BP PLC — Interim / Quarterly Report 2010

Apr 29, 2010

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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

xbrl,dc

for the period ended 31 March 2010 /xbrl,dc 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 þ Form 40-F o

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

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

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

Yes o No þ

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

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-157906) OF BP CAPITAL MARKETS p.l.c. AND BP p.l.c.; THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-155798) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c.,THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-102583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., 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.

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BP p.l.c. AND SUBSIDIARIES FORM 6-K FOR THE PERIOD ENDED 31 MARCH 2010(a)

| 1. | Management’s Discussion and Analysis of Financial Condition and Results of
Operations for the period January-March 2010 (b) | 3-10, 17-19 |
| --- | --- | --- |
| 2. | Consolidated Financial Statements including Notes to Consolidated Financial
Statements for the period January-March 2010 | 11-16, 20-24 |
| 3. | Signatures | 25 |
| 4. | Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges | 26 |
| | Exhibit 99.2: Capitalization and Indebtedness | 27 |
| (a) | In this Form 6-K, references to the first quarter 2010 and
first quarter 2009 refer to the three-month periods ended
31 March 2010 and 31 March 2009 respectively. | |
| (b) | This discussion should be read in conjunction with the
consolidated financial statements and related notes provided
elsewhere in this Form 6-K and with the information, including the
consolidated financial statements and related notes, in BP’s
Annual Report on Form 20-F for the year ended 31 December 2009. | |
| EX-99.1 | | |
| EX-99.2 | | |

/TOC

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BP p.l.c. Group results First quarter 2010

London 29 April 2010

				2010 vs
2010		2009		2009
$ million
Profit for the period (a)	6,079		2,562	137 %
Inventory holding (gains) losses, net of tax	(481	)	(175	)
Replacement
cost profit (b)	5,598		2,387	135 %
— Profit per ordinary share (cents)	32.39		13.69	137 %
— Profit per ADS (dollars)	1.94		0.82
— Replacement cost profit per ordinary share (cents)	29.82		12.75	134 %
— Replacement cost profit per ADS (dollars)	1.79		0.77

• BP’s first-quarter replacement cost profit was $5,598 million, compared with $2,387 million a year ago, an increase of 135%. Replacement cost profit for the group is a non-GAAP measure. For further information see pages 4 and 16. BP’s profit for the first quarter was $6,079 million, compared with $2,562 million a year ago.

• Non-operating items and fair value accounting effects for the first quarter had a net $49 million unfavourable impact compared with a net $194 million unfavourable impact in the first quarter of 2009. Information on fair value accounting effects is non-GAAP and further details are provided on page 18.

• Finance costs and net finance income or expense relating to pensions and other post-retirement benefits were $228 million for the first quarter, compared with $368 million for the same period last year.

• The effective tax rate on replacement cost profit for the first quarter was 34%, compared with 37.5% a year ago. The effective tax rate on profit for the first quarter was 34%, compared with 37.1% a year ago.

• Net cash provided by operating activities for the first quarter was $7.7 billion, compared with $5.6 billion a year ago.

• Net debt at the end of the first quarter was $25.2 billion. The ratio of net debt to net debt plus equity was 19% compared with 23% a year ago. Net debt information is non-GAAP and is defined on page 5. Gross finance debt at the end of the quarter was $32.2 billion compared to $34.7 billion a year ago. The ratio of gross debt to gross debt plus equity was 23%, compared with 28% a year ago.

• Total capital expenditure, including acquisitions and asset exchanges, for the first quarter was $4.7 billion. Organic capital expenditure (c) in the first quarter was $3.8 billion. Disposal proceeds were $0.1 billion for the first quarter. For 2010 as a whole, we continue to expect organic capital expenditure of around $20 billion and disposal proceeds of $2-3 billion.

| • | The quarterly dividend, to be paid on 21 June 2010, is 14 cents per share ($0.84
per ADS), the same as a year ago. The corresponding amount in sterling will be announced on 8
June 2010. A scrip dividend alternative is available, allowing shareholders to elect to
receive their dividend in the form of new ordinary shares and ADS holders in the form of new
ADSs. Details of the scrip dividend programme are available at www.bp.com/scrip. |
| --- | --- |
| (a) | Profit attributable to BP shareholders. |
| (b) | Replacement cost profit reflects the replacement cost of
supplies and is the measure of profit or loss for each operating
segment that is required to be disclosed under International
Financial Reporting Standards, as explained in more detail on page
16. The replacement cost profit for the period is arrived at by
excluding from profit inventory holding gains and losses and their
associated tax effect. Replacement cost profit for the group is
not a recognized GAAP measure. |
| | Management believes this information is useful to illustrate to
investors the fact that crude oil and product prices can vary
significantly from period to period and that the impact on our
reported result under IFRS can be significant. Inventory holding
gains and losses vary from period to period due principally to
changes in oil prices as well as changes to underlying inventory
levels. In order for investors to understand the operating
performance of the group excluding the impact of oil price changes
on the replacement of inventories, and to make comparisons of
operating performance between reporting periods, BP’s management
believes it is helpful to disclose this information. |
| (c) | Organic capital expenditure excludes acquisitions and asset
exchanges and the accounting for our transaction with Value
Creation Inc. (see page 15). |

The commentaries above and following should be read in conjunction with the cautionary statement on page 10.

