Edgar Filing: BP PLC

Dated: 30 July 2013

/s/ J Bertelsen

J BERTELSEN

Deputy Secretary

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

for the period ended 30 June 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 POST-EFFECTIVE AMENDMENT NO. 2 TO 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 30 JUNE 2013^(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2013^(b)		3 – 12, 20 – 22

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2013		13 – 19, 23 – 41

3.	Principal risks and uncertainties		42 – 49

4.	Legal proceedings		50 – 52

5.	Cautionary statement		53

6.	Signatures		54

7.	Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges		55

	Exhibit 99.2: Capitalization and Indebtedness		56

(a)	In this Form 6-K, references to the first half 2013 and first half 2012 refer to the six-month periods ended 30 June 2013 and 30 June 2012 respectively. References to second quarter 2013 and second quarter 2012 refer to the three-month periods ended 30 June 2013 and 30 June 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 second quarter and half year 2013


Second quarter 2012			Second quarter 2013		$ million	First half 2013			First half 2012
	94,975			94,711	Sales and other operating revenues		188,818			189,853

	(1,519	)		2,042	Profit (loss) for the period^(a)		18,905			4,248
	1,623			358	Inventory holding (gains) losses, net of tax		91			637

	104			2,400	Replacement cost profit^(b)		18,996			4,885
	3,447			312	Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax^(c)		(12,069	)		3,317

	3,551			2,712	Underlying replacement cost profit^(b)		6,927			8,202

	(7.99	)		10.73	Profit (loss) per ordinary share (cents)		99.07			22.35
	(0.48	)		0.64	Profit (loss) per ADS (dollars)		5.94			1.34
	0.54			12.62	Replacement cost profit per ordinary share (cents)		99.55			25.71
	0.03			0.76	Replacement cost profit per ADS (dollars)		5.97			1.54
	18.66			14.26	Underlying replacement cost profit per ordinary share (cents)		36.30			43.16
	1.12			0.86	Underlying replacement cost profit per ADS (dollars)		2.18			2.59

•

BP’s profit for the second quarter and half year was $2,042 million and $18,905 million respectively, compared with a loss of $1,519 million and a profit of $4,248 million for the same periods a year ago. BP’s second-quarter replacement cost (RC) profit was $2,400 million, compared with $104 million a year ago. After adjusting for a net charge for non-operating items of $366 million and net favourable fair value accounting effects of $54 million (both on a post-tax basis), underlying RC profit for the second quarter was $2,712 million, compared with $3,551 million for the same period in 2012. For the half year, RC profit was $18,996 million, compared with $4,885 million a year ago. After adjusting for a net gain for non-operating items of $12,058 million and net favourable fair value accounting effects of $11 million (both on a post-tax basis), underlying RC profit for the half year was $6,927 million, compared with $8,202 million for the same period last year. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 4, 19 and 21.

•

All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net adverse impact on a pre-tax basis of $209 million for the quarter and $241 million for the half year 2013. For further information on the Gulf of Mexico oil spill and its consequences, including information on utilization of the Deepwater Horizon Oil Spill Trust fund, see page 12 and Note 2 on pages 25 – 30. Information on the Gulf of Mexico oil spill is also included in Principal risks and uncertainties on pages 42 – 49 and Legal proceedings on pages 50 – 52.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and half year was $5.4 billion and $9.4 billion respectively, compared with $4.4 billion and $7.9 billion in the same periods of 2012. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the second quarter and half year was $5.2 billion and $9.5 billion respectively, compared with $6.1 billion and $10.7 billion in the same periods last year.

•

Gross debt at the end of the quarter was $47.0 billion compared with $47.6 billion a year ago. The ratio of gross debt to gross debt plus equity was 26.5%, compared with 29.6% a year ago. Net debt at the end of the quarter was $18.2 billion, compared with $31.5 billion a year ago. The ratio of net debt to net debt plus equity at the end of the quarter was 12.3% compared with 21.7% 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 second quarter and half year was 48% and 20% respectively, compared with 26% on the loss for the second quarter and 36% on the profit for the half year in 2012. The ETR on RC profit for the second quarter and half year was 46% and 20% respectively, compared with 56% and 35% for the same periods in 2012. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the second quarter and half year was 45% and 41% respectively, compared with 35% and 34% for the same periods in 2012. The increase in both periods was mainly due to foreign exchange impacts on deferred tax; the half year was also impacted by a reduction in equity-accounted earnings (which are reported net of tax).

•

Total capital expenditure for the second quarter was $5.8 billion, all of which was organic^(d). For the half year, total capital expenditure was $23.5 billion, of which organic capital expenditure was $11.5 billion. Disposal proceeds received in cash were $2.9 billion for the quarter and $21.2 billion for the half year.

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $369 million for the second quarter, compared with $390 million for the same period in 2012. For the half year, the respective amounts were $773 million and $795 million.

•

As at 26 July, BP had bought back 345 million shares for a total amount of $2.4 billion, including fees and stamp duty, since the announcement on 22 March of an $8 billion share repurchase programme expected to be fulfilled over 12 – 18 months.

•

BP today announced a quarterly dividend of 9 cents per ordinary share ($0.54 per ADS), which is expected to be paid on 20 September 2013. The corresponding amount in sterling will be announced on 10 September 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 53.

Analysis of RC profit before interest and tax

and reconciliation to profit for the period


Second quarter 2012			Second quarter 2013			$ million	First half 2013			First half 2012
						RC profit before interest and tax
	2,913			4,400		Upstream		9,962			9,896
	(1,732	)		1,016		Downstream		2,663			(873	)
	452			—		TNK-BP^(a)		12,500			1,516
	—			218		Rosneft^(b)		303			—
	(522	)		(573	)	Other businesses and corporate		(1,040	)		(1,193	)
	(843	)		(199	)	Gulf of Mexico oil spill response^(c)		(221	)		(813	)
	457			129		Consolidation adjustment – UPII^(d)		556			(84	)

	725			4,991		RC profit before interest and tax		24,723			8,449
	(390	)		(369	)	Finance costs and net finance expense relating to pensions and other post-retirement benefits		(773	)		(795	)
	(186	)		(2,138	)	Taxation on a RC basis		(4,791	)		(2,663	)
	(45	)		(84	)	Non-controlling interests		(163	)		(106	)

	104			2,400		RC profit attributable to BP shareholders		18,996			4,885

	(2,324	)		(506	)	Inventory holding gains (losses)		(100	)		(887	)
	701			148		Taxation (charge) credit on inventory holding gains and losses		9			250

	(1,519	)		2,042		Profit for the period attributable to BP shareholders		18,905			4,248

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See Note 3 on page 31 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See page 10 for further information.

(c)	See Note 2 on pages 25 – 30 for further information on the accounting for the Gulf of Mexico oil spill response.

(d)	Unrealized profit in inventory.

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


Second quarter 2012			Second quarter 2013			$ million	First half 2013			First half 2012
						Underlying RC profit before interest and tax
	4,401			4,288		Upstream		9,990			10,695
	1,133			1,201		Downstream		2,842			2,060
	452			—		TNK-BP		—			1,609
	—			218		Rosneft		303			—
	(540	)		(438	)	Other businesses and corporate		(899	)		(975	)
	457			129		Consolidation adjustment – UPII		556			(84	)

	5,903			5,398		Underlying RC profit before interest and tax		12,792			13,305
	(386	)		(359	)	Finance costs and net finance expense relating to pensions and other post-retirement benefits		(753	)		(785	)
	(1,921	)		(2,243	)	Taxation on an underlying RC basis		(4,949	)		(4,212	)
	(45	)		(84	)	Non-controlling interests		(163	)		(106	)

	3,551			2,712		Underlying RC profit attributable to BP shareholders		6,927			8,202

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 – 11 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

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

Per ordinary share (cents)

(7.99

)

10.73

Profit (loss) for the period

99.07

22.35

0.54

12.62

RC profit for the period

99.55

25.71

18.66

14.26

Underlying RC profit for the period

36.30

43.16

Per ADS (dollars)

(0.48

)

0.64

Profit (loss) for the period

5.94

1.34

0.03

0.76

RC profit for the period

5.97

1.54

1.12

0.86

Underlying RC profit for the period

2.18

2.59

The amounts shown above are calculated based on the basic weighted average number of shares outstanding. See Note 7 on page 33 for details of the calculation of earnings per share.

