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 31 March 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333-179406) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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 31 MARCH 2012^(a)

		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-March 2012(b)		3 – 13, 21 – 23
2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-March 2012		15 – 20, 24 –32
3.	Cautionary statement		14
4.	Legal proceedings		33 – 34
5.	Signatures		35
6.	Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges		36
	Exhibit 99.2: Capitalization and Indebtedness		37

(a) In this Form 6-K, references to the first quarter 2012 and first quarter 2011 refer to the three-month periods ended 31 March 2012 and 31 March 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 and Form 20-F for the year ended 31 December 2011.

2

Group results first quarter 2012

	First quarter 2012			First quarter 2011
$ million
Profit for the period(a)		5,915			7,254
Inventory holding (gains) losses, net of tax		(986	)		(1,643	)
Replacement cost profit(b)		4,929			5,611
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax(c)		(130	)		(107	)
Underlying replacement cost profit(b)		4,799			5,504
Profit per ordinary share (cents)		31.17			38.55
Profit per ADS (dollars)		1.87			2.31
Replacement cost profit per ordinary share (cents)		25.97			29.82
Replacement cost profit per ADS (dollars)		1.56			1.79
Underlying replacement cost profit per ordinary share (cents)		25.29			29.25
Underlying replacement cost profit per ADS (dollars)		1.52			1.76

• BP’s profit for the first quarter was $5,915 million, compared with $7,254 million a year ago. BP’s first-quarter replacement cost (RC) profit was $4,929 million, compared with $5,611 million a year ago. After adjusting for a net credit from non-operating items of $185 million and net unfavourable fair value accounting effects of $55 million (both on a post-tax basis), underlying RC profit for the first quarter was $4,799 million, compared with $5,504 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 first quarter included a gain of $933 million relating to the sale of businesses and fixed assets and a loss of $233 million relating to impairment and losses on sale of businesses and fixed assets(c). All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a de minimis net impact on the results this quarter. For further information on the Gulf of Mexico oil spill and its consequences see pages 4 – 5, Note 2 on pages 24 – 28, Legal proceedings on pages 33 – 34 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 $230 million for the first quarter, compared with $239 million for the same period last year.

• The effective tax rate on the profit for the first quarter 2012 was 33%, compared with 36% a year ago. The effective tax rate on RC profit for the first quarter was 33% compared with 37% a year ago. For the first quarter of 2011, the effective tax rate included the impact of a $683-million one-off deferred tax adjustment in respect of the increase in the supplementary charge on UK oil and gas production. Excluding this impact, the effective tax rates on profit and replacement cost profit for the first quarter of 2011 were 30% and 29% respectively. The increase in the effective tax rate for the first quarter of 2012 compared with the first quarter of 2011 (excluding the impact of the one-off deferred tax adjustment) is mainly due to the impact of the divestment programme in 2011.

• Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $3.4 billion, compared with $2.4 billion in the same period last year. The amount for the first quarter of 2012 included a net cash outflow of $1.2 billion relating to the Gulf of Mexico oil spill (first quarter 2011, $2.8 billion outflow).

• Gross debt at the end of the quarter was $46.5 billion compared with $47.1 billion a year ago. The ratio of gross debt to gross debt plus equity was 28.0% compared with 31.3% a year ago. Net debt at the end of the quarter was $31.2 billion, compared with $27.5 billion a year ago. The ratio of net debt to net debt plus equity was 20.7% compared with 21.0% a year ago. Net debt is a non-GAAP measure. See page 7 for further information.

• Total capital expenditure for the first quarter was $5.6 billion, almost all of which was organic(d). Disposal proceeds were $1.3 billion for the quarter. Since the start of 2010, we have announced disposals for a total of around $23 billion.

• The quarterly dividend expected to be paid on 27 June 2012 is 8 cents per share ($0.48 per ADS). The corresponding amount in sterling will be announced on 13 June 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 attributable to BP shareholders.

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

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

(d) Organic capital expenditure excludes acquisitions and asset exchanges (see page 19).

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

3

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 (the Incident). During the first 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 patrol and maintain areas of the shoreline impacted by the oil spill. These shoreline segments will continue to be patrolled and maintained until they meet the applicable clean-up standards.

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.

The settlement approval process began with the parties’ request that the court grant preliminary approval of the settlement agreements. The parties have also asked the court to approve proposed plans to notify class members of their rights under the settlement agreements and to schedule fairness hearings. Once these hearings have taken place, the court will decide whether to grant final approval of each settlement agreement. The timing of both the fairness hearings and future MDL 2179 proceedings will be determined by the court.

The proposed settlement provides for a transition from the Gulf Coast Claims Facility (GCCF). On 8 March, a transitional claims process for economic loss claims commenced operation while the infrastructure for the new court-supervised claims process is put in place.

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.

Claims update

To support the economic restoration of the impacted Gulf Coast communities, as at 31 March 2012, BP had paid a total of $8.3 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 31 March 2012, $6.6 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 $319 million of contributions, settlements and other payments for research, tourism, seafood testing and marketing, and behavioural health.

From its inception in August 2010 until 7 March 2012, the GCCF received a total of 1,059,873 claims from 574,379 claimants and paid out over $6.1 billion to individuals and businesses. A total of 195,438 final offers were accepted by claimants with 195,085 final payments issued and an additional 353 final payments pending. From 8 March 2012 to 18 April 2012, the date that definitive agreements were reached, the transitional court-supervised claims facility paid out more than $168 million in economic loss claims.

Environmental restoration

During the first 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 approximately $675 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 Phase 1 Early Restoration 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. The NRDA trustees are working to move the next phase of early restoration projects forward. Collectively, the projects are intended to restore and enhance wildlife and habitats, and provide additional access for recreational use.

4

Gulf of Mexico oil spill (continued)

Financial update

The group income statement includes a pre-tax credit of $24 million for the first quarter in relation to the Incident. This primarily reflects a credit relating to certain claims administration costs now expected to be paid from the Trust, partially offset by an increase in the provision for the costs of patrolling and maintenance of shoreline, and functional expenses of the Gulf Coast Restoration Organization (GCRO). The total cumulative charge recognized to date for the incident amounts to $37.2 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 – 28.

Trust update

During the first quarter, BP made contributions totalling $1.5 billion to the trust fund, including a $250-million cash settlement received in January from Cameron. As at 31 March 2012, BP’s cumulative contributions to the Trust amounted to $16.6 billion.

