Edgar Filing: BP PLC

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Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

of the Securities Exchange Act of 1934

for the period ended 31 March 2013

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., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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 2013(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-March 2013(b)		3 –13, 20 – 22

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-March 2013		14 – 19, 23 – 33

3.	Legal proceedings		34 – 35

4.	Cautionary statement		36

5.	Signatures		37

6.	Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges		38

	Exhibit 99.2: Capitalization and Indebtedness		39

(a)	In this Form 6-K, references to the first quarter 2013 and first quarter 2012 refer to the three-month periods ended 31 March 2013 and 31 March 2012 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 2012.

Group results first quarter 2013


$ million	First quarter 2013			First quarter 2012
Profit for the period(a)		16,863			5,767
Inventory holding (gains) losses, net of tax		(267	)		(986	)

Replacement cost profit(b)		16,596			4,781
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax(c)		(12,381	)		(130	)

Underlying replacement cost profit(b)		4,215			4,651

Profit per ordinary share (cents)		88.07			30.39
Profit per ADS (dollars)		5.28			1.82
Replacement cost profit per ordinary share (cents)		86.67			25.19
Replacement cost profit per ADS (dollars)		5.20			1.51
Underlying replacement cost profit per ordinary share (cents)		22.01			24.51
Underlying replacement cost profit per ADS (dollars)		1.32			1.47

•

BP’s profit for the first quarter was $16,863 million, compared with $5,767 million a year ago. BP’s first-quarter replacement cost (RC) profit was $16,596 million, compared with $4,781 million for the same period in 2012. After adjusting for a net gain from non-operating items of $12,424 million and net unfavourable fair value accounting effects of $43 million (both on a post-tax basis), underlying RC profit for the first quarter was $4,215 million, compared with $4,651 million for the same period in 2012. 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 4, 19 and 21.

•

Non-operating items for the first quarter on a pre-tax basis amounted to a net gain of $12,401 million, primarily relating to the gain on disposal of our interest in TNK-BP. All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a minimal net impact on the results this quarter. For further information on the Gulf of Mexico oil spill and its consequences see page 13, Note 2 on pages 25 – 29 and Legal proceedings on pages 34 – 35.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $4.0 billion, compared with $3.4 billion in the same period of 2012. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $4.3 billion, compared with $4.6 billion a year ago.

•

Gross debt at the end of the quarter was $46.4 billion compared with $46.5 billion a year ago. The ratio of gross debt to gross debt plus equity was 26.2%, compared with 28.0% a year ago. Net debt at the end of the quarter was $17.7 billion, compared with $31.0 billion a year ago, with the decrease driven primarily by a net cash inflow of $11.8 billion from the sale of our interest in TNK-BP to Rosneft. The ratio of net debt to net debt plus equity at the end of the quarter was 11.9% compared with 20.6% a year ago. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 5 for more information.

•

The effective tax rate (ETR) on the profit for the first quarter was 14%, compared with 33% for the equivalent period in 2012. The ETR on replacement cost profit for the first quarter was 14%, compared with 34% for the same period in 2012. The low rate for the first quarter 2013 reflects the fact that the gain on disposal of TNK-BP is expected to be exempt from UK corporation tax under the provisions of the substantial shareholdings exemption introduced for UK companies in 2002. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the first quarter of 2013 was 39% compared with 33% in the first quarter of 2012. The increase was mainly due to a reduction in equity-accounted earnings (which are reported net of tax) as a result of the TNK-BP disposal.

•

Total capital expenditure for the first quarter was $17.7 billion, of which organic capital expenditure(d) was $5.7 billion, with the remainder relating to our investment in Rosneft (see below for further information). Disposal proceeds received in cash were $18.3 billion for the quarter.

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $404 million for the first quarter, compared with $405 million for the same period in 2012.

•

On 21 March, BP and Rosneft completed transactions for the sale and purchase of BP’s 50% interest in TNK-BP for $16.7 billion in cash and 12.84% of Rosneft shares. BP used $4.9 billion of the cash consideration to acquire 5.66% of Rosneft shares from Rosneftegaz. Together with its existing 1.25% shareholding in the company, BP now holds a 19.75% stake in Rosneft, Russia’s largest oil company. See pages 11 and 30 for more information.

•

On 22 March, BP announced its intention to carry out a share repurchase programme with a total value of up to $8 billion over 12-18 months. As at 26 April, BP had bought back 120 million shares for a total amount of $834 million, including fees and stamp duty.

•

BP today announced a quarterly dividend of 9 cents per ordinary share ($0.54 per ADS), which is expected to be paid on 21 June 2013. The corresponding amount in sterling will be announced on 10 June 2013. 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 page 4 for definitions of RC profit and underlying RC profit.

(c)	See pages 20 and 21 respectively for further information on non-operating items and fair value accounting effects.

(d)	Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. See page 18 for further information.

The commentaries above and following should be read in conjunction with the cautionary statement on page 36.

Analysis of RC profit before interest and tax

and reconciliation to profit for the period


$ million	First quarter 2013			First quarter 2012
RC profit before interest and tax
Upstream		5,562			6,983
Downstream		1,647			859
TNK-BP(a)		12,500			1,064
Rosneft(b)		85			—
Other businesses and corporate		(467	)		(671	)
Gulf of Mexico oil spill response(c)		(22	)		30
Consolidation adjustment – UPII(d)		427			(541	)

RC profit before interest and tax		19,732			7,724
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(404	)		(405	)
Taxation on a RC basis		(2,653	)		(2,477	)
Non-controlling interests		(79	)		(61	)

RC profit attributable to BP shareholders		16,596			4,781

Inventory holding gains (losses)		406			1,437
Taxation (charge) credit on inventory holding gains and losses		(139	)		(451	)

Profit for the period attributable to BP shareholders		16,863			5,767

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See page 10 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See page 11 for further information.

(c)	See Note 2 on pages 25 – 29 for further information on the accounting for the Gulf of Mexico oil spill response.

(d)	The consolidation adjustment – unrealized profit in inventory (UPII) – for the first quarter of 2013 was impacted by lower levels of equity crude within inventory in Europe and the US at the end of the period.

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. See page 19 for further information on RC profit or loss.

Analysis of underlying RC profit before interest and tax


$ million	First quarter 2013			First quarter 2012
Underlying RC profit before interest and tax
Upstream		5,702			6,294
Downstream		1,641			927
TNK-BP		—			1,157
Rosneft		85			—
Other businesses and corporate		(461	)		(435	)
Consolidation adjustment – UPII		427			(541	)

Underlying RC profit before interest and tax		7,394			7,402
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(394	)		(399	)
Taxation on an underlying RC basis		(2,706	)		(2,291	)
Non-controlling interests		(79	)		(61	)

Underlying RC profit attributable to BP shareholders		4,215			4,651

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 20 and 21 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.

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 6 – 12 for the segments.

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.

Per share amounts


	First quarter 2013		First quarter 2012
Per ordinary share (cents)
Profit for the period		88.07		30.39
RC profit for the period		86.67		25.19
Underlying RC profit for the period		22.01		24.51
Per ADS (dollars)
Profit for the period		5.28		1.82
RC profit for the period		5.20		1.51
Underlying RC profit for the period		1.32		1.47

The amounts shown above are calculated based on the basic weighted average number of shares outstanding. See Note 7 on page 32 for details of the calculation of earnings per share.

Net debt ratio – net debt: net debt + equity


$ million	First quarter 2013			First quarter 2012
Gross debt		46,425			46,471
Less: fair value asset of hedges related to finance debt		1,083			1,224

		45,342			45,247
Less: cash and cash equivalents		27,679			14,267

Net debt		17,663			30,980

Equity		131,085			119,315
Net debt ratio		11.9	%		20.6	%

See Note 8 on page 33 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 9 cents per ordinary share expected to be paid in June. The corresponding amount in sterling will be announced on 10 June 2013, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 June 2013. Holders of American Depositary Shares (ADSs) will receive $0.54 per ADS. The dividend is due to be paid on 21 June 2013 to shareholders and ADS holders on the register on 10 May 2013. 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 2013		First quarter 2012
Dividends paid per ordinary share
cents		9.000		8.000
pence		6.001		5.096
Dividends paid per ADS (cents)		54.00		48.00

Scrip dividends
Number of shares issued (millions)		14.5		39.6
Value of shares issued ($ million)		101		306

Upstream


$ million	First quarter 2013		First quarter 2012
Profit before interest and tax		5,560		6,899
Inventory holding (gains) losses		2		84

RC profit before interest and tax		5,562		6,983
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		140		(689	)

Underlying RC profit before interest and tax(a)		5,702		6,294

(a)	See page 4 for information on underlying RC profit and see page 7 for a reconciliation to segment RC profit before interest and tax by region.

The replacement cost profit before interest and tax for the first quarter was $5,562 million compared with $6,983 million for the same period in 2012. The first quarter included a net non-operating loss of $80 million, primarily relating to impairment charges, compared with a net gain of $822 million in the same period last year, which was mainly due to gains on disposals. In the first quarter, fair value accounting effects had an unfavourable impact of $60 million compared with an unfavourable impact of $133 million in the same period last year.

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 $5,702 million, compared with $6,294 million in the same period last year. The result in the first quarter was impacted by lower production due to divestments and lower liquids realizations, partly offset by stronger gas marketing and trading activities.

Production for the quarter was 2,330mboe/d, 5% lower than the first quarter of 2012. After adjusting for the effects of divestments and entitlement impacts in our production-sharing agreements (PSAs), production increased by 1.6%. This primarily reflects major project delivery in Angola, the Gulf of Mexico, and the North Sea, and improved performance in Trinidad, partly offset by natural field decline across the portfolio.

