			3,734

	4,001		3,662		Total production(e)		7,700			7,892

(a)	These effects represent the favourable (unfavourable) impact relative to management’s measure of performance. Further information on fair value accounting effects is provided on page 21.

(b)

Refining availability represents Solomon Associates’ operational availability, 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 maintenance downtime.

(c)	Does not include volumes relating to crude oil.

(d)

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 upon product yields and a marker crude oil deemed appropriate for the region. The regional marker 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.

(e)	A minor amendment has been made in the second quarter and first half 2010.

Other businesses and corporate


Second quarter 2010		Second quarter 2011				First half
Second quarter 2010		Second quarter 2011				2011			2010
					$ million
	794		985		Sales and other operating revenues		1,841			1,584

	(74)		(592	)	Profit (loss) before interest and tax		(1,061	)		(400	)
	4		(6	)	Inventory holding (gains) losses		(15	)		2

	(70)		(598	)	Replacement cost profit (loss) before interest and tax(a)		(1,076	)		(398	)

					By region
	(119)		(168	)	US		(356	)		(350	)
	49		(430	)	Non-US		(720	)		(48	)

	(70)		(598	)			(1,076	)		(398	)

					Results include Non-operating items
	(7)		(12	)	US		(11	)		(113	)
	78		(251	)	Non-US		(433	)		66

	71		(263	)			(444	)		(47	)

(a)	See page 19 for information on replacement cost reporting for operating segments.

Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium business, Treasury (which includes interest income on the group’s cash and cash equivalents), and corporate activities worldwide.

The replacement cost loss before interest and tax for the second quarter and half year was $598 million and $1,076 million respectively, compared with losses of $70 million and $398 million a year ago. The net non-operating charge for the second quarter was $263 million, compared with a net gain of $71 million a year ago. For the half year the net non-operating charge was $444 million, compared with a net charge of $47 million a year ago.

In addition, compared with the same periods a year ago, the results for the second quarter and first half primarily reflected higher corporate expenditure as a result of the Gulf of Mexico oil spill and lower income following business restructuring.

In Alternative Energy, BP completed the installation of the 250MW Cedar Creek 2 wind farm in Weld County, Colorado, a 50:50 joint venture with Sempra Generation. Construction commenced at the 150MW Sherbino 2 wind farm in Pecos County, Texas, and at the Trinity Hills wind farm in Archer and Young Counties, Texas. Both wind farms are 100% owned by BP. BP’s net wind generation capacity(b) at the end of the second quarter was 774MW (1,362MW gross), compared with 711MW (1,237MW gross) at the end of the same period a year ago.

In our biofuels business, on 27 April BP completed the purchase of 83% of the shares of Companhia Nacional de Açúcar e Álcool (CNAA), a Brazilian ethanol and sugar producer, for $680 million.

In our solar business, a $261 million non-operating charge has been recognized with respect to raw materials purchase contracts and we intend to exit the module-only sales business.

(b)

Net wind 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. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership. Capacity figures include 32MW in the Netherlands managed by our Refining and Marketing segment.

Cautionary statement

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains forward-looking statements particularly those regarding the quarterly dividend payment; the timing of surveys of shoreline impacted by the Gulf of Mexico oil spill; the segregation of an additional $500 million of the Trust balance to cover costs associated with projects that will restore injured natural resources in the Gulf; the issuance of further Requests for Proposals pursuant to the Gulf of Mexico Research Initiative and the master research agreement thereunder; expectations regarding the impacts on costs of rig standby costs and of turnaround and related maintenance expenditures; the expected impact on third-quarter production of the divestment programme, ongoing seasonal turnaround activity across BP’s portfolio, and the ongoing decline of production in the Gulf of Mexico; expected full-year 2011 production, and the impact of acquisitions and divestments and PSA entitlement on full-year 2011 production; the magnitude and timing of remaining remediation costs related to the Gulf of Mexico oil spill; the factors that could affect the magnitude of BP’s ultimate exposure and the cost to BP in relation to the spill and any potential mitigation resulting from BP’s partners or others involved in the spill; the potential liabilities resulting from pending and future legal proceedings and potential investigations and civil or criminal actions that US state and/or local governments could seek to take against BP as a result of the spill; the timing of claims and litigation outcomes and of payment of legal costs; the anticipated timing for completion of the disposition of certain BP assets; contributions to and payments from the trust fund and the setting aside of assets while the fund is building; expectations for third-quarter refining margins; expectations for operations at the Texas City refinery; expected improvements in petrochemicals production volumes following the recent full recovery of operations at BP’s Decatur, Texas City and Cooper River petrochemicals sites; lower anticipated planned turnaround activity in the second half of 2011; the sale of BP Tanzania; the intentions of BP’s solar business to exit its module-only sales business; the anticipated timing of the completion of the disposition of ARCO Aluminum Inc.; exploration activity in four deepwater offshore blocks off of Australia; the timing for publication of investigation reports; the impact of BP’s potential liabilities relating to the Gulf of Mexico oil spill on the group, including its business, results and financial condition; the anticipated commencement of the trial regarding allegations pertaining to the Atlantis platform; and BP’s intentions to strongly defend itself against any claim for breach of the TNK-BP shareholders agreement that may be brought by Alfa, Access and Renova. 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. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; general economic conditions; 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; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed under “Risk factors” in our Annual Report and Form 20-F 2010 as filed with the US Securities and Exchange Commission (SEC).

Group income statement


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
	73,725		101,364		Sales and other operating revenues (Note 4)		186,693			146,796
	257		303		Earnings from jointly controlled entities – after interest and tax		565			660
	760		1,255		Earnings from associates – after interest and tax		2,664			1,523
	158		151		Interest and other income		275			300
	971		775		Gains on sale of businesses and fixed assets		1,963			1,009

	75,871		103,848		Total revenues and other income		192,160			150,288
	54,536		78,281		Purchases		140,002			106,177
	37,979		6,200		Production and manufacturing expenses(a)		12,708			43,719
	1,238		2,356		Production and similar taxes (Note 5)		4,187			2,514
	2,780		2,671		Depreciation, depletion and amortization		5,506			5,776
	(56)		1,383		Impairment and losses on sale of businesses and fixed assets		1,442			108
	132		679		Exploration expense		1,078			252
	2,939		3,448		Distribution and administration expenses		6,355			5,959
	452		(149	)	Fair value (gain) loss on embedded derivatives		396			306

	(24,129)		8,979		Profit (loss) before interest and taxation		20,486			(14,523	)
	225		314		Finance costs(a)		622			463
	(11)		(65	)	Net finance income relating to pensions and other post-retirement benefits		(134	)		(21	)

	(24,343)		8,730		Profit (loss) before taxation		19,998			(14,965	)
	(7,295)		3,040		Taxation(a)		7,123			(4,105	)

	(17,048)		5,690		Profit (loss) for the period		12,875			(10,860	)

					Attributable to
	(17,150)		5,620		BP shareholders		12,744			(11,071	)
	102		70		Minority interest		131			211

	(17,048)		5,690				12,875			(10,860	)

					Earnings per share – cents (Note 6)
					Profit for the period attributable to BP shareholders
	(91.29)		29.75		Basic		67.60			(58.96	)
	(91.29)		29.39		Diluted		66.82			(58.96	)

(a)	See Note 2 on pages 23 – 28 for further details of the impact of the Gulf of Mexico oil spill on the income statement line items.

Group statement of comprehensive income


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
	(17,048)		5,690		Profit (loss) for the period		12,875			(10,860	)

	(1,000)		401		Currency translation differences		1,058			(1,526	)
	39		2		Exchange (gains) losses on translation of foreign operations transferred to gain or loss on sales of businesses and fixed assets		13			39
	(230)		(95	)	Available-for-sale investments marked to market		171			(323	)
	(143)		(3	)	Available-for-sale investments – recycled to the income statement		(5	)		(143	)
	(245)		75		Cash flow hedges marked to market		193			(407	)
	21		(112	)	Cash flow hedges – recycled to the income statement		(128	)		(73	)
	18		(5	)	Cash flow hedges – recycled to the balance sheet		(3	)		31
	(48)		57		Taxation		52			(167	)

	(1,588)		320		Other comprehensive income (expense)		1,351			(2,569	)

	(18,636)		6,010		Total comprehensive income (expense)		14,226			(13,429	)

					Attributable to
	(18,737)		5,946		BP shareholders		14,085			(13,632	)
	101		64		Minority interest		141			203

	(18,636)		6,010				14,226			(13,429	)

Group statement of changes in equity


	BP shareholders’ equity			Minority interest			Total equity
$ million
At 1 January 2011		94,987			904			95,891


Total comprehensive income		14,085			141			14,226
Dividends		(1,603	)		(132	)		(1,735	)
Share-based payments (net of tax)		25			—			25
Transactions involving minority interests		—			1			1

At 30 June 2011		107,494			914			108,408


	BP shareholders’ equity			Minority interest			Total equity
$ million
At 1 January 2010		101,613			500			102,113


Total comprehensive income (expense)		(13,632	)		203			(13,429	)
Dividends		(2,626	)		(131	)		(2,757	)
Share-based payments (net of tax)		135			—			135
Transactions involving minority interests		—			300			300

At 30 June 2010		85,490			872			86,362

Group balance sheet


	30 June 2011		31 December 2010
$ million
Non-current assets
Property, plant and equipment		112,205		110,163
Goodwill		9,470		8,598
Intangible assets		16,768		14,298
Investments in jointly controlled entities		12,483		12,286
Investments in associates		14,093		13,335
Other investments		1,366		1,191

Fixed assets		166,385		159,871
Loans		868		894
Other receivables		5,804		6,298
Derivative financial instruments		4,267		4,210
Prepayments		1,521		1,432
Deferred tax assets		546		528
Defined benefit pension plan surpluses		2,573		2,176

		181,964		175,409


Current assets
Loans		256		247
Inventories		27,477		26,218
Trade and other receivables		42,922		36,549
Derivative financial instruments		3,796		4,356
Prepayments		3,983		1,574
Current tax receivable		268		693
Other investments		1,413		1,532
Cash and cash equivalents		18,749		18,556

		98,864		89,725

Assets classified as held for sale (Note 3)		10,167		7,128

		109,031		96,853

Total assets		290,995		272,262

Current liabilities
Trade and other payables		51,010		46,329
Derivative financial instruments		3,273		3,856
Accruals		6,126		5,612
Finance debt		12,445		14,626
Current tax payable		3,883		2,920
Provisions		9,060		9,489

		85,797		82,832

Liabilities directly associated with assets classified as held for sale (Note 3)		1,127		1,047

		86,924		83,879

Non-current liabilities
Other payables		10,259		14,285
Derivative financial instruments		3,705		3,677
Accruals		391		637
Finance debt		34,445		30,710
Deferred tax liabilities		13,751		10,908
Provisions		23,287		22,418
Defined benefit pension plan and other post-retirement benefit plan deficits		9,825		9,857

		95,663		92,492

Total liabilities		182,587		176,371

Net assets		108,408		95,891

Equity
BP shareholders’ equity		107,494		94,987
Minority interest		914		904

		108,408		95,891

Condensed group cash flow statement


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Operating activities
	(24,343)		8,730		Profit (loss) before taxation		19,998			(14,965	)
					Adjustments to reconcile profit before taxation to net cash provided by operating activities
	2,833		3,275		Depreciation, depletion and amortization and exploration expenditure written off		6,402			5,850
	(1,027)		608		Impairment and (gain) loss on sale of businesses and fixed assets		(521	)		(901	)
	(92)		666		Earnings from equity-accounted entities, less dividends received		(780	)		(761	)
	(61)		(121	)	Net charge for interest and other finance expense, less net interest paid		(70	)		(15	)
	150		113		Share-based payments		(11	)		4
	(171)		(159	)	Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(598	)		(661	)
	17,739		(64	)	Net charge for provisions, less payments		209			17,691
	13,464		(3,283	)	Movements in inventories and other current and non-current assets and liabilities(a)		(11,106	)		11,524
	(1,739)		(1,917	)	Income taxes paid		(3,271	)		(3,320	)

	6,753		7,848		Net cash provided by operating activities		10,252			14,446

					Investing activities
	(4,273)		(4,289	)	Capital expenditure(b)		(10,063	)		(8,562	)
	(1,268)		(3,884	)	Acquisitions, net of cash acquired		(3,886	)		(1,268	)
	(100)		(66	)	Investment in jointly controlled entities		(155	)		(182	)
	(19)		(19	)	Investment in associates		(30	)		(25	)
	636		1,273		Proceeds from disposal of fixed assets(c)		1,657			744
	87		376		Proceeds from disposal of businesses, net of cash disposed(c)		962			87
	203		116		Proceeds from loan repayments		151			259

	(4,734)		(6,493	)	Net cash used in investing activities		(11,364	)		(8,947	)

					Financing activities
	31		18		Net issue of shares		30			159
	756		2,696		Proceeds from long-term financing		7,613			1,098
	(192)		(3,102	)	Repayments of long-term financing		(5,724	)		(2,687	)
	(1,855)		(157	)	Net increase (decrease) in short-term debt		792			(2,102	)
	—		(795	)	Dividends paid – BP shareholders		(1,603	)		(2,626	)
	(128)		(96	)	– Minority interest		(102	)		(131	)

	(1,388)		(1,436	)	Net cash provided by (used in) financing activities		1,006			(6,289	)

	(162)		104		Currency translation differences relating to cash and cash equivalents		299			(239	)

	469		23		Increase (decrease) in cash and cash equivalents		193			(1,029	)
	6,841		18,726		Cash and cash equivalents at beginning of period		18,556			8,339

	7,310		18,749		Cash and cash equivalents at end of period		18,749			7,310


	(a) Includes:
	284		(493	)	Inventory holding (gains) losses		(2,905	)		(421	)
	452		(149	)	Fair value (gain) loss on embedded derivatives		396			306
	12,430		(2,912	)	Movements related to Gulf of Mexico oil spill response		(5,776	)		12,430

Inventory holding gains and losses and fair value gains and losses on embedded derivatives are also included within profit before taxation. See Note 2 for further information on the cash flow impacts of the Gulf of Mexico oil spill.