Payments from the Trust during the first quarter were $494 million, consisting of $353 million paid for individual and business claims, $62 million for NRD assessment costs, and $79 million for state and local government claims and other resolved items. As at 31 March 2012, the cumulative amount paid from the Trust since its inception was $7.2 billion.

As at 31 March 2012, the cumulative charges for provisions to be paid from the Trust and the associated reimbursement asset recognized amounted to $17.1 billion. This represents an increase of $0.5 billion for the quarter, including updates to provisions for claims payments, estimated NRD assessment costs and costs of claims administration. 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 33 – 34 herein, and Gulf of Mexico oil spill on pages 76 – 79 and Legal proceedings on pages 160 –164 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

	First quarter			First quarter
$ million	2012			2011
Underlying RC profit before interest and tax(a)
Upstream		6,290			6,684
Downstream		924			2,196
TNK-BP(b)		1,157			1,127
Other businesses and corporate		(436	)		(297	)
Consolidation adjustment – unrealized profit in inventory(c)		(541	)		(542	)
Underlying RC profit before interest and tax		7,394			9,168
Finance costs and net finance income or expense relating to pensions and other post-retirement benefits		(224	)		(223	)
Taxation on an underlying RC basis		(2,310	)		(3,380	)
Minority interest		(61	)		(61	)
Underlying RC profit attributable to BP shareholders		4,799			5,504
Non-operating items and fair value accounting effects(a)
Upstream		689			739
Downstream		(68	)		(117	)
TNK-BP, net of tax		(93	)		–
Other businesses and corporate		(236	)		(181	)
Gulf of Mexico oil spill response(d)		30			(384	)
Total before interest and taxation		322			57
Finance costs(e)		(6	)		(16	)
Taxation credit (charge)(f)		(186	)		66
Total after taxation for the period		130			107
RC profit before interest and tax(a)
Upstream		6,979			7,423
Downstream		856			2,079
TNK-BP(b)		1,064			1,127
Other businesses and corporate		(672	)		(478	)
Gulf of Mexico oil spill response(d)		30			(384	)
Consolidation adjustment – unrealized profit in inventory(c)		(541	)		(542	)
RC profit before interest and tax		7,716			9,225
Finance costs and net finance income or expense relating to pensions and other post-retirement benefits		(230	)		(239	)
Taxation on a RC basis		(2,496	)		(3,314	)
Minority interest		(61	)		(61	)
RC profit attributable to BP shareholders		4,929			5,611
Inventory holding gains (losses)		1,437			2,412
Taxation (charge) credit on inventory holding gains and losses		(451	)		(769	)
Profit for the period attributable to BP shareholders		5,915			7,254

(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 in the first quarter of 2012 was impacted by higher margins (driven both by a lower average cost of production and higher prices) and an increase in the volume of equity crude within the US refining and marketing system. In the first quarter of 2011, it was impacted by increases in volume (particularly in Europe) and higher prices.

(d) See Note 2 on pages 24 – 28 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 – 28 for further details.

(f) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill, equity-accounted earnings from the first quarter 2012, and, for the first quarter 2011, 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) on group profit or loss. However, the US statutory tax rate has been used for recoveries relating to the Gulf of Mexico oil spill and expenditures that qualify for tax relief. Excludes tax relating to TNK-BP items, which are reported after tax in the BP group income statement.

6

Per share amounts

	First quarter 2012		First quarter 2011
Per ordinary share (cents)
Profit for the period		31.17		38.55
RC profit for the period		25.97		29.82
Underlying RC profit for the period		25.29		29.25
Per ADS (dollars)
Profit for the period		1.87		2.31
RC profit for the period		1.56		1.79
Underlying RC profit for the period		1.52		1.76

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

Net debt ratio – net debt: net debt + equity

	First quarter 2012		First quarter 2011
$ million
Gross debt		46,470		47,102
Less: fair value asset of hedges related to finance debt		1,224		870
		45,246		46,232
Less: Cash and cash equivalents		14,092		18,726
Net debt		31,154		27,506
Equity		119,220		103,313
Net debt ratio		20.7%		21.0%

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 June. The corresponding amount in sterling will be announced on 13 June 2012, calculated based on the average of the market exchange rates for the four dealing days commencing on 7 June 2012. Holders of American Depositary Shares (ADSs) will receive $0.48 per ADS. The dividend is due to be paid on 27 June 2012 to shareholders and ADS holders on the register on 11 May 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 first-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

	First quarter 2012		First quarter 2011
Dividends paid per ordinary share
cents		8.000		7.000
pence		5.0958		4.3372
Dividends paid per ADS (cents)		48.00		42.00
Scrip dividends
Number of shares issued (millions)		39.6		66.6
Value of shares issued ($ million)		306		510

7

Upstream

	First quarter 2012			First quarter 2011
$ million
Profit before interest and tax		6,895			7,479
Inventory holding (gains) losses		84			(56	)
RC profit before interest and tax		6,979			7,423
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		(689	)		(739	)
Underlying RC profit before interest and tax(a)		6,290			6,684

(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. Comparative data has been restated to reflect this change.

The replacement cost profit before interest and tax for the first quarter in Upstream was $6,979 million, compared with $7,423 million for the same period in 2011. The first quarter of 2012 benefited from a net non-operating credit of $822 million, arising primarily due to gains on disposals as a result of the ongoing asset divestment programme, partly offset by losses on embedded derivatives. A year ago, there were net non-operating gains of $710 million. Fair value accounting effects in the first quarter had an unfavourable impact of $133 million, compared with a favourable impact of $29 million in the same period 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 first quarter was $6,290 million, compared with $6,684 million a year ago. The decrease was primarily due to higher costs, (reflecting increased activity levels, sector inflationary impacts, and higher depreciation, depletion and amortization), the impact of the divestment programme and the impact of lower production volumes from higher margin areas, partly offset by higher realizations and a higher contribution from gas marketing and trading.

Production for the quarter was 2,452mboe/d, 6% lower than the first quarter 2011. After adjusting for the effect of divestments, and entitlement impacts in our production-sharing agreements (PSAs), production increased slightly year on year. This primarily reflects stronger performance in Angola and new production from India, offset by production decline in the Gulf of Mexico, which continues to be impacted by the drilling moratorium in 2010 and 2011.

Looking ahead, we expect second-quarter reported production to be lower, and costs to be higher, as a result of normal seasonal turnaround activity concentrated on high-margin production in the Gulf of Mexico at Atlantis, Mad Dog and Holstein.

