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 2012

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):  ¨

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. 333-179953) 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. 333-123482) 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., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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 2012^(a)

		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2012(b)		3 – 14, 21 – 23
2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2012		15 – 20, 24 – 37
3.	Cautionary statement		14
4.	Principal risks and uncertainties		38 – 44
5.	Legal proceedings		45 – 55
6.	Signatures		56
7.	Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges		57
	Exhibit 99.2: Capitalization and Indebtedness		58

(a) In this Form 6-K, references to the first half 2012 and first half 2011 refer to the six-month periods ended 30 June 2012 and 30 June 2011 respectively. References to second quarter 2012 and second quarter 2011 refer to the three-month periods ended 30 June 2012 and 30 June 2011 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 2011.

2

Group results second quarter and half year 2012

Second quarter 2011			Second quarter 2012				First half 2012		First half 2011
						$ million
	101,364			93,341		Sales and other operating revenues		187,381		186,693
	5,718			(1,385	)	Profit (loss) for the period(a)		4,530		12,972
	(311	)		1,623		Inventory holding (gains) losses, net of tax		637		(1,954	)
	5,407			238		Replacement cost profit(b)		5,167		11,018
	298			3,447		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax(c)		3,317		191
	5,705			3,685		Underlying replacement cost profit(b)		8,484		11,209
	30.27			(7.29	)	Profit (loss) per ordinary share (cents)		23.84		68.81
	1.82			(0.44	)	Profit (loss) per ADS (dollars)		1.43		4.13
	28.62			1.25		Replacement cost profit per ordinary share (cents)		27.19		58.44
	1.72			0.07		Replacement cost profit per ADS (dollars)		1.63		3.51
	30.20			19.37		Underlying replacement cost profit per ordinary share (cents)		44.65		59.45
	1.81			1.16		Underlying replacement cost profit per ADS (dollars)		2.68		3.57

• In the second quarter, BP made a loss of $1,385 million, compared with a profit of $5,718 million a year ago. For the half year, the profit was $4,530 million, compared with $12,972 million. BP’s second-quarter replacement cost (RC) profit was $238 million, compared with $5,407 million a year ago. After adjusting for a net loss from non-operating items of $3,339 million and net unfavourable fair value accounting effects of $108 million (both on a post-tax basis), underlying RC profit for the second quarter was $3,685 million, compared with $5,705 million for the same period last year. For the half year, RC profit was $5,167 million, compared with $11,018 million a year ago. After adjusting for a net loss from non-operating items of $3,154 million and net unfavourable fair value accounting effects of $163 million (both on a post-tax basis), underlying RC profit for the half year was $8,484 million, compared with $11,209 million for the same period last year. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 6, 20 and 22.

• Non-operating items for the second quarter on a pre-tax basis amounted to a net loss of $5,002 million and included impairment losses of $4,782 million^(c) relating primarily to certain refineries, US shale gas assets and the decision to suspend the Liberty project in Alaska. All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net adverse impact on a pre-tax basis of $847 million for the quarter and $823 million for the half year 2012. For further information on the Gulf of Mexico oil spill and its consequences see pages 4 – 5, Note 2 on pages 24 – 29, Principal risks and uncertainties on pages 38 – 44, Legal proceedings on pages 45 – 55 and Legal proceedings on pages 160 – 164 of BP’s Annual Report and Form 20-F 2011.

• Finance costs and net finance income or expense relating to pensions and other post-retirement benefits were $212 million for the second quarter, compared with $249 million for the same period last year. For the half year, the respective amounts were $442 million and $488 million.

• Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and half year was $4.4 billion and $7.8 billion respectively, compared with $7.8 billion and $10.3 billion in the same periods of last year. The amounts for the quarter and half year of 2012 included net cash outflows of $1.7 billion and $2.9 billion respectively relating to the Gulf of Mexico oil spill (second quarter 2011 $1.9 billion outflow, half year 2011 $4.7 billion outflow).

• Gross debt at the end of the quarter was $47.7 billion compared with $46.9 billion a year ago. The ratio of gross debt to gross debt plus equity was 29.6%, compared with 30.1% a year ago. Net debt at the end of the quarter was $31.7 billion, compared with $27.0 billion a year ago. The ratio of net debt to net debt plus equity was 21.9% compared with 19.9% a year ago. Net debt is a non-GAAP measure. See page 7 for further information.

• The quarterly dividend expected to be paid on 25 September 2012 is 8 cents per share ($0.48 per ADS). The corresponding amount in sterling will be announced on 11 September 2012. 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 bp.com/scrip.

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

(b) See footnote (a) on page 6 for definitions of RC profit and underlying RC profit.

(c) See pages 21and 22 respectively for further information on non-operating items and fair value accounting effects.

The commentaries above and following should be read in conjunction with the cautionary statement on page 14.

3

Group headlines (continued)

• The effective tax rate on the loss for the second quarter and on the profit for the half year was 26% and 35% respectively, compared with 34% and 35% on the profit for the equivalent periods in 2011. The effective tax rate on RC profit for the second quarter and half year was 44% and 34% respectively, compared with 34% and 36% a year ago. In 2012, the rates for the second quarter were impacted by non-operating items. Half-year 2011 included the impact of a one-off deferred tax adjustment in respect of the increase in the supplementary charge on UK oil and gas production. In the third quarter we expect a one-off charge of around $250 million to $300 million related to further changes to the UK taxation of North Sea production.

• Total capital expenditure for the second quarter and half year was $5.4 billion and $11.1 billion respectively, of which organic capital expenditure was $5.3 billion and $10.6 billion respectively^(a). Disposal proceeds were $1.9 billion for the quarter and $3.2 billion for the half year. Since the start of 2010, we have announced disposals for a total of $24 billion.

• We now expect depreciation, depletion and amortization for 2012 to be around $1.4 billion higher than for 2011, with the revision mainly due to higher decommissioning costs.

(a) Organic capital expenditure excludes acquisitions and asset exchanges, and expenditure associated with deepening our natural gas asset base (see page 19).

Gulf of Mexico oil spill

Completing the response

We remain committed to meeting our responsibilities to the US federal, state and local governments and communities of the Gulf Coast following the Deepwater Horizon accident and oil spill in 2010 (the Incident). During the second quarter of 2012, BP, working under the direction of the US Coast Guard’s Federal On-Scene Coordinator (FOSC), and collaboratively with the individual federal and state entities, continued to work to meet the applicable clean-up standards established by the Shoreline Clean-up Completion plan.

As at 30 June 2012, the FOSC had deemed removal actions complete on 3,700 miles of shoreline out of 4,375 miles in the area of response. A further 371 miles were awaiting approval of removal actions deemed complete or were pending final monitoring. The remaining 304 miles were undergoing patrolling and maintenance, which will continue until the shoreline segments meet the applicable clean-up standards for the FOSC to determine that operational removal activity is complete.

Economic restoration

Settlement agreements with the Plaintiffs’ Steering Committee

On 18 April 2012, BP reached definitive and fully documented agreements with the Plaintiffs’ Steering Committee (PSC) in the Multi-District Litigation pending in New Orleans (MDL 2179), subject to court approval, to resolve the substantial majority of legitimate private economic loss and medical claims stemming from the Incident. On 2 May 2012, the court gave preliminary approval to the economic loss and medical settlement agreements, and scheduled a fairness hearing for 8 November 2012 to determine whether to grant final approval of the agreements.

On 4 June 2012, the Deepwater Horizon Court-Supervised Settlement Program began accepting claims from “in-class” claimants under the agreements covering economic loss claims and medical claims. On the same date, a separate BP claims programme began accepting claims from claimants who are not covered by the settlement agreements or who exercise their right to opt out of one or both settlements. The transitional court-supervised claims facility, which took over claims processing from the Gulf Coast Claims Facility (GCCF) and operated between 8 March 2012 and 4 June 2012, no longer accepts claims but will continue to process payments when final releases are received on unexpired outstanding offers.

BP estimates that the proposed settlement will cost approximately $7.8 billion, including claims paid to class members by the transitional court-supervised claims facility and the court-supervised settlement programme, claims paid by the BP claims programme to claimants who opt out of the classes, related administration costs, and plaintiffs’ attorneys’ fees and expenses. This cost is being paid from the $20-billion Deepwater Horizon Oil Spill Trust (Trust). While BP has sought to reliably estimate the cost of the settlement agreements, it is possible that the actual cost could be higher or lower than this estimate depending on the outcomes of the court-supervised claims process.

Claims update

As at 30 June 2012, BP had paid a total of nearly $8.8 billion for individual, business and government entity claims, advances and other payments, including payments made by BP prior to the establishment of the Trust.

As at 30 June 2012, $7.0 billion in total had been paid to individual and business claimants, and BP had paid federal, state and local government entities $1.4 billion for claims and advances. BP has also paid an additional $363 million for contributions, settlements and other payments for research, tourism, seafood testing and marketing, and behavioural health.

4

Gulf of Mexico oil spill (continued)

In June, the court-supervised settlement programme received 23,950 claims and expects to begin making final payments in the third quarter. This follows the 1,091,033 claims that were received through the GCCF and the transitional court-supervised claims facility while they were in operation.

Environmental restoration

During the second quarter we continued to work with scientists and trustee agencies through the Natural Resource Damages (NRD) assessment process to identify natural resources that may have been exposed to oil or otherwise impacted by the oil spill, and to look for evidence of injury. To date, BP has paid $718 million for NRD assessment efforts.

Under an agreement signed with federal and state agencies in April 2011, BP voluntarily committed to provide up to $1 billion to fund early restoration projects aimed at accelerating restoration efforts in the Gulf coast areas that were impacted by the accident. The agreement enables work on restoration projects to begin at the earliest opportunity, before funding is required by the Oil Pollution Act 1990 (OPA 90). These projects will be funded from the Trust.

The Tranche 1 Early Restoration Projects Plan was finalized on 18 April 2012 by the Natural Resource Damage Assessment (NRDA) Trustee Council following extensive public review. This plan includes eight projects along the Gulf Coast with a total estimated cost of approximately $60 million. Collectively, these projects are intended to restore and enhance wildlife and habitats, and provide additional access for recreational use.

Financial update

The group income statement includes a pre-tax charge of $847 million for the second quarter in relation to the Incident. The charge for the second quarter reflects an increase in the provision for various costs and litigation relating to the Incident. The total cumulative charge recognized to date for the Incident amounts to $38.0 billion.

The total amounts that will be paid by BP in relation to all obligations relating to the oil spill are subject to significant uncertainty as described further in Note 2 on pages 24 – 29.

Trust update

During the second quarter, BP made a contribution of $1,250 million to the Trust. As at 30 June 2012, BP’s cumulative contributions to the Trust amounted to $17.9 billion with a further payment of $1,250 million scheduled to be made in the third quarter 2012 and a final payment of $860 million scheduled in the fourth quarter 2012. Under the terms of the settlement agreements with the PSC, qualified settlement funds (QSFs) were established during the second quarter, funded from the Trust, for the purpose of paying the costs of the estimated $7.8 billion settlement.

Payments from the Trust and QSFs during the second quarter were $588 million, consisting of $443 million for individual and business claims, $41 million for NRD assessment costs, and $104 million for state and local government claims, court-supervised settlement programme expenses and other resolved items. As at 30 June 2012, the cumulative amount paid from the Trust and QSFs since inception was $7.8 billion, and the remaining cash balances were $10.1 billion.

As at 30 June 2012, the cumulative charges for provisions to be paid from the Trust and the associated reimbursement asset recognized amounted to $17.1 billion. A further $2.9 billion could be provided in subsequent periods for items covered by the Trust, with no net impact on the income statement.

Legal proceedings and investigations

In addition to the information provided on page 4 relating to the settlement agreements with the PSC, see also Legal proceedings on pages 45 – 55 herein and Gulf of Mexico oil spill on pages 76 – 79 of BP’s Annual Report and Form 20-F 2011 for details of legal proceedings, including external investigations relating to the Incident.

5

Analysis of underlying RC profit and RC profit before interest and tax

and reconciliation to profit for the period

Second quarter 2011			Second quarter 2012			$ million	First half 2012			First half 2011
						Underlying RC profit before interest and tax(a)
	6,330			4,401		Upstream		10,691			13,014
	1,392			1,129		Downstream		2,053			3,588
	1,081			452		TNK-BP(b)		1,609			2,208
	(335	)		(540	)	Other businesses and corporate		(976	)		(632	)
	515			457		Consolidation adjustment – UPII(c)		(84	)		(27	)
	8,983			5,899		Underlying RC profit before interest and tax		13,293			18,151
	(234	)		(208	)	Finance costs and net finance income or expense relating to pensions and other post-retirement benefits		(432	)		(457	)
	(2,974	)		(1,961	)	Taxation on an underlying RC basis		(4,271	)		(6,354	)
	(70	)		(45	)	Minority interest		(106	)		(131	)
	5,705			3,685		Underlying RC profit attributable to BP shareholders		8,484			11,209
						Non-operating items and fair value accounting effects(a)
	(699	)		(1,488	)	Upstream		(799	)		40
	(54	)		(2,865	)	Downstream		(2,933	)		(171	)
	—			—		TNK-BP, net of tax		(93	)		—
	(263	)		18		Other businesses and corporate		(218	)		(444	)
	617			(843	)	Gulf of Mexico oil spill response(d)		(813	)		233
	(399	)		(5,178	)	Total before interest and taxation		(4,856	)		(342	)
	(15	)		(4	)	Finance costs(e)		(10	)		(31	)
	116			1,735		Taxation credit (charge)(f)		1,549			182
	(298	)		(3,447	)	Total after taxation for the period		(3,317	)		(191	)
						RC profit before interest and tax(a)
	5,631			2,913		Upstream		9,892			13,054
	1,338			(1,736	)	Downstream		(880	)		3,417
	1,081			452		TNK-BP(b)		1,516			2,208
	(598	)		(522	)	Other businesses and corporate		(1,194	)		(1,076	)
	617			(843	)	Gulf of Mexico oil spill response(d)		(813	)		233
	515			457		Consolidation adjustment – UPII(c)		(84	)		(27	)
	8,584			721		RC profit before interest and tax		8,437			17,809
	(249	)		(212	)	Finance costs and net finance income or expense relating to pensions and other post-retirement benefits		(442	)		(488	)
	(2,858	)		(226	)	Taxation on a RC basis		(2,722	)		(6,172	)
	(70	)		(45	)	Minority interest		(106	)		(131	)
	5,407			238		RC profit attributable to BP shareholders		5,167			11,018
	493			(2,324	)	Inventory holding gains (losses)		(887	)		2,905
	(182	)		701		Taxation (charge) credit on inventory holding gains and losses		250			(951	)
	5,718			(1,385	)	Profit (loss) for the period attributable to BP shareholders		4,530			12,972

(a) Replacement cost (RC) profit or loss reflects the replacement cost of supplies and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. For further information on RC profit or loss, see page 20. Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and fair value accounting effects are not recognized GAAP measures. On pages 21 and 22 respectively, we provide additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects.

(b) Net of finance costs, taxation and minority interest.

(c) The consolidation adjustment – unrealized profit in inventory (UPII) in the second quarter of 2012 was impacted by lower margins (driven by lower prices and a higher average cost of production due to a different mix of equity crude within inventory. In the second quarter of 2011, it was impacted mainly by lower volumes.

(d) See Note 2 on pages 24 – 29 for further information on the accounting for the Gulf of Mexico oil spill response.

(e) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 24 – 29 for further details.

(f) For the Gulf of Mexico oil spill and certain impairment losses in the second quarter 2012, tax is based on US statutory tax rates. For other items, with the exception of TNK-BP items (which are reported net of tax), tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, certain impairment losses in the second quarter 2012, equity-accounted earnings from the first quarter 2012 and the impact of a $683-million one-off deferred tax adjustment in respect of an increase in the supplementary charge on UK oil and gas production for the first quarter 2011).