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

2010		2009
$ million
Exploration and Production	8,292		4,320
Refining and Marketing	729		1,090
Other businesses and corporate	(328	)	(761	)
Consolidation adjustment	208		(405	)
RC profit before interest and tax (a)	8,901		4,244
Finance costs and net finance income or expense relating to
pensions and other post-retirement benefits	(228	)	(368	)
Taxation on a replacement cost basis	(2,966	)	(1,454	)
Minority interest	(109	)	(35	)
Replacement cost profit attributable to BP shareholders	5,598		2,387
Inventory holding gains (losses)	705		254
Taxation (charge) credit on inventory holding gains and losses	(224	)	(79	)
Profit for the period attributable to BP shareholders	6,079		2,562

(a) Replacement cost profit reflects the replacement cost of supplies. Replacement cost profit for the group is a non-GAAP measure. For further information see page 16.

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

2010		2009
$ million
Exploration and Production	104		469
Refining and Marketing	(60	)	(459	)
Other businesses and corporate	(118	)	(321	)
	(74	)	(311	)
Taxation credit (charge) (c)	25		117
	(49	)	(194	)

(a)	An analysis of non-operating items by type is provided on page 17 and an analysis by region is shown on pages 7, 9 and 10.
(b)	Information on fair value accounting effects is non-GAAP. For further details, see page 18.
(c)	Tax is calculated using the quarter’s effective tax rate on replacement cost profit.

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Per share amounts

2010	2009
Per ordinary share (cents) (a)
Profit for the period	32.39	13.69
RC profit for the period	29.82	12.75
Per ADS (dollars) (a)
Profit for the period	1.94	0.82
RC profit for the period	1.79	0.77

(a) See Note 4 on page 22 for details of the calculation of earnings per share.

Net debt ratio — net debt: net debt + equity

2010	2009
$ million
Gross debt	32,153	34,698
Less: fair value asset (liability) of hedges related to finance debt	152	(323	)
	32,001	35,021
Cash and cash equivalents	6,841	8,360
Net debt	25,160	26,661
Equity	104,978	91,179
Net debt ratio	19%	23%

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 has announced a dividend of 14 cents per ordinary share to be paid in June. The corresponding amount in sterling will be announced on 8 June 2010, and calculated from the average of the market exchange rates for the four dealing days commencing on 2 June 2010. Holders of American Depositary Shares (ADSs) will receive $0.84 per ADS. The dividend is payable on 21 June 2010 to shareholders and ADS holders on the register on 7 May 2010. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the scrip dividend programme including the first quarter interim dividend and timetable are available at www.bp.com/scrip.

Dividends Paid	First quarter — 2010	2009
Dividends paid per ordinary share
cents	14.000	14.000
pence	8.679	9.818
Dividends paid per ADS (cents)	84.00	84.00

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Exploration and Production

2010		2009
$ million
Profit
before interest and
tax (a)	8,316		4,286
Inventory holding (gains) losses	(24	)	34
Replacement
cost profit before interest and
tax (b)	8,292		4,320
By region
US	2,762		1,143
Non-US	5,530		3,177
	8,292		4,320

(a)	Includes profit after interest and tax of equity-accounted entities.
(b)	See page 16 for information on replacement cost reporting for operating segments.

The replacement cost profit before interest and tax for the first quarter was $8,292 million, an increase of 92% compared with the first quarter of 2009. This increase was primarily due to higher realizations and higher earnings from equity-accounted entities (mainly TNK-BP), partly offset by a lower contribution from the gas marketing and trading business, higher production taxes and higher depreciation. Unit production costs were 3% lower than a year ago after adjusting for restructuring costs, and were 3% higher than a year ago including restructuring costs. Unit production costs after adjusting for restructuring costs is a non-GAAP measure – see page 19 for details.

The net non-operating gain of $41 million in the first quarter primarily relates to fair value gains on embedded derivatives, partly offset by restructuring costs. The corresponding quarter in 2009 included a net non-operating gain of $311 million. Additionally, in the first quarter, fair value accounting effects had a favourable impact of $63 million compared with a favourable impact of $158 million a year ago.

Production for the quarter was 4,010mboe/d, broadly flat with the first quarter of 2009 reflecting continued strong operational performance. After adjusting for entitlement impacts in our production-sharing agreements (PSAs) production was 1% higher. As previously indicated, we expect production in 2010 to be slightly lower than in 2009. The actual outcome will depend on a number of factors including the oil price and its impact on PSAs and OPEC quota restrictions. In the second quarter, we expect a normal seasonal turnaround effect of around 100mboe/d. These turnaround activities are planned for some of our higher-margin areas including the North Sea and the Gulf of Mexico, where activity is currently under way at Thunder Horse. This will impact costs and margins as well as volumes.

Two major projects started up during the first quarter. In the ultra-deepwater Gulf of Mexico, first oil was achieved from the Great White field (BP 33.3%). In Canada, the Noel major project commenced exporting and selling gas.

During the quarter, we announced that BP will pay Devon Energy $7.0 billion for assets in Brazil, Azerbaijan and the US deepwater Gulf of Mexico. These include ten exploration blocks in Brazil; a major portfolio of deepwater exploration acreage and prospects in the US Gulf of Mexico; and an interest in the ACG development in the Caspian Sea. Completion of certain of these transfers is subject to regulatory approvals and other third-party consents. In addition, BP will sell to Devon Energy a 50% stake in our Kirby oil sands interests in Alberta, Canada, for $500 million. The parties have agreed to form a 50:50 joint venture, operated by Devon, to pursue the development of Kirby. Devon will commit to fund an additional $150 million of capital costs on BP’s behalf.