We continued to make strategic progress during the first quarter.

We completed the sale of our interests in the Hugoton Jayhawk gas processing plant and associated producing gas fields in Kansas to LINN Energy Holdings, LLC for $1.2 billion in cash.

The Brazilian National Petroleum Agency approved our farm-in to four deepwater exploration and production concessions operated by Petrobras in the Brazilian equatorial margin. We are taking a 40% interest in each of the blocks, located in the Barreirinhas and Ceará basins and covering a total area of 2,100 square kilometres.

We reached agreement with the Associated Landowners of the Ohio Valley to establish a position of 300 square kilometres in northeast Ohio for future oil and gas production in the Utica/Point Pleasant shale formation.

We agreed to sell our interests in our southern gas assets in the UK North Sea to Perenco UK Ltd for $400 million in cash. Completion of the sale, which is expected before the end of 2012, is subject to a number of third-party and regulatory approvals.

Together with other Alaska North Slope leaseholders, we settled a six-year-old legal dispute with the state of Alaska over the pace and method of development of the Point Thomson Unit (PTU) (BP 32%), east of Prudhoe Bay on the North Slope of Alaska. The dispute arose over the termination of the PTU by the State of Alaska Department of Natural Resources in November 2006. The settlement means that BP can explore further options to commercialize gas condensate and natural gas from the field.

In Uruguay we were successful in the recent exploration licence round, winning three licence blocks covering 26,000 square kilometres in water depths ranging from 50 to 2,000 metres. Confirmation of the licences, which is subject to government approval, is expected by the end of the third quarter of 2012.

In April, we completed our disposal of the Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC, a wholly-owned subsidiary of Plains All American Pipeline, L.P.

On 17 April, the Shah Deniz consortium (BP 25.5% and operator) announced that the decision had been taken to start the front-end engineering and design on the Shah Deniz Stage 2 project intended to bring gas from the Caspian Sea to markets in Turkey and Europe.

Today we are announcing our intention to sell certain non-strategic assets in the Gulf of Mexico. These include our interests in the Marlin, Horn Mountain, Holstein, Ram Powell and Diana Hoover fields.

8

Upstream

	First quarter 2012			First quarter 2011
$ million
Underlying RC profit before interest and tax
By region
US		1,658			1,846
Non-US		4,632			4,838
		6,290			6,684
Non-operating items
US		947			4
Non-US		(125	)		706
		822			710
Fair value accounting effects(a)
US		(71	)		25
Non-US		(62	)		4
		(133	)		29
RC profit before interest and tax
US		2,534			1,875
Non-US		4,445			5,548
		6,979			7,423
Exploration expense
US		62			308
Non-US(b)		198			91
		260			399
Production (net of royalties)(c)
Liquids (mb/d)(d)
US		454			523
Europe		123			166
Rest of World		671			725
		1,248			1,414
Of which equity-accounted entities		282			308
Natural gas (mmcf/d)
US		1,820			1,905
Europe		500			373
Rest of World		4,665			4,589
		6,985			6,867
Of which equity-accounted entities		398			408
Total hydrocarbons (mboe/d)(e)
US		768			851
Europe		209			230
Rest of World		1,475			1,517
		2,452			2,598
Of which equity-accounted entities		350			378
Average realizations(f)
Total liquids ($/bbl)		108.13			93.93
Natural gas ($/mcf)		4.68			4.21
Total hydrocarbons ($/boe)		64.02			59.00

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

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

(d) Crude oil and natural gas liquids.

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

(f) 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

	First quarter 2012			First quarter 2011
$ million
Profit before interest and tax		2,351			4,367
Inventory holding (gains) losses		(1,495	)		(2,288	)
RC profit before interest and tax		856			2,079
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		68			117
Underlying RC profit before interest and tax(a)		924			2,196

(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.

With effect from 1 January 2012, we are reporting the Refining and Marketing segment as Downstream, with no changes in the composition of the segment.

The replacement cost profit before interest and tax for the first quarter was $856 million, compared with $2,079 million for the same period last year. The decrease was primarily due to reduced contributions from the fuels and petrochemicals businesses.

The first-quarter result included a net non-operating charge of $106 million, compared with a net charge of $17 million for the same period a year ago. Fair value accounting effects had a favourable impact of $38 million for the first quarter, compared with an unfavourable impact of $100 million in the first quarter of 2011.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $924 million, compared with $2,196 million a year ago.

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

The fuels business had a challenging first quarter, delivering an underlying replacement cost profit before interest and tax of $487 million compared with $1,305 million in the same quarter last year in a broadly similar refining environment. Compared with the same period last year we continued to benefit from strong refining feedstock optimization in the US Midwest due to high refinery availability and BP’s location advantage in accessing WTI-priced crude grades. This benefit was, however, more than offset by a significantly weaker performance from supply and trading, unfavourable local crude differentials in Europe, a difficult fuels marketing environment resulting from weaker demand, and the impact of the temporary shut-down of our Cherry Point refinery following a fire in February.

The lubricants business delivered an underlying replacement cost profit before interest and tax of $325 million in the first quarter compared with $372 million in the same quarter last year reflecting robust performance despite weak demand in some OECD markets and continued high base oil prices.

The petrochemicals business delivered an underlying replacement cost profit before interest and tax of $112 million in the first quarter compared with $519 million in the same period last year. This reflects a challenging margin environment compared with the particularly strong aromatics margins a year ago, although we have seen volumes improve from the low levels in the fourth quarter as a result of improved demand and higher availability.

Looking ahead to the second quarter, we expect refining margins to improve in line with seasonal trends and fuels marketing volumes and petrochemicals margins to remain subdued given the difficult economic conditions. The Cherry Point refinery is expected to resume full operations in May having completed both repairs and the scheduled second-quarter turnaround.

We continue to progress our plans for the sale of our Texas City refinery and the southern part of the US West Coast fuels value chain, including the Carson refinery, and are aiming to announce the sales by the end of 2012.

During the first quarter, we received regulatory approval for the purchase of aviation fuels assets at seven Brazilian airports from Shell and Cosan Industria e Commercio, which we expect to complete in the second quarter of 2012.