6

Per share amounts

Second quarter 2011		Second quarter 2012				First half 2012		First half 2011
					Per ordinary share (cents)
	30.27		(7.29	)	Profit (loss) for the period		23.84		68.81
	28.62		1.25		RC profit for the period		27.19		58.44
	30.20		19.37		Underlying RC profit for the period		44.65		59.45
					Per ADS (dollars)
	1.82		(0.44	)	Profit (loss) for the period		1.43		4.13
	1.72		0.07		RC profit for the period		1.63		3.51
	1.81		1.16		Underlying RC profit for the period		2.68		3.57

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 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
	46,890			47,662		Gross debt		47,662			46,890
	1,173			1,067		Less: fair value asset of hedges related to finance debt		1,067			1,173
	45,717			46,595				46,595			45,717
	18,749			14,881		Less: Cash and cash equivalents		14,881			18,749
	26,968			31,714		Net debt		31,714			26,968
	108,636			113,323		Equity		113,323			108,636
	19.9	%		21.9	%	Net debt ratio		21.9	%		19.9	%

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 8 cents per ordinary share expected to be paid in September. The corresponding amount in sterling will be announced on 11 September 2012, calculated based on the average of the market exchange rates for the four dealing days commencing on 5 September 2012. Holders of American Depositary Shares (ADSs) will receive $0.48 per ADS. The dividend is due to be paid on 25 September 2012 to shareholders and ADS holders on the register on 10 August 2012. 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 second-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

Dividends paid

Second quarter 2011		Second quarter 2012			First half 2012		First half 2011
				Dividends paid per ordinary share
	7.000		8.000	cents		16.000		14.000
	4.281		5.150	pence		10.246		8.618
	42.00		48.00	Dividends paid per ADS (cents)		96.00		84.00
				Scrip dividends
	72.8		11.1	Number of shares issued (millions)		50.7		139.4
	525		73	Value of shares issued ($ million)		379		1,035

7

Upstream

Second quarter 2011			Second quarter 2012			First half 2012		First half 2011
					$ million
	18,418			16,542	Sales and other operating revenues		35,800		36,823
	5,654			2,877	Profit before interest and tax		9,772		13,133
	(23	)		36	Inventory holding (gains) losses		120		(79	)
	5,631			2,913	RC profit before interest and tax		9,892		13,054
	699			1,488	Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		799		(40	)
	6,330			4,401	Underlying RC profit before interest and tax(a)		10,691		13,014

(a) See footnote (a) on page 6 for information on underlying RC profit and see page 9 for a reconciliation to segment RC profit before interest and tax by region.

With effect from 1 January 2012, the Exploration and Production segment was separated to form two new operating segments, Upstream and TNK-BP, reflecting the way in which our investment in TNK-BP is now managed.

Sales and other operating revenues for the second quarter and half year were $17 billion and $36 billion respectively, compared with $18 billion and $37 billion for the corresponding periods in 2011. For the second quarter, revenues were lower due to both lower realizations and lower volumes. For the half year, the reduction was mainly due to lower volumes. The reductions in both periods were partially offset by higher gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $2,913 million and $9,892 million respectively, compared with $5,631 million and $13,054 million for the same periods in 2011. The second quarter was impacted by net non-operating charges of $1,495 million, primarily due to net impairment and other charges of $2,389 million related to our US shale gas assets and the decision to suspend the Liberty project in Alaska, partially offset by net gains on disposal of $658 million and a fair value gain on embedded derivatives. For the half year, the net non-operating charge was $673 million due to the same factors, with additional gains on disposal recognized in the first quarter. A year ago, there was a net non-operating charge of $664 million in the second quarter and a net gain of $46 million in the first half. See page 21 for further information on non-operating items. Fair value accounting effects in the second quarter and half year had favourable impacts of $7 million, and unfavourable impacts of $126 million respectively, compared with unfavourable impacts of $35 million and $6 million in the same periods a year ago.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $4,401 million and $10,691 million respectively, compared with $6,330 million and $13,014 million a year ago. In the second quarter, there were lower realizations compared with the same period in 2011 due to a weaker price environment, with Brent trading at an average of $8.75 per barrel lower than a year ago, and Henry Hub trading at an average of $2.11 per mmBtu lower than a year ago. Additionally, both periods were impacted by higher costs, including the impact of higher depreciation, depletion and amortization, as well as ongoing sector inflation, and lower production. The persistently low Henry Hub price means that our North American gas business is operating at a loss.

Production for the quarter was 2,275mboe/d, 7.4% lower than the second quarter 2011. After adjusting for the effect of divestments, and entitlement impacts in our production-sharing agreements (PSAs), production was 2.7% lower. This is mainly due to planned downtime in the higher-margin Gulf of Mexico and in Trinidad, partly offset by production in India and major project start-ups in Angola and Trinidad. For the first half of the year, production was 2,364mboe/d, 6.5% lower than in the same period last year. After adjusting for the effect of divestments, and entitlement impacts in our PSAs, the first-half production was 1% lower than in 2011.

Looking ahead we expect third-quarter reported production to be slightly lower than the second quarter, as a result of ongoing seasonal turnaround activity across the portfolio, including in higher margin regions such as the UK North Sea, and the continuation of the divestment programme. We expect reported production to increase in the fourth quarter as we come out of the summer maintenance season and continue to see the impact of major project start-ups. Reported production for the full year is expected to be lower than 2011 due to the impact of divestments, with the actual outcome dependent on the timing of divestments and project start-ups, OPEC quotas, seasonal weather-related outages in the Gulf of Mexico, and the impact of the oil price on PSAs. We continue to expect full-year production (adjusted for divestments, the impact of the oil price on PSAs, and OPEC quotas) in 2012 to be broadly flat with 2011, excluding TNK-BP.

We continued to make strategic progress in the second quarter. In May we announced that we have signed two PSAs with the government of the Republic of Trinidad and Tobago. BP was awarded blocks 23(a) and 14 in the 2010/2011 deepwater competitive bid round in July 2011, with a 100% working interest. Also in May we agreed a Memorandum of Understanding as part of an expansion plan for the Tangguh LNG plant in Indonesia to provide long-term LNG supply to Indonesia’s state electricity company for domestic needs. Force majeure was lifted in respect of our Libyan Exploration and Production Sharing Agreement with the National Oil Corporation (NOC) effective 15 May. Force majeure had been in place since February 2011.

In June we announced the sale of our interests in the Jonah and Pinedale operations in Wyoming to LINN Energy, for $1.025 billion in cash. Completion of the sale is expected soon. We also announced that we have agreed to sell our interests in the Alba and Britannia fields in the UK North Sea to Mitsui & Co., Ltd. for $280 million in cash. Completion of the deal is anticipated by the end of the third quarter 2012, subject to regulatory and other licensee approvals. Also in June, first gas was produced from the Seth field, located in the East Nile Delta in Egypt. In the Gulf of Mexico we acquired 43 new leases in the June 2012 lease sale, which will be awarded subject to regulatory review. During the second quarter, the Shah Deniz consortium announced that front-end engineering design on the Stage 2 project intended to bring gas from the Caspian Sea to markets in Turkey and Europe would commence, selected the Nabucco West pipeline as the single pipeline option for the potential export of Stage 2 gas to central Europe, and concluded a co-operation agreement with the competing Trans-Adriatic Pipeline (TAP) project in respect of the southern route. In June we announced the start-up of the Galapagos development in the deepwater US Gulf of Mexico. In July, Exxon Mobil (the operator of the Kizomba Satellites Phase 1 project in Angola) announced that it had started production from the Mavacola and Clochas fields. BP has a 26.7% working interest in this project.

8

Upstream

Second quarter 2011			Second quarter 2012			$ million	First half 2012			First half 2011
						Underlying RC profit before interest and tax
						By region
	1,479			628		US		2,286			3,325
	4,851			3,773		Non-US		8,405			9,689
	6,330			4,401				10,691			13,014
						Non-operating items
	(730	)		(2,273	)	US		(1,326	)		(726	)
	66			778		Non-US		653			772
	(664	)		(1,495	)			(673	)		46
						Fair value accounting effects(a)
	(18	)		61		US		(10	)		7
	(17	)		(54	)	Non-US		(116	)		(13	)
	(35	)		7				(126	)		(6	)
						RC profit (loss) before interest and tax
	731			(1,584	)	US		950			2,606
	4,900			4,497		Non-US		8,942			10,448
	5,631			2,913				9,892			13,054
						Exploration expense
	625			413		US(b)		475			933
	54			203		Non-US(c)		401			145
	679			616				876			1,078
						Production (net of royalties)(d)
						Liquids (mb/d)(e)
	465			350		US		402			494
	151			119		Europe		121			158
	653			681		Rest of World		676			689
	1,269			1,150				1,199			1,341
	305			281		Of which equity-accounted entities		282			306
						Natural gas (mmcf/d)
	1,833			1,648		US		1,734			1,869
	391			478		Europe		489			382
	4,664			4,399		Rest of World		4,532			4,626
	6,888			6,525				6,755			6,877
	426			414		Of which equity-accounted entities		406			417
						Total hydrocarbons (mboe/d)(f)
	781			635		US		701			816
	218			201		Europe		205			224
	1,458			1,439		Rest of World		1,458			1,487
	2,457			2,275				2,364			2,527
	379			353		Of which equity-accounted entities		351			378
						Average realizations(g)
	106.99			100.89		Total liquids ($/bbl)		104.67			99.98
	4.54			4.54		Natural gas ($/mcf)		4.62			4.37
	63.23			60.17		Total hydrocarbons ($/boe)		62.18			61.05

(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 22.

(b) Second quarter and first half 2012 include $308 million classified within the ‘other’ category of non-operating items (second quarter and first half 2011 $395 million).

(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.

9

Downstream

Second quarter			Second quarter				First half			First half
2011			2012				2012			2011
						$ million
	93,886			86,692		Sales and other operating revenues		172,623			171,319
	1,820			(3,935	)	Profit (loss) before interest and tax		(1,584	)		6,187
	(482	)		2,199		Inventory holding (gains) losses		704			(2,770	)
	1,338			(1,736	)	RC profit (loss) before interest and tax		(880	)		3,417
	54			2,865		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		2,933			171
	1,392			1,129		Underlying RC profit before interest and tax(a)		2,053			3,588

(a) See footnote (a) on page 6 for information on underlying RC profit and see page 11 for a reconciliation to segment RC profit before interest and tax by region and by business.

Sales and other operating revenues for the second quarter were $87 billion compared with $94 billion for the corresponding period in 2011, primarily reflecting lower volumes. In addition, there were adverse foreign exchange effects and lower prices. For the half year sales and other operating revenues were $173 billion, compared with $171 billion for the corresponding period in 2011. The increase reflected higher prices in the first quarter, partially offset by lower volumes in both quarters.

The replacement cost loss before interest and tax for the second quarter and half year was $1,736 million and $880 million respectively, compared with a profit of $1,338 million and $3,417 million for the same periods last year.

The 2012 results included net non-operating charges of $2,678 million for the second quarter and $2,784 million for the half year, compared with $218 million and $235 million for the same periods a year ago. The charge for both the quarter and the half year mainly relates to impairments in the fuels business relating to certain refineries in our global portfolio, predominantly in the US. See pages 11 and 21 for further information on non-operating items. Fair value accounting effects had unfavourable impacts of $187 million for the second quarter and $149 million for the half year, compared with favourable impacts of $164 million and $64 million in the same periods a year ago.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $1,129 million and $2,053 million respectively, compared with $1,392 million and $3,588 million a year ago.

Replacement cost profit or loss before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 11.

The fuels business delivered an underlying replacement cost profit before interest and tax of $781 million in the second quarter and $1,268 million in the half year, compared with $754 million and $2,059 million in the same periods last year. The second quarter continued to benefit from strong refining feedstock optimization in the US Midwest. The refining environment was stronger than a year ago for both the second quarter and the first half, although this benefit was more than offset by significant adverse effects from prior-month pricing of barrels into our US refining system given the steep fall in oil prices, and adverse foreign exchange effects. The supply and trading contribution has been significantly weaker during the first half compared with a year ago, resulting in a loss for the half year.

During the first half of 2012, we continued to progress our plans for the sale of our Texas City refinery and the southern part of the West Coast fuels value chain, including the Carson refinery. We are in advanced discussions on both assets and remain on track to announce both sales by the end of 2012. In the second quarter we completed the acquisition of Shell and Cosan Industria e Commercio’s interests in significant aviation fuels assets at seven Brazilian airports having received regulatory approval in March 2012. In May, our Cherry Point refinery resumed full operations having completed repairs following a fire in February and a scheduled turnaround.

The lubricants business delivered an underlying replacement cost profit before interest and tax of $320 million in the second quarter and $645 million in the half year, compared with $368 million and $740 million in the same periods last year reflecting robust performance despite weaker demand, higher base oil prices and adverse foreign exchange effects.

The petrochemicals business delivered an underlying replacement cost profit before interest and tax of $28 million in the second quarter and $140 million in the half year, compared with $270 million and $789 million in the same periods last year. This reflects particular weakness in aromatics margins, resulting from growing capacity and subdued demand compared with particularly strong margins in the first half of 2011.

In July, BP signed two licensing agreements for our proprietary petrochemicals technology; one licensing BP’s latest generation purified terephthalic acid (PTA) technology for use by JBF Petrochemicals in a planned 1.25 million tonnes per annum unit in Mangalore, India and the second, licensing paraxylene (PX) technology for use by Reliance Industries for the world’s largest aromatics complex in Gujarat, India. These are the first steps in implementing a technology licensing strategy, which seeks to create a new long-term revenue stream.

Looking ahead to the third quarter, in the fuels business we expect refining margins to decline in line with the usual seasonal trend and the level of turnaround activity to be lower than in the second quarter. In addition, we expect petrochemicals margins to remain weak.

Looking to the fourth quarter, as part of our major project to upgrade the Whiting refinery to process significantly more Canadian heavy crude, we expect to commence a transitional outage to substantially reconfigure the largest of the refinery’s three crude units. We expect this to be completed by mid-year 2013, in time for the expected start-up of the full project in the second half of 2013.

10

Downstream

Second quarter			Second quarter				First half			First half
2011			2012			$ million	2012			2011
						Underlying RC profit before interest and tax – by region
	151			450		US		739			855
	1,241			679		Non-US		1,314			2,733
	1,392			1,129				2,053			3,588
						Non-operating items
	(239	)		(2,433	)	US		(2,521	)		(255	)
	21			(245	)	Non-US		(263	)		20
	(218	)		(2,678	)			(2,784	)		(235	)
						Fair value accounting effects(a)
	71			(1	)	US		(44	)		23
	93			(186	)	Non-US		(105	)		41
	164			(187	)			(149	)		64
						RC profit (loss) before interest and tax
	(17	)		(1,984	)	US		(1,826	)		623
	1,355			248		Non-US		946			2,794
	1,338			(1,736	)			(880	)		3,417
						Underlying RC profit before interest and tax – by business(b)(c)
	754			781		Fuels		1,268			2,059
	368			320		Lubricants		645			740
	270			28		Petrochemicals		140			789
	1,392			1,129				2,053			3,588
						Non-operating items and fair value accounting effects(a)
	(114	)		(2,863	)	Fuels		(2,931	)		(244	)
	60			(2	)	Lubricants		(2	)		73
	—			—		Petrochemicals		—			—
	(54	)		(2,865	)			(2,933	)		(171	)
						RC profit (loss) before interest and tax(b)(c)
	640			(2,082	)	Fuels		(1,663	)		1,815
	428			318		Lubricants		643			813
	270			28		Petrochemicals		140			789
	1,338			(1,736	)			(880	)		3,417
	13.92			15.84		BP Average refining marker margin (RMM) ($/bbl)(d)		13.72			12.48
						Refinery throughputs (mb/d)
	1,190			1,295		US		1,256			1,192
	749			706		Europe		741			758
	314			281		Rest of World		279			311
	2,253			2,282				2,276			2,261
	94.8			94.5		Refining availability (%)(e)		94.7			94.3
						Marketing sales volumes (mb/d)(f)
	1,407			1,409		US		1,379			1,391
	1,298			1,279		Europe		1,247			1,283
	613			603		Rest of World		589			611
	3,318			3,291				3,215			3,285
	2,729			2,568		Trading/supply sales		2,474			2,494
	6,047			5,859		Total refined product sales		5,689			5,779
						Petrochemicals production (kte)
	766			1,110		US		2,188			1,901
	1,050			998		Europe(c)		2,009			2,035
	1,846			1,750		Rest of World		3,567			3,764
	3,662			3,858				7,764			7,700

(a) Fair value accounting effects represent the favourable (unfavourable) impact relative to management’s measure of performance. For Downstream, these arise solely in the fuels business. Further information is provided on page 22.

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

(c) BP’s share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.

(d) The RMM is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. They 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. The quarterly regional marker margins can be found on bp.com and are updated weekly.

(e) 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.

(f) Marketing sales do not include volumes relating to crude oil.

11

TNK-BP^(a)

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
	1,419			852		Profit before interest and tax		2,333			2,945
	(34	)		(27	)	Finance costs		(63	)		(69	)
	(238	)		(393	)	Taxation		(624	)		(484	)
	(84	)		(69	)	Minority interest		(193	)		(143	)
	1,063			363		Net income (BP share)(b)		1,453			2,249
	18			89		Inventory holding (gains) losses, net of tax		63			(41	)
	1,081			452		Net income on a RC basis		1,516			2,208
	—			—		Net charge (credit) for non-operating items(c), net of tax		93			—
	1,081			452		Net income on an underlying RC basis(d)		1,609			2,208
						Cash flow
	1,634			—		Dividends received		690			1,634
						Production (net of royalties) (BP share)
	860			881		Crude oil (mb/d)		880			858
	675			779		Natural gas (mmcf/d)		796			697
	976			1,016		Total hydrocarbons (mboe/d)(e)		1,018			978

Balance sheet	30 June 2012		31 December 2011
Investments in associates		10,715		10,013

(a) All amounts shown relate to BP’s 50% share in TNK-BP.