Also during the quarter, BP and Value Creation Inc. (VCI) of Calgary agreed to form a partnership to explore and develop the Terre de Grace oil sands acreage, in the Athabasca region of Alberta, Canada, using in-situ techniques. BP will hold a 75% interest and VCI a 25% interest in a newly formed partnership. BP has agreed to pay $900 million for the interest with $500 million paid in cash at closing.

Furthermore, on behalf of our partners, BP announced the first major contracts to support the expansion of production from the Rumaila field in southern Iraq (BP has a 38% working interest).

After the end of the quarter, BP agreed with Total to acquire its 15.7% interest in Valhall and its 25% interest in Hod, both fields located in the southern part of the Norwegian continental shelf, for the sum of $991 million to be paid in cash. The agreement will deepen BP’s position as operator by giving BP a 43.8% interest in Valhall and 50% in Hod, subject to third-party consents and government approval. The deal has an effective date of 1 January 2010.

On 20 April 2010, the semi-submersible drilling rig Deepwater Horizon owned and operated by Transocean Limited caught fire in the US Gulf of Mexico and subsequently sank. The rig was drilling an exploration well (Mississippi Canyon 252) in which BP has a 65% interest. As operator under the MC 252 lease, BP is committed to doing everything in its power to contain the environmental consequences of the incident. BP is currently ramping up preparations for a major cleaning effort on the shorelines of Louisiana, Mississippi, Alabama and Florida. Efforts continue to stem the flow of oil from the well, currently estimated at up to 5,000 barrels a day. Preliminary estimates indicate that current efforts to contain the spill and secure the well are costing the MC 252 owners about $6 million per day. This figure is expected to rise as activity increases. It is too early to quantify other potential costs and liabilities associated with the incident.

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Exploration and Production

2010		2009
$ million
Non-operating items
US	(62	)	71
Non-US	103		240
	41		311
Fair
value accounting
effects (a)
US	81		208
Non-US	(18	)	(50	)
	63		158
Exploration expense
US	69		44
Non-US	51		75
	120		119
Production (net of royalties) (b)
Liquids (mb/d) (net of royalties) (c)
US	665		643
Europe	215		212
Russia	849		822
Rest of World	798		827
	2,527		2,504
Of which equity-accounted entities	1,132		1,116
Natural gas (mmcf/d) (net of royalties)
US	2,221		2,335
Europe	599		838
Russia	673		642
Rest of World	5,107		4,952
	8,600		8,767
Of which equity-accounted entities	1,093		1,072
Total hydrocarbons (mboe/d) (d)
US	1,048		1,046
Europe	318		357
Russia	965		933
Rest of World	1,679		1,680
	4,010		4,016
Of which equity-accounted entities	1,320		1,301
Average realizations (e)
Total liquids ($/bbl)	71.86		41.26
Natural gas ($/mcf)	4.26		3.63
Total hydrocarbons ($/boe)	49.16		31.40

| (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 18. |
| --- | --- |
| (b) | Includes BP’s share of production of equity-accounted entities. |
| (c) | Crude oil and natural gas liquids. |
| (d) | Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. |
| (e) | 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.

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Refining and Marketing

2010		2009
$ million
Profit before interest and tax (a)	1,408		1,417
Inventory holding (gains) losses	(679	)	(327	)
Replacement cost profit before interest and tax (b)	729		1,090
By region
US	(63	)	308
Non-US	792		782
	729		1,090

(a)	Includes profit after interest and tax of equity-accounted entities.
(b)	See page 16 for information on replacement cost reporting for operating segments.

The replacement cost profit before interest and tax for the first quarter was $729 million, compared with $1,090 million for the same period last year.

The first quarter’s result included a net non-operating charge of $70 million compared with a net charge of $350 million a year ago. Fair value accounting effects had a favourable impact of $10 million in the first quarter compared with an unfavourable impact of $109 million in the first quarter of 2009.

Compared with a year ago, the result reflected a significantly weaker supply and trading contribution in contrast to the particularly strong contribution in the first quarter of last year. The result was also impacted by a weaker refining environment, with the indicator margin at around half the level of the same period in 2009, and marketing margins for some products compressed by rising crude prices. These factors were partially offset by operational improvements and further cost efficiencies in the fuels value chains, and continued strong performance in the international businesses. In addition, BP’s actual refining margins fell by less than the indicator would suggest as a result of BP’s highly upgraded refining portfolio.

In the fuels value chains, Solomon refining availability was up by three percentage points year on year to 95.3%, the highest level since 2004. Refining throughput increased by over 8% compared with the same quarter last year and by over 5% compared with the previous quarter, principally driven by increased throughputs in our US refineries.

In the international businesses, our petrochemicals business had a particularly strong quarter with production volumes up almost 40% compared with the same period last year and 12% on the previous quarter.

In February, BP announced that it had received an offer from Delek Europe B.V. for the retail fuels and convenience business and selected fuels terminals in France. As a result, BP has agreed a period of exclusivity with Delek Europe B.V. to negotiate the terms for the sale and to allow consultation with the relevant works councils. Any transaction will be subject to regulatory approval and is expected to include a BP brand licence agreement.