Net debt ratio – net debt: net debt + equity


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
	47,647			46,990		Gross debt		46,990			47,647
	1,067			460		Less: fair value asset of hedges related to finance debt		460			1,067

	46,580			46,530				46,530			46,580
	15,075			28,313		Less: cash and cash equivalents		28,313			15,075

	31,505			18,217		Net debt		18,217			31,505

	113,415			130,133		Equity		130,133			113,415
	21.7	%		12.3	%	Net debt ratio		12.3	%		21.7	%

See Note 8 on page 34 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 September. The corresponding amount in sterling will be announced on 10 September 2013, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 September 2013. Holders of American Depositary Shares (ADSs) will receive $0.54 per ADS. The dividend is due to be paid on 20 September 2013 to shareholders and ADS holders on the register on 9 August 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 second-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

Dividends paid

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

Dividends paid per ordinary share

8.000

9.000

cents

18.000

16.000

5.150

5.834

pence

11.835

10.246

48.00

54.00

Dividends paid per ADS (cents)

108.00

96.00

Scrip dividends

11.1

43.8

Number of shares issued (millions)

58.3

50.7

315

Value of shares issued ($ million)

416

379

Upstream


Second quarter 2012		Second quarter 2013				First half 2013		First half 2012
					$ million
	16,606		16,418		Sales and other operating revenues		34,636		35,945

	2,877		4,396		Profit before interest and tax		9,956		9,776
	36		4		Inventory holding (gains) losses		6		120

	2,913		4,400		RC profit before interest and tax		9,962		9,896
	1,488		(112	)	Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		28		799

	4,401		4,288		Underlying RC profit before interest and tax^(a)		9,990		10,695

(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.

Sales and other operating revenues for the second quarter and half year were $16 billion and $35 billion respectively, compared with $17 billion and $36 billion for the corresponding periods in 2012. For the second quarter, revenues were lower mainly due to lower volumes. For the half year, the reduction was due to realizations and lower volumes. The reductions in both periods were partially offset by higher gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $4,400 million and $9,962 million respectively, compared with $2,913 million and $9,896 million for the same periods in 2012. The second quarter and half year included net non-operating gains of $143 million and $63 million respectively, primarily related to disposal gains and fair value gains on embedded derivatives, partly offset by impairment charges. A year ago, there were net non-operating charges of $1,495 million in the second quarter and $673 million for the half year. Fair value accounting effects in the second quarter and half year had unfavourable impacts of $31 million and $91 million respectively, compared with a favourable impact of $7 million and an unfavourable impact of $126 million in the same periods a year ago.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $4,288 million and $9,990 million respectively, compared with $4,401 million and $10,695 million a year ago. The results for the second quarter and half year were adversely impacted by lower liquids realizations, higher costs, mainly exploration write-offs and higher depreciation, depletion and amortization, and lower production due to divestments, partly offset by an increase in underlying volumes and higher gas realizations. In addition to these factors, the first half of 2013 benefited from stronger gas marketing and trading activities, mainly in the first quarter.

Production for the quarter was 2,241mboe/d, 1.5% lower than the second quarter of 2012. After adjusting for the effects of divestments and entitlement impacts in our production-sharing agreements (PSAs), underlying production increased by 4.4%. This primarily reflects new major project volumes in Angola, the North Sea and the Gulf of Mexico, and improved Trinidad performance, partly offset by underlying base decline. For the first half, production was 2,285mboe/d, 3.3% lower than in the same period last year. After adjusting for the effect of divestments and entitlement impacts in our PSAs, first-half underlying production was 3.0% higher than in 2012.

Looking ahead, we expect third-quarter reported production to be lower than the second quarter, similar to the reduction we saw between the first and second quarters of 2013. This is the result of planned major turnaround activity and repairs in the high-margin North Sea, planned maintenance in Alaska and the continuing impact of our divestment programme. This is partly offset by continued project ramp-ups and reduced maintenance activity in Asia Pacific. We also expect costs to be seasonally higher in the third quarter compared with the second quarter. Full-year reported production is expected to be lower than 2012, mainly due to the impact of divestments. The actual reported outcome will depend on the exact timing of divestments, OPEC quotas and the impact of entitlement effects in our PSAs. After adjusting for divestments and the impact of entitlement effects in our PSAs, we continue to expect full-year production in 2013 to increase compared with 2012.

We continued to make strategic progress. In May, we announced we have agreed to sell our 60% interest in the Polvo oil field in Brazil to HRT Oil & Gas Ltda for $135 million in cash. Subject to regulatory approvals, the deal is expected to close in the second half of 2013. Also in Brazil, BP and its partners Total, Petrobras and Petrogal were named winning bidders for eight deepwater blocks offshore Brazil in the Brazilian National Petroleum Agency’s 11th bid round. BP will be operator in two of the blocks.

Also in May, a significant gas and condensate discovery in the KG D6 block off the eastern coast of India was announced by Reliance Industries Limited and its partners, BP and NIKO.

In June, we announced plans to add $1 billion of new investment and two drilling rigs to our Alaska North Slope fields over the next five years. Changes in the state’s oil tax policy helped to enable this increased investment. In addition, BP has secured support from the other working interest owners at Prudhoe Bay to begin evaluating an additional $3 billion of new development projects.

In Azerbaijan, the Shah Deniz consortium announced that it has selected the Trans Adriatic Pipeline to deliver gas volumes from the Shah Deniz Stage 2 project to customers in Greece, Italy and south-east Europe.

Also in June, BP was awarded interests in two licences in the Barents Sea as part of the recent 22nd offshore licensing round in Norway.

After the end of the quarter, we announced the completion of a deal with Petrobras to farm in to five deepwater exploration and production blocks operated by Petrobras in the Potiguar Basin, located in the Brazilian Equatorial Margin. We also announced that BP and CNOOC signed a PSA for Block 54/11 in the South China Sea.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 53.

Upstream


Second quarter 2012			Second quarter 2013			$ million	First half 2013			First half 2012
						Underlying RC profit before interest and tax
	628			611		US		1,609			2,286
	3,773			3,677		Non-US		8,381			8,409

	4,401			4,288				9,990			10,695

						Non-operating items
	(2,273	)		62		US		56			(1,326	)
	778			81		Non-US		7			653

	(1,495	)		143				63			(673	)

						Fair value accounting effects^(a)
	61			(33	)	US		(73	)		(10	)
	(54	)		2		Non-US		(18	)		(116	)

	7			(31	)			(91	)		(126	)

						RC profit before interest and tax
	(1,584	)		640		US		1,592			950
	4,497			3,760		Non-US		8,370			8,946

	2,913			4,400				9,962			9,896

						Exploration expense
	413			85		US^(b)		165			475
	203			349		Non-US		591			401

	616			434				756			876

						Production (net of royalties)^(c)
						Liquids (mb/d)^(d)
	350			335		US		351			402
	119			97		Europe		106			121
	681			732		Rest of World		722			676

	1,150			1,165				1,179			1,199

	281			296		Of which equity-accounted entities		297			282

						Natural gas (mmcf/d)
	1,648			1,573		US		1,553			1,734
	478			286		Europe		307			489
	4,399			4,386		Rest of World		4,558			4,532

	6,525			6,244				6,418			6,755

	414			409		Of which equity-accounted entities		404			406

						Total hydrocarbons (mboe/d)^(e)
	635			606		US		618			701
	201			147		Europe		159			205
	1,439			1,488		Rest of World		1,508			1,458

	2,275			2,241				2,285			2,364

	353			367		Of which equity-accounted entities		367			351

						Average realizations^(f)
	100.89			94.92		Total liquids ($/bbl)		99.08			104.67
	4.54			5.37		Natural gas ($/mcf)		5.45			4.62
	60.17			61.27		Total hydrocarbons ($/boe)		63.23			62.18

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

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

(d)	Crude oil and natural gas liquids.