(b) TNK-BP is an associate accounted for using the equity method and therefore BP’s share of TNK-BP’s earnings after interest and tax is included in the group income statement within BP’s profit before interest and tax.

(c) Disclosure of non-operating items for TNK-BP began in the first quarter of 2012.

(d) See footnote (a) on page 6 for information on underlying RC profit.

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

With effect from 1 January 2012, the Exploration and Production segment was separated to form two new operating segments, Upstream and TNK-BP, reflecting the way in which our investment in TNK-BP is now managed.

The net income on a replacement cost basis from BP’s investment in TNK-BP for the second quarter and half year was $452 million and $1,516 million respectively, compared with $1,081 million and $2,208 million for the same periods a year ago.

The half-year result included a non-operating impairment charge of $93 million after tax, relating to the temporary shutdown of the Lisichansk refinery in the Ukraine due to deteriorating economic conditions. Prior to 2012, non-operating items relating to BP’s investment in TNK-BP were not identified or disclosed.

The net income on an underlying replacement cost basis from BP’s investment in TNK-BP for the second quarter and half year was $452 million and $1,609 million respectively, compared with $1,081 million and $2,208 million for the same periods in 2011. The primary factors impacting the second-quarter result, compared with the same period last year, were lower realizations and the impact of the tax reference price lag on Russian export duties in the falling price environment, while for the half year the reduction was primarily driven by the export duty lag effect. At current Urals prices, we would expect third-quarter net income to include some duty lag benefit.

Production for the second quarter and half year was 1,016mboe/d and 1,018mboe/d respectively, 4% higher than the same periods in 2011. After adjusting for the effect of the acquisition of BP’s upstream interests in Vietnam and Venezuela, the increase in both periods was approximately 1.9%, with the ramp-up of recent new developments more than offsetting a decline in mature fields.

On 21 May, TNK-BP announced the appointment of Evert Henkes to the board of TNK-BP Ltd as a BP-nominated independent director. Mr Henkes becomes the 10th member of the board of TNK-BP Ltd and the second of the board’s three independent directors. The appointment of Mr Henkes follows the resignations last year of Gerhard Schroeder and James Leng. TNK-BP’s shareholders continue joint efforts to identify candidates for the third independent director position.

On 28 May, TNK-BP announced that Mikhail Fridman had notified the board of TNK-BP Ltd of his resignation from the position of chief executive officer of the TNK-BP group. Mr Fridman also resigned from the position of chairman of the management board of TNK-BP Management, a Russian subsidiary of TNK-BP Group which manages the company’s assets in Russia and Ukraine, including the publicly traded company, TNK-BP Holding. Both resignations took effect at the end of June 2012.

On 1 June, BP announced it had received unsolicited indications of interest regarding the potential acquisition of its shareholding in TNK-BP. Consistent with a commitment to maximise shareholder value, and its obligations under the TNK-BP Shareholder Agreement, BP notified its partners, Alfa Access Renova (AAR), of the intention to pursue a potential sale. On 18 July, BP announced it was beginning the next stage in the process following notification by AAR of its decision to exercise its right to enter a period of negotiation to purchase part or all of BP’s shareholding in TNK-BP. As a result BP began a 90-day period of ‘good faith’ negotiations with AAR as required by the shareholder agreement. On 24 July, Rosneft also announced its interest in commencing negotiations to purchase BP’s shareholding in TNK-BP and BP confirmed it would begin such negotiations. BP is permitted to enter into negotiations with other interested parties in parallel to discussions with AAR. There can be no guarantee that any transaction will take place and a further announcement will be made when and if appropriate.

12

Other businesses and corporate

Second quarter			Second quarter				First half			First half
2011			2012				2012			2011
						$ million
	985			527		Sales and other operating revenues		955			1,841
	(592	)		(522	)	Profit (loss) before interest and tax		(1,194	)		(1,061	)
	(6	)		—		Inventory holding (gains) losses		—			(15	)
	(598	)		(522	)	RC profit (loss) before interest and tax		(1,194	)		(1,076	)
	263			(18	)	Net charge (credit) for non-operating items		218			444
	(335	)		(540	)	Underlying RC profit (loss) before interest and tax(a)		(976	)		(632	)
						By region
						Underlying RC profit (loss) before interest and tax(a)
	(156	)		(185	)	US		(350	)		(345	)
	(179	)		(355	)	Non-US		(626	)		(287	)
	(335	)		(540	)			(976	)		(632	)
						Non-operating items
	(12	)		(92	)	US		(234	)		(11	)
	(251	)		110		Non-US		16			(433	)
	(263	)		18				(218	)		(444	)
						RC profit (loss) before interest and tax
	(168	)		(277	)	US		(584	)		(356	)
	(430	)		(245	)	Non-US		(610	)		(720	)
	(598	)		(522	)			(1,194	)		(1,076	)

(a) See footnote (a) on page 6 for information on underlying RC profit or loss.

Other businesses and corporate comprises the Alternative Energy business, Shipping, 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 $522 million and $1,194 million respectively, compared with $598 million and $1,076 million for the same periods last year.

The second-quarter result included a net non-operating credit of $18 million, compared with a net non-operating charge of $263 million a year ago. For the half year the net non-operating charge was $218 million, compared with a net charge of $444 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $540 million and $976 million respectively, compared with $335 million and $632 million for the same periods last year, primarily due to adverse foreign exchange effects.

In Alternative Energy, net wind generation capacity^(b) at the end of the second quarter was 1,274MW (1,988MW gross), compared with 774MW (1,362MW gross) at the end of the same period a year ago. BP’s net share of wind generation from our 13 US wind farms for the second quarter was 920GWh (1,422GWh gross), compared with 648GWh (1,158GWh gross) in the same period a year ago. For the half year, BP’s net share was 1,940GWh (3,086GWh gross), compared with 1,250GWh (2,234GWh gross) a year ago.

In our biofuels business, BP owns and operates three producing ethanol mills in Brazil, with a total crush capacity^(c) of 7.2 million tonnes per annum. BP’s net share of ethanol production from these 3 mills for the second quarter was 97.7 million litres (BP interest 100%) compared with 94.9 million litres (124.8 million litres gross) in the same period a year ago^(d). There was no ethanol production in the first quarter of 2011 or 2012 due to the inter-harvest season.

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

(c) Crush capacity represents the maximum capacity of the plant to process biofuels feedstock.

(d) BP acquired the remaining 50% of Tropical Bioenergia on 22 November 2011.

13

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 expected impact of changes to UK taxation of North Sea production; the expected full-year level of depreciation, depletion and amortization for 2012; BP’s intentions to continue to patrol and maintain certain shoreline segments impacted by the Gulf of Mexico oil spill; the prospects for the approval of the settlement agreements with the Plaintiffs’ Steering Committee (PSC), and the timing of the fairness hearings in connection therewith; the timing of future MDL 2179 proceedings; the expected cost of the settlement agreements with the PSC, and the source of funding thereof; the source of funding for BP’s $1-billion commitment to early restoration projects, and the prospects for these early restoration projects; the quantum of and timing for completion of contributions to and payments from the $20-billion Trust fund; the prospects for and expected timing of certain investigations, claims, settlements and litigation outcomes; the expected level of production in the third quarter and fourth quarter of 2012, and the expected level of production for the year ended 31 December 2012; prospects for the completion of planned and announced divestments, including the sale of BP’s interests in the Jonah and Pinedale operations and in the Alba and Britannia fields in the UK North Sea, and the planned disposals of the Texas City refinery and the southern part of the US West Coast fuels value chain including the Carson refinery; the expected level of refining and petrochemicals margins in the third quarter of 2012 and the amount of turnaround activity; the timing and prospects for upgrades to the Whiting refinery; the impact of duty lag on TNK-BP’s third-quarter net income; and BP’s plans to enter negotiations regarding the potential sale of its shareholding in TNK-BP. 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; the timing of divestments; 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 “Principal risks and uncertainties” herein and under “Risk factors” in our Annual Report and Form 20-F 2011 as filed with the US Securities and Exchange Commission.

14

Group income statement

Second quarter			Second quarter				First half			First half
2011			2012				2012			2011
						$ million
	101,364			93,341		Sales and other operating revenues (Note 4)		187,381			186,693
	401			88		Earnings from jointly controlled entities – after interest and tax		378			793
	1,255			545		Earnings from associates – after interest and tax		1,805			2,664
	151			176		Interest and other income		351			275
	775			742		Gains on sale of businesses and fixed assets		1,675			1,963
	103,946			94,892		Total revenues and other income		191,590			192,388
	78,281			75,522		Purchases		147,165			140,002
	6,200			7,889		Production and manufacturing expenses(a)		14,610			12,708
	2,356			1,827		Production and similar taxes (Note 5)		4,173			4,187
	2,671			2,877		Depreciation, depletion and amortization		6,085			5,506
	1,383			4,821		Impairment and losses on sale of businesses and fixed assets		4,961			1,442
	679			616		Exploration expense		876			1,078
	3,448			3,213		Distribution and administration expenses		6,341			6,355
	(149	)		(270	)	Fair value (gain) loss on embedded derivatives		(171	)		396
	9,077			(1,603	)	Profit (loss) before interest and taxation		7,550			20,714
	314			267		Finance costs(a)		550			622
	(65	)		(55	)	Net finance income relating to pensions and other post-retirement benefits		(108	)		(134	)
	8,828			(1,815	)	Profit (loss) before taxation		7,108			20,226
	3,040			(475	)	Taxation(a)		2,472			7,123
	5,788			(1,340	)	Profit (loss) for the period		4,636			13,103
						Attributable to
	5,718			(1,385	)	BP shareholders		4,530			12,972
	70			45		Minority interest		106			131
	5,788			(1,340	)			4,636			13,103
						Earnings per share – cents (Note 6)
						Profit (loss) for the period attributable to BP shareholders
	30.27			(7.29	)	Basic		23.84			68.81
	29.90			(7.29	)	Diluted		23.52			68.01

(a) See Note 2 on pages 24 – 29 for further details of the impact of the Gulf of Mexico oil spill on the income statement line items.

15

Group statement of comprehensive income

Second quarter			Second quarter				First half			First half
2011			2012				2012			2011
						$ million
	5,788			(1,340	)	Profit (loss) for the period		4,636			13,103
	401			(1,038	)	Currency translation differences		(452	)		1,058
	2			(12	)	Exchange (gains) losses on translation of foreign operations transferred to gain or loss on sales of businesses and fixed assets		(12	)		13
	—			(2,301	)	Actuarial loss relating to pensions and other post-retirement benefits		(881	)		—
	(95	)		(109	)	Available-for-sale investments marked to market		(45	)		171
	(3	)		—		Available-for-sale investments – recycled to the income statement		—			(5	)
	75			(96	)	Cash flow hedges marked to market		(21	)		193
	(112	)		28		Cash flow hedges – recycled to the income statement		30			(128	)
	(5	)		4		Cash flow hedges – recycled to the balance sheet		9			(3	)
	—			(334	)	Share of equity-accounted entities’ other comprehensive income, net of tax		(131	)		—
	57			668		Taxation		217			52
	320			(3,190	)	Other comprehensive income (expense)		(1,286	)		1,351
	6,108			(4,530	)	Total comprehensive income (expense)		3,350			14,454
						Attributable to
	6,044			(4,564	)	BP shareholders		3,249			14,313
	64			34		Minority interest		101			141
	6,108			(4,530	)			3,350			14,454

Group statement of changes in equity

	BP shareholders’ equity			Minority interest			Total equity
$ million
At 1 January 2012		111,465			1,017			112,482
Total comprehensive income		3,249			101			3,350
Dividends		(2,659	)		(52	)		(2,711	)
Share-based payments (net of tax)		177			—			177
Transactions involving minority interests		—			25			25
At 30 June 2012		112,232			1,091			113,323
	BP shareholders’ equity			Minority interest			Total equity
$ million
At 1 January 2011		94,987			904			95,891
Total comprehensive income		14,313			141			14,454
Dividends		(1,603	)		(132	)		(1,735	)
Share-based payments (net of tax)		25			—			25
Transactions involving minority interests		—			1			1
At 30 June 2011		107,722			914			108,636

16

Group balance sheet

	30 June 2012		31 December 2011
$ million
Non-current assets
Property, plant and equipment		117,565		119,214
Goodwill		11,831		12,100
Intangible assets		22,345		21,102
Investments in jointly controlled entities		15,672		15,518
Investments in associates		13,877		13,291
Other investments		1,909		2,117
Fixed assets		183,199		183,342
Loans		832		884
Trade and other receivables		6,731		4,337
Derivative financial instruments		5,142		5,038
Prepayments		1,302		1,255
Deferred tax assets		683		611
Defined benefit pension plan surpluses		22		17
		197,911		195,484
Current assets
Loans		242		244
Inventories		26,434		25,661
Trade and other receivables		38,380		43,526
Derivative financial instruments		3,770		3,857
Prepayments		1,354		1,286
Current tax receivable		372		235
Other investments		304		288
Cash and cash equivalents		14,881		14,067
		85,737		89,164
Assets classified as held for sale (Note 3)		8,910		8,420
		94,647		97,584
Total assets		292,558		293,068
Current liabilities
Trade and other payables		47,149		52,405
Derivative financial instruments		3,417		3,220
Accruals		6,185		5,932
Finance debt		7,213		9,044
Current tax payable		1,880		1,941
Provisions		7,829		11,238
		73,673		83,780
Liabilities directly associated with assets classified as held for sale (Note 3)		2,524		538
		76,197		84,318
Non-current liabilities
Other payables		2,627		3,437
Derivative financial instruments		3,682		3,773
Accruals		460		389
Finance debt		40,449		35,169
Deferred tax liabilities		14,322		15,078
Provisions		29,224		26,404
Defined benefit pension plan and other post-retirement benefit plan deficits		12,274		12,018
		103,038		96,268
Total liabilities		179,235		180,586
Net assets		113,323		112,482
Equity
BP shareholders’ equity		112,232		111,465
Minority interest		1,091		1,017
		113,323		112,482

17

Condensed group cash flow statement

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Operating activities
	8,828			(1,815	)	Profit (loss) before taxation		7,108			20,226
						Adjustments to reconcile profit before taxation to net cash provided by operating activities
	3,275			3,269		Depreciation, depletion and amortization and exploration expenditure written off		6,557			6,402
	608			4,079		Impairment and (gain) loss on sale of businesses and fixed assets		3,286			(521	)
	568			(224	)	Earnings from equity-accounted entities, less dividends received		(748	)		(1,008	)
	(121	)		(154	)	Net charge for interest and other finance expense, less net interest paid		(168	)		(70	)
	113			99		Share-based payments		133			(11	)
	(159	)		(210	)	Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(370	)		(598	)
	(64	)		265		Net charge for provisions, less payments		430			209
	(3,283	)		949		Movements in inventories and other current and non-current assets and liabilities(a)		(5,211	)		(11,106	)
	(1,917	)		(1,855	)	Income taxes paid		(3,247	)		(3,271	)
	7,848			4,403		Net cash provided by operating activities		7,770			10,252
						Investing activities
	(4,185	)		(4,951	)	Capital expenditure		(10,390	)		(7,894	)
	(3,884	)		(116	)	Acquisitions, net of cash acquired		(116	)		(5,886	)
	(170	)		(449	)	Investment in jointly controlled entities		(693	)		(324	)
	(19	)		(11	)	Investment in associates		(34	)		(30	)
	1,273			521		Proceeds from disposal of fixed assets		1,788			1,657
	376			1,402		Proceeds from disposal of businesses, net of cash disposed		1,447			962
	116			142		Proceeds from loan repayments		207			151
	(6,493	)		(3,462	)	Net cash used in investing activities		(7,791	)		(11,364	)
						Financing activities
	18			17		Net issue of shares		38			30
	2,696			3,037		Proceeds from long-term financing		6,850			7,613
	(3,102	)		(613	)	Repayments of long-term financing		(3,029	)		(5,724	)
	(157	)		(745	)	Net increase (decrease) in short-term debt		(81	)		792
	(795	)		(1,447	)	Dividends paid – BP shareholders		(2,659	)		(1,603	)
	(96	)		(51	)	Dividends paid – Minority interest		(52	)		(102	)
	(1,436	)		198		Net cash provided by financing activities		1,067			1,006
	104			(350	)	Currency translation differences relating to cash and cash equivalents		(232	)		299
	23			789		Increase in cash and cash equivalents		814			193
	18,726			14,092		Cash and cash equivalents at beginning of period		14,067			18,556
	18,749			14,881		Cash and cash equivalents at end of period		14,881			18,749

(a) Includes

(493	)	2,324		Inventory holding (gains) losses	887		(2,905	)
(149	)	(270	)	Fair value (gain) loss on embedded derivatives	(171	)	396
(2,912	)	(1,439	)	Movements related to Gulf of Mexico oil spill response	(3,300	)	(5,776	)

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.