In March, BP announced that in sub-Saharan Africa it intends to sell its marketing businesses in Namibia, Malawi, Tanzania, Zambia and Botswana and focus its fuel marketing activities on South Africa and Mozambique.

There has been some improvement in refining margins in the early part of the second quarter although we expect opportunities for further improvement to be limited. BP’s refinery turnaround activities are expected to be higher in the second quarter than in the first. Continued low market volatility would limit the supply and trading contribution in the quarter. In the international businesses, we expect the current petrochemicals margins to come under some pressure as new capacity comes onstream.

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Refining and Marketing

2010		2009
$ million
Non-operating items
US	(3	)	(134	)
Non-US	(67	)	(216	)
	(70	)	(350	)
Fair value accounting effects (a)
US	16		65
Non-US	(6	)	(174	)
	10		(109	)
Refinery throughputs (mb/d)
US	1,366		1,164
Europe	780		783
Rest of World	282		299
Total throughput	2,428		2,246
Refining availability (%) (b)	95.3		92.3
Sales volumes (mb/d) (c)
Marketing sales by region
US	1,418		1,402
Europe	1,428		1,529
Rest of World	629		617
Total marketing sales	3,475		3,548
Trading/supply sales	2,622		2,312
Total refined product sales	6,097		5,860
Global Indicator Refining Margin (GIM) ($/bbl) (d)
US Gulf Coast	3.50		6.69
US Midwest	1.86		7.03
US West Coast	3.32		9.96
North West Europe	4.29		4.67
Mediterranean	3.11		3.56
Singapore	0.97		2.51
BP Average GIM	3.08		6.20
Chemicals production (kte)
US	940		713
Europe	981		788
Rest of World	1,887		1,244
Total production	3,808		2,745

| (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
18. |
| --- | --- |
| (b) | Refining availability represents Solomon Associates’
operational availability, which is defined as the percentage of
the year that a unit is available for processing after subtracting
the annualized time lost due to turnaround activity and all
planned mechanical, process and regulatory maintenance downtime. |
| (c) | Does not include volumes relating to crude oil. |
| (d) | The Global Indicator Refining Margin (GIM) is the average of
regional indicator margins weighted for BP’s crude refining
capacity in each region. Each regional indicator margin is based
on a single representative crude with product yields
characteristic of the typical level of upgrading complexity. The
regional indicator margins may not be representative of the
margins achieved by BP in any period because of BP’s particular
refinery configurations and crude and product slate. |

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Other businesses and corporate

2010		2009
$ million
Profit (loss) before interest and tax (a)	(326	)	(800	)
Inventory holding (gains) losses	(2	)	39
Replacement cost profit (loss) before interest and tax (b)	(328	)	(761	)
By region
US	(231	)	(279	)
Non-US	(97	)	(482	)
	(328	)	(761	)
Results include
Non-operating items
US	(106	)	(116	)
Non-US	(12	)	(205	)
	(118	)	(321	)

(a)	Includes profit after interest and tax of equity-accounted entities.
(b)	See page 16 for information on replacement cost reporting for operating segments.

Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium asset, 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 $328 million, compared with a loss of $761 million a year ago. The net non-operating charge for the first quarter was $118 million, compared with a net charge of $321 million a year ago. In addition, there were favourable foreign exchange effects and lower costs, and improved margins in Alternative Energy.

In Alternative Energy, our solar business achieved sales of 54MW in the first quarter. In March, BP Solar announced the closure of manufacturing at its Frederick facility, in Maryland, US, as it moves its manufacturing to lower-cost locations. BP Solar will maintain its US presence in sales and marketing, research and technology, project development, and key business support activities.

In our US wind business, construction has commenced at the 125MW Goshen North wind farm (BP 50%) in Bonneville County, Idaho. BP’s net wind generation capacity (c) at the end of the first quarter was 711MW (1,237MW gross), compared with 678MW (1,113MW gross) at the end of the same period a year ago.

(c) Net wind capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.

Cautionary statement regarding forward-looking statements: The foregoing discussion contains forward-looking statements particularly those regarding production and quarterly phasing of production, second quarter seasonal turn-around effect and its impact on costs, margins and volumes; refining and petrochemicals margins; refinery turnaround activities; expected supply and trading contribution in the second quarter; dividend and optional scrip dividend. 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; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; 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 in this Announcement. For more information you should refer to our Annual Report and Accounts 2009 and our 2009 Annual Report on Form 20-F filed with the US Securities and Exchange Commission.

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Group income statement

2010		2009
$ million
Sales and other operating revenues (Note 2)	73,071		47,296
Earnings from jointly controlled entities — after interest and tax	403		220
Earnings from associates — after interest and tax	763		285
Interest and other income	142		203
Gains on sale of businesses and fixed assets	38		81
Total revenues and other income	74,417		48,085
Purchases	51,641		30,777
Production and manufacturing expenses (Note 3)	5,740		5,894
Production and similar taxes (Note 3)	1,276		674
Depreciation, depletion and amortization	2,996		2,823
Impairment and losses on sale of businesses and fixed assets	164		137
Exploration expense	120		119
Distribution and administration expenses	3,020		3,349
Fair value (gain) loss on embedded derivatives	(146	)	(186	)
Profit before interest and taxation	9,606		4,498
Finance costs	238		318
Net finance (income) expense relating to pensions and
other post-retirement benefits	(10	)	50
Profit before taxation	9,378		4,130
Taxation	3,190		1,533
Profit for the period	6,188		2,597
Attributable to
BP shareholders	6,079		2,562
Minority interest	109		35
	6,188		2,597
Earnings per share — cents (Note 4)
Profit for the period attributable to BP shareholders
Basic	32.39		13.69
Diluted	31.99		13.54