Looking ahead we expect second quarter 2013 reported production to be lower than the first quarter, similar to the reduction we saw between the same periods last year, primarily as a result of planned major turnaround activity concentrated on higher margin assets in the Gulf of Mexico and the North Sea, and the continuing impact of our divestment programme mainly in the North Sea. We also expect costs to be higher in the second quarter compared with the first quarter, mainly due to seasonal turnaround activity.

We continued to make strategic progress. In January we announced the successful start-up of oil production from new facilities at the Valhall field in the southern part of the Norwegian North Sea. Production from Valhall is expected to continue to grow into the second half of 2013.

In February, we reached an agreement with Maersk Drilling to develop conceptual engineering designs for new advanced technology offshore drilling rigs which are intended to unlock the next frontier of deepwater oil and gas resources. The agreement is part of BP’s Project 20K^TM, a multi-year initiative to develop next-generation systems and tools for deepwater exploration and production.

In March, we announced that we have completed a successful flow test of the Itaipu-1A well offshore Brazil. The drill stem test was the latest activity in the ongoing appraisal programme at the BP-operated Itaipu discovery, indicating that commercially viable flow rates can be achieved from this pre-salt carbonate reservoir. The Itaipu-1A well is located in the deepwater sector of the Campos Basin, 125km offshore Brazil.

Also in March, together with our co-venturers, we announced the decision to proceed with a two-year appraisal programme to evaluate a potential third phase of the giant Clair field, west of the Shetland Islands. The initial commitment involves the drilling of five appraisal wells. Drilling on the first well has commenced.

In April in Azerbaijan, the Shah Deniz consortium began evaluating offers received from Nabucco Gas Pipeline International and Trans Adriatic Pipeline for transportation of Shah Deniz Stage 2 gas to Europe. The final selection decision on the European pipeline is expected to be made later this year.

Also in April we decided we will not move forward with the current plan for the Mad Dog Phase 2 project in the deepwater Gulf of Mexico. The current development plan is no longer as attractive as previously modelled, due largely to market conditions and industry cost inflation. BP, in collaboration with co-owners Union Oil Company of California, a subsidiary of Chevron Corp., and BHP Billiton Petroleum, is now reviewing existing plans and other options in order to evaluate how to develop the project.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

Upstream


$ million	First quarter 2013			First quarter 2012
Underlying RC profit before interest and tax
US		998			1,658
Non-US		4,704			4,636

		5,702			6,294

Non-operating items
US		(6	)		947
Non-US		(74	)		(125	)

		(80	)		822

Fair value accounting effects(a)
US		(40	)		(71	)
Non-US		(20	)		(62	)

		(60	)		(133	)

RC profit before interest and tax
US		952			2,534
Non-US		4,610			4,449

		5,562			6,983

Exploration expense
US		80			62
Non-US		242			198

		322			260

Production (net of royalties)(b)
Liquids (mb/d)(c)
US		366			454
Europe		115			123
Rest of World		712			671

		1,193			1,248

Of which equity-accounted entities		298			282

Natural gas (mmcf/d)
US		1,532			1,820
Europe		329			500
Rest of World		4,733			4,665

		6,593			6,985

Of which equity-accounted entities		398			398

Total hydrocarbons (mboe/d)(d)
US		631			768
Europe		171			209
Rest of World		1,528			1,475

		2,330			2,452

Of which equity-accounted entities		367			350

Average realizations(e)
Total liquids ($/bbl)		103.11			108.13
Natural gas ($/mcf)		5.52			4.68
Total hydrocarbons ($/boe)		65.11			64.02

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

(b)	Includes BP’s share of production of equity-accounted entities in the Upstream segment.

(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.

Downstream


$ million	First quarter 2013			First quarter 2012
Profit before interest and tax		2,055			2,354
Inventory holding (gains) losses		(408	)		(1,495	)

RC profit before interest and tax		1,647			859
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		(6	)		68

Underlying RC profit before interest and tax(a)		1,641			927

(a)	See page 4 for information on underlying RC profit and see page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.

The replacement cost profit before interest and tax for the first quarter was $1,647 million, compared with $859 million for the same period in 2012.

The first-quarter result included a net non-operating gain of $19 million, compared with a net charge of $106 million a year ago (see pages 9 and 20 for further information on non-operating items). Fair value accounting effects had an unfavourable impact of $13 million for the first quarter, compared with a favourable impact of $38 million for the first quarter of 2012.

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 $1,641 million, compared with $927 million a year ago.

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

The fuels business delivered an underlying replacement cost profit before interest and tax of $1,237 million for the first quarter, compared with $490 million for the same period in 2012, principally due to a significant improvement in the supply and trading contribution. In addition, the business delivered strong operations with Solomon availability at 95.1%, which allowed us to capture the more favourable refining environment, particularly in the US Midwest where heavy Canadian crude grades were significantly discounted to other grades for most of the quarter. These benefits were partly offset by the impact of the planned outage of the largest crude unit at our Whiting refinery as part of the Whiting refinery modernization project. The new crude unit remains on track for commissioning in the second quarter of 2013, enabling the start-up of the Whiting refinery modernization project in the second half of the year.

Late in the first quarter, heavy Canadian crude differentials narrowed significantly and to date in the second quarter have remained at these levels.

On 1 February 2013 we completed the sale of our Texas City refinery and a portion of its retail and logistics network in the south-eastern US to Marathon Petroleum Corporation. This divestment was the principal factor contributing to the decline in refining throughputs in the quarter of over 200mb/d compared with the same quarter last year and the fourth quarter of 2012.

In March 2013, BP-Husky Refining LLC successfully started up a new naphtha reformer at the Toledo refinery, which is intended to improve the plant’s efficiency and competitiveness.

We continue to expect the sale of the Carson refinery in California, and related marketing and logistics assets in the region, to complete by mid-2013, subject to regulatory approvals (see Note 4 on page 31 for further details).

The lubricants business delivered an underlying replacement cost profit before interest and tax of $345 million in the first quarter, compared with $325 million in the same period last year. This reflects continued robust performance supported by growth in the share of sales of our premium Castrol brands and strong profitability from growth markets.

The petrochemicals business delivered an underlying replacement cost profit before interest and tax of $59 million in the first quarter of 2013 compared with $112 million in the same period last year. This decrease was due to the continued difficult margin environment, which also led us to reduce our production particularly in Asia. Production volumes compared with the same quarter last year were also impacted by the sale of our petrochemicals plant in Malaysia in October 2012. To date in the second quarter petrochemicals margins have been lower relative to levels seen in the first quarter and we expect them to remain subdued during 2013.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

Downstream


$ million	First quarter 2013			First quarter 2012
Underlying RC profit before interest and tax – by region
US		750			289
Non-US		891			638

		1,641			927

Non-operating items
US		28			(88	)
Non-US		(9	)		(18	)

		19			(106	)

Fair value accounting effects(a)
US		(65	)		(43	)
Non-US		52			81

		(13	)		38

RC profit before interest and tax
US		713			158
Non-US		934			701

		1,647			859

Underlying RC profit before interest and tax – by business(b)(c)
Fuels		1,237			490
Lubricants		345			325
Petrochemicals		59			112

		1,641			927

Non-operating items and fair value accounting effects(a)
Fuels		11			(68	)
Lubricants		(5	)		—
Petrochemicals		—			—

		6			(68	)

RC profit before interest and tax(b)(c)
Fuels		1,248			422
Lubricants		340			325
Petrochemicals		59			112

		1,647			859


BP average refining marker margin (RMM) ($/bbl)(d)		17.4			14.6

Refinery throughputs (mb/d)
US		937			1,218
Europe		806			775
Rest of World		322			277

		2,065			2,270

Refining availability (%)(e)		95.1			94.9

Marketing sales of refined products (mb/d)
US		1,402			1,349
Europe(f)		1,158			1,192
Rest of World		557			574

		3,117			3,115
Trading/supply sales of refined products		2,308			2,380

Total sales volumes of refined products		5,425			5,495

Petrochemicals production (kte)
US		1,076			1,078
Europe(c)		1,014			1,011
Rest of World		1,417			1,817

		3,507			3,906

(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 21.

(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. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate. In 2013 BP updated the RMM methodology; prior periods have been restated.

(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)	A minor amendment has been made to the first quarter 2012.

TNK-BP


$ million	First quarter 2013			First quarter 2012
Profit before interest and tax(a)		12,500			1,090
Inventory holding (gains) losses		—			(26	)

RC profit before interest and tax		12,500			1,064
Net charge (credit) for non-operating items		(12,500	)		93

Underlying RC profit before interest and tax(b)		—			1,157

(a)	The TNK-BP segment includes equity-accounted earnings from associates, in which all amounts shown relate to BP’s 50% share in TNK-BP, as follows:


Profit before interest and tax	—	1,481
Finance costs	—	(36	)
Taxation	—	(231	)
Non-controlling interests	—	(124	)

Net income (BP share)	—	1,090

Inventory holding (gains) losses, net of tax	—	(26	)
Net charge (credit) for non-operating items, net of tax	—	93

Net income (BP share) on an underlying RC basis(b)	—	1,157

(b)	See page 4 for information on underlying RC profit.


	First quarter 2013		First quarter 2012
Production (net of royalties) (BP share)(c)
Crude oil (mb/d)		758		879
Natural gas (mmcf/d)		745		813
Total hydrocarbons (mboe/d)(d)		886		1,019

(c)	BP continued to report its share of TNK-BP’s production and reserves following the agreement to sell its 50% share to Rosneft until the sale completed on 21 March 2013.