18

Capital expenditure and acquisitions

Second quarter 2011		Second quarter 2012			First half 2012		First half 2011
				$ million
				By business
				Upstream
	1,001		1,149	US(a)		2,795		2,024
	5,439		2,641	Non-US(b)		5,470		7,550
	6,440		3,790			8,265		9,574
				Downstream
	626		890	US		1,564		1,148
	313		378	Non-US		580		528
	939		1,268			2,144		1,676
				Other businesses and corporate
	126		253	US		411		256
	689		120	Non-US(c)		259		709
	815		373			670		965
	8,194		5,431			11,079		12,215
				By geographical area
	1,753		2,292	US(a)		4,770		3,428
	6,441		3,139	Non-US(b)(c)		6,309		8,787
	8,194		5,431			11,079		12,215
				Included above:
	4,005		164	Acquisitions and asset exchanges(b)(c)		174		4,014

(a) First half 2012 includes $311 million associated with deepening our natural gas asset base.

(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.

Exchange rates

Second quarter 2011		Second quarter 2012			First half 2012		First half 2011
	1.63		1.58	US dollar/sterling average rate for the period		1.58		1.62
	1.60		1.55	US dollar/sterling period-end rate		1.55		1.60
	1.44		1.28	US dollar/euro average rate for the period		1.30		1.40
	1.44		1.24	US dollar/euro period-end rate		1.24		1.44

19

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

reconciliation to profit (loss) before taxation^(a)

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						By business
	5,631			2,913		Upstream		9,892			13,054
	1,338			(1,736	)	Downstream		(880	)		3,417
	1,081			452		TNK-BP(b)		1,516			2,208
	(598	)		(522	)	Other businesses and corporate		(1,194	)		(1,076	)
	7,452			1,107				9,334			17,603
	617			(843	)	Gulf of Mexico oil spill response		(813	)		233
	515			457		Consolidation adjustment – unrealized profit in inventory		(84	)		(27	)
	8,584			721		RC profit before interest and tax(c)		8,437			17,809
						Inventory holding gains (losses)(d)
	23			(36	)	Upstream		(120	)		79
	482			(2,199	)	Downstream		(704	)		2,770
	(18	)		(89	)	TNK-BP (net of tax)		(63	)		41
	6			—		Other businesses and corporate		—			15
	9,077			(1,603	)	Profit (loss) before interest and tax		7,550			20,714
	314			267		Finance costs		550			622
	(65	)		(55	)	Net finance income relating to pensions and other post-retirement benefits		(108	)		(134	)
	8,828			(1,815	)	Profit (loss) before taxation		7,108			20,226
						RC profit (loss) before interest and tax
						By geographical area
	1,361			(4,246	)	US		(2,311	)		3,174
	7,223			4,967		Non-US		10,748			14,635
	8,584			721				8,437			17,809

(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, both RC profit or loss before interest and tax and underlying RC profit or loss before interest and tax (see page 6 for further information) are provided regularly to the chief operating decision maker. In such cases IFRS requires that the measure of profit disclosed for each operating segment is the measure that is closest to IFRS, which for BP is RC 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) Net of finance costs, taxation and minority interest.

(c) RC profit or loss reflects the replacement cost of supplies. The RC 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. RC profit or loss for the group is not a recognized GAAP measure.

(d) 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 RC. 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.

20

Non-operating items_(a)

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Upstream
	(403	)		(1,455	)	Impairment and gain (loss) on sale of businesses and fixed assets(b)		(527	)		686
	—			—		Environmental and other provisions		—			—
	—			—		Restructuring, integration and rationalization costs		—			—
	142			271		Fair value gain (loss) on embedded derivatives		171			(186	)
	(403	)		(311	)	Other		(317	)		(454	)
	(664	)		(1,495	)			(673	)		46
						Downstream
	(209	)		(2,653	)	Impairment and gain (loss) on sale of businesses and fixed assets(c)		(2,738	)		(204	)
	(1	)		—		Environmental and other provisions		—			(1	)
	(4	)		(12	)	Restructuring, integration and rationalization costs		(24	)		(5	)
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	(4	)		(13	)	Other		(22	)		(25	)
	(218	)		(2,678	)			(2,784	)		(235	)
						TNK-BP (net of tax)(d)
	—			—		Impairment and gain (loss) on sale of businesses and fixed assets		(93	)		—
	—			—		Environmental and other provisions		—			—
	—			—		Restructuring, integration and rationalization costs		—			—
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	—			—		Other		—			—
	—			—				(93	)		—
						Other businesses and corporate
	4			29		Impairment and gain (loss) on sale of businesses and fixed assets		(21	)		39
	(12	)		—		Environmental and other provisions		(15	)		(12	)
	2			(1	)	Restructuring, integration and rationalization costs		(1	)		3
	7			(1	)	Fair value gain (loss) on embedded derivatives(e)		—			(210	)
	(264	)		(9	)	Other(f)		(181	)		(264	)
	(263	)		18				(218	)		(444	)
	617			(843	)	Gulf of Mexico oil spill response		(813	)		233
	(528	)		(4,998	)	Total before interest and taxation		(4,581	)		(400	)
	(15	)		(4	)	Finance costs(g)		(10	)		(31	)
	(543	)		(5,002	)	Total before taxation		(4,591	)		(431	)
	160			1,663		Taxation credit (charge)(h)		1,437			204
	(383	)		(3,339	)	Total after taxation for period		(3,154	)		(227	)

(a) Non-operating items are charges and credits arising in consolidated entities and in TNK-BP that are included in the financial statements and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. An analysis of non-operating items by region is shown on pages 9, 11 and 13.

(b) Second quarter 2012 includes net impairment charges of $2,113 million, primarily relating to our US shale gas assets and the decision to suspend the Liberty project in Alaska, partially offset by net gains on disposals of $658 million. Second quarter 2011 includes impairment charges of $1,049 million, partially offset by net gains on disposals of $646 million.

(c) Second quarter 2012 includes impairment charges of $2,665 million in the fuels business, mainly relating to certain refineries in our global portfolio, predominantly in the US.

(d) Non-operating items for TNK-BP are reported in the group income statement within earnings from associates – after interest and tax.

(e) First half 2011 includes a loss on an embedded derivative arising from a financing arrangement.

(f) Second quarter and first half 2012 include $10 million and $171 million respectively relating to our exit from the solar business (second quarter and first half 2011 include $261 million).

(g) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 24 – 29 for further details.

(h) For the Gulf of Mexico oil spill and certain impairment losses in the second quarter 2012, tax is based on US statutory tax rates. For other items, with the exception of TNK-BP items (which are reported net of tax), tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, certain impairment losses in the second quarter 2012, equity-accounted earnings from the first quarter 2012 and the impact of a $683-million one-off deferred tax adjustment in respect of an increase in the supplementary charge on UK oil and gas production for the first quarter 2011).

21

Non-GAAP information on fair value accounting effects

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Favourable (unfavourable) impact relative to management’s measure of performance
	(35	)		7		Upstream		(126	)		(6	)
	164			(187	)	Downstream		(149	)		64
	129			(180	)			(275	)		58
	(44	)		72		Taxation credit (charge)(a)		112			(22	)
	85			(108	)			(163	)		36

(a) Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, certain impairment losses in the second quarter 2012, equity-accounted earnings from the first quarter 2012 and the impact of a $683-million one-off deferred tax adjustment in respect of an increase in the supplementary charge on UK oil and gas production for the first quarter 2011).

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.

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Upstream
	5,666			2,906		Replacement cost profit before interest and tax adjusted for fair value accounting effects		10,018			13,060
	(35	)		7		Impact of fair value accounting effects		(126	)		(6	)
	5,631			2,913		Replacement cost profit before interest and tax		9,892			13,054
						Downstream
	1,174			(1,549	)	Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects		(731	)		3,353
	164			(187	)	Impact of fair value accounting effects		(149	)		64
	1,338			(1,736	)	Replacement cost profit (loss) before interest and tax		(880	)		3,417
						Total group
	8,948			(1,423	)	Profit (loss) before interest and tax adjusted for fair value accounting effects		7,825			20,656
	129			(180	)	Impact of fair value accounting effects		(275	)		58
	9,077			(1,603	)	Profit (loss) before interest and tax		7,550			20,714

22

Realizations and marker prices

Second quarter 2011		Second quarter 2012			First half 2012		First half 2011
				Average realizations(a)
				Liquids ($/bbl)(b)
	101.40		101.16	US		100.20		93.51
	114.43		104.18	Europe		110.91		108.14
	111.12		99.72	Rest of World		107.21		104.81
	106.99		100.89	BP Average		104.67		99.98
				Natural gas ($/mcf)
	3.61		1.91	US		2.08		3.40
	7.82		9.06	Europe		8.43		7.41
	4.63		5.09	Rest of World		5.22		4.52
	4.54		4.54	BP Average		4.62		4.37
				Total hydrocarbons ($/boe)
	68.43		61.35	US		62.20		64.20
	92.91		82.13	Europe		84.92		88.84
	53.45		55.48	Rest of World		57.94		53.11
	63.23		60.17	BP Average		62.18		61.05
				Average oil marker prices ($/bbl)
	117.04		108.29	Brent		113.61		111.09
	102.22		93.30	West Texas Intermediate		98.16		98.39
	115.26		109.85	Alaska North Slope		114.12		109.29
	111.68		104.05	Mars		109.73		106.85
	113.73		106.31	Urals (NWE – cif)		111.76		108.00
	50.26		48.22	Russian domestic oil		53.09		49.75
				Average natural gas marker prices
	4.32		2.21	Henry Hub gas price ($/mmBtu)(c)		2.47		4.21
	57.47		57.38	UK Gas – National Balancing Point (p/therm)		58.41		57.20

(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.

23

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. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2011 included in the BP Annual Report and Form 20-F 2011.

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.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. 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 2012, which do not differ significantly from those used in the BP Annual Report and Form 20-F 2011.

Segmental reporting

For the purposes of segmental reporting, the group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. With effect from 1 January 2012, the former Exploration and Production segment was separated to form two new operating segments, Upstream and TNK-BP, reflecting the way in which our investment in TNK-BP is now managed. In addition, we began reporting the Refining and Marketing segment as Downstream.

New or amended International Financial Reporting Standards adopted

There are no new or amended standards or interpretations adopted with effect from 1 January 2012 that have a significant impact on the financial statements.

Comparative group balance sheet as at 31 December 2011

The comparative group balance sheet as at 31 December 2011 presented in this report is the balance sheet approved by the board of directors on 6 March 2012 and published in the BP Annual Report and Form 20-F 2011. This differs from the group balance sheet as at 31 December 2011 published in BP’s fourth quarter and full year 2011 results announcement published on 7 February 2012. The differences relate to the announcement on 3 March 2012 of the proposed settlement with the Plaintiffs’ Steering Committee in the federal Multi-District Litigation proceedings pending in New Orleans (MDL 2179), which was an adjusting event after the reporting period, subsequent to the preliminary announcement of the fourth quarter 2011 results. The effect of the adjustment arising from the proposed settlement was to increase the provision for litigation and claims included within current and non-current provisions by $1,900 million and $241 million respectively, and the reimbursement asset included within current and non-current Trade and other receivables by the same amounts. There was no net impact on the group income statement or the group cash flow statement. For further details see Note 2 and Legal proceedings on pages 45 – 55 herein.

2. Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur various 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 2011 – Financial statements – Note 2, Note 36 and Note 43, and Legal proceedings on pages 45 – 55 herein.

The group income statement includes a pre-tax charge of $847 million for the second quarter in relation to the Gulf of Mexico oil spill and a pre-tax charge of $823 million for the first half of 2012. The charge for the second quarter reflects an increase in the provision for various costs and litigation relating to the Gulf of Mexico oil spill. The charge for the half year also reflects a credit relating to certain claims administration costs now expected to be paid from the Deepwater Horizon Oil Spill Trust. The cumulative pre-tax income statement charge since the incident amounts to $38,016 million.

24

Notes

2. Gulf of Mexico oil spill (continued)

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 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Income statement
	(617	)		843		Production and manufacturing expenses		813			(233	)
	617			(843	)	Profit (loss) before interest and taxation		(813	)		233
	15			4		Finance costs		10			31
	602			(847	)	Profit (loss) before taxation		(823	)		202
	(234	)		102		Less: Taxation		76			(33	)
	368			(745	)	Profit (loss) for the period		(747	)		169

	30 June 2012						31 December 2011
	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		5,109			5,109			8,487			8,233
Current liabilities
Trade and other payables		(2,377	)		(2,128	)		(5,425	)		(4,872	)
Provisions		(6,177	)		—			(9,437	)		—
Net current assets (liabilities)		(3,445	)		2,981			(6,375	)		3,361
Non-current assets
Other receivables		4,181			4,181			1,642			1,642
Non-current liabilities
Provisions		(8,745	)		—			(5,896	)		—
Deferred tax		7,285			—			7,775			—
Net non-current assets (liabilities)		2,721			4,181			3,521			1,642
Net assets (liabilities)		(724	)		7,162			(2,854	)		5,003

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Cash flow statement – Operating activities
	602			(847	)	Profit (loss) before taxation		(823	)		202
						Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
	15			4		Net charge for interest and other finance expense, less net interest paid		10			31
	(90	)		585		Net charge for provisions, less payments		670			112
	(2,912	)		(1,439	)	Movements in inventories and other current and non-current assets and liabilities		(3,300	)		(5,776	)
	(2,385	)		(1,697	)	Pre-tax cash flows		(3,443	)		(5,431	)

Net cash used in operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to $1,669 million and $2,877 million in the second quarter and half year 2012 respectively. For the second quarter and half year 2011 the amounts were $1,898 million and $4,706 million respectively.

25

Notes

2. Gulf of Mexico oil spill (continued)

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. The Trust is also being used to satisfy claims processed through the transitional court-supervised claims facility, to fund the qualified settlement funds established under the terms of the proposed settlement agreement with the PSC, and the separate BP claims programme – see below for further information.

During 2010 and 2011, BP contributed a total of $15,140 million to the fund, including cash settlements of $5,140 million received from co-owners and other third parties. A further cash settlement of $250 million was received in the first quarter of 2012 and was also contributed to the Trust in addition to regular contributions of $2,500 million in the first half of the year. As a result of these accelerated contributions, it is now expected that the $20-billion commitment will have been paid in full by the end of 2012. 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 and penalties are not covered by the trust fund.

The table below shows movements in the funding obligation during the period to 30 June 2012. This liability is recognized within current other payables on the balance sheet.

	Second quarter 2012			First half 2012
$ million
Opening balance		3,368			4,872
Unwinding of discount		4			9
Contributions		(1,250	)		(2,750	)
Other		6			(3	)
At 30 June 2012		2,128			2,128

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 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 2012. The amount of the reimbursement asset at 30 June 2012 is equal to the amount of provisions recognized at that date that will be covered by the trust fund – see below.

		Second quarter 2012			First half 2012
$ million
Opening balance			9,866			9,875
Increase in provision for items covered by the trust funds			12			497
Amounts paid directly by the trust funds			(588	)		(1,082	)
At 30 June 2012			9,290			9,290
Of which	– current		5,109			5,109
	– non-current		4,181			4,181

As noted above, the obligation to fund the $20-billion trust fund was 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 2012, the cumulative charges for provisions, and the associated reimbursement asset recognized, amounted to $17,102 million. Thus, a further $2,898 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 contingent liabilities 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) or otherwise that will ultimately be paid.

26

Notes

2. Gulf of Mexico oil spill (continued)

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 by the PSC court-supervised claims processes, 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. 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.

The proposed settlement agreement with the Plaintiffs’ Steering Committee (PSC) (see page 4 for further information) provides for a transition from the GCCF and a transitional claims facility for economic loss claims commenced operation in March 2012. The transitional claims facility ceased accepting new claims in June 2012 but will continue to process payments when final releases are received on unexpired outstanding offers. A new court-supervised settlement programme began accepting claims from “in-class” claimants under the PSC settlement agreements covering economic loss claims and medical claims. In addition, a separate BP claims programme began accepting claims from claimants who are not covered by the settlement agreements or who exercise their right to opt out.