(b)	First half 2011 included $2,000 million paid as a deposit relating to the transaction with Reliance Industries Limited.

See page 8 for further information.

(c)	Included in disposal proceeds are deposits received in respect of disposal transactions expected to complete in subsequent periods as follows: second quarter 2011 $568 million; first half 2011 $625.5 million; second quarter 2010 nil. For further information see Note 7.

Capital expenditure and acquisitions

Second

quarter

Second

quarter

First half

2010

2011

2010

$ million

By business

Exploration and Production

3,024

1,001

US(a)

2,024

4,157

2,172

5,439

Non-US(b)

7,550

4,987

5,196

6,440

9,574

9,144

Refining and Marketing

704

626

1,148

1,232

221

313

Non-US

528

365

925

939

1,676

1,597

Other businesses and corporate

126

256

689

Non-US(c)

709

100

815

965

158

6,212

8,194

12,215

10,899

By geographical area

3,758

1,753

US(a)

3,428

5,447

2,454

6,441

Non-US(b)(c)

8,787

5,452

6,212

8,194

12,215

10,899

Included above:

1,767

4,005

Acquisitions and asset exchanges(a)(b)(c)

4,014

1,767

(a)	Second quarter and first half 2010 included capital expenditure of $1,767 million in the US Deepwater Gulf of Mexico as part of the transaction with Devon Energy announced in first quarter 2010.

(b)	Second quarter and first half 2011 include capital expenditure of $3,236 million in Brazil as part of the transaction with Devon Energy announced in first quarter 2010.

(c)	Second quarter and first half 2011 include capital expenditure of $680 million in Brazil relating to the acquisition of CNAA. See page 12 for further information.

Exchange rates

Second

quarter

Second

quarter

First half

2010

2011

2010

1.49

1.63

US dollar/sterling average rate for the period

1.62

1.52

1.51

1.60

US dollar/sterling period-end rate

1.60

1.51

1.27

1.44

US dollar/euro average rate for the period

1.40

1.32

1.22

1.44

US dollar/euro period-end rate

1.44

1.22

Analysis of replacement cost profit (loss) before interest and tax and

reconciliation to profit (loss) before taxation(a)


Second quarter		Second quarter				First half
2010		2011			$ million	2011			2010
					By business
					Exploration and Production
	1,798		731		US		2,606			4,560
	4,446		5,883		Non-US		12,428			9,976

	6,244		6,614				15,034			14,536

					Refining and Marketing
	757		(17	)	US		623			694
	1,318		1,355		Non-US		2,794			2,110

	2,075		1,338				3,417			2,804

					Other businesses and corporate
	(119)		(168	)	US		(356	)		(350	)
	49		(430	)	Non-US		(720	)		(48	)

	(70)		(598	)			(1,076	)		(398	)

	8,249		7,354				17,375			16,942
	(32,192)		617		Gulf of Mexico oil spill response		233			(32,192	)
	98		515		Consolidation adjustment		(27	)		306

	(23,845)		8,486		Replacement cost profit (loss) before interest and tax(b)		17,581			(14,944	)
					Inventory holding gains (losses)(c)
	(55)		5		Exploration and Production		120			(31	)
	(225)		482		Refining and Marketing		2,770			454
	(4)		6		Other businesses and corporate		15			(2	)

	(24,129)		8,979		Profit (loss) before interest and tax		20,486			(14,523	)
	225		314		Finance costs		622			463
					Net finance income relating to pensions and other
	(11)		(65	)	post-retirement benefits		(134	)		(21	)

	(24,343)		8,730		Profit (loss) before taxation		19,998			(14,965	)

					Replacement cost profit (loss) before interest and tax
					By geographical area
	(29,171)		1,361		US		3,174			(26,581	)
	5,326		7,125		Non-US		14,407			11,637

	(23,845)		8,486				17,581			(14,944	)

(a)

IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before interest and tax. In addition, a reconciliation is required between the total of the operating segments’ measures of profit or loss and the group profit or loss before taxation.

(b)

Replacement cost profit or loss reflects the replacement cost of supplies. The replacement cost profit or loss for the period is arrived at by excluding from profit or loss inventory holding gains and losses and their associated tax effect. Replacement cost profit or loss for the group is not a recognized GAAP measure.

(c)

Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period 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 historic 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 if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. 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.

Management believes this information 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 principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil 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 information.

Non-operating items(a)


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Exploration and Production
	660		(403	)	Impairment and gain (loss) on sale of businesses and fixed assets(b)		686			647
	—		—		Environmental and other provisions		—			—
	(13)		—		Restructuring, integration and rationalization costs		—			(117	)
	(452)		142		Fair value gain (loss) on embedded derivatives		(186	)		(306	)
	(134)		(403	)	Other		(454	)		(122	)

	61		(664	)			46			102

					Refining and Marketing
	270		(209	)	Impairment and gain (loss) on sale of businesses and fixed assets		(204	)		225
	—		(1	)	Environmental and other provisions		(1	)		—
	(30)		(4	)	Restructuring, integration and rationalization costs		(5	)		(18	)
	—		—		Fair value gain (loss) on embedded derivatives		—			—
	(8)		(4	)	Other		(25	)		(45	)

	232		(218	)			(235	)		162

					Other businesses and corporate
	97		4		Impairment and gain (loss) on sale of businesses and fixed assets		39			29
	(4)		(12	)	Environmental and other provisions		(12	)		(4	)
	(22)		2		Restructuring, integration and rationalization costs		3			(60	)
	—		7		Fair value gain (loss) on embedded derivatives(c)		(210	)		—
	—		(264	)	Other		(264	)		(12	)

	71		(263	)			(444	)		(47	)

	(32,192)		617		Gulf of Mexico oil spill response		233			(32,192	)

	(31,828)		(528	)	Total before interest and taxation		(400	)		(31,975	)
	—		(15	)	Finance costs(d)		(31	)		—

	(31,828)		(543	)	Total before taxation		(431	)		(31,975	)
	9,877		160		Taxation credit (charge)(e)		204			9,927

	(21,951)		(383	)	Total after taxation for period		(227	)		(22,048	)

(a)	An analysis of non-operating items by region is shown on pages 9, 11 and 12.

(b)	Second quarter 2011 included impairment charges of $1,049 million, partially offset by net gains on disposals of $646 million.

(c)	Relates to an embedded derivative arising from a financing arrangement.

(d)	Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 23 – 28 for further details.

(e)

Non-operating items are charges and credits arising in consolidated entities that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. These disclosures are provided in order to enable investors better to understand and evaluate the group’s financial performance.

Non-GAAP information on fair value accounting effects


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Favourable (unfavourable) impact relative to management’s measure of performance
	(122)		(35	)	Exploration and Production		(6	)		(59	)
	119		164		Refining and Marketing		64			129

	(3)		129				58			70
	1		(44	)	Taxation credit (charge)(a)		(22	)		(24	)

	(2)		85				36			46

(a)

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 historic cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in income 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 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 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 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 requires that inventory held for trading be 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 storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments, which 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, capacity, oil and gas processing and LNG contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period 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. The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.

Reconciliation of non-GAAP information


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Exploration and Production
	6,366		6,649		Replacement cost profit before interest and tax adjusted for fair value accounting effects		15,040			14,595
	(122)		(35	)	Impact of fair value accounting effects		(6	)		(59	)

	6,244		6,614		Replacement cost profit before interest and tax		15,034			14,536

					Refining and Marketing
	1,956		1,174		Replacement cost profit before interest and tax adjusted for fair value accounting effects		3,353			2,675
	119		164		Impact of fair value accounting effects		64			129

	2,075		1,338		Replacement cost profit before interest and tax		3,417			2,804

					Total group
	(24,126)		8,850		Profit (loss) before interest and tax adjusted for fair value accounting effects		20,428			(14,593	)
	(3)		129		Impact of fair value accounting effects		58			70

	(24,129)		8,979		Profit (loss) before interest and tax		20,486			(14,523	)

Realizations and marker prices

Second
quarter

First half

2010

2011

2010

Average realizations(a)

Liquids ($/bbl)(b)

70.77

101.40

93.51

70.23

75.46

114.43

Europe

108.14

75.59

74.44

111.12

Rest of World

104.81

73.67

72.90

106.99

BP Average

99.98

72.35

Natural gas ($/mcf)

3.52

3.61

3.40

4.19

5.14

7.82

Europe

7.41

5.02

3.71

4.63

Rest of World

4.52

3.80

3.76

4.54

BP Average

4.37

4.01

Total hydrocarbons ($/boe)

50.87

68.43

64.20

52.80

59.89

92.91

Europe

88.84

60.16

41.47

53.45

Rest of World

53.11

41.84

47.08

63.23

BP Average

61.05

48.16

Average oil marker prices ($/bbl)

78.24

117.04

Brent

111.09

77.31

77.81

102.22

West Texas Intermediate

98.39

78.32

78.31

115.26

Alaska North Slope

109.29

78.72

77.42

111.68

Mars

106.85

76.64

76.92

113.73

Urals (NWE– cif)

108.00

76.12

35.61

50.26

Russian domestic oil

49.75

35.57

Average natural gas marker prices

4.09

4.32

Henry Hub gas price ($/mmBtu)(c)

4.21

4.69

38.26

57.47

UK Gas – National Balancing Point (p/therm)

57.20

36.96

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

(b)	Crude oil and natural gas liquids.

(c)	Henry Hub First of Month Index.

Notes

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 the periods presented. All such adjustments are of a normal recurring nature. After making enquiries, the directors have a reasonable expectation that the group has adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the interim financial statements. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2010 included in the BP Annual Report and Form 20-F 2010.

BP prepares its consolidated financial statements included within its Annual Report and Accounts 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. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB, however, 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 2011, which do not differ significantly from those used in the BP Annual Report and Form 20-F 2010.

New or amended International Financial Reporting Standards adopted

There are no new or amended standards or interpretations adopted with effect from 1 January 2011 that have a significant impact on the financial statements.

2.	Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur costs and has also recognized liabilities for future costs. The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2010 – Financial Statements – Note 2, Note 37 and Note 44, and Legal proceedings on pages 46 – 49 herein.

The group income statement includes a pre-tax credit of $602 million for the second quarter in relation to the Gulf of Mexico oil spill, and a pre-tax credit of $202 million for the first half of 2011. The amount for the second quarter includes credits of $1.1 billion relating to the settlement reached with MOEX Offshore 2007 LLC (MOEX), one of BP’s co-owners in the Macondo well, and $75 million relating to the settlement with Weatherford U.S., L.P., the contractor that manufactured the float collar used in the well. These amounts are partially offset by higher costs associated with the ongoing spill response, mainly increased costs of patrolling and maintenance of shoreline, as well as functional expenses of the GCRO. The total pre-tax income statement charge in 2010 amounted to $40.9 billion.

The settlement amounts with MOEX and Weatherford were not received during the second quarter, but were recorded as receivables on the balance sheet at 30 June 2011.