10

Downstream

	First quarter 2012			First quarter 2011
$ million
Underlying RC profit before interest and tax – by region
US		289			704
Non-US		635			1,492
		924			2,196
Non-operating items
US		(88	)		(16	)
Non-US		(18	)		(1	)
		(106	)		(17	)
Fair value accounting effects(a)
US		(43	)		(48	)
Non-US		81			(52	)
		38			(100	)
RC profit before interest and tax
US		158			640
Non-US		698			1,439
		856			2,079
Underlying RC profit before interest and tax – by business(b)(c)
Fuels		487			1,305
Lubricants		325			372
Petrochemicals		112			519
		924			2,196
Non-operating items and fair value accounting effects(a)
Fuels		(68	)		(130	)
Lubricants		–			13
Petrochemicals		–			–
		(68	)		(117	)
RC profit before interest and tax(b)(c)
Fuels		419			1,175
Lubricants		325			385
Petrochemicals		112			519
		856			2,079
BP Average refining marker margin (RMM) ($/bbl)(d)		11.60			11.02
Refinery throughputs (mb/d)
US		1,218			1,194
Europe		775			768
Rest of World		277			307
		2,270			2,269
Refining availability (%)(e)		94.9			93.9
Marketing sales volumes (mb/d)(f)
US		1,349			1,375
Europe		1,216			1,267
Rest of World		574			610
		3,139			3,252
Trading/supply sales		2,380			2,256
Total refined product sales		5,519			5,508
Petrochemicals production (kte)
US		1,078			1,135
Europe(c)		1,011			985
Rest of World		1,817			1,918
		3,906			4,038

(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)

	First quarter 2012			First quarter 2011
$ million
Profit before interest and tax		1,481			1,526
Finance costs		(36	)		(35	)
Taxation		(231	)		(246	)
Minority interest		(124	)		(59	)
Net income (BP share)(b)		1,090			1,186
Inventory holding (gains) losses, net of tax		(26	)		(59	)
Net income on a RC basis		1,064			1,127
Net charge (credit) for non-operating items(c), net of tax		93			–
Net income on an underlying RC basis(d)		1,157			1,127
Cash flow
Dividends received		690			–
Production (net of royalties) (BP share)
Crude oil (mb/d)		879			856
Natural gas (mmcf/d)		813			719
Total hydrocarbons (mboe/d)(e)		1,019			980
Balance sheet	31 March 2012			31 December 2011
Investments in associates		10,621			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 first quarter was $1,064 million, compared with $1,127 million for the same period a year ago.

The first-quarter 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 this quarter, 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 first quarter was $1,157 million, compared with $1,127 million for the same period in 2011. The primary factors impacting the first-quarter result, compared with the same period last year, were increased realizations offset by cost inflation and increased production taxes.

Production for the quarter was 1,019mboe/d, 4% higher than the first quarter of 2011. After adjusting for the effect of the acquisition of BP’s upstream interests in Vietnam and Venezuela, the increase was 1.6%. This increase arises due to the ramp-up of recent new developments, partially offset by a decline in mature fields.

12

Other businesses and corporate

	First quarter 2012			First quarter 2011
$ million
Profit (loss) before interest and tax		(672	)		(469	)
Inventory holding (gains) losses		–			(9	)
RC profit (loss) before interest and tax		(672	)		(478	)
Net charge (credit) for non-operating items		236			181
Underlying RC profit (loss) before interest and tax(a)		(436	)		(297	)
By region
Underlying RC profit (loss) before interest and tax(a)
US		(165	)		(189	)
Non-US		(271	)		(108	)
		(436	)		(297	)
Non-operating items
US		(142	)		1
Non-US		(94	)		(182	)
		(236	)		(181	)
RC profit (loss) before interest and tax
US		(307	)		(188	)
Non-US		(365	)		(290	)
		(672	)		(478	)

(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 first quarter was $672 million, compared with $478 million for the same period last year.

The first-quarter result included a net non-operating charge of $236 million, mainly relating to further charges as we prepare to exit the solar business. A year ago, there was a net non-operating charge of $181 million for the first quarter.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the first quarter was $436 million, compared with a loss of $297 million for the same period last year.

In Alternative Energy, net wind generation capacity(b) at the end of the first quarter was 1,274MW (1,988MW gross), compared with 774MW (1,362MW gross) at the end of the same period a year ago. In the first quarter, two new wind farms were fully commissioned in Texas, US, both of which are 100% owned by BP: Trinity Hills in Archer and Young Counties (225MW) and Sherbino 2 in Pecos County (150MW). BP now participates in a total of 13 wind farms in the US, of which we operate 12.

BP’s net share of wind generation from our US wind farms for the first quarter was 1,024GWh (1,675GWh gross), compared with 601GWh (1,076GWh gross) in the same period 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.

(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.

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; BP’s intentions to continue to patrol and maintain certain shoreline segments impacted by the 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 prospects for and expected timing of certain claims and litigation outcomes; the expected level of production in the second quarter of 2012; the expected timing for the award of licenses in connection with certain blocks in Uruguay; the expected level of refining margins in the second quarter of 2012; the prospects for the fuels marketing environment in the second quarter of 2012; the prospects for the petrochemicals margin environment; the expected timing for the resumption of operations at the Cherry Point refinery; prospects for the completion of planned and announced divestments, including the planned disposals of the Texas City refinery and the southern part of the US West Coast fuels value chain; and the expected timing of the completion of BP’s purchase of certain aviation fuels assets in Brazil. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed under “Risk factors” in our Annual Report and Form 20-F 2011 as filed with the US Securities and Exchange Commission.

14

Group income statement

	First			First
	quarter			quarter
	2012			2011
$ million
Sales and other operating revenues (Note 4)		94,040			85,329
Earnings from jointly controlled entities – after interest and tax		290			392
Earnings from associates – after interest and tax		1,260			1,409
Interest and other income		175			124
Gains on sale of businesses and fixed assets		933			1,188
Total revenues and other income		96,698			88,442
Purchases		71,643			61,721
Production and manufacturing expenses(a)		6,721			6,508
Production and similar taxes (Note 5)		2,346			1,831
Depreciation, depletion and amortization		3,208			2,835
Impairment and losses on sale of businesses and fixed assets		140			59
Exploration expense		260			399
Distribution and administration expenses		3,128			2,907
Fair value (gain) loss on embedded derivatives		99			545
Profit before interest and taxation		9,153			11,637
Finance costs(a)		283			308
Net finance income relating to pensions and other post-retirement benefits		(53	)		(69	)
Profit before taxation		8,923			11,398
Taxation(a)		2,947			4,083
Profit for the period		5,976			7,315
Attributable to
BP shareholders		5,915			7,254
Minority interest		61			61
		5,976			7,315
Earnings per share – cents (Note 6)
Profit for the period attributable to BP shareholders
Basic		31.17			38.55
Diluted		30.74			38.10