Under the terms of the proposed PSC settlement agreement, several qualified settlement funds (QSFs) were established during the second quarter. These QSFs each relate to specific elements of the proposed agreement and are available to make payments to claimants in accordance with those elements of the agreement. The QSFs are, in turn, funded by the Trust. The establishment of the QSFs under the proposed settlement agreement has had no impact on the amounts charged to the income statement nor on amounts recognized as provisions or reimbursement assets.

As at 30 June 2012, the cash balances in the Trust and the QSFs amounted to $10,056 million.

(b) Provisions and contingent liabilities

BP has recorded certain provisions and disclosed certain contingent liabilities 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 2011 – Financial statements – Notes 2, 36 and 43.

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. Movements in each class of provision during the second quarter and first half of the year are presented in the table below.

The environmental provision includes amounts for BP’s commitment to fund the Gulf of Mexico Research Initiative, natural resource damage (NRD) assessment costs, emergency NRD restoration projects and early NRD restoration projects under the $1-billion framework agreement.

Further amounts for spill response costs were provided during the first quarter primarily to recognize increased costs of patrolling and maintenance of the shoreline. Minor adjustments in the second quarter led to a slight reduction in the spill response provision. The majority of the active clean-up of the shorelines was completed in 2011.

The litigation and claims provision includes the estimated future cost of settling Individual and Business claims, and State and Local claims under OPA 90, claims for personal injuries, both reported and unreported, and other litigation as well as claims administration costs and legal fees. BP announced on 3 March 2012 that a proposed settlement had been reached with the Plaintiffs’ Steering Committee (PSC), subject to final written agreement and court approvals, to resolve the substantial majority of legitimate economic loss and property damage claims and medical claims (Individual and Business claims) stemming from the Deepwater Horizon accident and oil spill. The PSC acts on behalf of the individual and business plaintiffs in the Multi-District Litigation proceedings pending in New Orleans (MDL 2179). The proposed settlement was an adjusting event after the 2011 reporting period and the estimated $7.8-billion cost was therefore reflected in the 2011 financial statements. On 18 April 2012 BP announced that it had reached definitive and fully documented settlement agreements with the PSC consistent with the terms of that settlement. The agreements remain subject to final court approval. See page 4 and Legal proceedings on pages

45 – 55 herein for further information.

During the first quarter certain claims administration costs, previously treated as payable from outside the trust fund, were reallocated as payable by the trust fund, as a result of the definitive PSC settlement agreements noted above. In addition, an increase in the provision for Individual and Business claims, payable from the Trust, was recognized in the first quarter. The increase in the provision during the second quarter reflects various costs and litigation relating to the Gulf of Mexico oil spill.

27

Notes

2. Gulf of Mexico oil spill (continued)

A provision was recognized in 2010 for the estimated penalties for strict liability under the Clean Water Act, which are based on a specified range per barrel of oil released. No adjustments have been made subsequently to this estimate. The penalty rate per barrel used to calculate the provision is based upon the company’s conclusion, amongst other things, that it did not act with gross negligence or engage in wilful misconduct.

BP considers that it is not possible, at this time, to measure reliably any obligation in relation to Natural Resource Damages claims under OPA 90 (other than the estimated costs of the assessment phase and the costs of emergency and early restoration agreements referred to above). It is also not possible to measure reliably any obligation in relation to other potential litigation, fines, or penalties, other than as described above. These items are therefore disclosed as contingent liabilities – see below.

		Environmental			Spill response			Litigation and  claims			Clean Water Act  penalties		Total
$ million
At 1 April 2012			1,510			350			9,555			3,510		14,925
Increase (decrease) in provision – items not covered by the trust funds			(12	)		(47	)		838			—		779
Increase in provision – items covered by the trust funds			12			—			—			—		12
Utilization	– paid by BP		(16	)		25			(215	)		—		(206	)
	– paid by the trust funds		(41	)		—			(547	)		—		(588	)
At 30 June 2012			1,453			328			9,631			3,510		14,922
Of which	– current		1,111			257			4,809			—		6,177
	– non-current		342			71			4,822			3,510		8,745
Of which	– payable from the trust funds		1,040			—			8,250			—		9,290

		Environmental			Spill response			Litigation and  claims			Clean Water Act  penalties		Total
$ million
At 1 January 2012			1,517			336			9,970			3,510		15,333
Increase in provision – items not covered by the trust funds			(12	)		35			660			—		683
Increase in provision – items covered by the trust funds			77			—			420			—		497
Unwinding of discount			1			—			—			—		1
Utilization	– paid by BP		(27	)		(43	)		(440	)		—		(510	)
	– paid by the trust funds		(103	)		—			(979	)		—		(1,082	)
At 30 June 2012			1,453			328			9,631			3,510		14,922

The income statement charge is analysed in the table below.

	Second quarter 2012			First half 2012
$ million
Net increase in provisions		791			1,180
Recognition of reimbursement asset		(12	)		(497	)
Other costs charged directly to the income statement		64			130
Loss before interest and taxation		843			813
Finance costs		4			10
Loss before taxation		847			823

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, significant uncertainty exists in relation to the amount of claims that will become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BP’s culpability based on any findings of negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP.

28

Notes

2. Gulf of Mexico oil spill (continued)

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.

Further information on provisions is provided in BP Annual Report and Form 20-F 2011 – Financial statements – Note 36.

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 emergency and early restoration agreements as described above under Provisions) and claims asserted in civil litigation including any further litigation through potential opt-outs from the PSC settlement, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore no amounts have been provided for these items as at 30 June 2012.

For those items not covered by the trust fund, BP has provided for its best estimate of certain liabilities as described under ‘Overview’ and ‘Provisions’ above. It is not possible to measure reliably any obligation in relation to other potential litigation, fines, or penalties, therefore no amounts have been provided for these items as at 30 June 2012.

Under the settlement agreements with co-owners Anadarko and MOEX, and with Cameron International, the designer and manufacturer of the Deepwater Horizon blowout preventer, with M-I L.L.C. (M-I), the mud contractor, and with Weatherford, the designer and manufacturer of the float collar used on the Macondo well, BP has agreed to indemnify Anadarko, MOEX, Cameron, M-I and Weatherford for certain claims arising from the accident. It is therefore possible that BP may face claims under these indemnities, but it is not currently possible to reliably measure any obligation in relation to such claims and therefore no amount has been provided as at 30 June 2012.

See Legal proceedings on pages 45 – 55 for further information on contingent liabilities, including information on the federal multi-district litigation proceeding in New Orleans. Any settlements which may be reached relating to the Deepwater Horizon oil spill could impact the amount and timing of any future payments.

3. Non-current assets held for sale

As a result of the group’s disposal programme, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 30 June 2012. The carrying amount of the assets held for sale is $8,910 million, with associated liabilities of $2,524 million. Included within these amounts are the following items, which relate to the Upstream segment unless otherwise stated.

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 and the upstream and certain midstream assets in Vietnam completed during 2011. BP continues to work towards satisfaction of the regulatory and other approvals and conditions to completion of the sale of its equity-accounted investment in the Phu My 3 plant facility in Vietnam in 2012. The investment in the Phu My 3 plant facility has been classified as held for sale in the group balance sheet at 30 June 2012.

On 27 March 2012, BP announced that it had agreed to sell its interests in its southern gas assets (SGA) in the UK North Sea to Perenco UK Ltd (Perenco) for $400 million in cash. Perenco has made an initial payment to BP of $100 million in cash and the remaining $300 million will be paid on completion. A further $10 million may be paid in the future contingent on the prevailing gas prices. The assets, and associated liabilities, of SGA have been classified as held for sale in the group balance sheet at 30 June 2012. Completion of the transaction is subject to a number of third-party and regulatory approvals, and is expected to occur before the end of 2012.

In May 2012, BP announced its intention to sell its interests in the Marlin, King, Dorado, Horn Mountain, Holstein, Diana Hoover and Ram Powell fields in the Gulf of Mexico, together with its interests in some exploration prospects located in the vicinity of the fields. The assets, and associated liabilities, of these fields and prospects have been classified as held for sale in the group balance sheet at 30 June 2012. The transaction is expected to complete before the end of 2012.

29

Notes

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

On 25 June 2012, BP announced that it had agreed to sell its interest in the Jonah and Pinedale upstream operations in Wyoming to LINN Energy, LLC. Under the agreement, LINN Energy has agreed to pay BP $1.025 billion in cash for the assets. The assets, and associated liabilities, of these interests have been classified as held for sale in the group balance sheet at 30 June 2012. Completion of the sale is subject to closing conditions including the receipt of all necessary governmental and regulatory approvals. The sale is expected to complete during the third quarter.

Within the Downstream segment, BP continues to progress its plans for the sale of the Texas City refinery and related assets, and the southern part of its US West Coast fuels value chain, including the Carson refinery. We are in advanced discussions on both assets and remain on track to announce both sales by the end of 2012. The non-current assets, together with the inventories, of these businesses have been classified as held for sale in the group balance sheet at 30 June 2012.

Deposits of $30 million ($30 million at 31 December 2011) received in advance of completion of certain of these transactions have been classified as finance debt on the group balance sheet at 30 June 2012. 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.

4. Sales and other operating revenues

Second quarter 2011		Second quarter 2012				First half 2012		First half 2011
					$ million
					By business
	18,418		16,542		Upstream		35,800		36,823
	93,886		86,692		Downstream		172,623		171,319
	985		527		Other businesses and corporate		955		1,841
	113,289		103,761				209,378		209,983
					Less: sales and other operating revenues between businesses
	11,539		10,348		Upstream		21,005		22,064
	165		(163	)	Downstream		583		791
	221		235		Other businesses and corporate		409		435
	11,925		10,420				21,997		23,290
					Third party sales and other operating revenues
	6,879		6,194		Upstream		14,795		14,759
	93,721		86,855		Downstream		172,040		170,528
	764		292		Other businesses and corporate		546		1,406
	101,364		93,341		Total third party sales and other operating revenues		187,381		186,693
					By geographical area
	38,817		34,784		US		68,511		69,664
	73,350		67,670		Non-US		138,010		137,205
	112,167		102,454				206,521		206,869
	10,803		9,113		Less: sales and other operating revenues between areas		19,140		20,176
	101,364		93,341				187,381		186,693

30

Notes

5. Production and similar taxes

Second quarter 2011		Second quarter 2012			First half 2012		First half 2011
				$ million
	563		307	US		797		937
	1,793		1,520	Non-US		3,376		3,250
	2,356		1,827			4,173		4,187

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 2011			Second quarter 2012				First half 2012		First half 2011
						$ million
						Results for the period
	5,718			(1,385	)	Profit (loss) for the period attributable to BP shareholders		4,530		12,972
	1			1		Less: Preference dividend		1		1
	5,717			(1,386	)	Profit (loss) attributable to BP ordinary shareholders		4,529		12,971
	(311	)		1,623		Inventory holding (gains) losses, net of tax		637		(1,954	)
	5,406			237		RC profit attributable to BP ordinary shareholders		5,166		11,017
	298			3,447		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax		3,317		191
	5,704			3,684		Underlying RC profit attributable to BP shareholders		8,483		11,208
						Number of shares (thousand)(a)
	18,886,382			19,020,874		Basic weighted average number of shares outstanding		18,999,255		18,851,483
	3,147,730			3,170,146		ADS equivalent		3,166,543		3,141,914
	19,118,850			19,284,485		Weighted average number of shares outstanding used to calculate diluted earnings per share(b)		19,257,992		19,071,882
	3,186,475			3,214,081		ADS equivalent		3,209,665		3,178,647
	18,940,090			19,029,938		Shares in issue at period-end		19,029,938		18,940,090
	3,156,682			3,171,656		ADS equivalent		3,171,656		3,156,682

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

(b) Where the result for the period is a loss the basic weighted average number of shares is used to calculate diluted earnings per share.

31

Notes

7. Analysis of changes in net debt^(a)

Second quarter 2011			Second quarter 2012				First half 2012			First half 2011
						$ million
						Opening balance
	47,102			46,470		Finance debt		44,213			45,336
	18,726			14,092		Less: Cash and cash equivalents		14,067			18,556
	870			1,224		Less: FV asset of hedges related to finance debt		1,133			916
	27,506			31,154		Opening net debt		29,013			25,864
						Closing balance
	46,890			47,662		Finance debt		47,662			46,890
	18,749			14,881		Less: Cash and cash equivalents		14,881			18,749
	1,173			1,067		Less: FV asset of hedges related to finance debt		1,067			1,173
	26,968			31,714		Closing net debt		31,714			26,968
	538			(560	)	Decrease (increase) in net debt		(2,701	)		(1,104	)
	(81	)		1,139		Movement in cash and cash equivalents (excluding exchange adjustments)		1,046			(106	)
	563			(1,679	)	Net cash outflow (inflow) from financing (excluding share capital)		(3,740	)		(2,681	)
	2			—		Movement in finance debt relating to investing activities(b)		—			1,597
	5			(4	)	Other movements		(11	)		(16	)
	489			(544	)	Movement in net debt before exchange effects		(2,705	)		(1,206	)
	49			(16	)	Exchange adjustments		4			102
	538			(560	)	Decrease (increase) in net debt		(2,701	)		(1,104	)

(a) Net debt is a non-GAAP measure.

(b) During the second quarter 2012 no disposal transactions were completed in respect of which deposits had been received in advance (second quarter 2011 $502 million). At 30 June 2012, finance debt includes $30 million of deposits received in advance relating to disposal transactions ($500 million at 30 June 2011).

At 30 June 2012, $133 million of finance debt ($626 million at 30 June 2011) was secured by the pledging of assets, and no finance debt was secured in connection with deposits received relating to disposal transactions expected to complete in subsequent periods ($3,530 million at 30 June 2011). In addition, in connection with $2,066 million of finance debt ($3,014 million at 30 June 2011), 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 2012, the total available undrawn committed borrowing facilities stood at $6.9 billion ($7.2 billion at 30 June 2011).

8. Inventory valuation

A provision of $152 million was held at 31 December 2011 to write inventories down to their net realizable value. The net movement in the provision during the second quarter 2012 was an increase of $398 million (second quarter 2011 was an increase of $381 million). The net movement in the provision in the half year 2012 was an increase of $360 million, compared with an increase of $397 million for the half year 2011.

9. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 30 July 2012, is unaudited and does not constitute statutory financial statements.