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

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

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

Downstream


Second quarter 2012			Second quarter 2013			First half 2013		First half 2012
					$ million
	88,262			88,348	Sales and other operating revenues		175,132		174,950

	(3,931	)		501	Profit (loss) before interest and tax		2,556		(1,577	)
	2,199			515	Inventory holding (gains) losses		107		704

	(1,732	)		1,016	RC profit (loss) before interest and tax		2,663		(873	)
	2,865			185	Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		179		2,933

	1,133			1,201	Underlying RC profit before interest and tax^(a)		2,842		2,060

(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.

Sales and other operating revenues for the second quarter and half year were $88 billion and $175 billion, respectively, the same as the corresponding periods in 2012. Higher crude oil volumes in both the second quarter and half year of 2013 were mostly offset by lower prices.

The replacement cost profit before interest and tax for the second quarter and half year was $1,016 million and $2,663 million respectively, compared with losses of $1,732 million and $873 million for the same periods in 2012.

The 2013 results included net non-operating charges of $323 million for the second quarter and $304 million for the half year principally relating to impairment charges in our fuels business, compared with net charges of $2,678 million and $2,784 million for the same periods a year ago (see pages 9 and 20 for further information on non-operating items). Fair value accounting effects had favourable impacts of $138 million for the second quarter and $125 million for the half year, compared with unfavourable impacts of $187 million for the second quarter and $149 million for the half year of 2012.

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

The fuels business reported underlying replacement cost profit before interest and tax of $853 million for the second quarter and $2,090 million for the half year, compared with $785 million and $1,275 million in the same periods in 2012. For both the second quarter and half year, this improvement was principally due to a strong supply and trading contribution. The benefit from strong operations, including continued strong Solomon availability at 95.3% – a level that has not been exceeded since 2004, was more than offset by reduced throughput due to the planned crude unit outage at our Whiting refinery as part of the modernization project. Throughput was also impacted by planned turnarounds across the portfolio and divestments. Additionally, in comparison to 2012, the second-quarter results were favourably impacted by a decrease in the adverse effects from the prior-month pricing of barrels in our US refining system. This was offset by adverse impacts due to a narrowing of the discount for heavy Canadian crude compared with other grades.

The second quarter marked the safe start-up of the new crude unit at our Whiting refinery. The overall project is on track for completion during the second half of the year. Additionally, during March, BP-Husky Refining LLC successfully started up a new naphtha reformer at the Toledo refinery, and during May, we announced that the Cherry Point refinery commissioned its new diesel hydrotreater and hydrogen plant. Also during the second quarter we announced our intention to invest over $500 million in southern African refining and infrastructure projects.

On 3 June 2013, we completed the previously announced sale of the Carson, California refinery and related logistics and marketing assets to Tesoro Corporation for approximately $2.4 billion as part of a plan to reshape BP’s US fuels business. During the first half of 2013, we also completed the sale of our Texas City refinery and related retail and logistics network in the south-eastern US to Marathon Petroleum Corporation.

Looking ahead to the third quarter, we expect refining margins to decline relative to the same quarter a year ago given global capacity additions and major refineries returning from planned and unplanned outages. BP’s fuels profitability is expected to be lower than the record levels experienced in the third quarter of 2012 due to the absence of the profit generated by the divested Texas City and Carson refineries which delivered very strong results in that quarter.

The lubricants business delivered an underlying replacement cost profit before interest and tax of $372 million in the second quarter and $717 million in the half year, compared with $320 million and $645 million in the same periods last year. This represents another strong quarter and reflects continued margin capture driven by growth in the share of sales of our premium Castrol brands and strong profitability from growth markets.

The petrochemicals business reported an underlying replacement cost loss before interest and tax of $24 million in the second quarter and an underlying replacement cost profit before interest and tax of $35 million in the half year, compared with an underlying replacement cost profit before interest and tax of $28 million and $140 million respectively in the same periods last year. This decrease was due to the continued difficult environment impacting both volumes and margins and increased turnaround activity in the second quarter of this year. Margins and volumes are expected to remain under pressure for the rest of the year. In June, BP and its partner, Zhuhai Port Co, received final approvals from the Chinese government for the construction of a third purified terephthalic acid (PTA) plant, at Zhuhai, Guangdong.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 53.

Downstream


Second quarter 2012			Second quarter 2013			$ million	First half 2013			First Half 2012
						Underlying RC profit before interest and tax – by region
	450			557		US		1,307			739
	683			644		Non-US		1,535			1,321

	1,133			1,201				2,842			2,060

						Non-operating items
	(2,433	)		(17	)	US		11			(2,521	)
	(245	)		(306	)	Non-US		(315	)		(263	)

	(2,678	)		(323	)			(304	)		(2,784	)

						Fair value accounting effects^(a)
	(1	)		219		US		154			(44	)
	(186	)		(81	)	Non-US		(29	)		(105	)

	(187	)		138				125			(149	)

						RC profit (loss) before interest and tax
	(1,984	)		759		US		1,472			(1,826	)
	252			257		Non-US		1,191			953

	(1,732	)		1,016				2,663			(873	)

						Underlying RC profit (loss) before interest and tax – by business^(b)(c)
	785			853		Fuels		2,090			1,275
	320			372		Lubricants		717			645
	28			(24	)	Petrochemicals		35			140

	1,133			1,201				2,842			2,060

						Non-operating items and fair value accounting effects^(a)
	(2,863	)		(188	)	Fuels		(177	)		(2,931	)
	(2	)		3		Lubricants		(2	)		(2	)
	—			—		Petrochemicals		—			—

	(2,865)			(185	)			(179	)		(2,933	)

						RC profit (loss) before interest and tax^(b)(c)
	(2,078	)		665		Fuels		1,913			(1,656	)
	318			375		Lubricants		715			643
	28			(24	)	Petrochemicals		35			140

	(1,732	)		1,016				2,663			(873	)

	18.9			19.1		BP average refining marker margin (RMM) ($/bbl)^(d)		18.2			16.7

						Refinery throughputs (mb/d)
	1,295			711		US		824			1,256
	706			745		Europe		775			741
	281			252		Rest of World		287			279

	2,282			1,708				1,886			2,276

	94.5			95.3		Refining availability (%)^(e)		95.2			94.7

						Marketing sales of refined products (mb/d)
	1,409			1,340		US		1,371			1,379
	1,247			1,316		Europe^(f)		1,237			1,219
	603			549		Rest of World		553			589

	3,259			3,205				3,161			3,187
	2,568			2,527		Trading/supply sales of refined products		2,418			2,474

	5,827			5,732		Total sales volumes of refined products		5,579			5,661

						Petrochemicals production (kte)
	1,110			1,081		US		2,157			2,188
	998			814		Europe^(c)		1,828			2,009
	1,750			1,519		Rest of World		2,936			3,567

	3,858			3,414				6,921			7,764

(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 2012 volumes data.

Rosneft

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

$ million

—

231

Profit before interest and tax^(a)

316

—

(13

)

Inventory holding (gains) losses

(13

)

—

218

RC profit before interest and tax

303

—

Net charge (credit) for non-operating items

—

218

Underlying RC profit before interest and tax^(b)

303

—

(a)	The Rosneft segment includes equity-accounted earnings from associates, representing BP’s 19.75% share in Rosneft as shown in the table below. Second quarter 2013 as reported includes an amendment to first-quarter profit, which was reported based on a BP estimate.