(a) See Note 2 on pages 24 – 28 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

	First			First
	quarter			quarter
	2012			2011
$ million
Profit for the period		5,976			7,315
Currency translation differences		586			657
Exchange (gains) losses on translation of foreign operations transferred to gain or loss on sales of businesses and fixed assets		–			11
Actuarial gain (loss) relating to pensions and other post-retirement benefits		1,420			–
Available-for-sale investments marked to market		64			266
Available-for-sale investments – recycled to the income statement		–			(2	)
Cash flow hedges marked to market		75			118
Cash flow hedges – recycled to the income statement		2			(16	)
Cash flow hedges – recycled to the balance sheet		5			2
Share of equity-accounted entities’ other comprehensive income, net of tax		203			–
Taxation		(451	)		(5	)
Other comprehensive income (expense)		1,904			1,031
Total comprehensive income		7,880			8,346
Attributable to
BP shareholders		7,813			8,269
Minority interest		67			77
		7,880			8,346

Group statement of changes in equity

	BP
	shareholders’			Minority			Total
	equity			interest			equity
$ million
At 1 January 2012		111,465			1,017			112,482
Total comprehensive income		7,813			67			7,880
Dividends		(1,211	)		(1	)		(1,212	)
Share-based payments (net of tax)		59			–			59
Transactions involving minority interests		–			11			11
At 31 March 2012		118,126			1,094			119,220
	BP shareholders’ equity			Minority interest			Total equity
$ million
At 1 January 2011		94,987			904			95,891
Total comprehensive income		8,269			77			8,346
Dividends		(808	)		(6	)		(814	)
Share-based payments (net of tax)		(110	)		–			(110	)
At 31 March 2011		102,338			975			103,313

16

Group balance sheet

	31 March		31 December
	2012		2011
$ million
Non-current assets
Property, plant and equipment		119,991		119,214
Goodwill		12,210		12,100
Intangible assets		22,000		21,102
Investments in jointly controlled entities		15,862		15,518
Investments in associates		13,824		13,291
Other investments		2,066		2,117
Fixed assets		185,953		183,342
Loans		870		884
Trade and other receivables		7,587		4,337
Derivative financial instruments		5,274		5,038
Prepayments		1,338		1,255
Deferred tax assets		569		611
Defined benefit pension plan surpluses		19		17
		201,610		195,484
Current assets
Loans		255		244
Inventories		30,154		25,661
Trade and other receivables		41,392		43,526
Derivative financial instruments		4,424		3,857
Prepayments		1,232		1,286
Current tax receivable		222		235
Other investments		303		288
Cash and cash equivalents		14,092		14,067
		92,074		89,164
Assets classified as held for sale (Note 3)		9,860		8,420
		101,934		97,584
Total assets		303,544		293,068
Current liabilities
Trade and other payables		53,994		52,405
Derivative financial instruments		3,545		3,220
Accruals		5,711		5,932
Finance debt		7,897		9,044
Current tax payable		2,824		1,941
Provisions		7,479		11,238
		81,450		83,780
Liabilities directly associated with assets classified as held for sale (Note 3)		1,404		538
		82,854		84,318
Non-current liabilities
Other payables		2,909		3,437
Derivative financial instruments		3,742		3,773
Accruals		478		389
Finance debt		38,573		35,169
Deferred tax liabilities		16,169		15,078
Provisions		29,000		26,404
Defined benefit pension plan and other post-retirement benefit plan deficits		10,599		12,018
		101,470		96,268
Total liabilities		184,324		180,586
Net assets		119,220		112,482
Equity
BP shareholders’ equity		118,126		111,465
Minority interest		1,094		1,017
		119,220		112,482

17

Condensed group cash flow statement

	First			First
	quarter			quarter
	2012			2011
$ million
Operating activities
Profit before taxation		8,923			11,398
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		3,288			3,127
Impairment and (gain) loss on sale of businesses and fixed assets		(793	)		(1,129	)
Earnings from equity-accounted entities, less dividends received		(524	)		(1,576	)
Net charge for interest and other finance expense, less net interest paid		(14	)		51
Share-based payments		34			(124	)
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(160	)		(439	)
Net charge for provisions, less payments		165			273
Movements in inventories and other current and non-current assets and liabilities(a)		(6,160	)		(7,823	)
Income taxes paid		(1,392	)		(1,354	)
Net cash provided by operating activities		3,367			2,404
Investing activities
Capital expenditure		(5,439	)		(3,709	)
Acquisitions, net of cash acquired		–			(2,002	)
Investment in jointly controlled entities		(244	)		(154	)
Investment in associates		(23	)		(11	)
Proceeds from disposal of fixed assets		1,267			384
Proceeds from disposal of businesses, net of cash disposed		45			586
Proceeds from loan repayments		65			35
Net cash used in investing activities		(4,329	)		(4,871	)
Financing activities
Net issue of shares		21			12
Proceeds from long-term financing		3,813			4,917
Repayments of long-term financing		(2,416	)		(2,622	)
Net increase in short-term debt		664			949
Dividends paid – BP shareholders		(1,212	)		(808	)
Dividends paid – Minority interest		(1	)		(6	)
Net cash provided by financing activities		869			2,442
Currency translation differences relating to cash and cash equivalents		118			195
Increase (decrease) in cash and cash equivalents		25			170
Cash and cash equivalents at beginning of period		14,067			18,556
Cash and cash equivalents at end of period		14,092			18,726

(a) Includes

Inventory holding (gains) losses	(1,437	)	(2,412	)
Fair value (gain) loss on embedded derivatives	99		545
Movements related to Gulf of Mexico oil spill response	(1,861	)	(2,864	)

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

	First		First
	quarter		quarter
	2012		2011
$ million
By business
Upstream
US(a)		1,646		1,023
Non-US		2,829		2,111
		4,475		3,134
Downstream
US		674		522
Non-US		202		215
		876		737
Other businesses and corporate
US		158		130
Non-US		139		20
		297		150
		5,648		4,021
By geographical area
US(a)		2,478		1,675
Non-US		3,170		2,346
		5,648		4,021
Included above:
Acquisitions and asset exchanges		10		9

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

Exchange rates

	First		First
	quarter		quarter
	2012		2011
US dollar/sterling average rate for the period		1.57		1.60
US dollar/sterling period-end rate		1.59		1.61
US dollar/euro average rate for the period		1.31		1.37
US dollar/euro period-end rate		1.33		1.41