The amounts set out below reflect the impacts on the financial statements of the Gulf of Mexico oil spill for the periods presented, as described on pages 4 – 5. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Income statement
	32,192		(617	)	Production and manufacturing expenses		(233	)		32,192

	(32,192)		617		Profit (loss) before interest and taxation		233			(32,192	)
	—		15		Finance costs		31			—

	(32,192)		602		Profit (loss) before taxation		202			(32,192	)
	10,003		(234	)	Less: Taxation		(33	)		10,003

	(22,189)		368		Profit (loss) for the period		169			(22,189	)

Notes

2.	Gulf of Mexico oil spill (continued)


	30 June 2011						31 December 2010
	Total			Of which: amount related to the trust fund			Total			Of which: amount related to the trust fund
$ million

Balance sheet
Current assets
Trade and other receivables		7,170			6,030			5,943			5,943
Current liabilities
Trade and other payables		(6,796	)		(6,146	)		(6,587	)		(5,002	)
Provisions		(7,414	)		—			(7,938	)		—

Net current assets (liabilities)		(7,040	)		(116	)		(8,582	)		941

Non-current assets
Other receivables		2,667			2,667			3,601			3,601
Non-current liabilities
Other payables		(6,307	)		(6,307	)		(9,899	)		(9,899	)
Provisions		(6,964	)		—			(8,397	)		—
Deferred tax		10,497			—			11,255			—

Net non-current assets (liabilities)		(107	)		(3,640	)		(3,440	)		(6,298	)


Net assets		(7,147	)		(3,756	)		(12,022	)		(5,357	)


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Cash flow statement – Operating activities
	(32,192)		602		Profit (loss) before taxation		202			(32,192	)
					Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
	—		15		Net charge for interest and other finance expense, less net interest paid		31			—
	17,646		(90	)	Net charge for provisions, less payments		112			17,646
	12,430		(2,912	)	Movements in inventories and other current and non-current assets and liabilities		(5,776	)		12,430

	(2,116)		(2,385	)	Pre-tax cash flows		(5,431	)		(2,116	)

Net cash used in operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to $1,898 million and $4,706 million in the second quarter and half year 2011 respectively.

Trust fund

In 2010, BP established the Deepwater Horizon Oil Spill Trust (the Trust) to be funded in the amount of $20 billion over the period to the fourth quarter of 2013, which is available to satisfy legitimate individual and business claims administered by the Gulf Coast Claims Facility (GCCF), state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. In 2010 BP contributed $5 billion to the fund, and further contributions of $2.5 billion were made in the first half of 2011. The income statement charge for 2010 included $20 billion in relation to the trust fund, adjusted to take account of the time value of money. Fines, penalties and claims administration costs are not covered by the trust fund.

Under the settlement agreement noted above, MOEX paid BP $1.1 billion in early July, which was subsequently contributed to the trust fund, and Weatherford have paid BP $75 million which will also be contributed to the trust fund.

Notes

2.	Gulf of Mexico oil spill (continued)

The table below shows movements in the funding obligation during the period to 30 June 2011. This liability is recognized within other payables on the balance sheet apportioned between current and non-current elements according to the agreed schedule of contributions.


	Second			First
	quarter			half
	2011			2011
$ million
Opening balance		13,668			14,901
Unwinding of discount		14			28
Contribution		(1,250	)		(2,500	)
Other		21			24

At 30 June 2011		12,453			12,453

Of which – current		6,146			6,146
– non-current		6,307			6,307

An asset has been recognized representing BP’s right to receive reimbursement from the trust fund. This is the portion of the estimated future expenditure provided for that will be settled by payments from the trust fund. We use the term “reimbursement asset” to describe this asset. BP will not actually receive any reimbursements from the trust fund, instead payments will be made directly to claimants from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements. The table below shows movements in the reimbursement asset during the period to 30 June 2011. The amount of the reimbursement asset at 30 June 2011 is equal to the amount of provisions recognized at that date that will be covered by the trust fund – see below.


	Second			First
	quarter			half
	2011			2011
$ million
Opening balance		9,544			9,544
Increase in provision for items covered by the trust fund		163			1,225
Amounts paid directly by the trust fund		(1,010	)		(2,072	)

At 30 June 2011		8,697			8,697

Of which – current		6,030			6,030
– non-current		2,667			2,667

As noted above, the obligation to fund the $20-billion trust fund has been recognized in full. Any increases in the provision that will be covered by the trust fund (up to the amount of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 30 June 2011, the cumulative charges for provisions, and the associated reimbursement asset recognized, amounted to $13,792 million. Thus, a further $6,208 million could be provided in subsequent periods for items covered by the trust fund with no net impact on the income statement. Such future increases in amounts provided could arise from adjustments to existing provisions, or from the initial recognition of provisions for items that currently cannot be estimated reliably, namely final judgments and settlements and natural resource damages and related costs. Further information on those items that currently cannot be reliably estimated is provided under Provisions and contingencies below.

It is not possible at this time to conclude whether the $20-billion trust fund will be sufficient to satisfy all claims under the Oil Pollution Act 1990 (OPA 90) that will ultimately be paid.

The Trust agreement does not require BP to make further contributions to the trust fund in excess of the agreed $20 billion should this be insufficient to cover all claims administered by the GCCF, or to settle other items that are covered by the trust fund, as described above. Should the $20-billion trust fund not be sufficient, BP would commence settling legitimate claims and other costs by making payments directly to claimants. In this case, increases in estimated future expenditure above $20 billion would be recognized as provisions with a corresponding charge in the income statement. The provisions would be utilized and derecognized at the point that BP made the payments.

Notes

2.	Gulf of Mexico oil spill (continued)

(b) Provisions and contingencies

BP has recorded certain provisions and disclosed certain contingencies as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 2010 – Financial statements – Notes 2, 37 and 44.

Provisions

BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, spill response costs, litigation and claims, and Clean Water Act penalties.

On 21 April 2011, BP entered a framework agreement with natural resource trustees for the United States and five Gulf coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the Gulf of Mexico oil spill. Funding for these projects will come from the $20-billion Deepwater Horizon Oil Spill Trust.

BP considers that it is not possible, at this time, to measure reliably any obligation in relation to Natural Resources Damages claims under OPA 90 (other than the estimated costs of the assessment phase and the costs of the early and emergency restoration agreements referred to above) or litigation arising from alleged violations of OPA 90, any amounts in relation to fines and penalties except for those relating to the Clean Water Act and any obligation in relation to litigation or in relation to legal fees beyond 2012. These items are therefore disclosed as contingent liabilities – see below.

Movements in the provision during the second quarter and the half year are presented in the tables below.

Spill

Litigation

Clean Water

Environmental

response

and claims

Act penalties

Total

$ million

At 1 April 2011

1,740

470

9,757

3,510

15,477

Increase in provision – items not covered by the trust fund

338

)

—

359

Increase in provision – items covered by the trust fund

—

163

—

163

Unwinding of discount

—

Utilization – paid by BP

)

(270

)

(335

)

—

(612

)

– paid by the trust fund

(89

)

—

(921

)

—

(1,010

)

At 30 June 2011

1,675

538

8,655

3,510

14,378

Of which – current

773

538

6,103

—

7,414

– non-current

902

—

2,552

3,510

6,964

Of which – payable from the trust fund

1,226

—

7,471

—

8,697

Notes

2.	Gulf of Mexico oil spill (continued)


				Spill			Litigation			Clean Water
	Environmental			response			and claims			Act penalties		Total
$ million
At 1 January 2011		809			1,043			10,973			3,510		16,335
Increase in provision – items not covered by the trust fund		30			640			(9	)		—		661
Increase in provision – items covered by the trust fund		1,000			—			225			—		1,225
Unwinding of discount		3			—			—			—		3
Utilization – paid by BP		(10	)		(1,145	)		(619	)		—		(1,774	)
– paid by the trust fund		(157	)		—			(1,915	)		—		(2,072	)

At 30 June 2011		1,675			538			8,655			3,510		14,378

The total charge in the income statement is analysed in the table below.


	Second			First
	quarter			half
	2011			2011
$ million
Increase in provision		522			1,886
Recognition of reimbursement asset		(163	)		(1,225	)
Other costs charged directly to the income statement		199			281
Settlements credited to the income statement		(1,175	)		(1,175	)

(Profit) loss before interest and taxation		(617	)		(233	)
Finance costs		15			31

(Profit) loss before taxation		(602	)		(202	)

The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, the amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any determination of BP’s negligence), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, will also impact upon the ultimate cost for BP.

In estimating the amount of the provision at 30 June 2011 for Individual and Business Claims, as administered by the GCCF, and State and Local Claims, BP has concluded that a reasonable range of possible outcomes is $4.4 billion to $10.8 billion. BP believes that the provision recorded at 30 June 2011 of $7.2 billion represents a reliable best estimate from within this range of possible outcomes. This amount is included within amounts payable from the trust fund under Litigation and claims in the table above.

Although the provision recognized is the current best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is not possible to measure the obligation reliably as noted below under Contingent liabilities.

As noted above, an agreement has been reached with MOEX, one of the co-owners of the Macondo prospect leasehold, to settle all claims between the companies related to the incident and the prospect. The settlement has been recorded in the income statement in the second quarter. No amount has been recognized for recovery of costs from the other co-owner, Anadarko Petroleum Corporation (Anadarko), because under IFRS the recovery must be virtually certain before such receivables can be recognized. This item is therefore disclosed as a contingent asset.

Further information on provisions is provided in BP Annual Report and Form 20-F 2010 – Financial statements – Note 37.

Notes

2.	Gulf of Mexico oil spill (continued)

Contingent liabilities

BP has provided for its best estimate of certain claims under OPA 90 that will be paid through the $20-billion trust fund. It is not possible, at this time, to measure reliably any other items that will be paid from the trust fund, namely any obligation in relation to Natural Resource Damages claims (except for the estimated costs of the assessment phase and the costs relating to early and emergency restoration agreements as described above under Provisions) and claims resolved by civil litigation, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore no amounts have been provided for these items as of 30 June 2011.

For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties except, subject to certain assumptions, for those relating to the Clean Water Act. It is also not possible to reliably estimate legal fees beyond 2012. Therefore no amounts have been provided for these items as of 30 June 2011.

See Legal proceedings on pages 46 – 49 and BP Annual Report and Form 20-F 2010 – Financial statements – Note 44 for further information on contingent liabilities.

Contingent assets

See Legal proceedings on pages 46 – 49 and BP Annual Report and Form 20-F 2010 – Financial statements – Note 44 for information on contingent assets.

As of 30 June 2011, $5.5 billion had been billed to our co-owner, Anadarko, which BP believes to be contractually recoverable pursuant to the terms of the Macondo Prospect Offshore Deepwater Operating Agreement. Billings to co-owners under this Operating Agreement are based upon costs incurred to date rather than amounts provided in the period. As further costs are incurred, BP believes that certain of the costs will be billable to Anadarko under the Operating Agreement. No recovery amounts from Anadarko have been recognized in the financial statements as at 30 June 2011.

On 4 April 2011, BP initiated contractual out-of-court dispute resolution proceedings against Anadarko, claiming that it has breached the parties’ contract by failing to reimburse BP for their working-interest share of incident-related costs. These procedures will culminate in arbitration if the parties cannot resolve their disputes through negotiation. On 19 April 2011, Anadarko filed a cross-claim against BP, alleging gross negligence and 15 other counts under state and federal laws. Anadarko seeks a declaration that it is excused from its contractual obligation to pay incident-related costs. Anadarko also seeks damages from alleged economic losses and contribution or indemnity for claims filed against it by other parties. BP disputes Anadarko’s cross-claims and intends to defend against them vigorously.

On 15 July 2011, the judge in the federal multi-district litigation proceeding in New Orleans stayed Anadarko’s claims against BP pursuant to the arbitration clause in the operating agreement between the parties pertaining to the Macondo well.

There are also audit rights concerning billings under the Operating Agreement which may be exercised by Anadarko, and which may or may not lead to an adjustment of the amount billed. BP may ultimately need to enforce its rights to collect payment from Anadarko following any successful arbitration proceedings as provided for in the Operating Agreement. There is a risk that amounts billed to Anadarko may not ultimately be recovered should Anadarko be found not liable for these costs or be unable to pay them. Moreover, negotiations with Anadarko could result in settlement of these claims, which if reached, may result in amounts to be received by BP differing from the amounts billed.

3.	Non-current assets held for sale

As a result of the group’s disposal programme following the Gulf of Mexico oil spill, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 30 June 2011. The carrying amount of the assets held for sale is $10,167 million, with associated liabilities of $1,127 million. Included within these amounts are the following items, all of which relate to the Exploration and Production segment unless otherwise stated.

On 14 December 2010, BP announced that it had reached agreement to sell its exploration and production assets in Pakistan to United Energy Group Limited for $775 million in cash. These assets, and associated liabilities, have been classified as held for sale in the group balance sheet at 30 June 2011. An interim injunction entered by the Islamabad High Court on 9 March 2011 in a preferential rights dispute affecting the Mirpur Khas and Khipro concessions has now been lifted. The sale is expected to be completed in the third quarter of 2011, subject to certain conditions precedent, including the satisfaction of closing conditions and the receipt of government and regulatory approvals.