$ million

Income statement (BP share)

—

417

Profit before interest and tax

527

—

(127

)

Finance costs

(130

)

—

(31

)

Taxation

(53

)

—

(28

)

Non-controlling interests

(28

)

—

231

Net income

316

—

(13

)

Inventory holding (gains) losses, net of tax

(13

)

—

218

Net income on a RC basis

303

—

Net charge (credit) for non-operating items, net of tax

—

218

Net income on an underlying RC basis^(b)

303

—

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

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

Production (net of royalties) (BP share)^(c)

—

826

Liquids (mb/d)^(d)

466

—

689

Natural gas (mmcf/d)

391

—

945

Total hydrocarbons (mboe/d)^(e)

533

—


Balance sheet	30 June 2013		31 December 2012
$ million
Trade and other receivables – dividends receivable^(f)		514		—
Investments in associates		11,896		—

(c)	First half 2013 reflects production for the period 21 March – 30 June, averaged over the half year.

(d)	Liquids comprise crude oil, condensate and natural gas liquids.

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

(f)	Dividends receivable before deduction of withholding tax.

Following the completion of the sale and purchase agreements with Rosneft and Rosneftegaz on 21 March 2013, described in Note 3, BP’s investment in Rosneft is reported as a separate operating segment under IFRS. See Note 3 on page 31 for further information.

Replacement cost profit before interest and tax^(g) for the second quarter and half year was $218 million and $303 million respectively.

Production for the second quarter and half year was 945mboe/d and 533mboe/d respectively^(h).

On 20 June 2013, Rosneft’s Annual Shareholders Meeting approved the distribution of a dividend of approximately eight roubles per share. The dividend is expected to be received no later than 19 August 2013.

(g)	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.

(h)	Information on BP’s share of TNK-BP’s production for comparative periods is provided on page 22.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 53.

Other businesses and corporate


Second quarter			Second quarter				First half			First half
2012			2013				2013			2012
						$ million
	527			414		Sales and other operating revenues		834			955

	(522	)		(573	)	Profit (loss) before interest and tax		(1,040	)		(1,193	)
	—			—		Inventory holding (gains) losses		—			—

	(522	)		(573	)	RC profit (loss) before interest and tax		(1,040	)		(1,193	)
	(18	)		135		Net charge (credit) for non-operating items		141			218

	(540	)		(438	)	Underlying RC profit (loss) before interest and tax^(a)		(899	)		(975	)

						Underlying RC profit (loss) before interest and tax^(a)
	(185	)		(142	)	US		(263	)		(350	)
	(355	)		(296	)	Non-US		(636	)		(625	)

	(540	)		(438	)			(899	)		(975	)

						Non-operating items
	(92	)		(134	)	US		(138	)		(234	)
	110			(1	)	Non-US		(3	)		16

	18			(135	)			(141	)		(218	)

						RC profit (loss) before interest and tax
	(277	)		(276	)	US		(401	)		(584	)
	(245	)		(297	)	Non-US		(639	)		(609	)

	(522	)		(573	)			(1,040	)		(1,193	)

(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 including centralized functions.

The replacement cost loss before interest and tax for the second quarter and half year was $573 million and $1,040 million respectively, compared with $522 million and $1,193 million for the same periods last year.

The second-quarter result included a net non-operating charge of $135 million, compared with a net credit of $18 million a year ago. The charge for the quarter relates principally to an impairment of assets in our wind business. For the half year, the net non-operating charge was $141 million, compared with a net charge of $218 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $438 million and $899 million respectively, compared with $540 million and $975 million for the same periods last year.

In Alternative Energy, net wind generation capacity^(b) at the end of the second 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 16 US wind farms for the second quarter was 1,143GWh (1,957GWh gross), compared with 920GWh (1,422GWh gross) in the same period a year ago. For the half year, BP’s net share was 2,287GWh (4,021GWh gross), compared with 1,940GWh (3,086GWh gross) a year ago. BP has decided to retain and continue to operate its wind business.

In our biofuels business we have three operating mills in Brazil where ethanol-equivalent production^(c) for the second quarter was 116 million litres compared with 98 million litres in the same period a year ago. In the UK, the Vivergo joint venture plant (BP 47%) was commissioned in late 2012 and commenced start-up during the first half of 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.

(c)	Ethanol-equivalent production includes ethanol and sugar.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 53.

Gulf of Mexico oil spill

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

In May and June, following the extensive three-year clean-up effort, the US Coast Guard ended active clean-up operations in Mississippi, Alabama and Florida and transitioned the states back to the National Response Center reporting system. Approximately 100 miles of shoreline in Louisiana remained subject to patrolling and maintenance, final monitoring or inspection, or were pending final Coast Guard approval at the end of the second quarter.

Under the early restoration framework agreement that BP signed with state and federal agencies in 2011, BP agreed to fund up to $1 billion in early restoration projects to accelerate efforts to restore natural resources injured as a result of the incident. These projects will be funded from the Trust. An environmental provision of $1 billion was established to reflect this agreement. In May, BP announced that it had reached agreement in principle with state and federal Trustees on 28 additional early restoration projects totalling approximately $595 million. To date, BP and the Trustees have announced 38 projects totalling approximately $665 million. Ten of these projects have been finally approved and are in progress. The other projects are subject to public comment and further Trustee approval.

Financial update

The replacement cost loss before interest and tax for the second quarter was $199 million, compared with an $843 million loss for the same period last year. The second-quarter charge reflects an increase in the litigation and claims provision, the ongoing costs of the Gulf Coast Restoration Organization and adjustments to other provisions. The cumulative pre-tax charge recognized to date amounts to $42.4 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 Provisions and contingent liabilities in Note 2 on page 27, 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 Principal risks and uncertainties on pages 42 – 49.

Trust update

During the second quarter, $978 million was paid out of the Deepwater Horizon Oil Spill Trust (Trust) and qualified settlement funds (QSFs), including $912 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $65 million for natural resource damage assessment and early restoration. Of these amounts, $944 million is shown as a utilization of provisions this quarter, the remainder represents settlement of payables. In addition, $179 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 30 June 2013, the aggregate cash balances in the Trust and the QSFs amounted to $8.2 billion, including $1.4 billion remaining in the seafood compensation fund which is yet to be distributed.

As at 30 June 2013, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, amounted to $19.7 billion. This represents an increase of $1.4 billion for the quarter which relates principally to business economic loss claims processed by the DHCSSP for which eligibility notices have been issued, as well as increases in the provision for claims administration costs. A further $0.3 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 not yet processed by the DHCSSP as this liability cannot currently be estimated reliably. Given the current rate of issuance of eligibility notices for business economic loss claims under the DHCSSP, we expect that in the third quarter the remaining amount for items covered by the Trust will be fully utilized and additional amounts will be charged to the income statement. See Note 2 on pages 25 – 30 and Legal proceedings on pages 50 – 52 for further details.

Legal proceedings and investigations

Phase 1 of the Multi-District Litigation 2179 (MDL 2179) trial took place in federal court in New Orleans, Louisiana between 25 February and 17 April 2013. 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 incident and is now scheduled to commence on 30 September 2013.

On 8 July 2013, the US Court of Appeals for the Fifth Circuit heard BP’s appeal regarding the current implementation of the DHCSSP for the Economic and Property Damages Settlement. BP does not know when the court will rule on the appeal. For further details, see Legal proceedings on pages 50 – 52.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 53.