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Group statement of comprehensive income

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2010		2009
$ million
Profit for the period	6,188		2,597
Currency translation differences	(526	)	(1,011	)
Available-for-sale investments marked to market	(93	)	74
Available-for-sale investments – recycled to the income statement	—		2
Cash flow hedges marked to market	(162	)	(211	)
Cash flow hedges – recycled to the income statement	(94	)	239
Cash flow hedges – recycled to the balance sheet	13		71
Taxation	(119	)	(82	)
Other comprehensive income	(981	)	(918	)
Total comprehensive income	5,207		1,679
Attributable to
BP shareholders	5,105		1,668
Minority interest	102		11
	5,207		1,679

/xbrl,in xbrl,se

Group statement of changes in equity

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shareholders’		Minority		Total
equity		interest		equity
$ million
At 31 December 2009	101,613		500		102,113
Total comprehensive income	5,105		102		5,207
Dividends	(2,626	)	(3	)	(2,629	)
Share-based payments (net of tax)	(13	)	—		(13	)
Transactions involving minority interests	—		300		300
At 31 March 2010	104,079		899		104,978

shareholders’		Minority		Total
equity		interest		equity
$ million
At 31 December 2008	91,303		806		92,109
Total comprehensive income	1,668		11		1,679
Dividends	(2,619	)	(111	)	(2,730	)
Share-based payments (net of tax)	121		—		121
At 31 March 2009	90,473		706		91,179

/xbrl,se

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Group balance sheet

xbrl,body

2010	2009
$ million
Non-current assets
Property, plant and equipment	108,232	108,275
Goodwill	8,409	8,620
Intangible assets	12,675	11,548
Investments in jointly controlled entities	15,484	15,296
Investments in associates	13,396	12,963
Other investments	1,459	1,567
Fixed assets	159,655	158,269
Loans	982	1,039
Other receivables	2,216	1,729
Derivative financial instruments	4,770	3,965
Prepayments	1,359	1,407
Deferred tax assets	464	516
Defined benefit pension plan surpluses	1,494	1,390
	170,940	168,315
Current assets
Loans	236	249
Inventories	23,221	22,605
Trade and other receivables	31,159	29,531
Derivative financial instruments	5,355	4,967
Prepayments	2,647	1,753
Current tax receivable	238	209
Cash and cash equivalents	6,841	8,339
	69,697	67,653
Total assets	240,637	235,968
Current liabilities
Trade and other payables	38,146	35,204
Derivative financial instruments	5,530	4,681
Accruals	5,482	6,202
Finance debt	8,356	9,109
Current tax payable	2,624	2,464
Provisions	1,646	1,660
	61,784	59,320
Non-current liabilities
Other payables	3,206	3,198
Derivative financial instruments	3,899	3,474
Accruals	656	703
Finance debt	23,797	25,518
Deferred tax liabilities	20,156	18,662
Provisions	12,752	12,970
Defined benefit pension plan and other post-retirement benefit plan deficits	9,409	10,010
	73,875	74,535
Total liabilities	135,659	133,855
Net assets	104,978	102,113
Equity
BP shareholders’ equity	104,079	101,613
Minority interest	899	500
	104,978	102,113

/xbrl,bs

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Condensed group cash flow statement

xbrl,body

2010		2009
$ million
Operating activities
Profit before taxation	9,378		4,130
Adjustments to reconcile profit before taxation to net cash
provided by operating activities
Depreciation, depletion and amortization and exploration
expenditure written off	3,017		2,849
Impairment and (gain) loss on sale of businesses and fixed assets	126		56
Earnings from equity-accounted entities, less dividends received	(669	)	(252	)
Net charge for interest and other finance expense, less net
interest paid	46		89
Share-based payments	(146	)	86
Net operating charge for pensions and other post-retirement benefits,
less contributions and benefit payments for unfunded plans	(490	)	26
Net charge for provisions, less payments	(48	)	281
Movements in inventories and other current and non-current
assets and liabilities (a)	(1,940	)	32
Income taxes paid	(1,581	)	(1,725	)
Net cash provided by operating activities	7,693		5,572
Investing activities
Capital expenditure	(4,289	)	(4,817	)
Acquisitions, net of cash acquired	—		—
Investment in jointly controlled entities	(82	)	(103	)
Investment in associates	(6	)	(47	)
Proceeds from disposal of fixed assets	108		311
Proceeds from disposal of businesses, net of cash disposed	—		—
Proceeds from loan repayments	56		117
Other	—		47
Net cash used in investing activities	(4,213	)	(4,492	)
Financing activities
Net issue of shares	128		35
Proceeds from long-term financing	342		4,619
Repayments of long-term financing	(2,495	)	(2,580	)
Net decrease in short-term debt	(247	)	(182	)
Dividends paid – BP shareholders	(2,626	)	(2,619	)
– Minority interest	(3	)	(111	)
Net cash used in financing activities	(4,901	)	(838	)
Currency translation differences relating to cash and
cash equivalents	(77	)	(79	)
Increase (decrease) in cash and cash equivalents	(1,498	)	163
Cash and cash equivalents at beginning of period	8,339		8,197
Cash and cash equivalents at end of period	6,841		8,360

(a) Includes — Inventory holding (gains) losses	(705	)	(254	)
Fair value (gain) loss on embedded derivatives	(146	)	(186	)
Inventory holding gains and losses and fair value gains and losses on embedded
derivatives are also included within profit before taxation.