32

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 reclassifications			BP group
$ million
First half 2012
Sales and other operating revenues		2,877			—			187,381			(2,877	)		187,381
Earnings from jointly controlled entities – after interest and tax		—			—			378			—			378
Earnings from associates – after interest and tax		—			—			1,805			—			1,805
Equity-accounted income of subsidiaries – after interest and tax		(331	)		4,759			—			(4,428	)		—
Interest and other revenues		6			104			398			(157	)		351
Gains on sale of businesses and fixed assets		—			—			1,675			—			1,675
Total revenues and other income		2,552			4,863			191,637			(7,462	)		191,590
Purchases		441			—			149,601			(2,877	)		147,165
Production and manufacturing expenses		680			—			13,930			—			14,610
Production and similar taxes		741			—			3,432			—			4,173
Depreciation, depletion and amortization		235			—			5,850			—			6,085
Impairment and losses on sale of businesses and fixed assets		957			—			4,004			—			4,961
Exploration expense		—			—			876			—			876
Distribution and administration expenses		13			483			5,871			(26	)		6,341
Fair value (gain) loss on embedded derivatives		—			—			(171	)		—			(171	)
Profit (loss) before interest and taxation		(515	)		4,380			8,244			(4,559	)		7,550
Finance costs		24			27			630			(131	)		550
Net finance expense (income) relating to pensions and other post-retirement benefits		—			(215	)		107			—			(108	)
Profit (loss) before taxation		(539	)		4,568			7,507			(4,428	)		7,108
Taxation		(31	)		38			2,465			—			2,472
Profit (loss) for the period		(508	)		4,530			5,042			(4,428	)		4,636
Attributable to:
BP shareholders		(508	)		4,530			4,936			(4,428	)		4,530
Minority interest		—			—			106			—			106
		(508	)		4,530			5,042			(4,428	)		4,636

33

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
$ million
First half 2011
Sales and other operating revenues		3,084			—			186,693		(3,084	)		186,693
Earnings from jointly controlled entities – after interest and tax		—			—			793		—			793
Earnings from associates – after interest and tax		—			—			2,664		—			2,664
Equity-accounted income of subsidiaries – after interest and tax		266			13,266			—		(13,532	)		—
Interest and other revenues		3			76			293		(97	)		275
Gains on sale of businesses and fixed assets		—			—			1,963		—			1,963
Total revenues and other income		3,353			13,342			192,406		(16,713	)		192,388
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			12,778			20,377		(13,594	)		20,714
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			13,034			19,583		(13,532	)		20,226
Taxation		359			62			6,702		—			7,123
Profit (loss) for the period		782			12,972			12,881		(13,532	)		13,103
Attributable to:
BP shareholders		782			12,972			12,750		(13,532	)		12,972
Minority interest		—			—			131		—			131
		782			12,972			12,881		(13,532	)		13,103

34

Notes

10. Condensed consolidating information (continued)

	Issuer		Guarantor
Balance sheet	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries		Eliminations and reclassifications			BP group
$ million
At 30 June 2012
Non-current assets
Property, plant and equipment		8,137		—		109,428		—			117,565
Goodwill		—		—		11,831		—			11,831
Intangible assets		356		—		21,989		—			22,345
Investments in jointly controlled entities		—		—		15,672		—			15,672
Investments in associates		—		2		13,875		—			13,877
Other investments		—		—		1,909		—			1,909
Subsidiaries – equity-accounted basis		4,471		132,579		—		(137,050	)		—
Fixed assets		12,964		132,581		174,704		(137,050	)		183,199
Loans		44		—		5,062		(4,274	)		832
Other receivables		—		—		6,731		—			6,731
Derivative financial instruments		—		—		5,142		—			5,142
Prepayments		—		—		1,302		—			1,302
Deferred tax assets		—		—		683		—			683
Defined benefit pension plan surpluses		—		—		22		—			22
		13,008		132,581		193,646		(141,324	)		197,911
Current assets
Loans		—		—		242		—			242
Inventories		177		—		26,257		—			26,434
Trade and other receivables		3,904		14,856		44,582		(24,962	)		38,380
Derivative financial instruments		—		—		3,770		—			3,770
Prepayments		172		—		1,182		—			1,354
Current tax receivable		—		11		361		—			372
Other investments		—		—		304		—			304
Cash and cash equivalents		—		5		14,876		—			14,881
		4,253		14,872		91,574		(24,962	)		85,737
Assets classified as held for sale		—		—		8,910		—			8,910
Total assets		17,261		147,453		294,130		(166,286	)		292,558
Current liabilities
Trade and other payables		4,803		2,428		64,880		(24,962	)		47,149
Derivative financial instruments		—		—		3,417		—			3,417
Accruals		—		23		6,162		—			6,185
Finance debt		—		—		7,213		—			7,213
Current tax payable		158		—		1,722		—			1,880
Provisions		—		—		7,829		—			7,829
		4,961		2,451		91,223		(24,962	)		73,673
Liabilities directly associated with assets classified as held for sale		—		—		2,524		—			2,524
		4,961		2,451		93,747		(24,962	)		76,197
Non-current liabilities
Other payables		10		4,265		2,626		(4,274	)		2,627
Derivative financial instruments		—		—		3,682		—			3,682
Accruals		—		29		431		—			460
Finance debt		—		—		40,449		—			40,449
Deferred tax liabilities		1,637		—		12,685		—			14,322
Provisions		1,839		—		27,385		—			29,224
Defined benefit pension plan and other post-retirement benefit plan deficits		—		1,966		10,308		—			12,274
		3,486		6,260		97,566		(4,274	)		103,038
Total liabilities		8,447		8,711		191,313		(29,236	)		179,235
Net assets		8,814		138,742		102,817		(137,050	)		113,323
Equity
BP shareholders’ equity		8,814		138,742		101,726		(137,050	)		112,232
Minority interest		—		—		1,091		—			1,091
Total Equity		8,814		138,742		102,817		(137,050	)		113,323

35

Notes

10. Condensed consolidating information (continued)

	Issuer		Guarantor
Balance sheet	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries		Eliminations and reclassifications			BP group
$ million
At 30 June 2011
Non-current assets
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		—		—		15,352		—			15,352
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		160,937		(131,268	)		169,254
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		178,502		(135,580	)		184,833
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		—		—		7,526		—			7,526
Total assets		16,729		141,271		290,819		(157,596	)		291,223
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		97,209		(131,268	)		108,636
Equity
BP shareholders’ equity		8,691		134,004		96,295		(131,268	)		107,722
Minority interest		—		—		914		—			914
Total Equity		8,691		134,004		97,209		(131,268	)		108,636

36

Notes

10. Condensed consolidating information (continued)

	Issuer			Guarantor
Cash flow statement	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries			Eliminations and reclassifications		BP group
$ million
First half 2012
Net cash provided by operating activities		362			2,842			4,566			—		7,770
Net cash used in investing activities		(361	)		—			(7,430	)		—		(7,791	)
Net cash used in financing activities		—			(2,844	)		3,911			—		1,067
Currency translation differences relating to cash and cash equivalents		—			7			(239	)		—		(232	)
Increase in cash and cash equivalents		1			5			808			—		814
Cash and cash equivalents at beginning of period		(1	)		—			14,068			—		14,067
Cash and cash equivalents at end of period		—			5			14,876			—		14,881

	Issuer			Guarantor
Cash flow statement	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries			Eliminations and reclassifications			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

37

Principal risks and uncertainties

We urge you to consider carefully the risks described below. The potential impact of their occurrence could be for our business, financial condition and results of operations to suffer (including through the failure to achieve our current strategic priorities (see ‘10-point plan’ in BP’s Annual Report and Form 20-F 2011 on pages 38-39) 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 the remaining costs and liabilities relating to the Incident, the impact of the Incident on our reputation and the resulting possible impact on our licence to operate including 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.

By the end of the second quarter 2012, we had recognized a total net pre-tax charge of $38.0 billion as a result of the Incident since it occurred in 2010. 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 potential determination of BP’s negligence or gross negligence), the outcome of litigation, the amount and timing of payments under any settlements, 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. In particular, ongoing instability in or a collapse of the eurozone could trigger a new wave of financial crises and push the world back into recession, leading to lower demand and lower oil and gas prices. 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 are subject to volatility amid concerns over the European sovereign debt crisis and the slow-down of the global economy. 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 could impact our future hydrocarbon production.

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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 (including conflict situations) 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, Bolivia, Argentina and other countries could be adversely affected by heightened political and economic environment risks. See Annual Report and Form 20-F 2011 pages 34-35 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 or that we have not satisfactorily addressed all relevant stakeholder concerns in respect of our operations, our reputation and shareholder value could be damaged and development opportunities may be precluded.

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, if our innovation lagged the industry, or if we failed to adequately protect our company brands and trademarks.

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.

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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, settlements 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, by the end of the second-quarter 2012, we had recognized a total net pre-tax charge of $30.0 billion related to the Incident since it occurred in 2010, 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 pages 24 – 29, Legal proceedings on pages 45 - 55, and Annual Report and Form 20-F 2011 Financial statements – Note 2 on pages 190 – 194. 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.

See our Annual Report and Form 20-F 2011 Financial statements – Note 26 on page 217 for more information on financial instruments and financial risk factors.

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.

Compliance and control risks

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

After the Gulf of Mexico oil spill, it is likely that there will be 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. 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.

40

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.

See Annual Report and Form 20-F 2011 pages 107-110 for more information on environmental regulation.

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. Our renewed values, which were launched in 2011, are intended to guide the way we and our employees behave and do business. 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 and in contravention of our renewed values 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 45 – 55. For further information on the risks involved in BP’s trading activities, see Operational risks – Treasury and trading activities on page 44.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements 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 Oil Pollution Act of 1990 (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 certain natural resource damages associated with the spill and certain costs determined 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 45 – 55.

BP is subject to a number of investigations related to the Incident by numerous federal and State agencies. See Legal proceedings on pages 160-166 of BP’s Annual Report and Form 20-F 2011. 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, in some circumstances, their assessment of BP’s culpability, if any, 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 during 2011 with both partners, one contractor, and the manufacturer of the blowout preventer at the Macondo well, further recoveries are not certain and so have not been recognized in the financial statements (see Note 2 on pages 24 – 29 and our Annual Report and Form 20-F 2011 Financial statements – Note 2 on pages 190-194).

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 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.

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Principal risks and uncertainties (continued)

BP has reached agreement with the Plaintiffs’ Steering Committee (PSC) in the Multi-District Litigation pending in New Orleans (MDL 2179) to resolve the substantial majority of legitimate private economic loss and medical claims stemming from the Incident. While the court has given preliminary approval to these agreements, a further fairness hearing is scheduled for 8 November 2012 to determine whether to grant final approval of the settlements. Failure to receive final approval of the settlements could jeopardize their terms and ultimately cause court proceedings to re-commence.

BP estimates that the settlement will cost approximately $7.8 billion, including administration costs, plaintiffs’ attorneys’ fees and expenses. The cost is expected to be paid from the $20-billion Deepwater Horizon Oil Spill Trust fund (Trust). While BP has sought to reliably estimate the cost of the settlement agreements, it is possible that the actual cost could be higher or lower than this estimate depending on the outcomes of the court-supervised claims processes.

The Gulf of Mexico oil spill has damaged BP’s reputation. This, combined with other past 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 any alleged breaches of safety or environmental regulations.

See Legal proceedings on pages 45 – 55 and BP’s Annual Report and Form 20-F 2011 Financial statements – Note 36 on pages 231-234.

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 oil spill. 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 and strategic objectives due to the nature of some of its business relationships’ on page 44.

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 and safety 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, damage to our reputation or denial of our licence to operate.

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Principal risks and uncertainties (continued)

To help address health, safety, security, environmental and operations risks, and to provide a consistent framework within which the group can analyse the performance of its activities and identify and remediate shortfalls, BP has introduced a group-wide operating management system (OMS). Work on the application of OMS in individual operating businesses continues and following the Gulf of Mexico oil spill an enhanced safety and operational risk (S&OR) function was 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 conformance 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, cyber-attacks 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, among other things, conflict, civil strife or political unrest in areas where we operate.

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 oil spill 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 people and the environment and given the high volumes potentially 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’ on page 63 of our Annual Report and Form 20-F 2011.

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, breaches of regulations, litigation, legal liabilities and reparation costs.

The reliability and security of our digital infrastructure are critical to maintaining the availability of our business applications, including the reliable operation of technology in our various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. A breach of our digital security, either due to intentional actions or due to negligence, could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

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 our business and operations.

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Principal risks and uncertainties (continued)

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 Board and 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 personnel will need to continue to devote substantial attention to addressing 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 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.

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.

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Legal proceedings

Proceedings relating to the Deepwater Horizon 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 approximately 650 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. The other working interest owners at the time of the Incident were 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, insurers, and governmental entities and many of the lawsuits purport to be class actions. The lawsuits assert, among others, 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, claims for unpaid wages, injunctive and declaratory 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 implemented as part of the response to the Incident. 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, ERISA and dividend cases and another in federal court in New Orleans for the remaining cases.

In addition, BP has been named in several lawsuits alleging claims under the Racketeer-Influenced and Corrupt Organizations Act (RICO). 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.

On 26 August 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted in part BP’s motion to dismiss a master complaint raising claims for economic loss by private plaintiffs, dismissing plaintiffs’ state law claims and limiting the types of maritime law claims plaintiffs may pursue, but also held that certain classes of claimants may seek punitive damages under general maritime law. The judge did not, however, lift an earlier stay on the underlying individual complaints raising those claims or otherwise apply his dismissal of the master complaint to those individual complaints. On 30 September 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted in part BP’s motion to dismiss a master complaint asserting personal injury claims on behalf of persons exposed to crude oil or chemical dispersants, dismissing plaintiffs’ state law claims, claims by seamen for punitive damages, claims for medical monitoring damages by asymptomatic plaintiffs, claims for battery and nuisance under maritime law, and claims alleging negligence per se. As with his other rulings on motions to dismiss master complaints, the judge did not lift an earlier stay on the underlying individual complaints raising those claims or otherwise apply his dismissal of the master complaint to those individual complaints.

Shareholder derivative lawsuits related to the Incident have 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. On 15 September 2011, the judge in the federal multi-district litigation proceeding in Houston (MDL 2185) granted BP’s motion to dismiss the consolidated shareholder derivative litigation pending there on the grounds that the courts of England are the appropriate forum for the litigation. On 8 December 2011, a final judgment was entered dismissing the shareholder derivative case, and on 3 January 2012, one of the derivative plaintiffs filed a notice of appeal to the US Court of Appeals for the Fifth Circuit.

On 13 February 2012, the judge in the federal multi-district litigation proceeding in Houston issued two decisions on the defendants’ motions to dismiss the two consolidated securities fraud complaints filed on behalf of purported classes of BP ordinary shareholders and ADS holders. In those decisions the court dismissed all of the claims of the ordinary shareholders, dismissed the claims of the lead class of ADS holders against most of the individual defendants while holding that a subset of the claims against two individual defendants and the corporate defendants could proceed, and dismissed all of the claims of a smaller purported subclass with leave to re-plead in 20 days. On 2 April 2012, plaintiffs in the lead class and subclass filed an amended consolidated complaint with claims based on (1) the 12 alleged misstatements that the court held were actionable in its February 2012 order on BP’s motion to dismiss the earlier complaints; and (2) 13 alleged misstatements concerning BP’s Operating Management System that the judge either rejected with leave to re-plead or did not address in his February decisions. On 2 May 2012, defendants moved to dismiss the claims based on the 13 statements in the amended complaint that the judge did not already rule are actionable.

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In April and May 2012, six new cases were filed in state and federal courts on behalf of one or more state, county or municipal pension funds against BP entities and several current and former officers and directors seeking damages for alleged losses those funds suffered because of their holdings of BP ordinary shares and, in three cases, ADSs. The funds assert various state law and federal law claims. All of the cases have been transferred to the judge in the federal multi-district litigation proceeding in Houston. In May and June, plaintiffs in the two cases that were filed in state court have moved to send those cases back to state court. On 23 July 2012, another case was filed in Texas state court by a U.K. pension fund against BP entities and a current officer and former officer, asserting Texas state law claims, seeking damages for alleged losses that fund suffered because of its holdings of BP ordinary shares. On 20 July 2012, BP was served with an amended statement of claim for an action in Alberta, Canada, filed by three plaintiffs seeking to assert claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ordinary shares and ADSs.

On 5 July 2012, the judge in the federal multi-district litigation proceeding in Houston (MDL 2185) issued a decision granting the defendants’ motions to dismiss, for lack of personal jurisdiction, the lawsuit against BP p.l.c. for cancelling its dividend payment in June 2010.

Purported class action lawsuits have been filed in US federal courts against BP entities and/or various current and former officers and directors alleging, among other things, shareholder derivative claims, 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.

On 30 March 2012, the judge in the federal multi-district litigation proceeding in Houston (MDL 2185) issued a decision granting the defendants’ motions to dismiss the ERISA case related to BP share funds in several employee benefit savings plans. On 11 April 2012, plaintiffs requested leave to file an amended complaint.

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 types of enforcement action that might be pursued and the nature of the remedies that might be sought will depend on the judgement and discretion of the prosecutors and regulatory authorities and their assessment as to whether BP has violated any applicable laws and its culpability following their investigations. Such enforcement actions could include criminal proceedings against BP and/or employees of the group. Prosecutors have broad discretion in identifying what, if any, charges to pursue, but such charges could include, among others, criminal environmental, criminal securities, manslaughter and obstruction-related offences. The United States filed a civil complaint in the multi-district litigation proceeding in New Orleans 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 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 and Halliburton moved to dismiss BP’s claims against them in the DoJ Action. BP’s claim against Cameron has been resolved pursuant to settlement, but Halliburton’s motion remains pending.

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.

On 8 December 2011, the United States brought a motion for partial summary judgment seeking, among other things, an order finding that BP, Transocean, and Anadarko are strictly liable for a civil penalty under Section 311(b) (7)(A) of the Clean Water Act. On 22 February 2012, the judge ruled on motions filed in the DoJ Action by the United States, Anadarko, and Transocean seeking early rulings regarding the liability of BP, Anadarko, and Transocean under OPA 90 and the Clean Water Act, but limited the order to addressing the discharge of hydrocarbons occurring under the surface of the water. Regarding OPA 90, the judge held that BP and Anadarko are responsible parties under OPA 90 with regard to the subsurface discharge. The judge ruled that BP and Anadarko have joint and several liability under OPA 90 for removal costs and damages for such discharge, but did not rule on whether such liability under OPA 90 is unlimited. While the judge held that Transocean is not a responsible party under OPA 90 for subsurface discharge, the judge left open the question of whether Transocean may be liable under OPA 90 for removal costs for such discharge as the owner/operator of the Deepwater Horizon. Regarding the Clean Water Act, the judge held that the subsurface discharge was from the Macondo well, rather than from the Deepwater Horizon, and that BP and Anadarko are liable for civil penalties under Section 311 of the Clean Water Act as owners of the well. The judge left open the question of whether Transocean may be liable under the Clean Water Act as an operator of the Macondo well.