Group income statement


Second quarter			Second quarter				First half			First half
2012			2013				2013			2012
						$ million
	94,975			94,711		Sales and other operating revenues (Note 5)		188,818			189,853
	(36	)		102		Earnings from joint ventures – after interest and tax		227			115
	545			448		Earnings from associates – after interest and tax		732			1,805
	195			207		Interest and other income		364			390
	742			236		Gains on sale of businesses and fixed assets		12,777			1,675

	96,421			95,704		Total revenues and other income		202,918			193,838
	76,993			75,127		Purchases		146,788			149,294
	7,895			7,126		Production and manufacturing expenses^(a)		13,994			14,616
	1,827			1,672		Production and similar taxes (Note 6)		3,667			4,173
	2,925			3,162		Depreciation, depletion and amortization		6,359			6,186
	4,821			610		Impairment and losses on sale of businesses and fixed assets		720			4,961
	616			434		Exploration expense		756			876
	3,213			3,223		Distribution and administration expenses		6,177			6,341
	(270	)		(135	)	Fair value gain on embedded derivatives		(166	)		(171	)

	(1,599	)		4,485		Profit (loss) before interest and taxation		24,623			7,562
	253			252		Finance costs^(a)		534			522
	137			117		Net finance expense relating to pensions and other post-retirement benefits		239			273

	(1,989	)		4,116		Profit (loss) before taxation		23,850			6,767
	(515	)		1,990		Taxation^(a)		4,782			2,413

	(1,474	)		2,126		Profit (loss) for the period		19,068			4,354

						Attributable to
	(1,519	)		2,042		BP shareholders		18,905			4,248
	45			84		Non-controlling interests		163			106

	(1,474	)		2,126				19,068			4,354

						Earnings per share – cents (Note 7)
						Profit (loss) for the period attributable to BP shareholders
	(7.99	)		10.73		Basic		99.07			22.35
	(7.99	)		10.68		Diluted		98.53			22.05

(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


Second quarter			Second quarter				First half			First half
2012			2013				2013			2012
						$ million
	(1,474	)		2,126		Profit (loss) for the period		19,068			4,354

						Other comprehensive income (expense)
						Items that may be reclassified subsequently to profit or loss
	(1,045	)		(1,506	)	Currency translation differences		(2,093	)		(470	)
	(12	)		—		Exchange gains on translation of foreign operations reclassified to gain or loss on sales of businesses and fixed assets		—			(12	)
	(109	)		—		Available-for-sale investments marked to market		(172	)		(45	)
	—			—		Available-for-sale investments reclassified to the income statement		(523	)		—
	(96	)		(25	)	Cash flow hedges marked to market^(a)		(2,166	)		(21	)
	28			(1	)	Cash flow hedges reclassified to the income statement		(1	)		30
	4			12		Cash flow hedges reclassified to the balance sheet		15			9
	(335	)		(88	)	Share of items relating to equity-accounted entities, net of tax		(55	)		(126	)
	7			26		Income tax relating to items that may be reclassified		195			(25	)

	(1,558	)		(1,582	)			(4,800	)		(660	)

						Items that will not be reclassified to profit or loss
	(2,110	)		2,206		Remeasurements of the net pension and other post-retirement benefit liability or asset		2,156			(501	)
	1			—		Share of items relating to equity-accounted entities, net of tax		—			(5	)
	608			(732	)	Income tax relating to items that will not be reclassified		(731	)		151

	(1,501	)		1,474				1,425			(355	)

	(3,059	)		(108	)	Other comprehensive income (expense)		(3,375	)		(1,015	)

	(4,533	)		2,018		Total comprehensive income (expense)		15,693			3,339

						Attributable to
	(4,567	)		1,956		BP shareholders		15,556			3,238
	34			62		Non-controlling interests		137			101

	(4,533	)		2,018				15,693			3,339

(a)	First half 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

BP
shareholders’
equity

Non-controlling
interests

Total
equity

$ million

At 1 January 2013

118,546

1,206

119,752

Total comprehensive income

15,556

137

15,693

Dividends

(3,020

)

(236

)

(3,256

)

Repurchases of ordinary share capital

(2,469

)

—

(2,469

)

Share-based payments (net of tax)

378

—

378

Transactions involving non-controlling interests

—

At 30 June 2013

128,991

1,142

130,133


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


Total comprehensive income		3,238			101			3,339
Dividends		(2,659	)		(52	)		(2,711	)
Share-based payments (net of tax)		177			—			177
Transactions involving non-controlling interests		—			25			25

At 30 June 2012		112,324			1,091			113,415

Group balance sheet


	30 June 2013		31 December 2012
$ million
Non-current assets
Property, plant and equipment		128,370		125,331
Goodwill		11,936		12,190
Intangible assets		25,360		24,632
Investments in joint ventures		8,719		8,614
Investments in associates		14,924		2,998
Other investments		1,732		2,704

Fixed assets		191,041		176,469
Loans		604		642
Trade and other receivables		5,538		5,961
Derivative financial instruments		3,548		4,294
Prepayments		859		830
Deferred tax assets		855		874
Defined benefit pension plan surpluses		11		12

		202,456		189,082


Current assets
Loans		188		247
Inventories		28,314		28,203
Trade and other receivables		42,381		37,611
Derivative financial instruments		2,748		4,507
Prepayments		1,573		1,091
Current tax receivable		567		456
Other investments		712		319
Cash and cash equivalents		28,313		19,635

		104,796		92,069

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

		104,796		111,384

Total assets		307,252		300,466

Current liabilities
Trade and other payables		47,831		46,673
Derivative financial instruments		2,365		2,658
Accruals		6,811		6,875
Finance debt		8,725		10,033
Current tax payable		2,849		2,503
Provisions		6,893		7,587

		75,474		76,329
Liabilities directly associated with assets classified as held for sale (Note 4)		—		846

		75,474		77,175

Non-current liabilities
Other payables		4,841		2,292
Derivative financial instruments		2,483		2,723
Accruals		505		491
Finance debt		38,265		38,767
Deferred tax liabilities		17,127		15,243
Provisions		27,398		30,396
Defined benefit pension plan and other post-retirement benefit plan deficits		11,026		13,627

		101,645		103,539

Total liabilities		177,119		180,714

Net assets		130,133		119,752

Equity
BP shareholders’ equity		128,991		118,546
Non-controlling interests		1,142		1,206

		130,133		119,752

Condensed group cash flow statement


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Operating activities
	(1,989	)		4,116		Profit before taxation		23,850			6,767
						Adjustments to reconcile profit before taxation to net cash provided by operating activities
	3,317			3,453		Depreciation, depletion and amortization and exploration expenditure written off		6,822			6,658
	4,079			374		Impairment and (gain) loss on sale of businesses and fixed assets		(12,057	)		3,286
	(249	)		(254	)	Earnings from equity-accounted entities, less dividends received		(454	)		(730	)
	1			21		Net charge for interest and other finance expense, less net interest paid		193			137
	99			175		Share-based payments		221			133
	(211	)		(86	)	Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(370	)		(371	)
	265			1,308		Net charge for provisions, less payments		1,505			428
	999			(1,796	)	Movements in inventories and other current and non-current assets and liabilities^(a)		(7,141	)		(5,201	)
	(1,863	)		(1,924	)	Income taxes paid		(3,215	)		(3,253	)

	4,448			5,387		Net cash provided by operating activities		9,354			7,854

						Investing activities
	(4,943	)		(6,111	)	Capital expenditure		(11,840	)		(10,390	)
	(116	)		—		Acquisitions, net of cash acquired		—			(116	)
	(463	)		(47	)	Investment in joint ventures		(98	)		(689	)
	(11	)		(8	)	Investment in associates		(4,891	)		(34	)
	521			656		Proceeds from disposal of fixed assets		17,436			1,788
	1,436			2,284		Proceeds from disposal of businesses, net of cash disposed		3,785			1,507
	103			68		Proceeds from loan repayments		90			153

	(3,473	)		(3,158	)	Net cash provided by (used in) investing activities		4,482			(7,781	)

						Financing activities
	17			(1,890	)	Net issue (repurchase) of shares		(1,835	)		38
	3,037			3,039		Proceeds from long-term financing		3,102			6,850
	(613	)		(891	)	Repayments of long-term financing		(1,179	)		(3,029	)
	(761	)		(382	)	Net increase (decrease) in short-term debt		(1,873	)		(92	)
	(1,447	)		(1,398	)	Dividends paid – BP shareholders		(3,020	)		(2,659	)
	(51	)		(85	)	– non-controlling interests		(116	)		(52	)

	182			(1,607	)	Net cash provided by (used in) financing activities		(4,921	)		1,056