/xbrl,cf

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Capital expenditure and acquisitions

2010	2009
$ million
By business
Exploration and Production
US	1,133	1,670
Non-US (a)	2,815	2,035
	3,948	3,705
Refining and Marketing
US	528	567
Non-US	144	226
	672	793
Other businesses and corporate
US	28	56
Non-US	39	41
	67	97
	4,687	4,595
By geographical area
US	1,689	2,293
Non-US (a)	2,998	2,302
	4,687	4,595
Included above:
Acquisitions and asset exchanges	—	—

(a) First quarter 2010 included capital expenditure of $900 million in Exploration and Production relating to the formation of a partnership with Value Creation Inc. to develop the Terre de Grace oil sands acreage in the Athabasca region of Alberta, Canada.

Exchange rates

2010	2009
US dollar/sterling average rate for the period	1.56	1.43
US dollar/sterling period-end rate	1.51	1.42
US dollar/euro average rate for the period	1.38	1.30
US dollar/euro period-end rate	1.34	1.32

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Analysis of replacement cost profit before interest and tax and reconciliation to profit before taxation (a)

2010		2009
$ million
By business
Exploration and Production
US	2,762		1,143
Non-US	5,530		3,177
	8,292		4,320
Refining and Marketing
US	(63	)	308
Non-US	792		782
	729		1,090
Other businesses and corporate
US	(231	)	(279	)
Non-US	(97	)	(482	)
	(328	)	(761	)
	8,693		4,649
Consolidation adjustment	208		(405	)
Replacement cost profit before interest and tax (b)	8,901		4,244
Inventory holding gains (losses) (c)
Exploration and Production	24		(34	)
Refining and Marketing	679		327
Other businesses and corporate	2		(39	)
Profit before interest and tax	9,606		4,498
Finance costs	238		318
Net finance (income) expense relating to pensions
and other post-retirement benefits	(10	)	50
Profit before taxation	9,378		4,130
Replacement cost profit (loss) before interest and tax
By geographical area
US	2,590		854
Non-US	6,311		3,390
	8,901		4,244

| (a) | IFRS requires that the measure of profit or loss disclosed for
each operating segment is the measure that is provided regularly
to the chief operating decision maker for the purposes of
performance assessment and resource allocation. For BP, this
measure of profit or loss is replacement cost profit before
interest and tax. In addition, a reconciliation is required
between the total of the operating segments’ measures of profit or
loss and the group profit or loss before taxation. |
| --- | --- |
| (b) | Replacement cost profit reflects the replacement cost of
supplies. The replacement cost profit for the period is arrived at
by excluding from profit inventory holding gains and losses and
their associated tax effect. Replacement cost profit for the
group is not a recognized GAAP measure. |
| (c) | Inventory holding gains and losses represent the difference
between the cost of sales calculated using the average cost to BP
of supplies acquired during the period and the cost of sales
calculated on the first-in first-out (FIFO) method after adjusting
for any changes in provisions where the net realizable value of
the inventory is lower than its cost. Under the FIFO method, which
we use for IFRS reporting, the cost of inventory charged to the
income statement is based on its historic cost of purchase, or
manufacture, rather than its replacement cost. In volatile energy
markets, this can have a significant distorting effect on reported
income. The amounts disclosed represent the difference between the
charge (to the income statement) for inventory on a FIFO basis
(after adjusting for any related movements in net realizable value
provisions) and the charge that would have arisen if an average
cost of supplies was used for the period. For this purpose, the
average cost of supplies during the period is principally
calculated on a monthly basis by dividing the total cost of
inventory acquired in the period by the number of barrels
acquired. The amounts disclosed are not separately reflected in
the financial statements as a gain or loss. No adjustment is made
in respect of the cost of inventories held as part of a trading
position and certain other temporary inventory positions. Management believes this information is useful to illustrate to
investors the fact that crude oil and product prices can vary
significantly from period to period and that the impact on our
reported result under IFRS can be significant. Inventory holding
gains and losses vary from period to period due principally to
changes in oil prices as well as changes to underlying inventory
levels. In order for investors to understand the operating
performance of the group excluding the impact of oil price changes
on the replacement of inventories, and to make comparisons of
operating performance between reporting periods, BP’s management
believes it is helpful to disclose this information. |

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Non-operating items (a)

2010		2009
$ million
Exploration and Production
Impairment and gain (loss) on sale of businesses and fixed assets	(13	)	73
Environmental and other provisions	—		—
Restructuring, integration and rationalization costs	(104	)	(1	)
Fair value gain (loss) on embedded derivatives	146		243
Other	12		(4	)
	41		311
Refining and Marketing
Impairment and gain (loss) on sale of businesses and fixed assets	(45	)	(21	)
Environmental and other provisions	—		—
Restructuring, integration and rationalization costs	12		(263	)
Fair value gain (loss) on embedded derivatives	—		(57	)
Other	(37	)	(9	)
	(70	)	(350	)
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(68	)	(108	)
Environmental and other provisions	—		(75	)
Restructuring, integration and rationalization costs	(38	)	(71	)
Fair value gain (loss) on embedded derivatives	—		—
Other	(12	)	(67	)
	(118	)	(321	)
Total before taxation	(147	)	(360	)
Taxation credit (charge) (b)	50		135
Total after taxation for period	(97	)	(225	)

(a)	An analysis of non-operating items by region is shown on pages 7, 9 and 10.
(b)	Tax is calculated using the quarter’s effective tax rate on replacement cost profit.