Notes

3.	Non-current assets held for sale (continued)

On 18 October 2010, BP announced that it had reached agreement to sell its upstream and midstream assets in Vietnam, together with its upstream businesses and associated interests in Venezuela, to TNK-BP for $1.8 billion in cash, subject to post-closing adjustments. The sale of the Venezuelan business completed during the second quarter of 2011. The sale of the Vietnam business is expected to be completed in the third quarter of 2011, subject to regulatory and other approvals and conditions. The assets, and associated liabilities, of the Vietnam business have been classified as held for sale in the group balance sheet at 30 June 2011.

On 28 November 2010, BP announced that it had reached agreement to sell its interests in Pan American Energy (PAE) to Bridas Corporation for $7.06 billion in cash. PAE is an Argentina-based oil and gas company owned by BP (60%) and Bridas Corporation (40%). The transaction excludes the shares of PAE E&P Bolivia Ltd. BP’s investment in PAE has been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2011, subject to closing conditions and government and regulatory approvals.

On 4 April 2011, BP announced that it had agreed the sale of its wholly-owned subsidiary, ARCO Aluminum Inc. (reported within Other businesses and corporate), to a consortium of Japanese companies for cash consideration of $680 million, subject to closing adjustments. The assets, and associated liabilities, of this subsidiary have been classified as held for sale in the group balance sheet at 30 June 2011. Subject to obtaining required regulatory approvals, the parties expect to complete the transaction in the third quarter of 2011.

In Canada, BP intends to dispose of its NGL business. The assets, and associated liabilities, of this business have been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2011.

On 17 May 2011, BP announced that it had reached agreement to sell its interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd (‘Perenco’) for up to $610 million in cash. The price includes $55 million contingent on Perenco’s future development of the Beacon field and on oil prices in 2011-13. The sale is expected to be completed in early 2012, subject to a number of third party and regulatory approvals. These assets, and associated liabilities, have been classified as held for sale in the group balance sheet at 30 June 2011.

As previously announced, following a strategic review of our Refining and Marketing business, BP intends to divest the Texas City refinery. The non-current assets, together with the inventories, of this business have been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2012.

Disposal proceeds of $4.6 billion ($6.2 billion at 31 December 2010) received in advance of completion of certain of these transactions have been classified as finance debt on the group balance sheet. See Note 7 for further information.

The majority of the transactions noted above are subject to post-closing adjustments, which may include adjustments for working capital and adjustments for profits attributable to the purchaser between the agreed effective date and the closing date of the transaction. Such post-closing adjustments may result in the final amounts received by BP from the purchasers differing from the disposal proceeds noted above.

Notes

4.	Sales and other operating revenues

Second
quarter

First half

2010

2011

2010

$ million

By business

15,215

18,418

Exploration and Production

36,823

33,295

67,250

93,886

Refining and Marketing

171,319

131,536

794

985

Other businesses and corporate

1,841

1,584

83,259

113,289

209,983

166,415

Less: sales between businesses

9,042

11,539

Exploration and Production

22,064

18,788

281

165

Refining and Marketing

791

416

211

221

Other businesses and corporate

435

415

9,534

11,925

23,290

19,619

Third party sales and other operating revenues

6,173

6,879

Exploration and Production

14,759

14,507

66,969

93,721

Refining and Marketing

170,528

131,120

583

764

Other businesses and corporate

1,406

1,169

73,725

101,364

Total third party sales and other operating revenues

186,693

146,796

By geographical area

27,762

38,817

69,664

53,870

53,111

73,350

Non-US

137,205

107,120

80,873

112,167

206,869

160,990

7,148

10,803

Less: sales between areas

20,176

14,194

73,725

101,364

186,693

146,796

5.	Production and similar taxes

Second
quarter

First half

2010

2011

2010

$ million

209

563

937

522

1,029

1,793

Non-US

3,250

1,992

1,238

2,356

4,187

2,514

Notes

6.	Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. 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. If the inclusion of potentially issuable shares would decrease the loss per share, the potentially issuable shares are excluded from the diluted EpS calculation.


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Results for the period
	(17,150)		5,620		Profit (loss) for the period attributable to BP shareholders		12,744			(11,071	)
	1		1		Less: preference dividend		1			1

	(17,151)		5,619		Profit (loss) attributable to BP ordinary shareholders		12,743			(11,072	)
	177		(311	)	Inventory holding (gains) losses, net of tax		(1,954	)		(304	)

	(16,974)		5,308		RC profit (loss) attributable to BP ordinary shareholders		10,789			(11,376	)

	18,787,629		18,886,382		Basic weighted average number of shares outstanding (thousand)(a)		18,851,483			18,779,227
	3,131,272		3,147,730		ADS equivalent (thousand)(a)		3,141,914			3,129,871

	19,031,671		19,118,850		Weighted average number of shares outstanding used to calculate diluted earnings per share (thousand)(a)		19,071,882			19,007,478
	3,171,945		3,186,475		ADS equivalent (thousand)(a)		3,178,647			3,167,913

	18,791,926		18,940,090		Shares in issue at period-end (thousand)(a)		18,940,090			18,791,926
	3,131,988		3,156,682		ADS equivalent (thousand)(a)		3,156,682			3,131,988

(a)	Excludes treasury shares and the shares held by the Employee Share Ownership Plans and includes certain shares that will be issued in the future under employee share plans.

Notes

7.	Analysis of changes in net debt


Second quarter		Second quarter				First half
2010		2011				2011			2010
					$ million
					Opening balance
	32,153		47,102		Finance debt		45,336			34,627
	6,841		18,726		Less: Cash and cash equivalents		18,556			8,339
	152		870		Less: FV asset of hedges related to finance debt		916			127

	25,160		27,506		Opening net debt		25,864			26,161


					Closing balance
	30,580		46,890		Finance debt		46,890			30,580
	7,310		18,749		Less: Cash and cash equivalents		18,749			7,310
	53		1,173		Less: FV asset of hedges related to finance debt		1,173			53

	23,217		26,968		Closing net debt		26,968			23,217

	1,943		538		Decrease (increase) in net debt		(1,104	)		2,944

	631		(81	)	Movement in cash and cash equivalents (excluding exchange adjustments)		(106	)		(790	)
	1,291		563		Net cash outflow (inflow) from financing (excluding share capital)		(2,681	)		3,691
	—		2		Movement in finance debt relating to investing activities(a)		1,597			—
	20		5		Other movements		(16	)		27

	1,942		489		Movement in net debt before exchange effects		(1,206	)		2,928
	1		49		Exchange adjustments		102			16

	1,943		538		Decrease (increase) in net debt		(1,104	)		2,944

(a)

During the second quarter 2011 disposal transactions were completed in respect of which deposits of $502 million, (first half 2011 $2,097 million) had been received in 2010. In addition, deposits of $500 million were received in the second quarter 2011, in respect of disposals expected to complete within the next year.

At 30 June 2011, $626 million of finance debt, ($1,155 million at 30 June 2010) was secured by the pledging of assets, and $3,530 million was secured in connection with deposits received relating to certain disposal transactions expected to complete in subsequent periods. In addition, in connection with $3,014 million of finance debt, BP has entered into crude oil sales contracts in respect of oil produced from certain fields in offshore Angola and Azerbaijan to provide security to the lending banks. The remainder of finance debt was unsecured.

During the first quarter 2011 the company signed new three-year committed standby facilities totalling $6.8 billion, available to draw and repay until mid-March 2014, largely replacing existing arrangements. At 30 June 2011 the total available undrawn committed borrowing facilities stood at $7.2 billion.

Notes

8.	TNK-BP operational and financial information

Second

quarter

Second

quarter

First half

2010

2011

2010

Production (Net of royalties) (BP share)

859

860

Crude oil (mb/d)

858

854

647

675

Natural gas (mmcf/d)

697

660

971

976

Total hydrocarbons (mboe/d)(a)

978

968

$ million

Income statement (BP share)

843

1,419

Profit before interest and tax

2,945

1,631

(34)

(34

)

Finance costs

(69

)

(72

)

(266)

(238

)

Taxation

(484

)

(434

)

(53)

(84

)

Minority interest

(143

)

(92

)

490

1,063

Net income

2,249

1,033

Cash flow

505

1,634

Dividends received

1,634

761

Balance sheet

30 June

31 December

2011

2010

Investments in associates

10,536

9,995

(a)	Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

9.	Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 25 July 2011, is unaudited and does not constitute statutory financial statements.

Notes

10.

Condensed consolidating information

BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100% owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., and BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. for all years includes equity income arising from subsidiaries of BP Exploration (Alaska) Inc. some of which operate outside of Alaska and excludes the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.


	Issuer			Guarantor
Income statement	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries		Eliminations and reclassification			BP group
First half 2011	$ million
Sales and other operating revenues		3,084			—			186,693		(3,084	)		186,693
Earnings from jointly controlled entities – after interest and tax		—			—			565		—			565
Earnings from associates – after interest and tax		—			—			2,664		—			2,664
Equity-accounted income of subsidiaries – after interest and tax		266			13,038			—		(13,304	)		—
Interest and other income		3			76			293		(97	)		275
Gains on sale of businesses and fixed assets		—			—			1,963		—			1,963

Total revenues and other income		3,353			13,114			192,178		(16,485	)		192,160

Purchases		540			—			142,546		(3,084	)		140,002
Production and manufacturing expenses		590			—			12,118		—			12,708
Production and similar taxes		898			—			3,289		—			4,187
Depreciation, depletion and amortization		163			—			5,343		—			5,506
Impairment and losses on sale of businesses and fixed assets		—			3			1,439		—			1,442
Exploration expense		—			—			1,078		—			1,078
Distribution and administration expenses		9			561			5,820		(35	)		6,355
Fair value (gain) loss on embedded derivatives		—			—			396		—			396

Profit (loss) before interest and taxation		1,153			12,550			20,149		(13,366	)		20,486
Finance costs		13			11			660		(62	)		622
Net finance expense (income) relating to pensions and other post-retirement benefits		(1	)		(267	)		134		—			(134	)

Profit (loss) before taxation		1,141			12,806			19,355		(13,304	)		19,998
Taxation		359			62			6,702		—			7,123

Profit (loss) for the period		782			12,744			12,653		(13,304	)		12,875

Attributable to:
BP shareholders		782			12,744			12,522		(13,304	)		12,744
Minority interest		—			—			131		—			131

		782			12,744			12,653		(13,304	)		12,875

Notes

10.

Condensed consolidating information (continued)


	Issuer		Guarantor
Income statement	BP Exploration (Alaska) Inc.		BP p.l.c.			Other subsidiaries			Eliminations and reclassifications			BP group
First half 2010	$ million
Sales and other operating revenues		2,452		—			146,796			(2,452	)		146,796
Earnings from jointly controlled entities – after interest and tax		—		—			660			—			660
Earnings from associates – after interest and tax		—		—			1,523			—			1,523
Equity-accounted income of subsidiaries – after interest and tax		385		(11,056	)		—			10,671			—
Interest and other income		—		40			315			(55	)		300
Gains on sale of businesses and fixed assets		—		68			1,002			(61	)		1,009

Total revenues and other income		2,837		(10,948	)		150,296			8,103			150,288

Purchases		478		—			108,151			(2,452	)		106,177
Production and manufacturing expenses		486		—			43,233			—			43,719
Production and similar taxes		462		—			2,052			—			2,514
Depreciation, depletion and amortization		182		—			5,594			—			5,776
Impairment and losses on sale of businesses and fixed assets		—		—			108			—			108
Exploration expense		—		—			252			—			252
Distribution and administration expenses		14		220			5,749			(24	)		5,959
Fair value (gain) loss on embedded derivatives		—		—			306			—			306

Profit (loss) before interest and taxation		1,215		(11,168	)		(15,149	)		10,579			(14,523	)
Finance costs		5		8			481			(31	)		463
Net finance expense (income) relating to pensions and other post-retirement benefits		2		(191	)		168			—			(21	)

Profit (loss) before taxation		1,208		(10,985	)		(15,798	)		10,610			(14,965	)
Taxation		279		86			(4,470	)		—			(4,105	)

Profit (loss) for the period		929		(11,071	)		(11,328	)		10,610			(10,860	)

Attributable to:
BP shareholders		929		(11,071	)		(11,539	)		10,610			(11,071	)
Minority interest		—		—			211			—			211

		929		(11,071	)		(11,328	)		10,610			(10,860	)

Notes

10.