	(349	)		12		Currency translation differences relating to cash and cash equivalents		(237	)		(231	)

	808			634		Increase in cash and cash equivalents		8,678			898

	14,267			27,679		Cash and cash equivalents at beginning of period		19,635			14,177
	15,075			28,313		Cash and cash equivalents at end of period		28,313			15,075

(a)

Includes



2,186		509		Inventory holding (gains) losses	102		776
(270	)	(135	)	Fair value gain on embedded derivatives	(166	)	(171	)
(1,439	)	(1,430	)	Movements related to Gulf of Mexico oil spill response	(2,258	)	(3,300	)

Inventory holding gains and losses and fair value gains 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


Second quarter 2012		Second quarter 2013			First half 2013		First half 2012
				$ million
				By business
				Upstream
	1,149		1,562	US^(a)		3,101		2,795
	2,777		2,844	Non-US		5,801		5,765

	3,926		4,406			8,902		8,560

				Downstream
	916		777	US		1,616		1,613
	388		397	Non-US		612		600

	1,304		1,174			2,228		2,213

				Rosneft
	—		—	Non-US^(b)		11,941		—

	—		—			11,941		—

				Other businesses and corporate
	253		68	US		92		411
	120		172	Non-US		308		259

	373		240			400		670

	5,603		5,820			23,471		11,443

				By geographical area
	2,318		2,407	US^(a)		4,809		4,819
	3,285		3,413	Non-US^(b)		18,662		6,624

	5,603		5,820			23,471		11,443

				Included above:
	164		—	Acquisitions and asset exchanges		—		174
	—		—	Other inorganic capital expenditure^(a)(b)		11,941		311

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

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

Exchange rates

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

1.58

1.54

US dollar/sterling average rate for the period

1.54

1.58

1.55

1.52

US dollar/sterling period-end rate

1.52

1.55

1.28

1.31

US dollar/euro average rate for the period

1.31

1.30

1.24

1.30

US dollar/euro period-end rate

1.30

1.24

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
	2,913			4,400		Upstream		9,962			9,896
	(1,732	)		1,016		Downstream		2,663			(873	)
	452			—		TNK-BP^(a)		12,500			1,516
	—			218		Rosneft^(b)		303			—
	(522	)		(573	)	Other businesses and corporate		(1,040	)		(1,193	)

	1,111			5,061				24,388			9,346
	(843	)		(199	)	Gulf of Mexico oil spill response		(221	)		(813	)
	457			129		Consolidation adjustment – UPII		556			(84	)

	725			4,991		RC profit before interest and tax		24,723			8,449
						Inventory holding gains (losses)
	(36	)		(4	)	Upstream		(6	)		(120	)
	(2,199	)		(515	)	Downstream		(107	)		(704	)
	(89	)		—		TNK-BP (net of tax)		—			(63	)
	—			13		Rosneft (net of tax)		13			—

	(1,599	)		4,485		Profit before interest and tax		24,623			7,562
	253			252		Finance costs		534			522
	137			117		Net finance expense relating to pensions and other post-retirement benefits		239			273

	(1,989	)		4,116		Profit before taxation		23,850			6,767

						RC profit before interest and tax
	(4,246	)		1,206		US		2,977			(2,311	)
	4,971			3,785		Non-US		21,746			10,760

	725			4,991				24,723			8,449

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See Note 3 on page 31 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 10 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)


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Upstream
	(1,455	)		65		Impairment and gain (loss) on sale of businesses and fixed assets^(b)		(37	)		(527	)
	—			—		Environmental and other provisions		—			—
	—			—		Restructuring, integration and rationalization costs		—			—
	271			135		Fair value gain (loss) on embedded derivatives		166			171
	(311	)		(57	)	Other		(66	)		(317	)

	(1,495	)		143				63			(673	)

						Downstream
	(2,653	)		(310	)	Impairment and gain (loss) on sale of businesses and fixed assets^(c)		(276	)		(2,738	)
	—			—		Environmental and other provisions		(9	)		—
	(12	)		(2	)	Restructuring, integration and rationalization costs		(4	)		(24	)
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	(13	)		(11	)	Other		(15	)		(22	)

	(2,678	)		(323	)			(304	)		(2,784	)

						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
	29			(129	)	Impairment and gain (loss) on sale of businesses and fixed assets		(130	)		(21	)
	—			(6	)	Environmental and other provisions		(6	)		(15	)
	(1	)		—		Restructuring, integration and rationalization costs		(2	)		(1	)
	(1	)		—		Fair value gain (loss) on embedded derivatives		—			—
	(9	)		—		Other^(d)		(3	)		(181	)

	18			(135	)			(141	)		(218	)

	(843	)		(199	)	Gulf of Mexico oil spill response		(221	)		(813	)

	(4,998	)		(514	)	Total before interest and taxation		11,897			(4,581	)
	(4	)		(10	)	Finance costs^(e)		(20	)		(10	)

	(5,002	)		(524	)	Total before taxation		11,877			(4,591	)
	1,663			158		Taxation credit (charge)^(f)		181			1,437

	(3,339	)		(366	)	Total after taxation for period		12,058			(3,154	)

(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 11.

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

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

(d)	Second quarter and half year 2012 include $10 million and $171 million respectively relating to our exit from the solar business.

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

(f)

For the Gulf of Mexico oil spill and certain impairment losses and disposal gains, tax is based on statutory rates, except for non-deductible items. For other items reported for 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 reported within the equity-accounted earnings of TNK-BP are reported net of tax.

Non-GAAP information on fair value accounting effects


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Favourable (unfavourable) impact relative to management’s measure of performance
	7			(31	)	Upstream		(91	)		(126	)
	(187	)		138		Downstream		125			(149	)

	(180	)		107				34			(275	)
	72			(53	)	Taxation credit (charge)^(a)		(23	)		112

	(108	)		54				11			(163	)

(a)	Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, equity-accounted earnings and certain impairment losses and disposal gains).

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historic cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in income because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement from the time the derivative commodity contract is entered into on a fair value basis using forward prices consistent with the contract maturity.

BP enters into commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.

IFRS requires that inventory held for trading be recorded at its fair value using period-end spot prices whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices resulting in measurement differences.

BP enters into contracts for pipelines and storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments, which are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, capacity, oil and gas processing and LNG contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Upstream
	2,906			4,431		Replacement cost profit before interest and tax adjusted for fair value accounting effects		10,053			10,022
	7			(31	)	Impact of fair value accounting effects		(91	)		(126	)

	2,913			4,400		Replacement cost profit before interest and tax		9,962			9,896

						Downstream
	(1,545	)		878		Replacement cost profit before interest and tax adjusted for fair value accounting effects		2,538			(724	)
	(187	)		138		Impact of fair value accounting effects		125			(149	)

	(1,732	)		1,016		Replacement cost profit (loss) before interest and tax		2,663			(873	)

						Total group
	(1,419	)		4,378		Profit before interest and tax adjusted for fair value accounting effects		24,589			7,837
	(180	)		107		Impact of fair value accounting effects		34			(275	)

	(1,599	)		4,485		Profit (loss) before interest and tax		24,623			7,562

Realizations and marker prices

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

Average realizations^(a)

Liquids ($/bbl)^(b)

101.16

90.51

93.44

100.20

104.18

99.12

Europe

103.49

110.91

99.72

97.26

Rest of World

102.50

107.21

100.89

94.92

BP Average

99.08

104.67

Natural gas ($/mcf)

1.91

3.37

3.15

2.08

9.06

9.37

Europe

9.59

8.43

5.09

5.89

Rest of World

6.01

5.22

4.54

5.37

BP Average

5.45

4.62

Total hydrocarbons ($/boe)

61.35

58.62

60.82

62.20

82.13

84.24

Europe

87.86

84.92

55.48

59.53

Rest of World

60.90

57.94

60.17

61.27

BP Average

63.23

62.18

Average oil marker prices ($/bbl)

108.29

102.43

Brent

107.50

113.61

93.30

94.07

West Texas Intermediate

94.17

98.16

109.85

104.53

Alaska North Slope

107.65

114.12

104.05

99.41

Mars

104.10

109.73

106.31

101.89

Urals (NWE – cif)

106.21

111.76

48.22

51.28

Russian domestic oil

53.22

53.09

Average natural gas marker prices

2.21

4.10

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

3.72

2.47

57.38

65.60

UK Gas – National Balancing Point (p/therm)

69.72

58.41

(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.