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

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Non-GAAP information on fair value accounting effects

2010		2009
$ million
Favourable (unfavourable) impact relative to
management’s measure of performance
Exploration and Production	63		158
Refining and Marketing	10		(109	)
	73		49
Taxation charge (a)	(25	)	(18	)
	48		31

(a) Tax is calculated using the quarter’s effective tax rate on replacement cost profit.

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products as well as certain contracts to supply physical volumes at future dates. Under IFRS, these inventories and contracts are recorded at historic cost and on an accruals basis respectively. 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 and contracts 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.

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 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 which the inventory and the supply and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.

Reconciliation of non-GAAP information

2010	2009
$ million
Exploration and Production
Replacement cost profit before interest and tax adjusted for
fair value accounting effects	8,229	4,162
Impact of fair value accounting effects	63	158
Replacement cost profit before interest and tax	8,292	4,320
Refining and Marketing
Replacement cost profit before interest and tax adjusted for
fair value accounting effects	719	1,199
Impact of fair value accounting effects	10	(109	)
Replacement cost profit before interest and tax	729	1,090
Total group
Profit before interest and tax adjusted for fair value accounting effects	9,533	4,449
Impact of fair value accounting effects	73	49
Profit before interest and tax	9,606	4,498

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Realizations and marker prices

2010	2009
Average realizations (a)
Liquids ($/bbl) (b)
US	69.77	39.47
Europe	75.71	47.59
Rest of World	72.94	40.89
BP Average	71.86	41.26
Natural gas ($/mcf)
US	4.84	3.38
Europe	4.91	5.56
Rest of World	3.90	3.41
BP Average	4.26	3.63
Total hydrocarbons ($/boe)
US	54.54	31.83
Europe	60.39	41.36
Rest of World	42.20	28.35
BP Average	49.16	31.40
Average oil marker prices ($/bbl)
Brent	76.36	44.46
West Texas Intermediate	78.84	43.20
Alaska North Slope	79.14	45.40
Mars	75.85	43.83
Urals (NWE– cif)	75.31	43.65
Russian domestic oil	35.52	19.52
Average natural gas marker prices
Henry Hub gas price ($/mmBtu) (c)	5.30	4.91
UK Gas – National Balancing Point (p/therm)	35.65	46.80

(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.

Non-GAAP information on unit production costs adjusted for restructuring costs (a)

2010		2009
$ million
Production costs	1,524		1,499
Restructuring costs included in production costs	(86	)	–
Production costs adjusted for restructuring costs	1,438		1,499
Production (net of royalties) (b)
Total hydrocarbons (mboe/d) (c)	2,690		2,715
Unit production costs adjusted for restructuring costs ($/boe) (d)	5.94		6.13

| (a) | Production costs are costs incurred by Exploration and Production to operate and
maintain wells and related equipment and facilities. Amounts do not include ad valorem and
severance taxes. Restructuring costs are included within non-operating items. Further
information on non-operating items is provided on page 17. |
| --- | --- |
| (b) | Excludes BP’s share of production of equity-accounted entities. |
| (c) | Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. |
| (d) | For first quarter 2009, there were no restructuring costs within production costs. |

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Notes

| 1. |
| --- |
| The interim financial information included in this report has been prepared in
accordance with IAS 34 ‘Interim Financial Reporting’. |
| The results for the interim periods are unaudited and in the opinion of management include
all adjustments necessary for a fair presentation of the results for the periods presented.
All such adjustments are of a normal recurring nature. This report should be read in
conjunction with the consolidated financial statements and related notes for the year ended
31 December 2009 included in BP Annual Report and Accounts 2009 and in BP Annual Report on
Form 20-F 2009 . |
| BP prepares its consolidated financial statements included within its Annual Report and
Accounts on the basis of International Financial Reporting Standards (IFRS) as issued by the
International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU)
and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the
EU differs in certain respects from IFRS as issued by the IASB, however, the differences
have no impact on the group’s consolidated financial statements for the periods presented.
The financial information presented herein has been prepared in accordance with the
accounting policies expected to be used in preparing the Annual Report and Accounts and the
Annual Report on Form 20-F for 2010, which do not differ significantly from those used in
the BP Annual Report and Accounts 2009 or in BP Annual Report on Form 20-F 2009 . |
| BP has adopted the revised version of IFRS 3 ‘Business Combinations’, with effect from 1
January 2010. The revised standard still requires the purchase method of accounting to be
applied to business combinations but introduces some changes to the accounting treatment.
Assets and liabilities arising from business combinations that occurred before 1 January
2010 were not required to be restated and thus there was no effect on the group’s reported
income or net assets on adoption. |
| In addition, BP has adopted the amended version of IAS 27, ‘Consolidated and Separate
Financial Statements’, also with effect from 1 January 2010. This requires the effects of
all transactions with minority interests to be recorded in equity if there is no change in
control. When control is lost, any remaining interest in the entity is remeasured to fair
value and a gain or loss recognized in profit or loss. There was no effect on the group’s
reported income or net assets on adoption. |