Condensed consolidating information (continued)


	Issuer		Guarantor
Balance sheet	BP Exploration (Alaska) Inc		BP p.l.c.		Other subsidiaries		Eliminations and reclassification			BP group
At 30 June 2011 Non-current assets	$ million
Property, plant and equipment		7,849		—		104,356		—			112,205
Goodwill		—		—		9,470		—			9,470
Intangible assets		466		—		16,302		—			16,768
Investments in jointly controlled entities		—		—		12,483		—			12,483
Investments in associates		—		2		14,091		—			14,093
Other investments		—		—		1,366		—			1,366
Subsidiaries – equity-accounted basis		4,755		126,513		—		(131,268	)		—

Fixed assets		13,070		126,515		158,068		(131,268	)		166,385
Loans		—		40		5,140		(4,312	)		868
Other receivables		—		—		5,804		—			5,804
Derivative financial instruments		—		—		4,267		—			4,267
Prepayments		—		—		1,521		—			1,521
Deferred tax assets		—		—		546		—			546
Defined benefit pension plan surpluses		—		2,286		287		—			2,573

		13,070		128,841		175,633		(135,580	)		181,964


Current assets
Loans		—		—		256		—			256
Inventories		153		—		27,324		—			27,477
Trade and other receivables		3,341		12,417		49,180		(22,016	)		42,922
Derivative financial instruments		—		—		3,796		—			3,796
Prepayments		165		—		3,818		—			3,983
Current tax receivable		—		—		268		—			268
Other investments		—		—		1,413		—			1,413
Cash and cash equivalents		—		13		18,736		—			18,749

		3,659		12,430		104,791		(22,016	)		98,864

Assets classified as held for sale		—		—		10,167		—			10,167

Total assets		16,729		141,271		290,591		(157,596	)		290,995

Current liabilities
Trade and other payables		4,789		2,451		65,786		(22,016	)		51,010
Derivative financial instruments		—		—		3,273		—			3,273
Accruals		—		27		6,099		—			6,126
Finance debt		—		—		12,445		—			12,445
Current tax payable		168		—		3,715		—			3,883
Provisions		—		—		9,060		—			9,060

		4,957		2,478		100,378		(22,016	)		85,797

Liabilities directly associated with assets classified as held for sale		—		—		1,127		—			1,127

		4,957		2,478		101,505		(22,016	)		86,924

Non-current liabilities
Other payables		9		4,264		10,298		(4,312	)		10,259
Derivative financial instruments		—		—		3,705		—			3,705
Accruals		—		26		365		—			391
Finance debt		—		—		34,445		—			34,445
Deferred tax liabilities		2,122		499		11,130		—			13,751
Provisions		950		—		22,337		—			23,287
Defined benefit pension plan and other post-retirement benefit plan deficits		—		—		9,825		—			9,825

		3,081		4,789		92,105		(4,312	)		95,663

Total liabilities		8,038		7,267		193,610		(26,328	)		182,587

Net assets		8,691		134,004		96,981		(131,268	)		108,408

Equity

BP shareholders’ equity		8,691		134,004		96,067		(131,268	)		107,494
Minority interest		—		—		914		—			914

Total Equity		8,691		134,004		96,981		(131,268	)		108,408

Notes

10.

Condensed consolidating information (continued)


	Issuer		Guarantor
Balance sheet	BP Exploration (Alaska) Inc		BP p.l.c.		Other subsidiaries		Eliminations and reclassification			BP group
At 30 June 2010 Non-current assets	$ million
Property, plant and equipment		7,530		—		98,964		—			106,494
Goodwill		—		—		8,250		—			8,250
Intangible assets		373		—		13,825		—			14,198
Investments in jointly controlled entities		—		—		15,256		—			15,256
Investments in associates		—		2		13,472		—			13,474
Other investments		—		—		1,071		—			1,071
Subsidiaries – equity-accounted basis		4,809		85,822		—		(90,631	)		—

Fixed assets		12,712		85,824		150,838		(90,631	)		158,743
Loans		192		38		5,386		(4,692	)		924
Other receivables		—		—		3,905		—			3,905
Derivative financial instruments		—		—		4,404		—			4,404
Prepayments		—		—		1,292		—			1,292
Deferred tax assets		—		—		421		—			421
Defined benefit pension plan surpluses		—		1,360		317		—			1,677

		12,904		87,222		166,563		(95,323	)		171,366


Current assets
Loans		—		—		244		—			244
Inventories		154		—		21,952		—			22,106
Trade and other receivables		18,920		31,399		41,792		(56,403	)		35,708
Derivative financial instruments		—		—		4,479		—			4,479
Prepayments		109		15		2,512		—			2,636
Current tax receivable		—		—		139		—			139
Other investments		—		—		1,654					1,654
Cash and cash equivalents		—		31		7,279		—			7,310

		19,183		31,445		80,051		(56,403	)		74,276

Assets classified as held for sale		—		—		2,973		—			2,973

Total assets		32,087		118,667		249,587		(151,726	)		248,615

Current liabilities
Trade and other payables		4,797		2,322		94,786		(56,403	)		45,502
Derivative financial instruments		—		—		4,583		—			4,583
Accruals		—		21		5,463		—			5,484
Finance debt		—		—		8,321		—			8,321
Current tax payable		145		—		2,469		—			2,614
Provisions		—		—		13,439		—			13,439

		4,942		2,343		129,061		(56,403	)		79,943

Liabilities directly associated with assets classified as held for sale		—		—		363		—			363

		4,942		2,343		129,424		(56,403	)		80,306

Non-current liabilities
Other payables		211		4,255		16,498		(4,692	)		16,272
Derivative financial instruments		—		—		4,181		—			4,181
Accruals		—		17		575		—			592
Finance debt		—		—		22,259		—			22,259
Deferred tax liabilities		1,880		305		8,864		—			11,049
Provisions		1,052		—		17,536		—			18,588
Defined benefit pension plan and other post-retirement benefit plan deficits		—		—		9,006		—			9,006

		3,143		4,577		78,919		(4,692	)		81,947

Total liabilities		8,085		6,920		208,343		(61,095	)		162,253

Net assets		24,002		111,747		41,244		(90,631	)		86,362

Equity
BP shareholders’ equity		24,002		111,747		40,372		(90,631	)		85,490
Minority interest		—		—		872		—			872

Total Equity		24,002		111,747		41,244		(90,631	)		86,362

Notes

10.

Condensed consolidating information (continued)


	Issuer			Guarantor
Cash flow statement	BP Exploration (Alaska) Inc			BP p.l.c.			Other subsidiaries			Eliminations and reclassification			BP group
	$ million
First half 2011
Net cash provided by operating activities		365			1,867			8,050			(30	)		10,252
Net cash used in investing activities		(364	)		(3	)		(10,997	)		—			(11,364	)
Net cash used in financing activities		—			(1,855	)		2,831			30			1,006
Currency translation differences relating to cash and cash equivalents		—			—			299			—			299

Increase in cash and cash equivalents		1			9			183			—			193
Cash and cash equivalents at beginning of period		(1	)		4			18,553			—			18,556

Cash and cash equivalents at end of period		—			13			18,736			—			18,749


	Issuer			Guarantor
Cash flow statement	BP Exploration (Alaska) Inc			BP p.l.c.			Other subsidiaries			Eliminations and reclassification			BP group
	$ million
First half 2010
Net cash provided by operating activities		422			2,952			13,775			(2,703	)		14,446
Net cash used in investing activities		(381	)		(189	)		(8,377	)		—			(8,947	)
Net cash used in financing activities		(19	)		(2,760	)		(6,213	)		2,703			(6,289	)
Currency translation differences relating to cash and cash equivalents		—			—			(239	)		—			(239	)

(Decrease) increase in cash and cash equivalents		22			3			(1,054	)		—			(1,029	)
Cash and cash equivalents at beginning of period		(22	)		28			8,333			—			8,339

Cash and cash equivalents at end of period		—			31			7,279			—			7,310

Principal risks and uncertainties

We urge you to consider these risks carefully. The potential impact of their occurrence could be for our business, financial condition and results of operations to suffer and the trading price and liquidity of our securities to decline.

Our system of risk management identifies and provides the response to risks of group significance through the establishment of standards and other controls. Any failure of this system could lead to the occurrence, or re-occurrence, of any of the risks described below and a consequent material adverse effect on BP’s business, financial position, results of operations, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda.

The risks are categorized against the following areas: strategic; compliance and control; and safety and operational. In addition, we have also set out two further risks for your attention – those resulting from the 2010 Gulf of Mexico oil spill (the Incident) and those related to the general macroeconomic outlook.

The Gulf of Mexico oil spill has had and could continue to have a material adverse impact on BP.

There is significant uncertainty in the extent and timing of costs and liabilities relating to the Incident, the impact of the Incident on our reputation and the resulting possible impact on our ability to access new opportunities. There is also significant uncertainty regarding potential changes in applicable regulations and the operating environment that may result from the Incident. These increase the risks to which the group is exposed and may cause our costs to increase. These uncertainties are likely to continue for a significant period. Thus, the Incident has had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US.

We recognized charges totalling $40.9 billion in 2010 and a credit of $0.2 billion during the first half of 2011 as a result of the Incident. The total amounts that will ultimately be paid by BP in relation to all obligations relating to the Incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, the amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any determination of BP’s negligence), the outcome of litigation, and any costs arising from any longer-term environmental consequences of the oil spill, will also impact upon the ultimate cost for BP. Although the provision recognized is the current best estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is not possible to measure the obligation reliably. The risks associated with the Incident could also heighten the impact of the other risks to which the group is exposed as further described below.

The general macroeconomic outlook can affect BP’s results given the nature of our business.

In the continuing uncertain financial and economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices can be very volatile, with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all businesses, which may impact costs and margins. At the same time, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks of the oil and gas industry, including the risk of increased taxation, nationalization and expropriation. The global financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition, business prospects and liquidity and may result in a decline in the trading price and liquidity of our securities.

Capital markets have regained some confidence after the banking crisis of 2008 but are still subject to volatility and if there are extended periods of constraints in these markets, or if we are unable to access the markets, including due to our financial position or market sentiment as to our prospects, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment programme may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.

Strategic risks

Access and renewal – BP’s future hydrocarbon production depends on our ability to renew and reposition our portfolio. Increasing competition for access to investment opportunities, the effects of the Gulf of Mexico oil spill on our reputation and cash flows, and more stringent regulation could result in decreased access to opportunities globally.

Successful execution of our group strategy depends on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally among both national and international oil companies, and heightened political and economic risks in certain countries where significant hydrocarbon basins are located. Lack of material positions in new markets could impact our future hydrocarbon production.

Principal risks and uncertainties (continued)

Moreover, the Gulf of Mexico oil spill has damaged BP’s reputation, which may have a long-term impact on the group’s ability to access new opportunities, both in the US and elsewhere. Adverse public, political and industry sentiment towards BP, and towards oil and gas drilling activities generally, could damage or impair our existing commercial relationships with counterparties, partners and host governments and could impair our access to new investment opportunities, exploration properties, operatorships or other essential commercial arrangements with potential partners and host governments, particularly in the US. In addition, responding to the Incident has placed, and will continue to place, a significant burden on our cash flow over the next several years, which could also impede our ability to invest in new opportunities and deliver long-term growth.

More stringent regulation of the oil and gas industry generally, and of BP’s activities specifically, arising from the Incident, could increase this risk.

Prices and markets – BP’s financial performance is subject to the fluctuating prices of crude oil and gas as well as the volatile prices of refined products and the profitability of our refining and petrochemicals operations.

Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price. Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.

Refining profitability can be volatile, with both periodic over-supply and supply tightness in various regional markets, coupled with fluctuations in demand. Sectors of the petrochemicals industry are also subject to fluctuations in supply and demand, with a consequent effect on prices and profitability.

Climate change and carbon pricing – climate change and carbon pricing policies could result in higher costs and reduction in future revenue and strategic growth opportunities.

Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Our commitment to the transition to a lower-carbon economy may create expectations for our activities, and the level of participation in alternative energies carries reputational, economic and technology risks.

Socio-political – the diverse nature of our operations around the world exposes us to a wide range of political developments and consequent changes to the operating environment, regulatory environment and law.

We have operations, and are seeking new opportunities, in countries where political, economic and social transition is taking place. Some countries have experienced, or may experience in the future, political instability, changes to the regulatory environment, changes in taxation, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, could limit our ability to pursue new opportunities and could cause us to incur additional costs. In particular, our investments in the US, Russia, Iraq, Egypt, Libya and other countries could be adversely affected by heightened political and economic environment risks. See Annual Report and Form 20-F 2010 pages 14 – 15 for information on the locations of our major assets and activities.

We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.

Competition – BP’s group strategy depends upon continuous innovation in a highly competitive market.

The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency, while ensuring safety and operational risk is not compromised. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.

Investment efficiency – poor investment decisions could negatively impact our business.

Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection and development could lead to loss of value and higher capital expenditure.

Principal risks and uncertainties (continued)

Reserves replacement – inability to progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves and negatively impact our business.

Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.

Liquidity, financial capacity and financial exposure – failure to operate within our financial framework could impact our ability to operate and result in financial loss. Exchange rate fluctuations can impact our underlying costs and revenues.

The group seeks to maintain a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity. This framework constrains the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to accurately forecast or maintain sufficient liquidity and credit to meet these needs could impact our ability to operate and result in a financial loss. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth and to meet our obligations. The change in the group’s financial framework during 2010 to make it more prudent may not be sufficient to avoid a substantial and unexpected cash call.

BP’s clean-up costs and potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Gulf of Mexico oil spill, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. Furthermore, we have recognized a total charge of $40.9 billion during 2010 and a credit of $0.2 billion during the first half of 2011, and further potential liabilities may continue to have a material adverse effect on the group’s results of operations and financial condition. See Note 2 on page 23 – 28 and Legal proceedings on pages 46 – 49. More stringent regulation of the oil and gas industry arising from the Incident, and of BP’s activities specifically, could increase this risk.

Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues.

For more information on financial instruments and financial risk factors see Annual Report and Form 20-F 2010 – Note 27 on page 185.

Insurance – BP’s insurance strategy means that the group could, from time to time, be exposed to material uninsured losses which could have a material adverse effect on BP’s financial condition and results of operations.

In the context of the limited capacity of the insurance market, many significant risks are retained by BP. The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This means that the group could be exposed to material uninsured losses, which could have a material adverse effect on its financial condition and results of operations. In particular, these uninsured costs could arise at a time when BP is facing material costs arising out of some other event which could put pressure on BP’s liquidity and cash flows. For example, BP has borne and will continue to bear the entire burden of its share of any property damage, well control, pollution clean-up and third-party liability expenses arising out of the Gulf of Mexico oil spill incident.

Compliance and control risks

Regulatory – the oil industry in general, and in particular the US industry following the Gulf of Mexico oil spill, may face increased regulation that could increase the cost of regulatory compliance and limit our access to new exploration properties.

The Gulf of Mexico oil spill is likely to result in more stringent regulation of oil and gas activities in the US and elsewhere, particularly relating to environmental, health and safety controls and oversight of drilling operations, as well as access to new drilling areas. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards BP. The US government imposed a moratorium on certain offshore drilling activities, which was subsequently lifted in October 2010. While the industry has resumed drilling activity, BP has not yet done so. BP has, however, restarted rig operations. Similar actions may be taken by governments elsewhere in the world. New regulations and legislation, as well as evolving practices, could increase the cost of compliance and may require changes to our drilling operations, exploration, development and decommissioning plans, and could impact our ability to capitalize on our assets and limit our access to new exploration properties or operatorships, particularly in the deepwater Gulf of Mexico. In addition, increases in taxes, royalties and other amounts payable to governments or governmental agencies, or restrictions on availability of tax relief, could also be imposed as a response to the Incident.

Principal risks and uncertainties (continued)

In addition, the oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental, health and safety controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs.

For more information on environmental regulation, see Annual Report and Form 20-F 2010 pages 78 – 81.

Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our employees could be damaging to our reputation and shareholder value.

Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations, including non-compliance with anti-bribery, anti-corruption and other applicable laws could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations. For example, in our trading businesses, there is the risk that a determined individual could operate as a ‘rogue trader’, acting outside BP’s delegations, controls or code of conduct in pursuit of personal objectives that could be to the detriment of BP and its shareholders.

For certain legal proceedings involving the group, see Legal proceedings on pages 46 – 49. For further information on the risks involved in BP’s trading activities, see Operational risks – Treasury and trading activities on page 45.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Gulf of Mexico oil spill, together with the potential cost and burdens of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had, and are expected to continue to have, a material adverse impact on the group’s business.

Under the OPA 90 BP Exploration & Production Inc. is one of the parties financially responsible for the clean-up of the Gulf of Mexico oil spill and for certain economic damages as provided for in OPA 90, as well as any natural resource damages associated with the spill and certain costs incurred by federal and state trustees engaged in a joint assessment of such natural resource damages.

BP and certain of its subsidiaries have also been named as defendants in numerous lawsuits in the US arising out of the Incident, including actions for personal injury and wrongful death, purported class actions for commercial or economic injury, actions for breach of contract, violations of statutes, property and other environmental damage, securities law claims and various other claims. See Legal proceedings on pages 46 – 49.

BP is subject to a number of investigations related to the Incident by numerous federal and State agencies. See Legal proceedings on pages 46 – 49. The types of enforcement action pursued and the nature of the remedies sought will depend on the discretion of the prosecutors and regulatory authorities and their assessment of BP’s culpability following their investigations. Such enforcement actions could include criminal proceedings against BP and/or employees of the group. In addition to fines and penalties, such enforcement actions could result in the suspension of operating licences and debarment from government contracts. Debarment of BP Exploration & Production Inc. would prevent it from bidding on or entering into new federal contracts or other federal transactions, and from obtaining new orders or extensions to existing federal contracts, including federal procurement contracts or leases. Dependent on the circumstances, debarment or suspension may also be sought against affiliated entities of BP Exploration & Production Inc. Although BP believes that there are costs arising out of the spill that are recoverable from its partners and other parties responsible under OPA 90, and although settlements have been agreed with one partner and one contractor during the second quarter, further recoveries are not certain and so have not been recognized in the financial statements (see Note 2 on pages 23 – 28).

Any finding of gross negligence for purposes of penalties sought against the group under the Clean Water Act would also have a material adverse impact on the group’s reputation, would affect our ability to recover costs relating to the Incident from our partners and other parties responsible under OPA 90 and could affect the fines and penalties payable by the group with respect to the Incident under enforcement actions outside the Clean Water Act context.

The Gulf of Mexico oil spill has damaged BP’s reputation. This, combined with other recent events in the US (including the 2005 explosion at the Texas City refinery and the 2006 pipeline leaks in Alaska), may lead to an increase in the number of citations and/or the level of fines imposed in relation to the Gulf of Mexico oil spill and any future alleged breaches of safety or environmental regulations.

Principal risks and uncertainties (continued)

Claims by individuals and businesses under OPA 90 are adjudicated by the Gulf Coast Claims Facility (GCCF) headed by Kenneth Feinberg, who was jointly appointed by BP and the US Administration. On 18 February 2011, the GCCF announced its final rules governing payment options, eligibility and substantiation criteria, and final payment methodology. The impact of these rules, or other events related to the adjudication of claims, on future payments by the GCCF is uncertain. Payments could ultimately be significantly higher or lower than the amount we have estimated for individual and business claims under OPA 90 included in the provision BP recognized for litigation and claims. See Note 2 on pages 23 – 28.

Changes in external factors could affect our results of operations and the adequacy of our provisions.

We remain exposed to changes in the external environment, such as new laws and regulations (whether imposed by international treaty or by national or local governments in the jurisdictions in which we operate), changes in tax or royalty regimes, price controls, government actions to cancel or renegotiate contracts, market volatility or other factors. Such factors could reduce our profitability from operations in certain jurisdictions, limit our opportunities for new access, require us to divest or write-down certain assets or affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities. Potential changes to pension or financial market regulation could also impact funding requirements of the group.

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

External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation.

Safety and operational risks

The risks inherent in our operations include a number of hazards that, although many may have a low probability of occurrence, can have extremely serious consequences if they do occur, such as the Gulf of Mexico incident. The occurrence of any such risks could have a consequent material adverse impact on the group’s business, competitive position, cash flows, results of operations, financial position, prospects, liquidity, shareholder returns and/or implementation of the group’s strategic goals.

Process safety, personal safety and environmental risks – the nature of our operations exposes us to a wide range of significant health, safety, security and environmental risks, the occurrence of which could result in regulatory action, legal liability and increased costs and damage to our reputation.

The nature of the group’s operations exposes us to a wide range of significant health, safety, security and environmental risks. The scope of these risks is influenced by the geographic range, operational diversity and technical complexity of our activities. In addition, in many of our major projects and operations, risk allocation and management is shared with third parties, such as contractors, sub-contractors, joint venture partners and associates. See ‘Joint ventures and other contractual arrangements – BP may not have full operational control and may have exposure to counterparty credit risk and disruptions to our operations due to the nature of some of its business relationships’ on page 45.

There are risks of technical integrity failure as well as risk of natural disasters and other adverse conditions in many of the areas in which we operate, which could lead to loss of containment of hydrocarbons and other hazardous material, as well as the risk of fires, explosions or other incidents.

In addition, inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.

Our operations are often conducted in difficult or environmentally sensitive locations, in which the consequences of a spill, explosion, fire or other incident could be greater than in other locations. These operations are subject to various environmental laws, regulations and permits and the consequences of failure to comply with these requirements can include remediation obligations, penalties, loss of operating permits and other sanctions. Accordingly, inherent in our operations is the risk that if we fail to abide by environmental and safety and protection standards, such failure could lead to damage to the environment and could result in regulatory action, legal liability, material costs and damage to our reputation or licence to operate.

To help address health, safety, security, environmental and operations risks, and to provide a consistent framework within which the group can analyze the performance of its activities and identify and remediate shortfalls, BP implemented a group-wide operating management system (OMS). The embedding of OMS continues and following the Gulf of Mexico oil spill an enhanced S&OR function has been established, reporting directly to the group chief executive. There can be no assurance that OMS will adequately identify all process safety, personal safety and environmental risk or provide the correct mitigations, or that all operations will be in compliance with OMS at all times.

Security – hostile activities against our staff and activities could cause harm to people and disrupt our operations.

Security threats require continuous oversight and control. Acts of terrorism, piracy, sabotage and similar activities directed against our operations and offices, pipelines, transportation or computer systems could cause harm to people and could severely disrupt business and operations. Our business activities could also be severely disrupted by civil strife and political unrest in areas where we operate.

Principal risks and uncertainties (continued)

Product quality – failure to meet product quality standards could lead to harm to people and the environment and loss of customers.

Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers.

Drilling and production – these activities require high levels of investment and are subject to natural hazards and other uncertainties. Activities in challenging environments heighten many of the drilling and production risks including those of integrity failures, which could lead to curtailment, delay or cancellation of drilling operations, or inadequate returns from exploration expenditure.

Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. Our exploration and production activities are often conducted in extremely challenging environments, which heighten the risks of technical integrity failure and natural disasters discussed above. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. In addition, exploration expenditure may not yield adequate returns, for example in the case of unproductive wells or discoveries that prove uneconomic to develop. The Gulf of Mexico incident illustrates the risks we face in our drilling and production activities.

Transportation – all modes of transportation of hydrocarbons involve inherent and significant risks.

All modes of transportation of hydrocarbons involve inherent risks. An explosion or fire or loss of containment of hydrocarbons or other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.

Major project delivery – our group plan depends upon successful delivery of major projects, and failure to deliver major projects successfully could adversely affect our financial performance.

Successful execution of our group plan depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production or production growth, including maintenance turnaround programmes, and/or a major programme designed to enhance shareholder value could adversely affect our financial performance. Successful project delivery requires, among other things, adequate engineering and other capabilities and therefore successful recruitment and development of staff is central to our plans. See ‘People and capability – successful recruitment and development of staff is central to our plans’ below.

Digital infrastructure is an important part of maintaining our operations, and a breach of our digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment and breaches of regulations.

The reliability and security of our digital infrastructure are critical to maintaining the availability of our business applications. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations.

Business continuity and disaster recovery – the group must be able to recover quickly and effectively from any disruption or incident, as failure to do so could adversely affect our business and operations.

Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations.

Crisis management – crisis management plans are essential to respond effectively to emergencies and to avoid a potentially severe disruption in our business and operations.

Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond, or are perceived not to respond, in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

People and capability – successful recruitment and development of staff is central to our plans.

Successful recruitment of new staff, employee training, development and long-term renewal of skills, in particular technical capabilities such as petroleum engineers and scientists, are key to implementing our plans. Inability to develop human capacity and capability, both across the organization and in specific operating locations, could jeopardize performance delivery.

In addition, significant management focus is required in responding to the Gulf of Mexico oil spill Incident. Although BP set up the Gulf Coast Restoration Organization to manage the group’s long-term response, key management and operating personnel will need to continue to devote substantial attention to responding to the Incident and to address the associated consequences for the group. The group relies on recruiting and retaining high-quality employees to execute its strategic plans and to operate its business. The Incident response has placed significant demands on our employees, and the reputational damage suffered by the group as a result of the Incident and any consequent adverse impact on our performance could affect employee recruitment and retention.

Principal risks and uncertainties (continued)

Treasury and trading activities – control of these activities depends on our ability to process, manage and monitor a large number of transactions. Failure to do this effectively could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.