BP share of TNK-BP production for comparative periods


Second quarter 2012		Second quarter 2013			First half 2013		First half 2012
				$ million
				Production (net of royalties) (BP share)^(a)(b)
	881		—	Crude oil (mb/d)		377		880
	779		—	Natural gas (mmcf/d)		370		796
	1,016		—	Total hydrocarbons (mboe/d)^(c)		441		1,018

(a)

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. Estimated hydrocarbon production for the first half 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the half year as appropriate.

(b)	On 21 March 2013, Rosneft acquired 100% of TNK-BP. BP’s share of Rosneft production, which includes TNK-BP, is shown on page 10.

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

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.

After making enquiries, the directors have a reasonable expectation that the group has adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the interim financial statements.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB, however, the differences have no impact on the group’s consolidated financial statements for the periods presented.

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

As noted in BP’s results announcement for the first quarter 2013, 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 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, profit before tax was $767 million and $500 million lower for full year 2012 and the first half 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 30 June 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 was published in the quarterly supplement of BP Financial and Operating Information 2008-2012 on bp.com/investors in May 2013.


	First quarter 2012						Second quarter 2012						Third quarter 2012						Fourth quarter 2012						Full year 2012
Selected lines only	As reported			As restated			As reported			As restated			As reported			As restated			As reported			As restated			As reported			As restated
$ million
(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 50 – 52 of this report.

The group income statement includes a pre-tax charge of $209 million for the second quarter in relation to the Gulf of Mexico oil spill and $241 million for the first half 2013. The second-quarter charge reflects an increase in the litigation and claims provision, the ongoing costs of the Gulf Coast Restoration Organization and adjustments to other provisions. The cumulative pre-tax income statement charge since the incident amounts to $42,448 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 Provisions 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 Principal risks and uncertainties on pages 42 – 49.

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


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Income statement
	843			199		Production and manufacturing expenses		221			813

	(843	)		(199	)	Profit (loss) before interest and taxation		(221	)		(813	)
	4			10		Finance costs		20			10

	(847	)		(209	)	Profit (loss) before taxation		(241	)		(823	)
	102			42		Taxation		37			76

	(745	)		(167	)	Profit (loss) for the period		(204	)		(747	)


	30 June 2013						31 December 2012
	Total			Of which: amount related to the trust fund			Total			Of which: amount related to the trust fund
$ million
Balance sheet
Current assets
Trade and other receivables		4,530			4,530			4,239			4,178
Current liabilities
Trade and other payables		(1,063	)		(1	)		(522	)		(22	)
Provisions		(5,183	)		—			(5,449	)		—

Net current assets (liabilities)		(1,716	)		4,529			(1,732	)		4,156

Non-current assets
Other receivables		2,067			2,067			2,264			2,264
Non-current liabilities
Other payables		(3,144	)		—			(175	)		—
Provisions		(6,057	)		—			(9,751	)		—
Deferred tax		3,443			—			4,002			—

Net non-current assets (liabilities)		(3,691	)		2,067			(3,660	)		2,264

Net assets (liabilities)		(5,407	)		6,596			(5,392	)		6,420

Notes

2.	Gulf of Mexico oil spill (continued)


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Cash flow statement – Operating activities
	(847	)		(209	)	Profit (loss) before taxation		(241	)		(823	)
						Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
	4			10		Net charge for interest and other finance expense, less net interest paid		20			10
	585			1,390		Net charge for provisions, less payments		1,694			670
	(1,439	)		(1,430	)	Movements in inventories and other current and non-current assets and liabilities		(2,258	)		(3,300	)

	(1,697	)		(239	)	Pre-tax cash flows		(785	)		(3,443	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an inflow of $142 million and an outflow of $189 million in the second quarter and first half of 2013 respectively. For the same periods in 2012, the amounts were an outflow of $1,669 million and $2,877 million respectively.

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 30 June 2013. The increase in the provision of $1,419 million for the second quarter ($1,911 million for the first half) relates principally to business economic loss claims processed by the DHCSSP for which eligibility notices have been issued, as well as increases in the provision for claims administration costs. The amount of the reimbursement asset at 30 June 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund – see below.


	Second quarter 2013			First half 2013
$ million
Opening balance		6,156			6,442
Increase in provision for items covered by the trust fund		1,419			1,911
Amounts paid directly by the trust fund		(978	)		(1,756	)

At 30 June 2013		6,597			6,597

Of which – current		4,530			4,530
– non-current		2,067			2,067

Any increases in estimated future expenditure that will be covered by the trust fund (up to an aggregate of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 30 June 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,707 million. Thus, a further $293 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. Additional liabilities 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,

Notes

2.	Gulf of Mexico oil spill (continued)

including the various claims described in Legal proceedings on pages 50 – 52 in this report and on pages 162 – 169 of BP Annual Report and Form 20-F 2012, would be expensed to the income statement. Information on those items that currently cannot be reliably estimated is provided under Provisions below. Given the current rate of issuing eligibility notices for business economic loss claims under the DHCSSP, we expect that in the third quarter the remaining amount for items covered by the trust fund will be fully utilized and additional amounts will be charged to the income statement.

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 30 June 2013, the aggregate cash balances in the Trust and the QSFs amounted to $8,240 million, including $1,351 million remaining in the seafood compensation fund which has yet to be distributed. Should the cash balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.

The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012. The interpretation of the EPD Settlement Agreement is currently subject to challenge. 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 claims administrator has been appointed 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 50 – 52 herein and 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 second quarter and first half of 2013 are presented in the tables below.

Environmental

Spill
response

Litigation
and claims

Clean Water
Act penalties

Total

$ million

At 1 April 2013

1,742

320

5,222

3,510

10,794

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

—

(72

)

250

—

178

Increase in provision – items covered by the trust fund

—

1,419

—

1,419

Utilization

– paid by BP

(14

)

(43

)

(150

)

—

(207

)

– paid by the trust fund

(65

)

—

(879

)

—

(944

)

At 30 June 2013

1,663

205

5,862

3,510

11,240

Of which

– current

514

175

4,494

—

5,183

– non-current

1,149

1,368

3,510

6,057

Of which

– payable from the trust fund

1,298

5,201

—

6,546

Notes

2.	Gulf of Mexico oil spill (continued)

Environmental

Spill
response

Litigation
and claims

Clean Water
Act penalties

Total

$ million

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

)

(66

)

258

—

168

Increase in provision – items covered by the trust fund

—

1,887

—

1,911

Unwinding of discount

—

Reclassified to other payables

—

(3,933

)

—

(3,933

)

Utilization

– paid by BP

(37

)

(74

)

(274

)

—

(385

)

– paid by the trust fund

(163

)

—

(1,559

)

—

(1,722

)

At 30 June 2013

1,663

205

5,862

3,510

11,240

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 shoreline operational activity.

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.

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 only for business economic loss claims for which eligibility notices have been issued by the DHCSSP and continues to consider that no reliable estimate can be made of business economic loss claims not yet received or not yet processed by the DHCSSP. Further details are provided below.

The provision for business economic loss claims for which eligibility notices have been issued by the DHCSSP has been increased by $0.9 billion during the second quarter to reflect additional notices issued for claims received and processed subsequent to finalizing BP’s first quarter results announcement dated 30 April 2013. In addition, further claims administration costs of $0.5 billion have been provided for in the second quarter.