19

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation^(a)

	First			First
	quarter			quarter
	2012			2011
$ million
By business
Upstream		6,979			7,423
Downstream		856			2,079
TNK-BP(b)		1,064			1,127
Other businesses and corporate		(672	)		(478	)
		8,227			10,151
Gulf of Mexico oil spill response		30			(384	)
Consolidation adjustment – unrealized profit in inventory		(541	)		(542	)
RC profit before interest and tax(c)		7,716			9,225
Inventory holding gains (losses)(d)
Upstream		(84	)		56
Downstream		1,495			2,288
TNK-BP (net of tax)		26			59
Other businesses and corporate		–			9
Profit before interest and tax		9,153			11,637
Finance costs		283			308
Net finance income relating to pensions and other post-retirement benefits		(53	)		(69	)
Profit before taxation		8,923			11,398
RC profit before interest and tax
By geographical area
US		1,935			1,813
Non-US		5,781			7,412
		7,716			9,225

(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)

	First			First
	quarter			quarter
	2012			2011
$ million
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets		928			1,089
Environmental and other provisions		–			–
Restructuring, integration and rationalization costs		–			–
Fair value gain (loss) on embedded derivatives		(100	)		(328	)
Other		(6	)		(51	)
		822			710
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets		(85	)		5
Environmental and other provisions		–			–
Restructuring, integration and rationalization costs		(12	)		(1	)
Fair value gain (loss) on embedded derivatives		–			–
Other		(9	)		(21	)
		(106	)		(17	)
TNK-BP (net of tax)(b)
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
Impairment and gain (loss) on sale of businesses and fixed assets		(50	)		35
Environmental and other provisions		(15	)		–
Restructuring, integration and rationalization costs		–			1
Fair value gain (loss) on embedded derivatives(c)		1			(217	)
Other(d)		(172	)		–
		(236	)		(181	)
Gulf of Mexico oil spill response		30			(384	)
Total before interest and taxation		417			128
Finance costs(e)		(6	)		(16	)
Total before taxation		411			112
Taxation credit (charge)(f)		(226	)		44
Total after taxation for period		185			156

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

(c) First quarter 2011 included a loss on an embedded derivative arising from a financing arrangement.

(d) First quarter 2012 included charges of $161 million, in relation to our exit from the solar business.

(e) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 24 – 28 for further details.

(f) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill, equity-accounted earnings from the first quarter 2012, and, for the first quarter 2011, 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) on group profit or loss. However, the US statutory tax rate has been used for recoveries relating to the Gulf of Mexico oil spill and expenditures that qualify for tax relief. Excludes tax relating to TNK-BP items, which are reported after tax in the BP group income statement.

21

Non-GAAP information on fair value accounting effects

	First			First
	quarter			quarter
	2012			2011
$ million
Favourable (unfavourable) impact relative to management’s measure of performance
Upstream		(133	)		29
Downstream		38			(100	)
		(95	)		(71	)
Taxation credit (charge)(a)		40			22
		(55	)		(49	)

(a) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill, equity-accounted earnings from the first quarter 2012, and, for the first quarter 2011, 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) on group profit or loss.

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.

	First			First
	quarter			quarter
	2012			2011
$ million
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		7,112			7,394
Impact of fair value accounting effects		(133	)		29
Replacement cost profit before interest and tax		6,979			7,423
Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		818			2,179
Impact of fair value accounting effects		38			(100	)
Replacement cost profit before interest and tax		856			2,079
Total group
Profit before interest and tax adjusted for fair value accounting effects		9,248			11,708
Impact of fair value accounting effects		(95	)		(71	)
Profit before interest and tax		9,153			11,637

22

Realizations and marker prices

	First		First
	quarter		quarter
	2012		2011
Average realizations(a)
Liquids ($/bbl)(b)
US		99.39		86.53
Europe		116.96		102.37
Rest of World		114.79		99.68
BP Average		108.13		93.93
Natural gas ($/mcf)
US		2.24		3.20
Europe		7.83		6.96
Rest of World		5.34		4.41
BP Average		4.68		4.21
Total hydrocarbons ($/boe)
US		62.94		60.30
Europe		87.50		84.94
Rest of World		60.30		52.79
BP Average		64.02		59.00
Average oil marker prices ($/bbl)
Brent		118.60		105.43
West Texas Intermediate		103.10		94.49
Alaska North Slope		118.47		103.22
Mars		115.50		101.95
Urals (NWE – cif)		116.87		102.55
Russian domestic oil		58.22		49.18
Average natural gas marker prices
Henry Hub gas price ($/mmBtu)(c)		2.72		4.11
UK Gas – National Balancing Point (p/therm)		59.38		56.94

(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.

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 33 – 34 herein.

2. Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur costs and has also recognized liabilities for future costs. The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2011 – Financial statements – Note 2, Note 36 and Note 43, and Legal proceedings on pages 33 – 34 herein.

The group income statement includes a pre-tax credit of $24 million for the first quarter in relation to the Gulf of Mexico oil spill. This primarily reflects a credit relating to certain claims administration costs now expected to be paid from the Deepwater Horizon Oil Spill Trust, partially offset by an increase in the provision for the costs of patrolling and maintenance of shoreline, and functional expenses of the Gulf Coast Restoration Organization (GCRO). The cumulative pre-tax income statement charge since the incident amounts to $37,169 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.

	First			First
	quarter			quarter
	2012			2011
$ million
Income statement
Production and manufacturing expenses		(30	)		384
Profit (loss) before interest and taxation		30			(384	)
Finance costs		6			16
Profit (loss) before taxation		24			(400	)
Less: Taxation		(26	)		201
Profit (loss) for the period		(2	)		(199	)

	31 March 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		4,985			4,985			8,487			8,233
Current liabilities
Trade and other payables		(3,800	)		(3,368	)		(5,425	)		(4,872	)
Provisions		(5,877	)		–			(9,437	)		–
Net current assets (liabilities)		(4,692	)		1,617			(6,375	)		3,361
Non-current assets
Other receivables		4,881			4,881			1,642			1,642
Non-current liabilities
Provisions		(9,048	)		–			(5,896	)		–
Deferred tax		7,211			–			7,775			–
Net non-current assets (liabilities)		3,044			4,881			3,521			1,642
Net assets		(1,648	)		6,498			(2,854	)		5,003

	First			First
	quarter			quarter
	2012			2011
$ million
Cash flow statement – Operating activities
Profit (loss) before taxation		24			(400	)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Net charge for interest and other finance expense, less net interest paid		6			16
Net charge for provisions, less payments		85			202
Movements in inventories and other current and non-current assets and liabilities		(1,861	)		(2,864	)
Pre-tax cash flows		(1,746	)		(3,046	)

Net cash used in operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to $1,208 million in the first quarter of 2012. For the first quarter of 2011 the amount was $2,808 million.