Following the Gulf of Mexico oil spill, Moody’s Investors Service, Standard and Poor’s and Fitch Ratings downgraded the group’s long-term credit ratings. Since that time, the group’s credit ratings have improved somewhat but are still lower than they were immediately before the Gulf of Mexico oil spill. The impact that a significant operational incident can have on the group’s credit ratings, taken together with the reputational consequences of any such incident, the ratings and assessments published by analysts and investors’ concerns about the group’s costs arising from any such incident, ongoing contingencies, liquidity, financial performance and volatile credit spreads, could increase the group’s financing costs and limit the group’s access to financing. The group’s ability to engage in its trading activities could also be impacted due to counterparty concerns about the group’s financial and business risk profile in such circumstances. Such counterparties could require that the group provide collateral or other forms of financial security for its obligations, particularly if the group’s credit ratings are downgraded. Certain counterparties for the group’s non-trading businesses could also require that the group provide collateral for certain of its contractual obligations, particularly if the group’s credit ratings were downgraded below investment grade or where a counterparty had concerns about the group’s financial and business risk profile following a significant operational incident. In addition, BP may be unable to make a drawdown under certain of its committed borrowing facilities in the event we are aware that there are pending or threatened legal, arbitration or administrative proceedings which, if determined adversely, might reasonably be expected to have a material adverse effect on our ability to meet the payment obligations under any of these facilities. Credit rating downgrades could trigger a requirement for the company to review its funding arrangements with the BP pension trustees. Extended constraints on the group’s ability to obtain financing and to engage in its trading activities on acceptable terms (or at all) would put pressure on the group’s liquidity. In addition, this could occur at a time when cash flows from our business operations would be constrained following a significant operational incident, and the group could be required to reduce planned capital expenditures and/or increase asset disposals in order to provide additional liquidity, as the group did following the Gulf of Mexico oil spill.

Joint ventures and other contractual arrangements – BP may not have full operational control and may have exposure to counterparty credit risk and disruptions to our operations and strategic objectives due to the nature of some of its business relationships.

Many of our major projects and operations are conducted through joint ventures or associates and through contracting and sub-contracting arrangements. These arrangements often involve complex risk allocation, decision-making processes and indemnification arrangements. In certain cases, we may have less control of such activities than we would have if BP had full operational control. Our partners may have economic or business interests or objectives that are inconsistent with or opposed to, those of BP, and may exercise veto rights to block certain key decisions or actions that BP believes are in its or the joint venture’s or associate’s best interests, or approve such matters without our consent. Additionally, our joint venture partners or associates or contractual counterparties are primarily responsible for the adequacy of the human or technical competencies and capabilities which they bring to bear on the joint project, and in the event these are found to be lacking, our joint venture partners or associates may not be able to meet their financial or other obligations to their counterparties or to the relevant project, potentially threatening the viability of such projects. Furthermore, should accidents or incidents occur in operations in which BP participates, whether as operator or otherwise, and where it is held that our sub-contractors or joint-venture partners are legally liable to share any aspects of the cost of responding to such incidents, the financial capacity of these third parties may prove inadequate to fully indemnify BP against the costs we incur on behalf of the joint venture or contractual arrangement. Should a key sub-contractor, such as a lessor of drilling rigs, be no longer able to make these assets available to BP, this could result in serious disruption to our operations. Where BP does not have operational control of a venture, BP may nonetheless still be pursued by regulators or claimants in the event of an incident.

Legal proceedings

Proceedings relating to the Gulf of Mexico oil spill

BP p.l.c., BP Exploration & Production Inc. (BP E&P) and various other BP entities (collectively referred to as BP) are among the companies named as defendants in more than 500 private civil lawsuits resulting from the 20 April 2010 explosions and fire on the semi-submersible rig Deepwater Horizon and resulting oil spill (the Incident) and further actions are likely to be brought. BP E&P is lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico (Macondo), where the Deepwater Horizon was deployed at the time of the Incident, and holds a 65% working interest. The other working interest owners are Anadarko Petroleum Company (Anadarko) and MOEX Offshore 2007 LLC (MOEX). The Deepwater Horizon, which was owned and operated by certain affiliates of Transocean, Ltd. (Transocean), sank on 22 April 2010. The pending lawsuits and/or claims arising from the Incident have been brought in US federal and state courts. Plaintiffs include individuals, corporations and governmental entities and many of the lawsuits purport to be class actions. The lawsuits assert, among other things, claims for personal injury in connection with the Incident itself and the response to it, wrongful death, commercial and economic injury, breach of contract and violations of statutes. The lawsuits seek various remedies including compensation to injured workers and families of deceased workers, recovery for commercial losses and property damage, claims for environmental damage, remediation costs, injunctive relief, treble damages and punitive damages. Purported classes of claimants include residents of the states of Louisiana, Mississippi, Alabama, Florida, Texas, Tennessee, Kentucky, Georgia and South Carolina, property owners and rental agents, fishermen and persons dependent on the fishing industry, charter boat owners and deck hands, marina owners, gasoline distributors, shipping interests, restaurant and hotel owners, cruise lines and others who are property and/or business owners alleged to have suffered economic loss. Among other claims arising from the spill response efforts, lawsuits have been filed claiming that additional payments are due by BP under certain Master Vessel Charter Agreements entered into in the course of the Vessels of Opportunity Program.

Shareholder derivative lawsuits related to the Incident have also been filed in US federal and state courts against various current and former officers and directors of BP alleging, among other things, breach of fiduciary duty, gross mismanagement, abuse of control and waste of corporate assets. Purported class action lawsuits have also been filed in US federal courts against BP entities and various current and former officers and directors alleging, among other things, securities fraud claims, violations of the Employee Retirement Income Security Act (ERISA) and contractual and quasi-contractual claims related to the cancellation of the dividend on 16 June 2010. In addition, BP has been named in several lawsuits alleging claims under the Racketeer-Influenced and Corrupt Organizations Act (RICO). In August 2010, many of the lawsuits pending in federal court were consolidated by the Federal Judicial Panel on Multidistrict Litigation into two multi-district litigation proceedings, one in federal court in Houston for the securities, derivative and ERISA cases and another in federal court in New Orleans for the remaining cases. Since late September 2010, most of the Deepwater Horizon related cases have been pending before these courts.

On 1 June 2010, the US Department of Justice (DoJ) announced that it is conducting an investigation into the Incident encompassing possible violations of US civil or criminal laws. The United States filed a civil complaint against BP E&P and others on 15 December 2010 (DoJ Action). The complaint seeks a declaration of liability under the Oil Pollution Act of 1990 (OPA 90) and civil penalties under the Clean Water Act and sets forth a purported reservation of rights on behalf of the US to amend the complaint or file additional complaints seeking various remedies under various US federal laws and statutes.

On 18 February 2011, Transocean filed a third party complaint against BP, the US government, and other corporations involved in the Incident, naming those entities as formal parties in its Limitation of Liability action pending in federal court in New Orleans.

On 4 April 2011, BP initiated contractual out-of-court dispute resolution proceedings against Anadarko and MOEX, claiming that they have breached the parties’ contract by failing to reimburse BP for their working-interest share of Incident-related costs. On 19 April 2011, Anadarko filed a cross-claim against BP, alleging gross negligence and 15 other counts under state and federal laws. Anadarko seeks a declaration that it is excused from its contractual obligation to pay Incident-related costs. Anadarko also seeks damages from alleged economic losses and contribution or indemnity for claims filed against it by other parties. On 20 May 2011, BP and MOEX announced a settlement agreement of all claims between them, including a cross-claim brought by MOEX on 19 April 2011 similar to the Anadarko claim. On 15 July 2011, the judge in the federal multi-district litigation proceeding in New Orleans stayed Anadarko’s claims against BP pursuant to the arbitration clause in the operating agreement between the parties pertaining to the Macondo well.

On 20 April 2011, Transocean filed claims in its Limitation of Liability action alleging that BP had breached BP America Production Company’s contract with Transocean Holdings LLC by BP not agreeing to indemnify Transocean against liability related to the Incident and by not paying certain invoices. Transocean also asserted claims against BP under state law, maritime law, and OPA 90 for contribution.

On 20 April 2011, Halliburton Energy Services, Inc. (Halliburton), filed claims in Transocean’s Limitation of Liability action seeking indemnification from BP for claims brought against Halliburton in that action, and Cameron International Corporation (Cameron) asserted claims against BP for contribution under state law, maritime law, and OPA 90, as well as for contribution on the basis of comparative fault. Halliburton also asserted a claim for negligence, gross negligence and willful misconduct against BP and others. On 19 April 2011, Halliburton filed a separate lawsuit in Texas state court seeking indemnification from BP E&P for certain tort and pollution-related liabilities resulting from the Incident and resulting oil spill.

Legal proceedings (continued)

On 20 April 2011, BP asserted claims against Cameron, Halliburton, and Transocean in the Limitation of Liability action. BP’s claims against Transocean include breach of contract, unseaworthiness of the Deepwater Horizon vessel, negligence (or gross negligence and/or gross fault as may be established at trial based upon the evidence), contribution and subrogation for costs (including those arising from litigation claims) resulting from the Incident and oil spill, as well as a declaratory claim that Transocean is wholly or partly at fault for the Incident and responsible for its proportionate share of the costs and damages. BP’s claims against Cameron assert that Cameron is liable under maritime law for providing a Blowout Preventer (BOP) that was unreasonably dangerous in design based on certain design defects, that Cameron was negligent with respect to certain maintenance and repair that it conducted on the Deepwater Horizon BOP, and that Cameron is liable to BP for contribution and subrogation of the damages, costs and expenses that BP has paid and will continue to pay relating to BP’s response efforts and the various claims brought against BP. BP asserted claims against Halliburton for fraud and fraudulent concealment based on Halliburton’s misrepresentations to BP concerning, among other things, the stability testing on the foamed cement used at the Macondo well; for negligence (or, if established by the evidence at trial, gross negligence) based on Halliburton’s performance of its professional services, including cementing and mud logging services; and for contribution and subrogation for amounts that BP has paid in responding to the Incident and oil spill, as well as in OPA assessments and in payments to plaintiffs. BP filed a similar complaint in federal court in the Southern District of Texas, Houston Division, against Halliburton, and the action was transferred on 4 May 2011 to the federal multi-district litigation proceedings pending in New Orleans.

On 20 April 2011, BP filed claims against Cameron, Halliburton, and Transocean in the DoJ Action, seeking contribution for any assessments against BP under OPA 90 based on those entities’ fault. On 20 June 2011, Cameron moved to strike BP’s tender of Cameron as liable to the US. That motion remains pending.

On 20 May 2011, Dril-Quip, Inc. and M-I L.L.C. filed claims against BP in Transocean’s Limitation of Liability action, each claiming a right to contribution from BP for damages assessed against them as a result of the Incident, based on allegations of negligence. M-I L.L.C. also claimed a right to indemnity for such damages based on their well services contracts with BP. On 20 June 2011, BP filed counter-complaints against Dril-Quip, Inc. and M-I L.L.C., asking for contribution and subrogation based on those entities’ fault in connection with the Incident and under OPA, and seeking declaratory judgment that Dril-Quip, Inc. and M-I L.L.C. caused or contributed to, and are responsible in whole or in part for damages incurred by BP in relation to, the Incident.

On 30 May 2011, Transocean filed claims against BP in the DoJ Action alleging that BP America Production Company had breached its contract with Transocean Holdings LLC by not agreeing to indemnify Transocean against liability related to the Incident. Transocean also asserted claims against BP under state law, maritime law, and OPA 90 for contribution. On 20 June 2011, Cameron filed similar claims against BP in the DoJ Action.

The State of Alabama has filed a lawsuit seeking damages for alleged economic and environmental harms, including natural resource damages, civil penalties under state law, declaratory and injunctive relief, and punitive damages as a result of the Incident. The State of Louisiana has filed a lawsuit to declare various BP entities (as well as other entities) liable for removal costs and damages, including natural resource damages under federal and state law, to recover civil penalties, attorney’s fees, and response costs under state law, and to recover for alleged negligence, nuisance, trespass, fraudulent concealment and negligent misrepresentation of material facts regarding safety procedures and BP’s (and other defendants’) ability to manage the oil spill, unjust enrichment from economic and other damages to the State of Louisiana and its citizens, and punitive damages. The Louisiana Department of Environmental Quality has issued an administrative order seeking injunctive relief and environmental civil penalties under state law, and several local governments in the State of Louisiana have filed suits under state wildlife statutes seeking penalties for damage to wildlife as a result of the spill. On 10 December 2010, the Mississippi Department of Environmental Quality issued a Complaint and Notice of Violation alleging violations of several State environmental statutes.