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

Replacement cost profit before interest and tax(e) for the first quarter was $12,500 million, compared with $1,064 million for the same period in 2012. The first-quarter result reflects the non-operating gain on disposal of BP’s interest in TNK-BP. See Note 3 on page 30 for more information on the disposal of TNK-BP. First quarter 2012 included a non-operating impairment charge of $93 million.

No equity-accounted earnings are included in the TNK-BP segment result for the first quarter 2013 because our investment was classified as an asset held for sale from 22 October 2012. Accordingly, underlying replacement cost profit before interest and tax for the segment in the first quarter was nil, compared with $1,157 million a year ago.

Total estimated hydrocarbon production for the first quarter was 886mboe/d which represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full quarter. This was 13% lower than production for the same period in 2012, primarily due to completion of the sale transaction on 21 March 2013.

(e)	Under equity accounting, BP’s share of TNK-BP’s earnings after interest and tax in 2012 was included in the BP group income statement within profit before interest and tax.

Rosneft


$ million	First quarter 2013		First quarter 2012
Profit before interest and tax(a)(b)		85		—
Inventory holding (gains) losses		—		—

RC profit before interest and tax(c)		85		—
Net charge (credit) for non-operating items		—		—

Underlying RC profit before interest and tax(c)		85		—

(a)	The Rosneft segment includes equity-accounted earnings from associates, representing BP’s 19.75% share in Rosneft.

(b)	BP estimate based on Rosneft and TNK-BP historical financial data, adjusted for oil and gas prices and exchange rates.

(c)	Assumed to be the same as profit before interest and tax.


	First quarter 2013		First quarter 2012
Production (net of royalties) (BP share)(d)
Crude oil (mb/d)		102		—
Natural gas (mmcf/d)		89		—
Total hydrocarbons (mboe/d)(e)		117		—

(d)	BP estimates based on available information from Rosneft and TNK-BP and, in the case of natural gas, Rosneft historical information.

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

Balance sheet


$ million	31 March 2013		31 December 2012
Investments in associates		12,970		—

With effect from 21 March 2013, the completion date of the sale and purchase agreements with Rosneft and Rosneftegaz described in Note 3, BP’s 19.75% shareholding in Rosneft meets the criteria to be accounted for using the equity method and is reported as a separate operating segment under IFRS. See Note 3 on page 30 for further information.

Inventory holding gains or losses and non-operating items in respect of the Rosneft segment have not been reported for the first quarter but we intend to begin reporting this information later this year. Replacement cost profit before interest and tax(f) for the Rosneft segment in the first quarter, which has been assumed to be the same as profit before interest and tax, was $85 million, reflecting BP’s equity-accounted share of Rosneft’s earnings from 21 March as estimated by BP.

Total hydrocarbon production for the first quarter as estimated by BP was 117mboe/d. This represents BP’s 19.75% share of Rosneft’s estimated production from 21 March to 31 March, averaged over the full quarter.

The operational and financial information of the Rosneft segment presented above is based on BP’s estimates of Rosneft’s and TNK-BP’s operational and financial results for the period ended 31 March 2013. Actual results may differ from these estimates. Any adjustments to this operational and financial information based on BP’s review of actual reported results will be reflected in BP’s second quarter results.

(f)	Under equity accounting, BP’s share of Rosneft’s earnings after interest and tax is included in the BP group income statement within profit before interest and tax.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

Other businesses and corporate


$ million	First quarter 2013			First quarter 2012
Profit (loss) before interest and tax		(467	)		(671	)
Inventory holding (gains) losses		—			—

RC profit (loss) before interest and tax		(467	)		(671	)
Net charge (credit) for non-operating items		6			236

Underlying RC profit (loss) before interest and tax(a)		(461	)		(435	)


Underlying RC profit (loss) before interest and tax(a)
US		(121	)		(165	)
Non-US		(340	)		(270	)

		(461	)		(435	)

Non-operating items
US		(4	)		(142	)
Non-US		(2	)		(94	)

		(6	)		(236	)

RC profit (loss) before interest and tax
US		(125	)		(307	)
Non-US		(342	)		(364	)

		(467	)		(671	)

(a)	See page 4 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 $467 million, compared with $671 million for the same period last year.

The first-quarter result included a net non-operating charge of $6 million, compared with a net non-operating charge of $236 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the first quarter was $461 million, compared with $435 million for the same period last year.

In Alternative Energy, net wind generation capacity(b) at the end of the first quarter was 1,590MW (2,619MW gross), compared with 1,274MW (1,988MW gross) at the end of the same period a year ago. BP’s net share of wind generation from our US wind farms for the first quarter was 1,144GWh (2,063GWh gross), compared with 1,024GWh (1,675GWh gross) in the same period a year ago. BP intends to market its wind business for sale.

In our biofuels business, the first quarter is the inter-harvest period in Brazil so the mills were on planned turnaround and there was no production. In the UK, the Vivergo joint venture (BP 47%) was commissioned in late 2012 and commenced start-up during the first quarter 2013.

(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.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

Gulf of Mexico oil spill

Financial update

BP continues to support completing the operational clean-up response, facilitating economic restoration through claims processes, and facilitating environmental restoration through natural resource damage assessment and early restoration projects relating to the Gulf of Mexico oil spill.

The replacement cost loss before interest and tax for the first quarter was $22 million, compared with a $30 million profit for the same period last year. The first-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization and adjustments to provisions. The cumulative pre-tax charge recognized to date amounts to $42.2 billion.

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Contingent liabilities in Note 2 on page 29, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the accident could also heighten the impact of the other risks to which the group is exposed, as further described under Risk factors on pages 38 – 44 of BP Annual Report and Form 20-F 2012.

Trust update

During the first quarter, $778 million was paid out of the Deepwater Horizon Oil Spill Trust (Trust) and qualified settlement funds (QSFs) toward provisions, including $680 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $98 million for natural resource damage assessment and early restoration. In addition, $318 million was paid out to claimants from the seafood compensation fund, for which the related provision and reimbursement asset had been previously derecognized upon funding of the QSF. At the end of the first quarter, the cash balances in the Trust and the QSFs amounted to $9.4 billion, with $20 billion contributed by BP and $10.6 billion paid out.

As at 31 March 2013, the cumulative charges for provisions to be paid from the Trust and the associated reimbursement asset recognized amounted to $18.3 billion. This represents an increase of $492 million for the quarter primarily for business economic loss claims received and processed by the DHCSSP. A further $1.7 billion could be provided in subsequent periods for items covered by the Trust, with no net impact on the income statement. The amount provided does not include any amounts for future business economic loss claims not yet received or processed by the DHCSSP as this liability cannot currently be estimated reliably. See Note 2 on pages 26 – 27 and Legal proceedings on pages 34 – 35 for further details.

Legal proceedings and investigations

Phase 1 of the MDL (Multi-District Litigation) 2179 trial took place in federal court in New Orleans, Louisiana between 25 February and 17 April. The presentation of evidence in the first trial phase addressed issues arising out of the conduct of various parties allegedly relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on the Deepwater Horizon on 20 April 2010, the sinking of the vessel on 22 April 2010 and the initiation of the release of oil from the Deepwater Horizon or the Macondo well during those time periods, including whether BP or any other party was grossly negligent. BP does not know when the court will rule on the issues presented in phase 1 of the trial. Phase 2 will consider the issues of source control efforts and volume of oil spilled as a result of the accident. For further details, see Legal proceedings on pages 34 – 35.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

Group income statement


$ million	First quarter 2013			First quarter 2012
Sales and other operating revenues (Note 5)		94,107			94,878
Earnings from joint ventures – after interest and tax		125			151
Earnings from associates – after interest and tax		284			1,260
Interest and other income		157			195
Gains on sale of businesses and fixed assets		12,541			933

Total revenues and other income		107,214			97,417
Purchases		71,661			72,301
Production and manufacturing expenses(a)		6,868			6,721
Production and similar taxes (Note 6)		1,995			2,346
Depreciation, depletion and amortization		3,197			3,261
Impairment and losses on sale of businesses and fixed assets		110			140
Exploration expense		322			260
Distribution and administration expenses		2,954			3,128
Fair value (gain) loss on embedded derivatives		(31	)		99

Profit before interest and taxation		20,138			9,161
Finance costs(a)		282			269
Net finance expense relating to pensions and other post-retirement benefits		122			136

Profit before taxation		19,734			8,756
Taxation(a)		2,792			2,928

Profit for the period		16,942			5,828

Attributable to
BP shareholders		16,863			5,767
Non-controlling interests		79			61

		16,942			5,828

Earnings per share – cents (Note 7)
Profit for the period attributable to BP shareholders
Basic		88.07			30.39
Diluted		87.61			29.97

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

Group statement of comprehensive income


$ million	First quarter 2013			First quarter 2012
Profit for the period		16,942			5,828

Other comprehensive income (expense)
Items that may be reclassified subsequently to profit or loss
Currency translation differences		(587	)		575
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sales of businesses and fixed assets		—			—
Available-for-sale investments marked to market		(172	)		64
Available-for-sale investments reclassified to the income statement		(523	)		—
Cash flow hedges marked to market(a)		(2,141	)		75
Cash flow hedges reclassified to the income statement		—			2
Cash flow hedges reclassified to the balance sheet		3			5
Share of items relating to equity-accounted entities, net of tax		33			209
Income tax relating to items that may be reclassified		169			(32	)

		(3,218	)		898

Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset		(50	)		1,609
Share of items relating to equity-accounted entities, net of tax		—			(6	)
Income tax relating to items that will not be reclassified		1			(457	)

		(49	)		1,146

Other comprehensive income (expense)		(3,267	)		2,044

Total comprehensive income		13,675			7,872

Attributable to
BP shareholders		13,600			7,805
Non-controlling interests		75			67

		13,675			7,872

(a)	First quarter 2013 includes $2,061 million loss relating to the contracts to acquire Rosneft shares. See Note 3 for further information.