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. 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 fund in addition to a regular contribution of $1,250 million. 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 31 March 2012. This liability is recognized within current other payables on the balance sheet.

	$ million
At 1 January 2012		4,872
Unwinding of discount		5
Contributions		(1,500	)
Other		(9	)
At 31 March 2012		3,368

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 31 March 2012. The amount of the reimbursement asset at 31 March 2012 is equal to the amount of provisions recognized at that date that will be covered by the trust fund – see below.

	$ million
At 1 January 2012		9,875
Increase in provision for items covered by the trust fund		485
Amounts paid directly by the trust fund		(494	)
At 31 March 2012		9,866
Of which – current		4,985
– non-current		4,881

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 31 March 2012, the cumulative charges for provisions, and the associated reimbursement asset recognized, amounted to $17,090 million. Thus, a further $2,910 million could be provided in subsequent periods for items covered by the trust fund with no net impact on the income statement. Such future increases in amounts provided could arise from adjustments to existing provisions, or from the initial recognition of provisions for items that currently cannot be estimated reliably, namely final judgments and settlements and natural resource damages and related costs. Further information on those items that currently cannot be reliably estimated is provided under Provisions and contingencies below.

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

The Trust agreement does not require BP to make further contributions to the trust fund in excess of the agreed $20 billion should this be insufficient to cover all claims administered by the GCCF or 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.

26

Notes

2. Gulf of Mexico oil spill (continued)

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 process for economic loss claims commenced operation in March 2012 while the infrastructure for a new court-supervised claims process is put in place. It is expected that the cost of the settlement will be paid from the Trust.

(b) Provisions and contingencies

BP has recorded certain provisions and disclosed certain contingencies as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 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 first quarter 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. 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 and claims for personal injuries, both reported and unreported, 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 which have been filed for preliminary court approval. See page 4 and Legal proceedings on pages 33 – 34 herein for further information.

During the first quarter certain claims administration costs, previously treated as payable from outside the trust fund, have been 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 period.

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) or litigation arising from alleged violations of OPA 90, any amounts in relation to fines and penalties except for those relating to the Clean Water Act and any obligation in relation to litigation. These items are therefore disclosed as contingent liabilities – see below.

	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 (decrease) in provision – items not covered by the trust fund		–			82			(178	)		–		(96	)
Increase in provision – items covered by the trust fund		65			–			420			–		485
Unwinding of discount		1			–			–			–		1
Utilization – paid by BP		(11	)		(68	)		(225	)		–		(304	)
– paid by the trust fund		(62	)		–			(432	)		–		(494	)
At 31 March 2012		1,510			350			9,555			3,510		14,925
Of which – current		680			277			4,920			–		5,877
– non-current		830			73			4,635			3,510		9,048
Of which – payable from the trust fund		1,069			–			8,797			–		9,866

27

Notes

2. Gulf of Mexico oil spill (continued)

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

	First
	quarter
	2012
$ million
Net increase in provisions		389
Recognition of reimbursement asset		(485	)
Other costs charged directly to the income statement		66
Profit before interest and taxation		(30	)
Finance costs		6
Profit before taxation		(24	)

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.

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 31 March 2012.

For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties except, subject to certain assumptions, for those relating to the Clean Water Act. Therefore no amounts have been provided for these items as at 31 March 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 SWACO, the mud contractor (M-I), 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 31 March 2012.

See Legal proceedings on pages 33 – 34 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.

28

Notes

3. Non-current assets held for sale

As a result of the group’s disposal programme following the Gulf of Mexico oil spill, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 31 March 2012. The carrying amount of the assets held for sale is $9,860 million, with associated liabilities of $1,404 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 is in ongoing negotiations and expects to complete a sale of its equity-accounted investment in the Phu My 3 plant facility in Vietnam in 2012, subject to the satisfaction of regulatory and other approvals and conditions. The investment in the Phu My 3 plant facility has been classified as held for sale in the group balance sheet at 31 March 2012.

On 1 December 2011, BP announced that it had agreed to sell its Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC, a wholly-owned subsidiary of Plains All American Pipeline, L.P., for $1.67 billion in cash, subject to post-closing adjustments. The assets, and associated liabilities, of this business have been classified as held for sale in the group balance sheet at 31 March 2012. Completion of the transaction occurred on 1 April 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 31 March 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.

Within the Downstream segment, BP intends to divest the Texas City refinery and related assets, and the southern part of its US West Coast fuels value chain, including the Carson refinery. The non-current assets, together with the inventories, of these businesses have been classified as held for sale in the group balance sheet at 31 March 2012. BP aims to announce the sales by the end of 2012.

Deposits of $30 million received in advance of completion of certain of these transactions have been classified as finance debt on the group balance sheet at 31 March 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.

29

Notes

4. Sales and other operating revenues

	First		First
	quarter		quarter
	2012		2011
$ million
By business
Upstream		19,258		18,405
Downstream		85,931		77,433
Other businesses and corporate		428		856
		105,617		96,694
Less: sales and other operating revenues between businesses
Upstream		10,657		10,525
Downstream		746		626
Other businesses and corporate		174		214
		11,577		11,365
Third party sales and other operating revenues
Upstream		8,601		7,880
Downstream		85,185		76,807
Other businesses and corporate		254		642
Total third party sales and other operating revenues		94,040		85,329
By geographical area
US		33,727		30,847
Non-US		70,340		63,855
		104,067		94,702
Less: sales and other operating revenues between areas		10,027		9,373
		94,040		85,329

5. Production and similar taxes

	First		First
	quarter		quarter
	2012		2011
$ million
US		490		374
Non-US		1,856		1,457
		2,346		1,831

30

Notes

6. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

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

	First			First
	quarter			quarter
	2012			2011
$ million
Results for the period
Profit for the period attributable to BP shareholders		5,915			7,254
Less: Preference dividend		–			–
Profit attributable to BP ordinary shareholders		5,915			7,254
Inventory holding (gains) losses, net of tax		(986	)		(1,643	)
RC profit attributable to BP ordinary shareholders		4,929			5,611
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax		(130	)		(107	)
Underlying RC profit attributable to BP shareholders		4,799			5,504
Number of shares(a)
Basic weighted average number of shares outstanding (thousand)		18,976,062			18,816,868
ADS equivalent (thousand)		3,162,677			3,136,145
Weighted average number of shares outstanding used to calculate diluted earnings per share (thousand)		19,240,896			19,038,387
ADS equivalent (thousand)		3,206,816			3,173,065
Shares in issue at period-end (thousand)		19,016,208			18,866,532
ADS equivalent (thousand)		3,169,368			3,144,422

(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.