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Notes

1. Sales and other operating revenues

2010	2009
$ million
By business
Exploration and Production	18,080	12,343
Refining and Marketing	64,286	40,573
Other businesses and corporate	790	584
	83,156	53,500
Less: sales between businesses
Exploration and Production	9,746	5,800
Refining and Marketing	135	111
Other businesses and corporate	204	293
	10,085	6,204
Third party sales and other operating revenues
Exploration and Production	8,334	6,543
Refining and Marketing	64,151	40,462
Other businesses and corporate	586	291
Total third party sales and other operating revenues	73,071	47,296
By geographical area
US	26,108	17,580
Non-US	54,009	33,586
	80,117	51,166
Less: sales between areas	7,046	3,870
	73,071	47,296

1. Production and similar taxes

2010	2009
$ million
US	313	79
Non-US	963	595
	1,276	674

Comparative figures have been restated to include amounts previously reported as production and manufacturing expenses amounting to $213 million for the first quarter 2009, which we believe are more appropriately classified as production taxes. There was no effect on the group profit for the period or the group balance sheet.

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Notes

xbrl,n

1. Earnings per share and shares in issue

xbrl,body

| Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit
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. |

2010		2009
$ million
Results for the period
Profit for the period attributable to BP shareholders	6,079		2,562
Less: preference dividend	—		—
Profit attributable to BP ordinary shareholders	6,079		2,562
Inventory holding (gains) losses, net of tax	(481	)	(175	)
RC profit attributable to BP ordinary shareholders	5,598		2,387
Basic weighted average number of shares outstanding
(thousand) (a)	18,769,888		18,720,354
ADS
equivalent (thousand) (a)	3,128,315		3,120,059
Weighted average number of shares outstanding used to
calculate diluted earnings per share (thousand) (a)	19,004,740		18,920,515
ADS equivalent (thousand) (a)	3,167,457		3,153,419
Shares in issue at period-end (thousand) (a)	18,784,361		18,724,785
ADS equivalent (thousand) (a)	3,130,727		3,120,798

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

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Notes

xbrl,n

1. Analysis of changes in net debt

xbrl,body

2010		2009
$ million
Opening balance
Finance debt	34,627		33,204
Less: Cash and cash equivalents	8,339		8,197
Less: FV asset (liability) of hedges related to finance debt	127		(34	)
Opening net debt	26,161		25,041
Closing balance
Finance debt	32,153		34,698
Less: Cash and cash equivalents	6,841		8,360
Less: FV asset (liability) of hedges related to finance debt	152		(323	)
Closing net debt	25,160		26,661
Decrease (increase) in net debt	1,001		(1,620	)
Movement in cash and cash equivalents
(excluding exchange adjustments)	(1,421	)	242
Net cash outflow (inflow) from financing
(excluding share capital)	2,400		(1,857	)
Other movements	7		7
Movement in net debt before exchange effects	986		(1,608	)
Exchange adjustments	15		(12	)
Decrease (increase) in net debt	1,001		(1,620	)

xbrl,n

1. TNK-BP operational and financial information

xbrl,body

2010		2009
Production (Net of royalties) (BP share)
Crude oil (mb/d)	849		822
Natural gas (mmcf/d)	673		642
Total hydrocarbons (mboe/d) (a)	965		933
$ million
Income statement (BP share)
Profit (loss) before interest and tax	788		419
Finance costs	(38	)	(68	)
Taxation	(168	)	(185	)
Minority interest	(39	)	(32	)
Net income	543		134
Cash flow
Dividends received	256		—

	31 March	31 December
Balance sheet	2010	2009
Investments in associates	9,428	9,141

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

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Notes

xbrl,n

1. Inventory valuation

xbrl,body

A provision of $46 million was held at 31 December 2009 to write inventories down to their net realizable value. The net movement in the provision during the first quarter 2010 was a decrease of $22 million (first quarter 2009 was a decrease of $1,163 million).

xbrl,n

1. Post balance sheet event

xbrl,body

On 20 April 2010, the semi-submersible drilling rig Deepwater Horizon owned and operated by Transocean Limited caught fire in the US Gulf of Mexico and subsequently sank. The rig was drilling an exploration well (Mississippi Canyon 252) in which BP has a 65% interest. As operator under the MC 252 lease, BP is committed to doing everything in its power to contain the environmental consequences of the incident. BP is currently ramping up preparations for a major cleaning effort on the shorelines of Louisiana, Mississippi, Alabama and Florida. Efforts continue to stem the flow of oil from the well, currently estimated at up to 5,000 barrels a day. Preliminary estimates indicate that current efforts to contain the spill and secure the well are costing the MC 252 owners about $6 million per day. This figure is expected to rise as activity increases. It is too early to quantify other potential costs and liabilities associated with the incident.

xbrl,n

1. Second-quarter results

xbrl,body

BP’s second-quarter results will be announced on 27 July 2010.

xbrl,n

1. Statutory accounts

xbrl,body

The financial information shown in this publication, which was approved by the board of directors on 26 April 2010, is unaudited and does not constitute statutory financial statements.

/xbrl,ns

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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: 29 April 2010	/s/ D J Pearl
	D J PEARL
	Deputy Company Secretary

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