Group statement of changes in equity


$ million	BP shareholders’ equity			Non-controlling interests			Total equity
At 1 January 2013		118,546			1,206			119,752


Total comprehensive income		13,600			75			13,675
Dividends		(1,621	)		(66	)		(1,687	)
Repurchases of ordinary share capital		(850	)		—			(850	)
Share-based payments (net of tax)		176			—			176
Transactions involving non-controlling interests		—			19			19

At 31 March 2013		129,851			1,234			131,085


$ million	BP shareholders’ equity			Non-controlling interests			Total equity
At 1 January 2012		111,568			1,017			112,585


Total comprehensive income		7,805			67			7,872
Dividends		(1,211	)		(1	)		(1,212	)
Share-based payments (net of tax)		59			—			59
Transactions involving non-controlling interests		—			11			11

At 31 March 2012		118,221			1,094			119,315

Group balance sheet


$ million	31 March 2013		31 December 2012
Non-current assets
Property, plant and equipment		126,848		125,331
Goodwill		11,940		12,190
Intangible assets		24,962		24,632
Investments in joint ventures		8,701		8,614
Investments in associates		16,077		2,998
Other investments		1,407		2,704

Fixed assets		189,935		176,469
Loans		586		642
Trade and other receivables		5,722		5,961
Derivative financial instruments		4,340		4,294
Prepayments		924		830
Deferred tax assets		787		874
Defined benefit pension plan surpluses		13		12

		202,307		189,082

Current assets
Loans		227		247
Inventories		28,628		28,203
Trade and other receivables		41,649		37,611
Derivative financial instruments		2,967		4,507
Prepayments		1,262		1,091
Current tax receivable		548		456
Other investments		596		319
Cash and cash equivalents		27,679		19,635

		103,556		92,069

Assets classified as held for sale (Note 4)		4,947		19,315

		108,503		111,384

Total assets		310,810		300,466

Current liabilities
Trade and other payables		49,787		46,673
Derivative financial instruments		2,503		2,658
Accruals		6,688		6,875
Finance debt		8,901		10,033
Current tax payable		3,083		2,503
Provisions		6,908		7,587

		77,870		76,329
Liabilities directly associated with assets classified as held for sale (Note 4)		722		846

		78,592		77,175

Non-current liabilities
Other payables		4,888		2,292
Derivative financial instruments		2,706		2,723
Accruals		498		491
Finance debt		37,524		38,767
Deferred tax liabilities		16,044		15,243
Provisions		26,344		30,396
Defined benefit pension plan and other post-retirement benefit plan deficits		13,129		13,627

		101,133		103,539

Total liabilities		179,725		180,714

Net assets		131,085		119,752

Equity
BP shareholders’ equity		129,851		118,546
Non-controlling interests		1,234		1,206

		131,085		119,752

Condensed group cash flow statement


$ million	First quarter 2013			First quarter 2012
Operating activities
Profit before taxation		19,734			8,756
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		3,369			3,341
Impairment and (gain) loss on sale of businesses and fixed assets		(12,431	)		(793	)
Earnings from equity-accounted entities, less dividends received		(200	)		(481	)
Net charge for interest and other finance expense, less net interest paid		172			136
Share-based payments		46			34
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(284	)		(160	)
Net charge for provisions, less payments		197			163
Movements in inventories and other current and non-current assets and liabilities(a)		(5,345	)		(6,200	)
Income taxes paid		(1,291	)		(1,390	)

Net cash provided by operating activities		3,967			3,406

Investing activities
Capital expenditure		(5,729	)		(5,447	)
Investment in joint ventures		(51	)		(226	)
Investment in associates		(4,883	)		(23	)
Proceeds from disposal of fixed assets		16,780			1,267
Proceeds from disposal of businesses, net of cash disposed		1,501			71
Proceeds from loan repayments		22			50

Net cash provided by (used in) investing activities		7,640			(4,308	)

Financing activities
Net issue (repurchase) of shares		55			21
Proceeds from long-term financing		63			3,813
Repayments of long-term financing		(288	)		(2,416	)
Net increase (decrease) in short-term debt		(1,491	)		669
Dividends paid – BP shareholders		(1,622	)		(1,212	)
– non-controlling interests		(31	)		(1	)

Net cash provided by (used in) financing activities		(3,314	)		874

Currency translation differences relating to cash and cash equivalents		(249	)		118

Increase (decrease) in cash and cash equivalents		8,044			90

Cash and cash equivalents at beginning of period		19,635			14,177
Cash and cash equivalents at end of period		27,679			14,267

(a) Includes
Inventory holding (gains) losses		(407	)		(1,410	)
Fair value (gain) loss on embedded derivatives		(31	)		99
Movements related to Gulf of Mexico oil spill response		(828	)		(1,861	)

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.

Capital expenditure and acquisitions


$ million	First quarter 2013		First quarter 2012
By business
Upstream
US(a)		1,539		1,646
Non-US		2,957		2,988

		4,496		4,634

Downstream
US		839		697
Non-US		215		212

		1,054		909

Rosneft
Non-US(b)		11,941		—

		11,941		—

Other businesses and corporate
US		24		158
Non-US		136		139

		160		297

		17,651		5,840

By geographical area
US(a)		2,402		2,501
Non-US(b)		15,249		3,339

		17,651		5,840

Included above:
Acquisitions and asset exchanges		—		10
Other inorganic capital expenditure(a)(b)		11,941		311

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

(b)	First quarter 2013 includes $11,941 million related to our investment in Rosneft – see Note 3 for further information.

Exchange rates


	First quarter 2013		First quarter 2012
US dollar/sterling average rate for the period		1.55		1.57
US dollar/sterling period-end rate		1.51		1.59
US dollar/euro average rate for the period		1.32		1.31
US dollar/euro period-end rate		1.28		1.33

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation


$ million	First quarter 2013			First quarter 2012
Upstream		5,562			6,983
Downstream		1,647			859
TNK-BP(a)		12,500			1,064
Rosneft(b)		85			—
Other businesses and corporate		(467	)		(671	)

		19,327			8,235
Gulf of Mexico oil spill response		(22	)		30
Consolidation adjustment – UPII		427			(541	)

RC profit before interest and tax		19,732			7,724
Inventory holding gains (losses)
Upstream		(2	)		(84	)
Downstream		408			1,495
TNK-BP (net of tax)		—			26

Profit before interest and tax		20,138			9,161
Finance costs		282			269
Net finance expense relating to pensions and other post-retirement benefits		122			136

Profit before taxation		19,734			8,756


RC profit before interest and tax
US		1,771			1,935
Non-US		17,961			5,789

		19,732			7,724

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See TNK-BP on page 10 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 11 for further information.

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 replacement cost (RC) profit or loss before interest and tax and underlying RC profit or loss before interest and tax (see page 4 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.

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.

Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.

Management believes this information is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this information.

Non-operating items(a)


$ million	First quarter 2013			First quarter 2012
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets		(102	)		928
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		—			—
Fair value gain (loss) on embedded derivatives		31			(100	)
Other		(9	)		(6	)

		(80	)		822

Downstream
Impairment and gain (loss) on sale of businesses and fixed assets		34			(85	)
Environmental and other provisions		(9	)		—
Restructuring, integration and rationalization costs		(2	)		(12	)
Fair value gain (loss) on embedded derivatives		—			—
Other		(4	)		(9	)

		19			(106	)

TNK-BP
Impairment and gain (loss) on sale of businesses and fixed assets		12,500			(93	)
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		—			—
Fair value gain (loss) on embedded derivatives		—			—
Other		—			—

		12,500			(93	)

Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets		(1	)		(50	)
Environmental and other provisions		—			(15	)
Restructuring, integration and rationalization costs		(2	)		—
Fair value gain (loss) on embedded derivatives		—			1
Other(b)		(3	)		(172	)

		(6	)		(236	)

Gulf of Mexico oil spill response		(22	)		30

Total before interest and taxation		12,411			417
Finance costs(c)		(10	)		(6	)

Total before taxation		12,401			411
Taxation credit (charge)(d)		23			(226	)

Total after taxation for period		12,424			185

(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 7, 9 and 12.

(b)	First quarter 2012 includes $161 million relating to our exit from the solar business.

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

(d)

For the Gulf of Mexico oil spill, tax is based on US statutory tax rates, except for non-deductible items. For the gain on disposal of TNK-BP in the first quarter 2013 there is no tax arising. For other items reported by consolidated subsidiaries, tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the items noted above and equity-accounted earnings). Non-operating items arising within the equity-accounted earnings of TNK-BP are reported net of tax.

Non-GAAP information on fair value accounting effects


$ million	First quarter 2013			First quarter 2012
Favourable (unfavourable) impact relative to management’s measure of performance
Upstream		(60	)		(133	)
Downstream		(13	)		38

		(73	)		(95	)
Taxation credit (charge)(a)		30			40

		(43	)		(55	)

(a)	Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for Gulf of Mexico oil spill and equity-accounted earnings, and for the first quarter 2013, the gain on disposal of TNK-BP).

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.