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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 sought a declaration that it was excused from its contractual obligation to pay Incident-related costs. Anadarko also sought 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. Under the settlement agreement, MOEX has paid BP $1.065 billion, which BP has applied towards the $20-billion Trust and has also agreed to transfer all of its 10% interest in the MC252 lease to BP. On 17 October 2011, BP and Anadarko announced that they had reached a final agreement to settle all claims between the companies related to the Incident, including mutual releases of all claims between BP and Anadarko that are subject to the contractual out-of-court dispute resolution proceedings or the federal multi-district litigation proceeding in New Orleans. Under the settlement agreement, Anadarko has paid BP $4 billion, which BP has applied towards the $20-billion Trust, and has also agreed to transfer all of its 25% interest in the MC252 lease to BP. The settlement agreement also grants Anadarko the opportunity for a 12.5% participation in certain future recoveries from third parties and certain insurance proceeds in the event that such recoveries and proceeds exceed $1.5 billion in aggregate. Any such payments to Anadarko are capped at a total of $1 billion. BP has agreed to indemnify Anadarko and MOEX for certain claims arising from the Incident (excluding civil, criminal or administrative fines and penalties, claims for punitive damages, and certain other claims). The settlement agreements with Anadarko and MOEX are not an admission of liability by any party regarding the Incident.

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 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 1 November 2011, Transocean filed a motion for partial summary judgment on certain claims filed in the Limitation Action and the DoJ Action between BP and Transocean. Transocean’s motion sought an order which would bar BP’s contribution claims against Transocean and require BP to defend and indemnify Transocean against all pollution claims, including those resulting from any gross negligence, and from civil fines and penalties sought by the government. On 7 December 2011, BP filed a cross-motion for summary judgment seeking an order that BP is not required to indemnify Transocean for any civil fines and penalties sought by the government or for punitive damages.

On 26 January 2012, the judge ruled on BP’s and Transocean’s indemnity motions, holding that BP is required to indemnify Transocean for third-party claims for compensatory damages resulting from pollution originating beneath the surface of the water, regardless of whether the claim results from Transocean’s strict liability, negligence, or gross negligence. The court, however, ruled that BP does not owe Transocean indemnity for such claims to the extent Transocean is held liable for punitive damages or for civil penalties under the Clean Water Act, or if Transocean acted with intentional or wilful misconduct in excess of gross negligence. The court further held that BP’s obligation to defend Transocean for third-party claims does not require BP to fund Transocean’s defence of third-party claims at this time, nor does it include Transocean’s expenses in proving its right to indemnity. The court deferred a final ruling on the question of whether Transocean breached its drilling contract with BP so as to invalidate the contract’s indemnity clause.

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 wilful 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. On 3 May 2011, BP E&P removed Halliburton’s case to federal court, and on 9 August 2011, the action was transferred to the federal multi-district litigation proceedings pending in New Orleans.

Subsequently, on 30 November 2011, Halliburton filed a motion for summary judgment in the federal multi-district litigation proceedings pending in New Orleans. Halliburton’s motion seeks an order stating that Halliburton is entitled to full and complete indemnity, including payment of defence costs, from BP for claims related to the Incident and denying BP’s claims seeking contribution against Halliburton. On 21 December 2011, BP filed a cross-motion for partial summary judgment seeking an order that BP has no contractual obligation to indemnify Halliburton for fines, penalties, or punitive damages resulting from the Incident.

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On 31 January 2012, the judge ruled on BP’s and Halliburton’s indemnity motions, holding that BP is required to indemnify Halliburton for third-party claims for compensatory damages resulting from pollution that did not originate from property or equipment of Halliburton located above the surface of the land or water, regardless of whether the claims result from Halliburton’s gross negligence. The court, however, ruled that BP does not owe Halliburton indemnity to the extent that Halliburton is held liable for punitive damages or for civil penalties under the Clean Water Act. The court further held that BP’s obligation to defend Halliburton for third-party claims does not require BP to fund Halliburton’s defence of third-party claims at this time, nor does it include Halliburton’s expenses in proving its right to indemnity. The court deferred ruling on whether BP is required to indemnify Halliburton for any penalties or fines under the Outer Continental Shelf Lands Act. It also deferred ruling on whether Halliburton acted so as to invalidate the indemnity by breaching its contract with BP, by committing fraud, or by committing another act that materially increased the risk to BP or prejudiced the rights of BP as an indemnitor.

On 1 September 2011, Halliburton filed an additional lawsuit against BP in Texas state court. Its complaint alleges that BP did not identify the existence of a purported hydrocarbon zone at the Macondo well to Halliburton in connection with Halliburton’s cement work performed before the Incident and that BP has concealed the existence of this purported hydrocarbon zone following the Incident. Halliburton claims that the alleged failure to identify this information has harmed its business ventures and reputation and resulted in lost profits and other damages. On 16 September 2011, BP removed the action to federal court, where it was stayed pending a decision by the Judicial Panel on Multidistrict Litigation on transfer of the action to the multi-district litigation proceeding in New Orleans. On 1 September 2011, Halliburton also moved to amend its claims in Transocean’s Limitation of Liability action to add claims for fraud based on similar factual allegations to those included in its 1 September 2011 lawsuit against BP in Texas state court. On 11 October 2011, the magistrate judge in the federal multi-district litigation proceeding in New Orleans denied Halliburton’s motion to amend its claims, and Halliburton’s motion to review the order was denied by the judge on 19 December 2011.

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, 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 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, 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 proceeding pending in New Orleans.

On 16 December 2011, BP and Cameron announced their agreement to settle all claims between the companies related to the Incident, including mutual releases of claims between BP and Cameron that are subject to the federal multi-district litigation proceeding in New Orleans. Under the settlement agreement, Cameron has paid BP $250 million in cash in January 2012, which BP has applied towards the $20-billion Trust. BP has agreed to indemnify Cameron for compensatory claims arising from the Incident, including claims brought relating to pollution damage or any damage to natural resources, but excluding civil, criminal or administrative fines and penalties, claims for punitive damages, and certain other claims.

On 20 May 2011, Dril-Quip, Inc. and M-I L.L.C. (M-I) 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 also claimed a right to indemnity for such damages based on its well services contracts with BP. On 20 June 2011, BP filed counter-complaints against Dril-Quip, Inc. and M-I, asking for contribution and subrogation based on those entities’ fault in connection with the Incident and under OPA 90, and seeking declaratory judgment that Dril-Quip, Inc. and M-I caused or contributed to, and are responsible in whole or in part for damages incurred by BP in relation to, the Incident. On 20 January 2012, the court granted Dril-Quip, Inc.’s motion for summary judgment, dismissing with prejudice all claims asserted against Dril-Quip in the federal multi-district litigation proceeding in New Orleans.

On 21 January 2012, BP and M-I entered into an agreement settling all claims between the companies related to the Incident, including mutual releases of claims between BP and M-I that are subject to the federal multi-district litigation proceeding in New Orleans. Under the settlement agreement, M-I has agreed to indemnify BP for personal injury and death claims brought by M-I employees. BP has agreed to indemnify M-I for claims resulting from the Incident, but excluding certain claims.

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On 14 September 2011, the BOEMRE issued its report (BOEMRE Report) regarding the causes of the 20 April 2010 Macondo well blowout. The BOEMRE Report states that decisions by BP, Halliburton and Transocean increased the risk or failed to fully consider or mitigate the risk of a blowout on 20 April 2010. The BOEMRE Report also states that BP, and Transocean and Halliburton, violated certain regulations related to offshore drilling. In itself, the BOEMRE Report does not constitute the initiation of enforcement proceedings relating to any violation. On 12 October 2011, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement issued to BP E&P, Transocean, and Halliburton Notification of Incidents of Noncompliance (INCs). The notification issued to BP E&P is for a number of alleged regulatory violations concerning Macondo well operations. The Department of Interior has indicated that this list of violations may be supplemented as additional evidence is reviewed, and on 7 December 2011, the Bureau of Safety and Environmental Enforcement issued to BP E&P a second INC. This notification was issued to BP for five alleged violations related to drilling and abandonment operations at the Macondo well. BP has filed an administrative appeal with respect to the first and second INCs. BP has filed a joint stay of proceedings with the Department of Interior with respect to both INCs.

A Trial of Liability, Limitation, Exoneration, and Fault Allocation was originally scheduled to begin in the federal multi-district litigation proceeding in New Orleans in February 2012. The court’s pre-trial order issued 14 September 2011 provided for the trial to proceed in three phases and to include issues asserted in or relevant to the claims, counterclaims, cross-claims, third-party claims, and comparative fault defences raised in Transocean’s Limitation of Liability Action.

On 18 October 2011, Cameron filed a petition for writ of mandamus with US Court of Appeals for the Fifth Circuit seeking an order vacating the trial plan for the 27 February 2012 trial and requiring that all claims against Cameron in that proceeding be tried before a jury. On 26 December 2011, the Court of Appeals denied the application for mandamus.

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 environmental civil penalties and other relief under state law. On 23 September 2011, BP removed this matter to federal district court. District Attorneys of 11 parishes 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 14 November 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted in part BP’s motion to dismiss the complaints filed by the States of Alabama and Louisiana. The judge’s order dismissed the States’ claims brought under state law, including claims for civil penalties and the State of Louisiana’s request for a declaratory judgment under the Louisiana Oil Spill Prevention and Response Act, holding that those claims were pre-empted by federal law. It also dismissed the State of Louisiana’s claims of nuisance and trespass under general maritime law. The judge’s order further held that the States have stated claims for negligence and products liability under general maritime law, that the States have sufficiently alleged presentment of their claims under OPA 90, and that the States may seek punitive damages under general maritime law. On 9 December 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted in part BP’s motion to dismiss a master complaint brought on behalf of local government entities. The judge’s order dismissed plaintiffs’ state law claims and limited the types of maritime law claims plaintiffs may pursue, but also held that the plaintiffs have sufficiently alleged presentment of their claims under OPA 90 and that certain local government entity claimants may seek punitive damages under general maritime law. The judge did not, however, lift an earlier stay on the underlying individual complaints raising those claims or otherwise apply his dismissal of the master complaint to those individual complaints.

On 9 December 2011 and 28 December 2011, the judge in the federal multi-district litigation proceeding in New Orleans also granted BP’s motions to dismiss complaints filed by the District Attorneys of 11 parishes in the State of Louisiana seeking penalties for damage to wildlife, holding that those claims are pre-empted by the Clean Water Act. All eleven of the District Attorneys of parishes in the State of Louisiana have now filed notices of appeal. Since May 2012, amicus briefs have been filed in those appeals by the States of Alabama, Louisiana, and Mississippi.

On 3 March 2012, BP announced a settlement with the Plaintiffs’ Steering Committee (PSC) in the federal Multi-District Litigation proceedings pending in New Orleans (MDL 2179) to resolve the substantial majority of legitimate private economic loss and medical claims stemming from the Incident. On 18 April 2012, BP announced that it had reached definitive and fully documented agreements consistent with the terms of that settlement. The agreements remain subject to final court approval.

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The proposed settlement is comprised of two separate agreements. The first of these resolves economic loss claims and the other resolves medical claims. The agreement to resolve economic loss claims includes a $2.3 billion BP commitment to help resolve economic loss claims related to the Gulf seafood industry and a fund to support continued advertising that promotes Gulf Coast tourism. It also resolves claims for additional payments under certain Master Vessel Charter Agreements entered into in the course of the Vessels of Opportunity Program implemented as part of the response to the Incident.

The agreement to resolve medical claims involves payments based on a matrix for certain currently manifested physical conditions, as well as a 21-year medical consultation programme for qualifying class members. Although claims will not be paid until final approval of the medical settlement agreement, class members will be permitted to file claim forms in advance of any effective date of the settlement to facilitate prompt administration of the medical settlement should it be approved. It also provides that class members claiming later-manifested physical conditions may pursue their claims through a mediation/litigation process, but waive the right to seek punitive damages. Consistent with its commitment to the Gulf, BP has also agreed thereunder to provide $105 million to the Gulf Region Health Outreach Program to improve the availability, scope and quality of healthcare in Gulf communities. This healthcare outreach programme would be available to, and is intended to benefit, all individuals in those communities, regardless of whether they are class members.

Each agreement provides that class members would be compensated for their claims on a claims-made basis, according to agreed compensation protocols in separate court-supervised claims processes. The compensation protocols under the economic loss settlement agreement provide for the payment of class members’ economic losses and property damages. In addition many economic loss class members will receive payments based on negotiated risk transfer premiums (RTPs), which are multiplication factors designed to compensate claimants for potential future damages that are not currently known, relating to the Incident.

BP estimates the cost of the proposed settlement would be approximately $7.8 billion (including the $2.3 billion commitment to help resolve economic loss claims related to the Gulf seafood industry). While this is BP’s reliable best estimate of the cost of the proposed settlement, it is possible that the actual cost could be higher or lower than this estimate depending on the outcomes of the court-supervised claims processes. In accordance with its normal procedures, BP will re-evaluate the assumptions underlying this estimate on a quarterly basis as more information, including the outcomes of the court-supervised claims processes, becomes available. (For more information, see Note 2 on pages 24 - 29 and the Annual Report and Form 20-F 2011 – Financial statements – Note 36.) At this time, BP expects all settlements under these agreements to be paid from the Trust. Other costs to be paid from the Trust include state and local government claims, state and local response costs, natural resource damages and related claims, and final judgments and settlements. It is not possible at this time to determine whether the Trust will be sufficient to satisfy all of these claims as well as those under the proposed settlement. Should the Trust not be sufficient, payments under the proposed settlement would be made by BP directly.

The economic loss settlement agreement provides for a transition from the Gulf Coast Claims Facility (GCCF) to a new court-supervised claims programme, to administer payments made to qualifying class members. A court-supervised transitional claims process will be in operation while the infrastructure for the new settlement claims process is put in place. During this transitional period, the processing of claims that have been submitted to the GCCF will continue, and new claimants may submit their claims. BP has agreed not to wait for final approval of the economic loss settlement agreement before claims are paid. The economic loss claims process will continue under court supervision before final approval of the settlement, first under the transitional claims process, and then through the settlement claims process established by the economic loss settlement agreement.

Under the settlement agreement, class members would release and dismiss their claims against BP. The settlement agreement also provides that, to the extent permitted by law, BP will assign to the PSC certain of its claims, rights and recoveries against Transocean and Halliburton for damages with protections such that Transocean and Halliburton cannot pass those damages through to BP.

On 2 May 2012, the court overseeing the federal Multi-District Litigation proceedings pending in New Orleans (MDL 2179) issued orders preliminarily and conditionally certifying the Economic and Property Damages Settlement Class and the Medical Benefits Settlement Class and preliminarily approving the proposed Economic and Property Damages Settlement and the proposed Medical Benefits Settlement. Under US federal law, there is an established procedure for determining the fairness, reasonableness and adequacy of class action settlements. Pursuant to this procedure, an extensive outreach programme to the public has been implemented to explain settlement agreements and class members’ rights, including the right to “opt out” of the classes, and the processes for making claims. The Deepwater Horizon Court Supervised Settlement Program, the new claims facility operating under the frameworks established by the economic loss and property damages settlement agreement, commenced operation on 4 June 2012 under the oversight of claims administrator Patrick Juneau. The Court set a fairness hearing for 8 November 2012 in which to consider, among other things, whether to grant final approval of the proposed settlements, whether to certify the class for settlement purposes only, whether the fees and expenses submitted by class counsel should be approved, and the merits of any objections to the settlement. At the fairness hearing, class members and various other parties would have an opportunity to be heard and present evidence and the court will decide whether or not to approve each settlement agreement. Should the number of class members opting out exceed an agreed and court-approved threshold, BP will have the right to terminate the proposed settlement. The Court set a deadline of 31 August 2012 for claimants objecting the settlements to file their objections with the court and a deadline of 1 October 2012 through which class members may opt out of the settlements.

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Under the proposed settlement, class members would release and dismiss their claims against BP. After final approval of the settlement, claims of class members who have not excluded themselves from the settlement will be dismissed. The settlement is not an admission of liability by BP.

The proposed settlement does not include claims made against BP by the DoJ or other federal agencies (including under the Clean Water Act and for Natural Resource Damages under the Oil Pollution Act) or by the states and local governments. Also excluded are certain other claims against BP, such as securities and shareholder claims pending in MDL 2185, and claims based solely on the deepwater drilling moratorium and/or the related permitting process.

On 30 May 2012, the Court issued an amended pre-trial order providing for Trial of Liability, Limitation, Exoneration, and Fault Allocation to proceed in two phases, the first of which is scheduled to commence on 14 January 2013. Under the Court’s order, the Trial will include issues asserted in or relevant to the claims, counterclaims, cross-claims, third-party claims, and comparative fault defences raised in Transocean’s Limitation of Liability Action.