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Notes

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

	First			First
	quarter			quarter
	2012			2011
$ million
Opening balance
Finance debt		44,213			45,336
Less: Cash and cash equivalents		14,067			18,556
Less: FV asset of hedges related to finance debt		1,133			916
Opening net debt		29,013			25,864
Closing balance
Finance debt		46,470			47,102
Less: Cash and cash equivalents		14,092			18,726
Less: FV asset of hedges related to finance debt		1,224			870
Closing net debt		31,154			27,506
Increase in net debt		(2,141	)		(1,642	)
Movement in cash and cash equivalents (excluding exchange adjustments)		(93	)		(25	)
Net cash outflow (inflow) from financing (excluding share capital)		(2,061	)		(3,244	)
Movement in finance debt relating to investing activities(b)		–			1,595
Other movements		(7	)		(21	)
Movement in net debt before exchange effects		(2,161	)		(1,695	)
Exchange adjustments		20			53
Increase in net debt		(2,141	)		(1,642	)

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

(b) During the first quarter 2012 no disposal transactions were completed in respect of which deposits had been received in advance (first quarter 2011 $1,595 million). At 31 March 2012, finance debt includes $30 million of deposits received in advance relating to disposal transactions ($4.6 billion at 31 March 2011).

At 31 March 2012, $136 million of finance debt ($796 million at 31 March 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 31 March 2011). In addition, in connection with $2,201 million of finance debt ($3,799 million at 31 March 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 31 March 2012, the total available undrawn committed borrowing facilities stood at $6.9 billion ($7.5 billion at 31 March 2011).

8. Statutory accounts

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

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Legal proceedings

The following discussion sets forth the developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, please see pages 160 - 166 of our Annual Report and Form 20-F 2011.

Proceedings relating to the Deepwater Horizon oil spill

i) On 18 April 2012 BP announced that it had reached definitive and fully documented agreements 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 Deepwater Horizon accident and resulting oil spill. The settlement agreements are consistent with the terms of the proposed settlement announced on 3 March 2012, one resolving economic loss and property damage claims and the other resolving medical claims.

Under the economic loss agreement, there are agreed compensation protocols for the payment of class members’ economic losses and property damages. In addition, many economic loss class members will also receive payments based on negotiated risk transfer premiums (RTPs), which are multipliers designed to compensate claimants for potential future losses relating to the accident, along with other potential damages. A new claims facility will open within 30 days of the granting of preliminary approval by the court (unless otherwise ordered by the court) and will operate under the frameworks established by the economic loss and property damage settlement agreement.

Under the medical settlement agreement, payments will be made based on a matrix for certain specified physical conditions. 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. The agreement also provides for a 21-year periodic medical consultation programme for qualifying class members. Class members claiming later-manifested physical conditions may pursue their claims in the future through a mediation/litigation process, but waive the right to seek punitive damages. Under the agreement, BP has also agreed 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 is intended to benefit both class members and others in those communities.

The parties have filed for preliminary approval of the settlement agreements. As part of the motions seeking approval, the parties have asked the court to approve proposed plans to notify class members of their rights under the settlement agreements and schedule fairness hearings. Once these hearings have taken place, the court will decide whether to give final approval to each settlement agreement. BP has also asked the court to adjourn the MDL 2179 liability trial until after it determines whether to grant final approval of the settlement agreements.

Under US federal law, there is an established procedure for determining the fairness, reasonableness and adequacy of class action settlements. Pursuant to this procedure, there would be an extensive notification to the public, including through direct mail, print and broadcast media, and a website, to explain settlement agreements, class members’ rights, including the right to “opt out” of the classes, and the processes for making claims.

Under the 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 settlement agreements do not include claims made against BP by the Department of Justice 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.

ii) 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.

iii) On 19 and 20 April 2012, five 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 two cases, ADSs. The funds assert various state law and federal law claims.

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Legal proceedings

Other legal proceedings

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 seeks a declaration of the validity of (1) the 28 November 2010 Share Purchase Agreement between BP and Bridas, including the Area of Mutual Interest 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 Area of Mutual Interest Waiver and Release and the Settlement Agreement remained enforceable, notwithstanding Bridas’ fraud claims, which BP believes have no basis.

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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: 1 May 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

	First quarter 2012
	$ million, except ratios
Profit before taxation		8,923
Group’s share of income in excess of dividends of equity-accounted entities		(524	)
Capitalized interest, net of amortization		(67	)
Profit as adjusted		8,332
Fixed charges:
Interest expense		208
Rental expense representative of interest		420
Capitalized interest		90
		718
Total adjusted earnings available for payment of fixed charges		9,050
Ratio of earnings to fixed charges		12.6

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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 31 March 2012 in accordance with IFRS:

	31 March 2012
	$ million
Share capital
Capital shares (1-2)		5,234
Paid-in surplus (3)		11,030
Merger reserve (3)		27,206
Own shares		(56	)
Available-for-sale investments		453
Cash flow hedges		(46	)
Foreign currency translation reserve		4,976
Treasury shares		(20,914	)
Share-based payment reserve		1,288
Profit and loss account		88,955
BP shareholders’ equity		118,126
Finance debt (4-6)
Due within one year		7,897
Due after more than one year		38,573
Total finance debt		46,470
Total capitalization (7)		164,596

(1) Issued share capital as of 31 March 2012 comprised 19,019,743,262 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,835,231,793 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 31 March 2012.

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

(6) As of 31 March 2012, the parent company, BP p.l.c., had outstanding guarantees totalling $44,928 million, of which $44,898 million related to guarantees in respect of liabilities of subsidiary undertakings, including $41,817 million relating to finance debt of subsidiaries. Thus 90% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 31 March 2012, $136 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 $2,201 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 31 March 2012 in the consolidated capitalization and indebtedness of BP.

37