$ million	First quarter 2013			First quarter 2012
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		5,622			7,116
Impact of fair value accounting effects		(60	)		(133	)

Replacement cost profit before interest and tax		5,562			6,983

Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		1,660			821
Impact of fair value accounting effects		(13	)		38

Replacement cost profit before interest and tax		1,647			859

Total group
Profit before interest and tax adjusted for fair value accounting effects		20,211			9,256
Impact of fair value accounting effects		(73	)		(95	)

Profit before interest and tax		20,138			9,161

Realizations and marker prices


	First quarter 2013		First quarter 2012
Average realizations(a)
Liquids ($/bbl)(b)
US		96.11		99.39
Europe		107.15		116.96
Rest of World		108.04		114.79
BP Average		103.11		108.13

Natural gas ($/mcf)
US		2.92		2.24
Europe		9.78		7.83
Rest of World		6.12		5.34
BP Average		5.52		4.68

Total hydrocarbons ($/boe)
US		62.94		62.94
Europe		90.93		87.50
Rest of World		62.22		60.30
BP Average		65.11		64.02

Average oil marker prices ($/bbl)
Brent		112.57		118.60
West Texas Intermediate		94.29		103.10
Alaska North Slope		110.97		118.47
Mars		109.10		115.50
Urals (NWE – cif)		110.53		116.87
Russian domestic oil		55.24		58.22

Average natural gas marker prices
Henry Hub gas price ($/mmBtu)(c)		3.34		2.72
UK Gas – National Balancing Point (p/therm)		73.83		59.38

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

(b)	Crude oil and natural gas liquids.

(c)	Henry Hub First of Month Index.

Notes

1.	Basis of preparation

(a) Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’.

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2012 included in BP Annual Report and Form 20-F 2012.

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.

To the greatest extent possible, 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 2013. These accounting policies differ from those used in BP Annual Report and Form 20-F 2012 as noted below.

Segmental reporting

On 21 March 2013, BP completed sale and purchase agreements with Rosneft and Rosneftegaz – the Russian state-owned parent company of Rosneft – for the sale of BP’s 50% interest in TNK-BP to Rosneft, and for BP’s further investment in Rosneft. With effect from that date, BP’s 19.75% shareholding in Rosneft is accounted for using the equity method and is reported as a separate operating segment.

Comparative group income statement and group balance sheet

In addition to the changes made to the comparative data presented in this report as a result of the adoption of the amended IAS 19 and the new standard IFRS 11 (as detailed below), the comparative group balance sheet as at 31 December 2012 also reflects an adjustment, made subsequent to releasing our unaudited fourth quarter and full year 2012 results announcement dated 5 February 2013, which was included in the balance sheet approved by the board of directors on 6 March 2013 and published in BP Annual Report and Form 20-F 2012. The difference relates to an adjustment of $0.8 billion that was made to decrease provisions relating to the Gulf of Mexico oil spill as at 31 December 2012, with a corresponding decrease in the reimbursement asset. There was no impact on profit or loss for the year. A further adjustment was made to the group income statement to correct a $4.7 billion understatement of revenue and purchases for the year ended 31 December 2012. There was no impact on profit or loss for the year. For further information, see BP Annual Report and Form 20-F 2012.

New or amended International Financial Reporting Standards adopted

BP adopted several new or amended accounting standards issued by the IASB with effect from 1 January 2013.

IFRS 10 ‘Consolidated Financial Statements’, IFRS 11 ‘Joint Arrangements’ and IFRS 12 ‘Disclosure of Interests in Other Entities’ were issued in May 2011. The main impact of this suite of new standards for BP is that certain of the group’s jointly controlled entities, which were previously being equity accounted, now fall under the definition of a joint operation under IFRS 11 and thus we now recognize the group’s assets, liabilities, revenue and expenses relating to these arrangements. Whilst the effect on the group’s reported income and net assets as a result of the new requirements is not material, the change impacts certain of the component lines of the income statement, balance sheet and cash flow statement. On the balance sheet, there is a reduction in investments in joint ventures of approximately $7 billion as at 31 December 2012, which is replaced with the recognition (on the relevant line items, principally intangible assets and property, plant and equipment) of our share of the assets and liabilities relating to these arrangements.

An amended version of IAS 19 ‘Employee Benefits’ was issued in June 2011. The main impact for BP is that the expense for defined benefit pension and other post-retirement benefit plans now includes a net interest income or expense, which is calculated by applying the discount rate used for measuring the obligation and applying that to the net defined benefit asset or liability. This means that the expected return on assets credited to profit or loss (previously calculated based on the expected long-term return on pension assets) is now based on a lower corporate bond rate, the same rate that is used to discount the pension liability. Under the amended IAS 19, net finance expense (income) relating to pensions and other post-retirement benefits and profit before tax was $767 million and $250 million lower for full year 2012 and the first quarter of 2013 respectively, with corresponding pre-tax increases in other comprehensive income. There is no impact on cash flows or on the balance sheet at 31 December 2012 or 31 March 2013.

Notes

1.	Basis of preparation (continued)

The accounting policies which will be used in preparing BP Annual Report and Form 20-F 2013 which differ from those used in BP Annual Report and Form 20-F 2012 are shown in full in BP Financial and Operating Information 2008-2012 available on bp.com/investors.

There are no other new or amended standards or interpretations adopted with effect from 1 January 2013 that have a significant effect on the financial statements.

(b) Impact of the adoption of new or amended International Financial Reporting Standards

The following tables set out the adjustments made to certain selected line items of the previously reported comparative amounts as a result of the adoption of the amended IAS 19 ‘Employee Benefits’ and the new standard IFRS 11 ‘Joint Arrangements’.

Annual restated information for 2012 is shown in BP Financial and Operating Information 2008-2012 available on bp.com/investors. Full restated quarterly information for 2012 will be available in the quarterly supplement of BP Financial and Operating Information 2008-2012 on bp.com/investors in early May 2013.


	First quarter 2012						Second quarter 2012						Third quarter 2012						Fourth quarter 2012						Full year 2012
Selected lines only $ million	As reported			As restated			As reported			As restated			As reported			As restated			As reported			As restated			As reported			As restated
(except per share amounts)
Income statement
Earnings from joint ventures – after interest and tax		290			151			88			(36	)		235			107			131			38			744			260
Net finance income (expense) relating to pensions and other post-retirement benefits		53			(136	)		55			(137	)		58			(133	)		35			(160	)		201			(566	)
Profit (loss) for the period		5,976			5,828			(1,340	)		(1,474	)		5,500			5,347			1,680			1,550			11,816			11,251

Earnings per share
Basic (cents)		31.17			30.39			(7.29	)		(7.99	)		28.54			27.74			8.48			7.80			60.86			57.89
Diluted (cents)		30.74			29.97			(7.29	)		(7.99	)		28.39			27.59			8.43			7.75			60.45			57.50

Replacement cost profit (loss) before interest and tax
Upstream
US		2,534			2,534			(1,584	)		(1,584	)		1,178			1,178			4,790			4,790			6,918			6,918
Non-US		4,445			4,449			4,497			4,497			3,732			3,729			2,882			2,898			15,556			15,573
		6,979			6,983			2,913			2,913			4,910			4,907			7,672			7,688			22,474			22,491
Downstream
US		158			158			(1,984	)		(1,984	)		1,106			1,106			478			478			(242	)		(242	)
Non-US		698			701			248			252			1,297			1,302			845			851			3,088			3,106
		856			859			(1,736	)		(1,732	)		2,403			2,408			1,323			1,329			2,846			2,864
Group
US		1,935			1,935			(4,246	)		(4,246	)		1,422			1,422			1,069			1,069			180			180
Non-US		5,781			5,789			4,967			4,971			5,956			5,959			3,443			3,464			20,147			20,183
		7,716			7,724			721			725			7,378			7,381			4,512			4,533			20,327			20,363

Balance sheet
Property, plant and equipment		119,991			124,379			117,565			121,960			119,687			124,288			120,488			125,331			120,488			125,331
Intangible assets		22,000			22,570			22,345			22,919			23,184			23,766			24,041			24,632			24,041			24,632
Investments in joint ventures		15,862			8,578			15,672			8,532			15,920			8,843			15,724			8,614			15,724			8,614
Net assets		119,220			119,315			113,323			113,415			118,773			118,883			119,620			119,752			119,620			119,752

Cash flow statement
Profit (loss) before taxation		8,923			8,756			(1,815	)		(1,989	)		8,239			8,064			3,462			3,300			18,809			18,131
Net cash provided by (used in) operating activities		3,367			3,406			4,403			4,448			6,287			6,246			6,340			6,379			20,397			20,479
Net cash provided by (used in) investing activities		(4,329	)		(4,308	)		(3,462	)		(3,473	)		(4,672	)		(4,702	)		(499	)		(592	)		(12,962	)		(13,075	)
Increase (decrease) in cash and cash equivalents		25			90			789			808			1,160			1,099			3,507			3,461			5,481			5,458

Notes

2.	Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur various costs and has also recognized liabilities for future costs. The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2012 – Financial statements – Note 2, Note 36 and Note 43 and Legal proceedings on pages 162 – 169 and on pages 34 – 35 of this report.

The group income statement includes a pre-tax charge of $32 million for the first quarter in relation to the Gulf of Mexico oil spill. The cumulative pre-tax income statement charge since the incident amounts to $42,239 million.

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information see Contingent liabilities below.

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further described under Risk factors on pages 38 – 44 of BP Annual Report and Form 20-F 2012.

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 page 13. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.