On 11 July 2012, BP filed motions to dismiss several categories of claims in MDL 2179 that were not covered by the proposed Economic and Property Damages Settlement and the proposed Medical Benefits Settlement. Those motions remain pending.

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 9 December 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted in part BP’s motion to dismiss the three Mexican states’ complaints, dismissing their claims under OPA 90 and for nuisance and negligence per se, and preserving their claims for negligence and gross negligence only to the extent there has been a physical injury to a proprietary interest of the states. The court in MDL 2179 has also set a schedule for targeted discovery on the legal issue of whether the Mexican States of Quintana Roo, Tamaulipas, and Veracruz have a justiciable claim. 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. BP anticipates further claims from the Mexican federal government.

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. In addition, a different set of environmental groups filed a motion to reconsider dismissal of their Endangered Species Act claims on 14 July 2011. That motion remains pending. On 31 January 2012, the court, on motion by the Center for Biological Diversity, entered final judgment on the basis of the 16 June 2011 order with respect to two actions brought against BP by that plaintiff. On 2 February 2012, the Center for Biological Diversity filed a notice of appeal of both actions. The appeal is now fully briefed and awaiting a determination by the Fifth Circuit as to whether to set the case for oral argument.

In addition, BP is aware that actions have been or may be brought under the Qui Tam (whistleblower) provisions of the False Claims Act.

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 Incident. Other US federal agencies may commence investigations relating to the Incident. The SEC and DoJ are investigating potential securities law violations, including potential securities fraud claims, alleged to have arisen in relation to the Incident.

On 21 April 2011, BP announced an agreement with natural resource trustees for the US 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 Incident. Funding for these projects will come from the $20-billion Trust fund.

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 24 - 29 and the Annual Report and Form 20-F 2011 – Financial statements – Note 2 on pages 190-194 for information regarding the financial impact of the Incident.

Investigations and reports relating to the Deepwater Horizon oil spill

BP has been 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.

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Legal proceedings (continued)

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 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. As part of this effort, on July 24, 2012, the CSB conducted a hearing at which it released its preliminary findings on, among other things, the use of safety indicators by industry (including BP and Transocean) and government regulators in offshore operations prior to the accident. The CSB found that BP and other offshore industry members have placed too great an emphasis on personal safety rather than process safety overall. The CSB is expected to issue interim reports in late 2012, as well as a final report in early 2013 that will include discussion of topics not covered during the July hearing. The CSB will seek to recommend improvements to BP and industry practices and to regulatory programmes to prevent recurrence and mitigate potential consequences, with special emphasis on safety indicators.

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. On 14 December 2011, the Committee published its final report, including findings and recommendations. A second, unrelated National Academies Committee will be looking at the methodologies available for assessing spill impacts on ecosystem services in the Gulf of Mexico, with a final report expected in late 2012 or early 2013. A third National Academies Committee studied methods for assessing the effectiveness of safety and environmental management systems (SEMS) established by offshore oil and gas operators and issued its report 19 June 2012.

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 13,000 b/d to over 100,000 b/d. The report concludes that the most accurate estimate was 53,000 b/d just prior to shut in, with an uncertainty on that value of ±10% based on FRTG collective experience and judgement, and, based on modelling, the flow on day one of the Incident was 62,000 b/d.

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, since April 2010, BP representatives have testified multiple times before the US Congress regarding the Incident. BP has provided documents and written information in response to requests from Members, committees and subcommittees of the US Congress.

Other legal proceedings

The US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) are currently investigating several BP entities regarding trading in the next-day natural gas market at Houston Ship Channel during September, October and November 2008. The FERC Office of Enforcement staff notified BP on 12 November 2010 of their preliminary conclusions relating to alleged market manipulation in violation of 18 C.F.R. Sec. 1c.1. On 30 November 2010, CFTC Enforcement staff also provided BP with a notice of intent to recommend charges based on the same conduct alleging that BP engaged in attempted market manipulation in violation of Section 6(c), 6(d), and 9(a)(2) of the Commodity Exchange Act. On 23 December 2010, BP submitted responses to the FERC and CFTC November 2010 notices providing a detailed response that it did not engage in any inappropriate or unlawful activity. On 28 July 2011, the FERC staff issued a Notice of Alleged Violations stating that it had preliminarily determined that several BP entities fraudulently traded physical natural gas in the Houston Ship Channel and Katy markets and trading points to increase the value of their financial swing spread positions. Other investigations into BP’s trading activities continue to be conducted from time to time.

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Legal proceedings (continued)

On 23 March 2005, an explosion and fire occurred in the isomerization unit of BP Products North America’s (BP Products) Texas City refinery. Fifteen workers died in the incident and many others were injured. BP Products has resolved all civil injury claims arising from the March 2005 incident. In September of 2005, BP Products entered into a settlement agreement with the US Occupational Safety and Health Administration (OSHA) resolving citations issued in connection with the explosion (2005 Agreement).

In March 2007, the US Chemical Safety and Hazard Investigation Board (CSB) issued a report on the incident. The report contained recommendations to the Texas City refinery and to the board of directors of BP. To date, CSB has accepted the majority of BP’s responses. BP and the CSB will continue to discuss BP’s unresolved responses with the objective of the CSB’s agreeing to close out all of its recommendations.

On 25 October 2007, the DoJ announced that it had entered into a criminal plea agreement with BP Products related to the March 2005 explosion and fire pursuant to which BP Products pleaded guilty to one felony violation of the risk management planning regulations promulgated under the US Clean Air Act (CAA). On 12 March 2009, the court accepted the plea agreement. In connection with the plea agreement, BP Products paid a $50-million criminal fine and was sentenced to three years’ probation which expired on 12 March 2012. In addition, compliance with the 2005 Agreement was one of the conditions of probation.

In September 2009, BP Products filed a petition to clarify specific required actions and deadlines under the 2005 Agreement. OSHA denied BP Products’ petition. In October 2009 OSHA issued citations to the Texas City refinery seeking a total of $87.4 million in civil penalties for alleged violations of the 2005 Agreement and alleged process safety management violations.

A settlement agreement between BP Products and OSHA in August 2010 (2010 Agreement) resolved the petition filed by BP Products in September 2009 and the alleged violations of the 2005 Agreement. BP Products has paid a penalty of $50.6 million in that matter and has completed the required abatement actions.

The OSHA process safety management citations issued in October 2009 were not resolved by the 2010 Agreement. On 12 July 2012, OSHA and BP resolved 409 of the 439 remaining citations. The agreement requires that BP pay a civil penalty of $13,027,000 and that BP abate the alleged violations by 31 December 2012. The settlement excludes 30 citations for which BP and OSHA could not reach agreement. However, the parties agreed that BP’s penalty liability will not exceed $1 million if those citations are resolved through litigation. Additional efforts will be made in the future to resolve these citations.

A flaring event occurred at BP Products’ Texas City refinery in April and May 2010. This flaring event is the subject of a number of civil suits by many area workers and residents alleging personal injury and property damages and seeking substantial damages. In addition, this emissions event is the subject of a federal governmental investigation.

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 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. The shareholder has appealed the dismissal and the appeal is pending.

In March and August 2006, oil leaked from oil transit pipelines operated by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit on the North Slope of Alaska. 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 favour 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. The BP p.l.c. shareholder filed an amended complaint, in response to which BP filed a new motion to dismiss, which was granted on March 14, 2012. Plaintiff has appealed the court’s dismissal of the case, and the appeal is pending. On 31 March 2009, the United States filed a complaint seeking civil penalties and damages relating to the events at Prudhoe Bay. The complaint also involved claims related to asbestos handling, allegations of non-compliance at multiple facilities for failure to comply with EPA’s spill prevention plan regulations, and for non-compliance with US Department of Transportation orders and regulations. The parties settled the dispute and on 13 July 2011 the Court entered a Consent Agreement in which BPXA agreed to pay a $25-million penalty and to perform certain injunctive measures over the next three years with respect to pipeline inspection and maintenance. 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 December 2011, the State of Alaska and BPXA entered into a Dispute Resolution Agreement concerning this matter that will result in arbitration of the amount of the State’s lost royalty income and payment by BPXA of the additional amount of $10 million on account of other claims in the complaint.

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Legal proceedings (continued)

Approximately 200 lawsuits were filed in state and federal courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 46.9% interest (reduced during 2001 from 50% by a sale of 3.1% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP’s combination with Atlantic Richfield. Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages that it has incurred. If any claims are asserted by Exxon that affect Alyeska and its owners, BP will defend the claims vigorously.

Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another company that manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that the incurrence of liability is remote. Consequently, BP believes that the impact of these lawsuits on the group’s results, financial position or liquidity will not be material.

On 8 March 2010, OSHA issued 65 citations to BP’s Toledo refinery alleging violations of the Process Safety Management Standard, with penalties of approximately $3 million. These citations resulted from an inspection conducted pursuant to OSHA’s Petroleum Refinery Process Safety Management National Emphasis Program. BP Products contested the citations, and a trial of 42 citations was completed in June 2012 before an Administrative Law Judge from the OSH Review Commission. A decision is pending. Prior to the trial, the parties resolved the other 23 citations for a penalty of $45,000.

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. Abbott seeks damages measured by the value, net of royalties, of all past and future production from the Atlantis platform, trebled, plus penalties. 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 was scheduled to begin on 10 April 2012, but the trial date was vacated and not rescheduled pending consideration of the parties’ summary judgment motions.

Various non-governmental organizations (“NGOs”) and the EPA challenged certain aspects of the air permits issued by the Indiana Department of Environmental Management (IDEM) for upgrades to the Whiting refinery. In response to these challenges, the IDEM reviewed the permits and responded formally to the EPA. BP has been in discussions with the EPA, the IDEM and certain environmental groups over these and other CAA issues relating to the Whiting refinery. BP has also been in settlement discussions with EPA to resolve alleged CAA violations at the Toledo, Carson and Cherry Point refineries.

On 23 May 2012, BP Products North America, Inc., the EPA, the Department of Justice (DOJ), the IDEM and the NGOs resolved objections to the air permit for the Whiting Refinery modernization project and settled allegations of air emissions violations at the Whiting Refinery. The settlement requires emission reduction projects with an estimated cost of approximately $400 million and the payment of a civil penalty of $8 million. The settlement will be subject to public notice and an opportunity for comment before it becomes enforceable.

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Legal proceedings (continued)

An application was brought in the English High Court on 1 February 2011 by Alfa Petroleum Holdings Limited and OGIP Ventures Limited against BP International Limited and BP Russian Investments Limited alleging breach of a Shareholders Agreement on the part of BP and seeking an interim injunction restraining BP from taking steps to conclude, implement or perform the transactions with Rosneft Oil Company, originally announced on 14 January 2011, relating to oil and gas exploration, production, refining and marketing in Russia (the Arctic Opportunity). Those transactions included the issue or transfer of shares between Rosneft Oil Company and any BP group company (pursuant to the Rosneft Share Swap Agreement). The court granted an interim order restraining BP from taking any further steps in relation to the Rosneft transactions pending an expedited UNCITRAL arbitration procedure in accordance with the Shareholders Agreement between the parties. The arbitration has commenced and the interim injunction was continued by the arbitration panel. 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 the interim orders referred to above. These interim orders did not address the question of whether or not BP breached the Shareholders Agreement. The arbitration proceedings, which are subject to strict confidentiality obligations, are ongoing.

Five minority shareholders of OAO TNK-BP Holding (TBH) have filed two civil actions in Tyumen, Siberia, against BP Russia Investments Limited and BP p.l.c. and against two of the BP nominated directors of TBH. These two actions sought to recover alleged losses to TBH of $13 billion and $2.7 billion respectively arising from the failure to involve TNK-BP in BP’s proposed alliance with Rosneft. On 11 November 2011, the Tyumen Court dismissed both claims fully on their merits. The plaintiffs appealed both of these decisions to the Omsk Appellate court. On 26 January 2012, the Appellate court upheld the Tyumen Court’s dismissal of the claim in relation to the BP nominated directors of TBH. The Omsk Appellate court subsequently confirmed the Tyumen court of first instance’s dismissal of the minority suits against BP Russia Investments Limited and BP p.l.c. The plaintiffs then appealed both of the Omsk Appellate court decisions to the cassation court of appeal in Tyumen. The cassation court upheld the dismissal of the claim against the BP nominated directors but remitted the case against the BP companies back to the Tyumen Court of first instance for reconsideration. The plaintiffs amended their claim to reduce their damages to approximately $8.6 billion. On 27 July 2012 the Tyumen Court ruled in favour of the plaintiffs and awarded $3.0 billion in damages against the BP companies. BP intends to appeal the Tyumen Court’s decision which it considers to be unjustified, and considers the plaintiffs’ claims to be wholly without merit. Consequently no amounts have been provided.

On 9 February 2011, Apache Canada Ltd (Apache) commenced arbitration against BP Canada Energy. Apache alleged that various properties/sites in respect of which it acquired interests from BP Canada Energy pursuant to the parties’ Purchase and Sale Agreement signed in July 2010 will require work to bring the properties/sites into compliance with applicable environmental laws, and Apache claimed that the purchase price should be adjusted for its estimated possible costs. In June 2012, the claims made in the arbitration were settled by the parties, and the arbitration was terminated, without there being any adjustment made to the purchase price in respect of the costs claimed by Apache.

On 24 January 2012, the Republic of Bolivia issued a press statement declaring its intent to nationalize Pan American Energy’s interests in the Caipipendi Operations Contract. No formal nationalization process has yet commenced. Pan American Energy and its shareholders BP and Bridas intend to vigorously defend their legal interests under the Caipipendi Operations Contract and available Bilateral Investment Treaties.

On 23 April 2012, BP Argentina Exploration Company and BP Alternative Energy North America Inc. (BP) filed a declaratory judgment action in federal court in New York against Bridas Corporation and Bridas Investments Ltd. (Bridas). BP sought a declaration of the validity of (1) the 28 November 2010 Share Purchase Agreement between BP and Bridas, including the Area of Mutual Interest (AMI) Waiver and Release, and (2) the 28 November 2010 Settlement Agreement. BP claims that after Bridas terminated the Share Purchase Agreement in November 2011 and BP wired $700 million to Bridas after termination, the AMI Waiver and Release and the Settlement Agreement remained enforceable, notwithstanding Bridas’ fraud claims, which BP believes have no basis. BP and Bridas resolved this dispute on 4 May 2012 and in accordance with the terms of the share purchase agreement, BP paid $700 million to Bridas. The parties have agreed that the AMI Waiver and Release and the releases set forth in the Settlement Agreement are in full force and effect and the declaratory judgment action has been dismissed.

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Signatures

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

BP p.l.c.

(Registrant)

Dated: 31 July 2012	/s/ J Bertelsen
	J BERTELSEN
	Head of Group Secretariat

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Exhibit 99.1

Computation of ratio of earnings to fixed charges

	Half year 2012
	$ million, except ratio
Profit before taxation		7,108
Group’s share of income in excess of dividends of equity-accounted entities		(748	)
Capitalized interest, net of amortization		(123	)
Profit as adjusted		6,237
Fixed charges:
Interest expense		404
Rental expense representative of interest		842
Capitalized interest		186
		1,432
Total adjusted earnings available for payment of fixed charges		7,669
Ratio of earnings to fixed charges		5.4

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Exhibit 99.2

Capitalization and indebtedness

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2012 in accordance with IFRS:

	30 June 2012
	$ million
Shareholders’ equity
Capital shares (1-2)		5,238
Paid-in surplus (3)		11,027
Merger reserve (3)		27,206
Own shares		(55	)
Available-for-sale investments		344
Cash flow hedges		(104	)
Foreign currency translation reserve		3,938
Treasury shares		(20,879	)
Share-based payment reserve		1,384
Profit and loss account		84,133
BP shareholders’ equity		112,232
Finance debt (4-6)
Due within one year		7,213
Due after more than one year		40,449
Total finance debt		47,662
Total capitalization (7)		159,894

(1) Issued share capital as of 30 June 2012 comprised 19,033,524,441 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,832,599,986 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 2012.

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

(6) As of 30 June 2012, the parent company, BP p.l.c., had outstanding guarantees totalling $45,399 million, of which $45,369 million related to guarantees in respect of liabilities of subsidiary undertakings, including $43,349 million relating to finance debt by subsidiaries. Thus 91% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2012, $133 million of finance debt was secured by the pledging of assets, and no finance debt was secured in connection with deposits received relating to disposal transactions expected to complete in subsequent periods. In addition, in connection with $2,066 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.

(7) There has been no material change since 30 June 2012 in the consolidated capitalization and indebtedness of BP.

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