On 15 September 2010, three Mexican states bordering the Gulf of Mexico (Veracruz, Quintana Roo, and Tamaulipas) filed lawsuits in federal court in Texas against several BP entities. These lawsuits allege that the Incident harmed their tourism, fishing, and commercial shipping industries (resulting in, among other things, diminished tax revenue), damaged natural resources and the environment, and caused the states to incur expenses in preparing a response to the Incident. On 5 April 2011, the State of Yucatan submitted a claim to the GCCF alleging potential damage to its natural resources and environment, and seeking to recover the cost of assessing the alleged damage.

Citizens groups have also filed either lawsuits or notices of intent to file lawsuits seeking civil penalties and injunctive relief under the Clean Water Act and other environmental statutes. On 16 June 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted BP’s motion to dismiss a master complaint raising claims for injunctive relief under various federal environmental statutes brought by various citizens groups and others. The judge did not, however, lift an earlier stay on the underlying individual complaints raising those claims for injunctive relief or otherwise apply his dismissal of the master complaint to those individual complaints. A motion for clarification has been filed asking the judge to clarify whether the dismissal of the master complaint also applies to the individual complaints. On 15 July 2011, the judge granted BP’s motion to dismiss a master complaint raising RICO claims against BP. The court’s order dismissed the claims of the plaintiffs in four RICO cases encompassed by the master complaint.

The DoJ announced on 7 March 2011 that it created a unified task force of federal agencies, led by the DoJ Criminal Division, to investigate the Gulf of Mexico incident. Other US federal agencies may commence investigations relating to the Incident. The SEC and DoJ are investigating securities matters arising in relation to the Incident.

Legal proceedings (continued)

BP’s potential liabilities resulting from threatened, pending and potential future claims, lawsuits and enforcement actions relating to the Incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had and are expected to have a material adverse impact on the group’s business, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. These potential liabilities may continue to have a material adverse effect on the group’s results and financial condition. See Note 2 on pages 23 – 28 for information regarding the financial impact in 2011 of the Incident and see the financial statements contained in BP’s Annual Report and Form 20-F 2010 for information regarding 2010.

Investigations and reports relating to the Gulf of Mexico Oil Spill

BP is subject to a number of investigations related to the Incident by numerous agencies of the US government. The related published reports are available on the websites of the agencies and commissions referred to below.

On 11 January 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission), established by President Obama, published its report on the causes of the Incident and its recommendations for policy and regulatory changes for offshore drilling. On 17 February 2011, the National Commission’s Chief Counsel published a separate report on his investigation that provides additional information regarding the causes of the Incident.

In a report dated 20 March 2011, with an Addendum dated 30 April 2011, the Joint Investigation Team (JIT) for the Marine Board of Investigation established by the US Coast Guard and Bureau of Ocean Energy Management (BOEMRE) issued the Final Report of the Forensic Examination of the Deepwater Horizon Blowout Preventer (BOP) prepared by Det Norske Veritas (BOP Report). The BOP Report concludes that the position of the drill pipe against the blind shear rams prevented the BOP from functioning as intended. Subsequently, BP helped to sponsor additional BOP testing conducted by Det Norske Veritas under court auspices, which concluded on 21 June 2011. BP continues to review the BOP Report and is in the process of evaluating the data obtained from the additional testing.

On 22 April 2011, the US Coast Guard issued its report (Maritime Report) focused upon the maritime aspects of the Incident. The Maritime Report criticizes Transocean’s maintenance operations and safety culture, while also criticizing the Republic of the Marshall Islands — the flag state responsible for certifying Transocean’s Deepwater Horizon vessel. The BOEMRE is expected to issue a subsequent report that will likely focus more heavily on the drilling aspects of the Incident and hence the roles of BP, Halliburton and Cameron.

The US Chemical Safety and Hazard Investigation Board (CSB) is also conducting an investigation of the Incident that is focused on the explosions and fire, and not the resulting oil spill or response efforts. The CSB is expected to issue a single investigation report in late 2011 or early 2012 that will seek to identify the alleged root cause(s) of the Incident, and recommend improvements to BP and industry practices and to regulatory programmes to prevent recurrence and mitigate potential consequences.

Also, at the request of the Department of the Interior, the National Academy of Engineering/National Research Council established a Committee (Committee) to examine the performance of the technologies and practices involved in the probable causes of the Incident and to identify and recommend technologies, practices, standards and other measures to avoid similar future events. On 17 November 2010 the Committee publicly released its interim report setting forth the Committee’s preliminary findings and observations on various actions and decisions including well design, cementing operations, well monitoring, and well control actions. The interim report also considers management, oversight, and regulation of offshore operations. The Committee has stated that it will issue its final report, including findings and/or recommendations, in late summer 2011 (a public pre-publication version of report), with a published version to follow by 30 December 2011. A second, unrelated National Academies’ Committee will be looking at the methodologies available for assessing spill impacts on ecosystems in the Gulf of Mexico, with a final report expected in the latter part of 2012, and a third National Academies’ Committee will be studying methods for assessing the effectiveness of safety and environmental management systems (SEMS) established by offshore oil and gas operators. This third Committee expects to complete the final report of recommendations by 30 December 2011.

On 10 March 2011, the Flow Rate Technical Group (FRTG), Department of the Interior, issued its final report titled “Assessment of Flow Rate Estimates for the Deepwater Horizon/Macondo Well Oil Spill.” The report provides a summary of the strengths and limitations of the different methods used by the US government to estimate the flow rate and a range of estimates from 13mb/d to over 100mb/d. The report concludes that the most accurate estimate was 53mb/d just prior to shut in, with an uncertainty on that value of ±10% based on FRTG collective experience and judgment, and, based on modeling, the flow on day one of the Incident was 62mb/d. BP is currently reviewing the report.

On 18 March 2011 the US Coast Guard ISPR team released its final report capturing lessons learned from the incident as well as making recommendations on how to improve future oil spill response and recovery efforts.

Additionally, BP representatives have appeared before multiple committees of the US Congress that have been conducting inquiries into the Incident. BP has provided documents and written information in response to requests by these committees and will continue to do so.

Legal proceedings (continued)

Other legal proceedings

The following discussion sets forth the developments in the group’s other material legal proceedings during the recent period. Other pending material legal proceedings are described in the group’s results announcement for the period ended 31 March 2011.

A shareholder derivative action was filed against several current and former BP officers and directors based on alleged violations of the US Clean Air Act (CAA) and Occupational Safety and Health Administration (OSHA) regulations at the Texas City refinery subsequent to the March 2005 explosion and fire. An investigation by a special committee of BP’s board into the shareholder allegations has been completed and the committee has recommended that the allegations do not warrant action by BP against the officers and directors. BP has filed a motion to dismiss the shareholder derivative action and a plea to the jurisdiction. On 16 June 2011, the court granted BP’s plea to the jurisdiction and dismissed the action in its entirety.

On 29 November 2007, BP Exploration (Alaska) Inc. (BPXA) entered into a criminal plea agreement with the DoJ relating to leaks of crude oil in March and August 2006. BPXA’s guilty plea, to a misdemeanour violation of the US Water Pollution Control Act, included a term of three years’ probation. On 29 November, 2009 a spill of approximately 360 barrels of crude oil and produced water was discovered beneath a line running from a well pad to the Lisburne Processing Center in Prudhoe Bay, Alaska. On 17 November 2010, the US Probation Officer filed a petition in federal district court to revoke BPXA’s probation based on an allegation that the Lisburne event was a criminal violation of state or federal law. A hearing is scheduled for the week of 11 October 2011. On 12 May 2008, a BP p.l.c. shareholder filed a consolidated complaint alleging violations of federal securities law on behalf of a putative class of BP p.l.c. shareholders against BP p.l.c., BPXA, BP America, and four officers of the companies, based on alleged misrepresentations concerning the integrity of the Prudhoe Bay pipeline before its shutdown on 6 August 2006. On 8 February 2010, the Ninth Circuit Court of Appeals accepted BP’s appeal from a decision of the lower court granting in part and denying in part BP’s motion to dismiss the lawsuit. On 29 June 2011, the Ninth Circuit ruled in BP’s favor that the filing of a trust related agreement with the SEC containing contractual obligations on the part of BP was not a misrepresentation which violated federal securities laws. On 31 March 2009, the State of Alaska filed a complaint seeking civil penalties and damages relating to these events. The complaint alleges that the two releases and BPXA’s corrosion management practices violated various statutory, contractual and common law duties to the State, resulting in penalty liability, damages for lost royalties and taxes, and liability for punitive damages.

In April 2009, Kenneth Abbott, as relator, filed a US False Claims Act lawsuit against BP, alleging that BP violated federal regulations, and made false statements in connection with its compliance with those regulations, by failing to have necessary documentation for the Atlantis subsea and other systems. BP is the operator and 56% interest owner of the Atlantis unit in production in the Gulf of Mexico. That complaint was unsealed in May 2010 and served on BP in June 2010. In September 2010, Kenneth Abbott and Food & Water Watch filed an amended complaint in the False Claims Act lawsuit seeking an injunction shutting down the Atlantis platform. The court denied BP’s motion to dismiss the complaint in March 2011. Separately, also in March 2011, BOEMRE issued its investigation report of the Abbott Atlantis allegations, which concluded that Mr. Abbott’s allegations that Atlantis operations personnel lacked access to critical, engineer-approved drawings were without merit and that his allegations about false submissions by BP to BOEMRE were unfounded. Trial is scheduled to begin on 5 March 2012.

On 17 May 2011, BP announced that both the Rosneft Share Swap Agreement and the Arctic Opportunity, originally announced on 14 January 2011, had terminated. This termination was as a result of the deadline for the satisfaction of conditions precedent having expired following delays resulting from interim orders granted by the English High Court and a UNCITRAL arbitration tribunal after applications brought by Alfa Petroleum Holdings Limited (Alfa) and OGIP Ventures Limited (OGIP) against BP International Limited (BPIL) and BP Russian Investments Limited (BPRIL) alleging breach of the related TNK-BP shareholders agreement (SHA). These interim orders did not address the question of whether or not BP breached the SHA.

The UNCITRAL arbitration proceedings with Alfa, Access and Renova (AAR) are still ongoing and AAR has now provided notice of its intention to bring a claim for breach of the SHA in the arbitration although they have stated they do not require the tribunal to determine the question of loss or quantum of damages. BP intends to strongly defend any such action or claim. No procedural timetable for the resolution of this dispute has yet been determined.

Signatures

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

BP p.l.c.

(Registrant)

Dated: 26 July 2011

/s/ D J Pearl

D J PEARL

Deputy Company Secretary

Exhibit 99.1

Computation of ratio of earnings to fixed charges


	Half year 2011
	$ million, except ratios
Profit before taxation		19,998

Group’s share of income in excess of dividends of equity-accounted entities		(780	)

Capitalized interest, net of amortization		(82	)


Profit as adjusted		19,136


Fixed charges:

Interest expense		399
Rental expense representative of interest		821
Capitalized interest		171

		1,391


Total adjusted earnings available for payment of fixed charges		20,527


Ratio of earnings to fixed charges		14.8

Exhibit 99.2

Capitalization and indebtedness

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2011 in accordance with IFRS:


	30 June 2011
	$ million
Share capital
Capital shares (1-2)		5,218
Paid-in surplus (3)		11,027
Merger reserve (3)		27,206
Own shares		(121	)
Available-for-sale investments		629
Cash flow hedges		66
Foreign currency translation reserve		6,027
Treasury shares		(21,027	)
Share-based payment reserve		1,396
Profit and loss account		77,073

BP shareholders’ equity		107,494


Finance debt (4-6)
Due within one year		12,445
Due after more than one year		34,445

Total finance debt		46,890

Total capitalization (7)		154,384

(1)

Issued share capital as of 30 June 2011 comprised 18,941,250,151 ordinary shares, par value $0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,845,638,661 ordinary shares which have been bought back and held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.

(2)	Capital shares represent the ordinary shares of BP which have been issued and are fully paid.

(3)	Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.

(4)	Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2011.

(5)	Obligations under finance leases are included within finance debt in the above table.

(6)

As of 30 June 2011, the parent company, BP p.l.c., had outstanding guarantees totalling $37,157 million, of which $37,127 million related to guarantees in respect of liabilities of its subsidiary undertakings, including $36,386 million relating to borrowings by subsidiaries. Thus 78% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2011, $626 million of finance debt ($1,155 at 30 June 2010) was secured by the pledging of assets, and $3,530 million was secured in connection with deposits received relating to certain disposal transactions expected to complete in subsequent periods, BP has entered into crude oil sales contracts in respect of oil produced from certain fields in offshore Angola and Azerbaijan to provide security to the lending banks. The remainder of finance debt was unsecured. BP had, as of 30 June 2011 no material outstanding contingent indebtedness and there have been no material changes since that date.

(7)	There has been no material change since 30 June 2011 in the consolidated capitalization and indebtedness of BP.