$ million	First quarter 2013			First quarter 2012
Income statement
Production and manufacturing expenses		22			(30	)

Profit (loss) before interest and taxation		(22	)		30
Finance costs		10			6

Profit (loss) before taxation		(32	)		24
Taxation		(5	)		(26	)

Profit (loss) for the period		(37	)		(2	)


	31 March 2013						31 December 2012
$ million	Total			Of which: amount related to the trust fund			Total			Of which: amount related to the trust fund
Balance sheet
Current assets
Trade and other receivables		4,082			4,082			4,239			4,178
Current liabilities
Trade and other payables		(1,082	)		(1	)		(522	)		(22	)
Provisions		(4,810	)		—			(5,449	)		—

Net current assets (liabilities)		(1,810	)		4,081			(1,732	)		4,156

Non-current assets
Other receivables		2,074			2,074			2,264			2,264
Non-current liabilities
Other payables		(3,160	)		—			(175	)		—
Provisions		(5,984	)		—			(9,751	)		—
Deferred tax		3,782			—			4,002			—

Net non-current assets (liabilities)		(3,288	)		2,074			(3,660	)		2,264

Net assets (liabilities)		(5,098	)		6,155			(5,392	)		6,420

Notes

2.	Gulf of Mexico oil spill (continued)


$ million	First quarter 2013			First quarter 2012
Cash flow statement – Operating activities
Profit (loss) before taxation		(32	)		24
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		10			6
Net charge for provisions, less payments		304			85
Movements in inventories and other current and non-current assets and liabilities		(828	)		(1,861	)

Pre-tax cash flows		(546	)		(1,746	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $331 million in the first quarter of 2013. For the first quarter of 2012, the amount was an outflow of $1,208 million.

Trust fund

BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. The Trust is available to fund the qualified settlement funds (QSFs) established under the terms of the settlement agreements (comprising the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) and the Medical Benefits Class Action Settlement) with the Plaintiffs’ Steering Committee (PSC) administered through the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), and the separate BP claims programme – see below for further information. Fines and penalties are not covered by the trust fund.

The funding of the Trust was completed in the fourth quarter of 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income statement.

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 2013. The increase in the provision of $492 million relates principally to business economic loss claims processed by the DHCSSP for which eligibility notices have been issued. The amount of the reimbursement asset at 31 March 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund – see below.


$ million	First quarter 2013
Opening balance		6,442
Increase in provision for items covered by the trust fund		492
Amounts paid directly by the trust fund		(778	)

At 31 March 2013		6,156

Of which – current		4,082
– non-current		2,074

Any increases in estimated future expenditure 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 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $18,288 million. Thus, a further $1,712 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. To the extent that there is any additional liability in excess of this amount regarding claims under the Oil Pollution Act of 1990 (OPA 90), claims that are currently administered by the DHCSSP, or otherwise, including the various claims described in Legal proceedings on pages 34 – 35 in this report and on pages 162 – 171 of BP Annual Report and Form 20-F 2012, such amounts would be paid by BP directly and expensed to the income statement at that time. Information on those items that currently cannot be reliably estimated is provided under Provisions below.

Notes

2.	Gulf of Mexico oil spill (continued)

Under the terms of the EPD Settlement Agreement with the PSC, several QSFs were established in 2012. These QSFs each relate to specific elements of the agreement, have been and will continue to be funded through payments from the Trust, and are available to make payments to claimants in accordance with those elements of the agreement.

As at 31 March 2013, the aggregate cash balances in the Trust and the QSFs amounted to $9,396 million, including $1,529 million remaining in the seafood compensation fund which is yet to be distributed.

The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012. In addition, a separate BP claims programme began processing claims from claimants not in the Economic and Property Damages class as determined by the EPD Settlement Agreement or who have requested to opt out of that settlement. Payments made to claimants through the BP claims programme are paid directly from the Trust. A separate court-supervised settlement programme has been established to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on pages 166 – 168 in BP Annual Report and Form 20-F 2012.

(b) Provisions and contingent liabilities

BP has recorded certain provisions and disclosed certain contingent liabilities as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 2012 – 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 of 2013 are presented in the table below.

$ million

Environmental

Spill
response

Litigation
and claims

Clean Water
Act penalties

Total

At 1 January 2013

1,862

345

9,483

3,510

15,200

Increase (decrease) in provision – items not covered by the trust fund

(24

)

—

(10

)

Increase in provision – items covered by the trust fund

—

468

—

492

Unwinding of discount

—

Reclassified to other payables

—

(3,933

)

—

(3,933

)

Utilization – paid by BP

(23

)

(31

)

(124

)

—

(178

)

– paid by the trust fund

(98

)

—

(680

)

—

(778

)

At 31 March 2013

1,742

320

5,222

3,510

10,794

Of which – current

911

243

3,656

—

4,810

– non-current

831

1,566

3,510

5,984

Of which – payable from the trust fund

1,363

4,662

—

6,072

Environmental

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

Spill response

The spill response provision relates primarily to ongoing patrolling and maintenance of the shoreline.

Litigation and claims

The litigation and claims provision includes amounts that can be reliably estimated for the future cost of settling claims by individuals and businesses for removal costs, damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources (“Individual and Business Claims”), other than as noted below, and claims by state and local government entities for removal costs, physical damage to real or personal property, loss of government revenue and increased public services costs (“State and Local Claims”) under OPA 90, except as described under Contingent liabilities below. Claims administration costs and legal fees have also been provided for.

Notes

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of business economic loss claims. BP has provided for business economic loss claims for which eligibility notices have been issued by the DHCSSP but has concluded that no reliable estimate can be made of business economic loss claims not yet received or processed by the DHCSSP. Further details are provided below.

The provision for claims under the PSC settlement was increased by $0.5 billion during the first quarter of 2013 to reflect additional eligibility notices issued by the DHCSSP for business economic loss claims received and processed subsequent to finalizing BP Annual Report and Form 20-F 2012 which was published in early March 2013.

As disclosed in BP Annual Report and Form 20-F 2012, as part of its monitoring of payments made by the DHCSSP during 2012, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect. On 5 March 2013, the District Court affirmed the claims administrator’s interpretation of the agreement and rejected BP’s position as it relates to business economic loss claims and BP’s related motions for injunctions and other relief. BP has subsequently appealed the District Court’s 5 March 2013 rulings to the Fifth Circuit. On 23 April 2013, the Fifth Circuit denied BP’s motion for a stay pending appeal, but granted BP’s request for expedited consideration. For further information, see Legal proceedings on pages 34 – 35 in this report.

Given the inherent uncertainty that currently exists as to the interpretation of the EPD Settlement Agreement which is subject to ongoing appeals, the lack of sufficient claims data from which to extrapolate any reliable trends and the higher number of claims received and higher average claims payments than previously assumed by BP, which may or may not continue, management continues to believe that no reliable estimate can be made of any business economic loss claims not yet received or processed by the DHCSSP. A provision will be re-established when a reliable estimate can be made of the liability as explained more fully below.

BP’s current estimate of the total cost of those elements of the PSC settlement that can be estimated reliably, which excludes any future business economic loss claims not yet received or processed by the DHCSSP, is $8.2 billion. If BP is successful in challenging the claims administrator’s interpretation of the EPD Settlement Agreement, the total estimated cost of the PSC settlement will, nevertheless, be significantly higher than the current estimate of $8.2 billion because business economic loss claims not yet received or processed are not reflected in the current estimate and the average payments per claim determined so far are higher than anticipated. If BP is not successful in challenging the claims administrator’s interpretation of the EPD Settlement Agreement, a further significant increase to the total estimated cost of the PSC settlement will be required. BP is continuing to evaluate available legal options to challenge the District Court’s rulings. However, there can be no certainty as to how the dispute will ultimately be resolved or determined. To the extent that there are insufficient funds available in the Trust, payments under the PSC settlement will be made by BP directly and charged to the income statement. The PSC settlement is uncapped except for economic loss claims related to the Gulf seafood industry.

The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP’s current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on pages 34 – 35 and Contingent liabilities below for further details.

Clean Water Act penalties

A provision was recognized in 2010 for the estimated civil 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.

Provision movements and analysis of income statement charge

During the first quarter of 2013, a net increase in the provision for the estimated cost of the settlement with the PSC and various other costs of $482 million was recognized. In addition, the provisions relating to the agreement with the US government to resolve all criminal claims and relating to the Gulf Region Health Outreach Program, amounting to $3.9 billion, have been reclassified to payables during the quarter, upon court approval. Utilization of the provision of $956 million during the first quarter 2013 included $629 million paid out under the PSC settlement from the Trust.

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


$ million	First quarter 2013
Net increase in provisions		482
Recognition of reimbursement asset		(492	)
Other net costs charged (credited) directly to the income statement		32

Loss before interest and taxation		22
Finance costs		10


Loss before taxation			32

Notes

2.	Gulf of Mexico oil spill (continued)

Items not provided for and uncertainties

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 early restoration agreements as described above under Provisions). It is not possible, at this time, to measure reliably other obligations arising from the incident, namely any obligation in relation to Natural Resource Damages claims (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings on pages 34 – 35, the cost of business economic loss claims under the PSC settlement not yet received or processed by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private or governmental litigation, fines or penalties (except for the Clean Water Act civil penalty claims and governmental claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment. These items are therefore disclosed as contingent liabilities – see below.

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable, including claims payable under the DHCSSP and State and Local Claims. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported. In addition, there is further uncertainty in relation to interpretations of the claims administrator regarding the protocols, relating to business economic loss claims, (which, as set out more fully in Legal Proceedings on pages 34– 35, are subject to appeal) under the EPD Settlement Agreement and judicial interpretation of these protocols, and the outcomes of any further litigation including in relation to potential opt-outs from the settlement or otherwise.

Furthermore, significant uncertainty exists in relation to 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. The amount and timing of any amounts payable could also be impacted by any further settlements which may or may not occur.

Further information on provisions is provided in BP Annual Report and Form 20-F 2012 – Financial statements – Note 36.

Contingent liabilities

Since 6 March 2013, BP has been named as a defendant in more than 2,200 additional civil lawsuits brought by individuals, corporations and government entities related to the incident, and further actions are likely to be brought. See Legal proceedings on pages 34 – 35 for further information. Until further fact and expert disclosures occur, court rulings clarify the venue for these lawsuits and the issues in dispute, liability and damage trial activity nears or progresses, or other actions such as possible settlements occur, it is not possible given these uncertainties to arrive at a range of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits. Therefore no amounts have been provided for these additional civil lawsuits as at 31 March 2013.

See also BP Annual Report and Form 20-F 2012 – Financial statements – Note 43. At 31 March 2013, the magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty. Furthermore, for those items where a provision has been recorded, significant uncertainty also exists in relation to the ultimate exposure and cost to BP.

Notes

3.	Disposal of TNK-BP and investment in Rosneft

Disposal of TNK-BP

In BP Annual Report and Form 20-F 2012 the transaction to sell BP’s investment in TNK-BP and acquire an investment in Rosneft was described as consisting of three tranches under which BP would receive $25.4 billion (including the $0.7 billion dividend received from TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft; BP would then use $4.8 billion of the cash to acquire a further 5.66% in Rosneft from Rosneftegaz and $8.3 billion to acquire a further 9.80% stake in Rosneft from a Rosneft subsidiary. On completion, the transactions between BP, Rosneft and the Rosneft subsidiary were instead settled on a net basis, so that BP received the 9.80% stake in Rosneft directly rather than receiving and immediately paying $8.3 billion in cash. The net result was the same.

The gain on disposal of BP’s investment in TNK-BP, recognized in the TNK-BP segment, was $12.5 billion as shown in the table below.


	$ billion
Agreed cash disposal proceeds		25.4
Amount settled net in Rosneft shares (9.80% stake)		(8.3	)
TNK-BP dividend received by BP in December 2012		(0.7	)
Interest on cash proceeds		0.3

Disposal proceeds received in cash in the quarter		16.7
Shares in Rosneft received (9.80% and 3.04% stake)		10.8

Consideration received		27.5
Less: carrying value of investment in TNK-BP		(12.5	)

		15.0
Deferral of gain		(3.0	)
Gain on existing 1.25% investment in Rosneft		0.5

Gain on disposal of investment in TNK-BP		12.5

Disposal proceeds of $4.9 billion were used to purchase the 5.66% stake in Rosneft from Rosneftegaz ($4.8 billion described above plus $0.1 billion of interest). The net cash inflow relating to the transaction included in net cash flow from investing activities in the cash flow statement was $11.8 billion.

Part of the gain arising on the disposal, amounting to $3.0 billion, has been deferred due to BP selling its investment in TNK-BP to Rosneft, which in turn is now accounted for by BP as an associate. The deferred gain will be released to BP’s income statement over time as the TNK-BP assets are depreciated or amortized.

Investment in Rosneft

BP’s investment in Rosneft is included in the balance sheet within investments in associates. The investment is measured at cost less the deferred gain described above (in Roubles), plus post-acquisition changes in BP’s share of Rosneft’s net assets, and amounted to $13.0 billion at 31 March 2013 as shown in the table below.


	$ billion
Shares in Rosneft received		10.8
Shares purchased from Rosneftegaz		4.9
Value of agreements to purchase Rosneft shares accounted for as derivatives		(0.7	)
Deferred gain		(3.0	)

Amount included in capital expenditure		11.9
Value of existing 1.25% investment in Rosneft		1.0

Investment in Rosneft on completion		12.9
BP’s share of Rosneft’s post-acquisition earnings after tax		0.1

Investment in Rosneft at 31 March 2013		13.0

During the quarter a charge of $2.1 billion (fourth quarter 2012 $1.4 billion credit) was recognized in other comprehensive income in relation to the agreements which were accounted for as derivatives in a cash flow hedge. The resulting cumulative charge of $0.7 billion recognized in other comprehensive income would only be recognized in the income statement if the investment in Rosneft were either sold or impaired. The cash flow hedge derivatives were valued using the quoted Rosneft share price at the time the deal completed, of $7.60 per share. BP’s share of the fair value of Rosneft’s identifiable net assets, and the consequent impact on the depreciation and amortization recognized via equity accounting in BP’s income statement, are provisional at 31 March, and will be finalized during the remainder of 2013.

Notes

4.	Non-current assets held for sale

As a result of the group’s disposal programme, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 31 March 2013. The carrying amount of the assets held for sale is $4,947 million, with associated liabilities of $722 million.

The majority of the transactions noted below 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 below.

The sale of BP’s investment in TNK-BP completed during the quarter, as described in Note 3, as did the sale of the Texas City refinery. The assets held for sale at 31 March 2013 are described below.

Upstream

On 28 November 2012, BP announced that it had agreed to sell its interests in a number of central North Sea oil and gas fields to TAQA for $1,058 million plus future payments which, dependent on oil price and production, are currently expected to exceed $250 million after tax. The assets included in the sale are BP’s interests in the BP-operated Maclure, Harding and Devenick fields and non-operated interests in the Brae complex of fields and the Braemar field. The assets and associated liabilities are classified as held for sale in the group balance sheet at 31 March 2013. The sale is subject to third-party and regulatory approvals and is expected to complete this year.

Downstream

On 13 August 2012, BP announced that it had reached an agreement to sell its Carson refinery in California and related assets in the region, including marketing and logistics assets, to Tesoro Corporation for $2.5 billion, including the estimated value of hydrocarbon inventories of $1.3 billion. The assets, and associated liabilities, of the refinery and related assets are classified as held for sale in the group balance sheet at 31 March 2013. Completion is subject to regulatory and other approvals, and the transaction is expected to close by the middle of 2013.

5.	Sales and other operating revenues


$ million	First quarter 2013		First quarter 2012
By business
Upstream		18,218		19,339
Downstream		86,784		86,688
Other businesses and corporate		420		428

		105,422		106,455


Less: sales and other operating revenues between businesses
Upstream		10,861		10,657
Downstream		240		746
Other businesses and corporate		214		174

		11,315		11,577


Third party sales and other operating revenues
Upstream		7,357		8,682
Downstream		86,544		85,942
Other businesses and corporate		206		254

Total third party sales and other operating revenues		94,107		94,878


By geographical area
US		35,281		34,502
Non-US		68,316		70,403

		103,597		104,905
Less: sales and other operating revenues between areas		9,490		10,027

		94,107		94,878

Notes

6.	Production and similar taxes


$ million	First quarter 2013		First quarter 2012
US		372		490
Non-US		1,623		1,856

		1,995		2,346

7.	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. During the quarter the company repurchased 21.4 million ordinary shares at a cost of $151 million as part of the share repurchase programme announced on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period, for which an amount of $699 million has been accrued at 31 March 2013. The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. If the inclusion of potentially issuable shares would decrease the loss per share, the potentially issuable shares are excluded from the diluted EpS calculation.


$ million	First quarter 2013			First quarter 2012
Results for the period
Profit for the period attributable to BP shareholders		16,863			5,767
Less: preference dividend		—			—

Profit attributable to BP ordinary shareholders		16,863			5,767
Inventory holding (gains) losses, net of tax		(267	)		(986	)

RC profit attributable to BP ordinary shareholders		16,596			4,781
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax		(12,381	)		(130	)

Underlying RC profit attributable to BP shareholders		4,215			4,651


Number of shares (thousand)(a)
Basic weighted average number of shares outstanding		19,147,437			18,976,062
ADS equivalent		3,191,239			3,162,677


Weighted average number of shares outstanding used to calculate diluted earnings per share		19,247,671			19,240,896
ADS equivalent		3,207,945			3,206,816


Shares in issue at period-end		19,153,586			19,016,208
ADS equivalent		3,192,264			3,169,368

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

Notes

8.	Analysis of changes in net debt(a)


$ million	First quarter 2013			First quarter 2012
Opening balance
Finance debt		48,800			44,208
Less: cash and cash equivalents		19,635			14,177
Less: FV asset of hedges related to finance debt		1,700			1,133

Opening net debt		27,465			28,898

Closing balance
Finance debt		46,425			46,471
Less: cash and cash equivalents(b)		27,679			14,267
Less: FV asset of hedges related to finance debt		1,083			1,224

Closing net debt		17,663			30,980

Decrease (increase) in net debt		9,802			(2,082	)

Movement in cash and cash equivalents (excluding exchange adjustments)		8,293			(28	)
Net cash outflow (inflow) from financing (excluding share capital and dividends)		1,716			(2,066	)
Movement in finance debt relating to investing activities(c)		—			—
Other movements		(126	)		(7	)

Movement in net debt before exchange effects		9,883			(2,101	)
Exchange adjustments		(81	)		19

Decrease (increase) in net debt		9,802			(2,082	)

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

(b)

The cash balance at 31 December 2012 included $709 million relating to the dividend received from TNK-BP in the fourth quarter 2012 which met the criteria to be treated as restricted cash until completion of the sale of BP’s interest in TNK-BP to Rosneft. This is no longer restricted because the transaction completed in March 2013.

(c)

During the first quarter 2013 no disposal transactions were completed in respect of which deposits had been received in advance (first quarter 2012 nil). No deposits were received in the first quarter 2013, in respect of disposals expected to complete within the next year (first quarter 2012 nil). At 31 March 2013, finance debt includes $632 million deposits received in advance relating to disposal transactions ($30 million at 31 March 2012).

At 31 March 2013, $141 million of finance debt ($136 million at 31 March 2012) was secured by the pledging of assets. The remainder of finance debt was unsecured.

During the first quarter the company has renegotiated its committed bank standby facilities and by the end of the quarter had in place five-year facilities totalling $6.9 billion, available to draw and repay until early March 2018. The facilities replace previous similar arrangements having a 3-year duration that were in place until mid-March 2014 and totalling $6.9 billion at 31 March 2012. No drawings have ever been made against any of the standby facilities.

9.	Inventory valuation

A provision of $194 million was held at 31 March 2013 to write inventories down to their net realizable value. The net movement in the provision during the first quarter 2013 was an increase of $70 million (first quarter 2012 was a decrease of $38 million).

10.

Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 29 April 2013, is unaudited and does not constitute statutory financial statements.

Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see pages 162 – 171 of BP Annual Report and Form 20-F 2012.

Matters relating to the Deepwater Horizon accident and oil spill (the Incident)

Federal multi-district litigation proceeding in New Orleans (MDL 2179)

As disclosed in BP Annual Report and Form 20-F 2012, on 25 February 2013, the first phase of a Trial of Liability, Limitation, Exoneration and Fault Allocation commenced in MDL 2179. The presentation of evidence in the first trial phase, which completed on 17 April 2013, addressed issues arising out of the conduct of various parties allegedly relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on the Deepwater Horizon on 20 April 2010, the sinking of the vessel on 22 April 2010 and the initiation of the release of oil from the Deepwater Horizon or the Macondo well during those time periods, including whether BP or any other party was grossly negligent. BP is not currently aware of the timing of the court’s ruling in respect of issues addressed in the first trial phase. The second trial phase is scheduled to commence on 16 September 2013, and will address the amount of oil that was spilled as a result of the Incident and source control efforts. For further information, see page 162 of BP Annual Report and Form 20-F 2012.

Additional civil lawsuits and related OPA 90 matters

Since 6 March 2013, BP has been among the companies named as defendants in more than 2,200 additional civil lawsuits related to the Incident which have been brought in US federal and state courts, and further actions are likely to be brought. Plaintiffs in these lawsuits include individuals, corporations, certain States and local government entities and a foreign government. While BP is currently evaluating these lawsuits, preliminary review suggests that the vast majority of the lawsuits assert claims under the Oil Pollution Act of 1990 (OPA 90). Certain of these lawsuits relate to earlier submissions of claims to BP under OPA 90 by certain States and local governments, as disclosed in our Group results fourth quarter and full year, dated 5 February 2013 and BP Annual Report and Form 20-F 2012. BP believes that claimants in these new additional civil lawsuits may have sought to file these lawsuits in advance of the third anniversary of the Incident on 20 April 2013, on which date certain OPA 90 claims may have been subject to time bar challenges by BP under OPA 90’s three-year statute of limitations. The new lawsuits also assert various other claims (including, but not limited to, claims for economic loss and/or real property damage and under maritime law, state law and the Declaratory Judgment Act) as well as seeking various remedies including economic and compensatory damages, punitive damages, removal costs and natural resource damages. Many of the lawsuits assert claims which are excluded from the Economic and Property Damages Settlement Agreement, including claims for recovery for losses allegedly resulting from the 2010 federal deepwater drilling moratoria and/or the related permitting process. BP intends to apply to have these lawsuits consolidated with MDL 2179. For further information, see Contingent liabilities in Note 2 on page 29.

As disclosed in BP Annual Report and Form 20-F 2012, the States of Alabama, Mississippi, Louisiana and Florida and various local governments have submitted or asserted claims to BP under OPA 90 for alleged losses as a result of the Incident. As disclosed above, since 6 March 2013, certain of these States and local governments (including the states of Alabama, Florida and Mississippi) have filed civil lawsuits that pertain to claims asserted by them under their earlier OPA 90 submissions to BP.

Plaintiffs’ Steering Committee (PSC) Settlements

As part of its monitoring of payments made by the court-supervised claims processes operated by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) for the Economic and Property Damages Settlement between BP and the PSC, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement by that settlement’s claims administrator that BP believes was incorrect. This interpretation produced a higher number and value of awards than the interpretation BP used in making its initial estimate of the total cost of the Economic and Property Damages Settlement. Pursuant to the mechanisms in the Economic and Property Damages Settlement Agreement, the claims administrator sought clarification from the federal district court in New Orleans (the District Court) on this matter and on 30 January 2013, the District Court initially upheld the claims administrator’s interpretation of the agreement. On 6 February 2013, the District Court reconsidered and vacated its ruling of 30 January 2013 and stayed the processing of certain types of business economic loss claims. The District Court lifted the stay on 28 February 2013. On 5 March 2013, the District Court affirmed the claims administrator’s interpretation of the agreement and rejected BP’s position as it relates to business economic loss claims. Business economic loss claims have continued to be paid at a higher average amount than the amount BP assumed in determining its initial estimate of the total cost.

Legal proceedings (continued)

On 15 March 2013, BP filed an emergency motion in MDL 2179 seeking a preliminary injunction against the DHCSSP and the claims administrator to enjoin payments and awards based on the disputed interpretation of the Economic and Property Damages Settlement Agreement. That same day BP also filed a substantially identical motion and complaint with the District Court in a separate action against the DHCSSP and the claims administrator seeking a similar preliminary injunction, a permanent injunction against the DHCSSP and the claims administrator from acting upon the disputed interpretation of the agreement, as well as other relief. On 25 March 2013, the District Court granted the Economic and Property Damages Settlement Class leave to intervene in the new action. On 4 April 2013, BP filed a motion for preliminary injunction or stay pending appeal with the District Court. On 5 April 2013, after holding a public hearing, the District Court denied BP’s motions and granted the DHCSSP’s motion to dismiss the separate action BP had brought against it. On 9 April 2013, the District Court issued an order declaring that BP, the Economic and Property Damages Settlement Class and the DHCSSP (along with its internal appeal panellists) must follow and are bound by (i) the 5 March 2013 ruling; (ii) the 12 December 2012 ruling of the District Court regarding non-profit entity revenue and (iii) an analysis of causation as set forth in paragraph 2 of the Claims Administrator’s “Announcement of Policy Decisions Regarding Claims Administration”, dated 10 October 2012.

BP continues to strongly disagree with the District Court ruling of 5 March 2013 (including its confirmation in the District Court’s order on 9 April 2013) and the current implementation of the agreement by the claims administrator. BP appealed the District Court’s 5 March 2013 and 5 April 2013 rulings to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), and filed motions for injunctions and stays pending appeal to prevent the claims administrator from paying business economic loss claims pursuant to his interpretation. BP also moved to consolidate and expedite consideration of its appeals, proposing that briefing be completed in the Fifth Circuit by 31 May 2013. On 22 April 2013, the Fifth Circuit denied BP’s motions for injunctions and stays pending appeal, but granted BP’s motion to expedite the appeal. BP is continuing to evaluate other available legal options to challenge the District Court rulings.

For information about BP’s current estimate of the total cost of the PSC settlements, see Note 2. For further information about the PSC settlements, see pages 166 – 168 of BP Annual Report and Form 20-F 2012.

MDL 2185 and other securities-related litigation

From July 2012 to March 2013, eleven cases were filed in Texas state and federal courts (later consolidated into eight actions) by pension or investment funds or advisors against BP entities and current and former officers, asserting state law and other claims and seeking damages for alleged losses that those funds suffered because of their purchases of BP ordinary shares and/or ADSs. All of the cases have been transferred to the judge presiding over the federal multi-district litigation proceeding in Houston (MDL 2185). Oral argument on a motion to dismiss three of the eleven cases is scheduled for 10 May 2013.

On 5 July 2012, the judge in MDL 2185 issued a decision granting a motion to dismiss, for lack of personal jurisdiction, the lawsuit against BP p.l.c. for cancelling its dividend payment in June 2010. On 10 August 2012, the plaintiffs filed an amended complaint, which BP moved to dismiss on 9 October 2012. On 12 April 2013, the judge granted BP’s motion to dismiss.

For further information about MDL 2185 and other securities-related litigation, see pages 162 – 163 of BP Annual Report and Form 20-F 2012.

Cautionary statement

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operation and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, certain statements regarding the expected quarterly dividend payment; BP’s intentions in respect of its announced share repurchase programme, including the total quantum of shares expected to be purchased in connection therewith; the expected level of reported production in the second quarter of 2013; the expected level of Upstream costs in the second quarter of 2013; expectations regarding the level of oil production at the Valhall field in the second half of 2013; the timing of and prospects for the decision regarding the pipeline for transportation of Shah Deniz Stage 2 gas to Europe; the expected timing of the commissioning of the new crude unit at the Whiting refinery and the completion of the Whiting refinery modernization project; the expected timing of completion of planned and announced divestments, including the disposal of BP’s interest in the Carson refinery and related assets; prospects for BP-Husky Refining LLC’s new naphtha reformer at the Toledo refinery; the expected level of petrochemicals margins in 2013; BP’s plans to report inventory holding gains or losses and non-operating items in respect of the Rosneft segment later in 2013; BP’s intentions to market its wind business for sale; the expected quantum of funds that could be provided in subsequent periods for items covered by the $20-billion Trust fund with no net impact on the income statement; and certain statements regarding the anticipated timing of, prospects for and BP’s prospective responses to legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties ; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of turnaround activity; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; 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 BP Annual Report and Form 20-F 2012 as filed with the US Securities and Exchange Commission.

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: 30 April 2013

/s/ J Bertelsen

J BERTELSEN

Deputy Secretary