As disclosed in BP Annual Report and Form 20-F 2012, as part of its monitoring of payments made by the DHCSSP, 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 federal district court in New Orleans (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 appealed the District Court’s ruling on the interpretation of the EPD Settlement Agreement as it relates to business economic loss claims to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) and oral arguments were presented to the Fifth Circuit on 8 July 2013. For further information, see Legal proceedings on pages 50 – 52 in this report.

Given: (i) the inherent uncertainty as to the interpretation of the EPD Settlement Agreement that currently exists and will continue until the Fifth Circuit rules in the appeal described above and thereafter until the impact of such ruling on the value and volume of future claims becomes clear; (ii) the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends – the number of claims received and the average claims payments have been higher than previously assumed by BP, which may or may not continue; and (iii) uncertainty as to the ultimate deadline for filing business economic loss claims, which is dependent on the date at which all relevant appeals are concluded, management is unable to estimate reliably future claims based on the claims data received to date and therefore continues to believe that no reliable estimate can be made of any business economic loss claims not yet received or not yet processed by the DHCSSP. A provision will be established when a reliable estimate can be made of the liability as explained more fully below.

Notes

2.	Gulf of Mexico oil spill (continued)

As reported in BP Annual Report and Form 20-F 2011, the estimated cost of the PSC settlement for Individual and Business Claims was originally $7.8 billion. BP’s current estimate of the total cost of those elements of the PSC settlement that can be estimated reliably, which for business economic loss claims only includes claims for which eligibility notices have been issued by the DHCSSP, is $9.6 billion. The provision excludes any future business economic loss claims not yet received or not yet processed by the DHCSSP.

If BP is successful in challenging the claims administrator’s interpretation of the EPD Settlement Agreement before the Fifth Circuit, the total cost of the PSC settlement will nevertheless be significantly higher than the current estimate of $9.6 billion because the current estimate does not reflect business economic loss claims not yet received or not yet processed. There are a significant number of business economic loss claims which have been received but have not yet been processed, and further claims are likely to be received.

If BP is ultimately unsuccessful in its challenge of the claims administrator’s interpretation of the EPD Settlement Agreement, a further significant increase to the total cost of the PSC settlement will be required. In addition to the current challenge before the Fifth Circuit, BP is continuing to evaluate available further legal options to challenge the District Court’s rulings and their effect. However, there can be no certainty as to how the dispute will ultimately be resolved or determined.

To the extent that the costs of the PSC settlement cause the aggregate amounts provided for under the Trust to exceed $20 billion, such costs will be 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 50 – 52 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. The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court in the federal multi-district litigation proceedings in New Orleans (MDL 2179) as to gross negligence, the volume of oil spilled and the application of penalty factors, or upon any settlement, if one were to be reached. The trial court has wide discretion in its determination as to whether a defendant’s conduct involved gross negligence. See BP Annual Report and Form 20-F 2012 – Financial statements – Note 36 for further details.

Provision movements and analysis of income statement charge

A net increase in the provision for the estimated cost of the settlement with the PSC and various other costs of $1,597 million for the second quarter and $2,079 million for the first half 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, were reclassified to payables during the first quarter, upon court approval. Utilization of the provision of $2,107 million during the first half of 2013 included $1,460 million paid out under the PSC settlement from the Trust.

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


	Second quarter 2013			First half 2013
$ million
Net increase in provisions		1,597			2,079
Recognition of reimbursement asset		(1,419	)		(1,911	)
Other net costs charged (credited) directly to the income statement		21			53

Loss before interest and taxation		199			221
Finance costs		10			20

Loss before taxation		209			241

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 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 50 – 52, the cost of business economic loss claims under the PSC settlement not yet received or not yet 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 BP Annual Report and Form 20-F 2012 – Financial Statements Note – 43.

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 50 – 52, 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 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 50 – 52 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 30 June 2013.

At 30 June 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.

See also BP Annual Report and Form 20-F 2012 – Financial statements – Note 43.

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 in the first quarter, was $12.5 billion as shown in the table below.


	$ million
Agreed cash disposal proceeds		25,425
Amount settled net in Rosneft shares (9.80% stake)		(8,309	)
TNK-BP dividend received by BP in December 2012		(709	)
Interest on cash proceeds		239

Disposal proceeds received in cash		16,646
Shares in Rosneft received (9.80% and 3.04% stake)		10,755

Consideration received		27,401
Less: carrying value of investment in TNK-BP		(12,393	)

		15,008
Deferral of gain		(2,959	)
Gain on existing 1.25% investment in Rosneft		523
Other		(72	)

Gain on disposal of investment in TNK-BP		12,500

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, was 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.


	$ million
Shares in Rosneft received		10,755
Shares purchased from Rosneftegaz		4,871
Value of agreements to purchase Rosneft shares accounted for as derivatives		(726	)
Deferred gain		(2,959	)

Amount included in capital expenditure		11,941
Value of existing 1.25% investment in Rosneft		1,006

Investment in Rosneft on completion		12,947

During the first 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 30 June, and will be finalized during the remainder of 2013.

Notes

4.	Non-current assets held for sale

The disposals of the assets and associated liabilities classified as held for sale at 31 December 2012 completed during the first half of 2013. The sale of the Maclure, Harding and Devenick fields and non-operated interests in the Brae complex of fields and the Braemar field in the central North Sea, and the sale of the Carson refinery in California and related assets in the region completed during the second quarter. The sale of BP’s investment in TNK-BP completed during the first quarter, as described in Note 3, as did the sale of the Texas City refinery.

5.	Sales and other operating revenues

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

$ million

By business

16,606

16,418

Upstream

34,636

35,945

88,262

88,348

Downstream

175,132

174,950

527

414

Other businesses and corporate

834

955

105,395

105,180

210,602

211,850

Less: sales and other operating revenues between businesses

10,348

10,116

Upstream

20,977

21,005

(163

)

109

Downstream

349

583

235

244

Other businesses and corporate

458

409

10,420

10,469

21,784

21,997

Third party sales and other operating revenues

6,258

6,302

Upstream

13,659

14,940

88,425

88,239

Downstream

174,783

174,367

292

170

Other businesses and corporate

376

546

94,975

94,711

Total third party sales and other operating revenues

188,818

189,853

By geographical area

36,372

34,624

69,905

70,874

67,716

69,863

Non-US

138,179

138,119

104,088

104,487

208,084

208,993

9,113

9,776

Less: sales and other operating revenues between areas

19,266

19,140

94,975

94,711

188,818

189,853

6.	Production and similar taxes

Second
quarter
2012

Second
quarter
2013

First
half
2013

First
half
2012

$ million

307

218

590

797

1,520

1,454

Non-US

3,077

3,376

1,827

1,672

3,667

4,173

Notes

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 267 million ordinary shares at a cost of $1,897 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 $422 million has been accrued at 30 June 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.


Second quarter 2012			Second quarter 2013			First half 2013			First half 2012
					$ million
					Results for the period
	(1,519	)		2,042	Profit for the period attributable to BP shareholders		18,905			4,248
	1			1	Less: preference dividend		1			1

	(1,520	)		2,041	Profit attributable to BP ordinary shareholders		18,904			4,247

	1,623			358	Inventory holding (gains) losses, net of tax		91			637

	103			2,399	RC profit attributable to BP ordinary shareholders		18,995			4,884
	3,447			312	Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax		(12,069	)		3,317

	3,550			2,711	Underlying RC profit attributable to BP shareholders		6,926			8,201


					Number of shares (thousand)^(a)
	19,020,874			19,015,720	Basic weighted average number of shares outstanding		19,081,305			18,999,255
	3,170,146			3,169,287	ADS equivalent		3,180,218			3,166,543


	19,284,485			19,108,668	Weighted average number of shares outstanding used to calculate diluted earnings per share		19,185,749			19,257,992
	3,214,081			3,184,778	ADS equivalent		3,197,625			3,209,665


	19,029,938			18,935,572	Shares in issue at period-end		18,935,572			19,029,938
	3,171,656			3,155,929	ADS equivalent		3,155,929			3,171,656

(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)


Second quarter 2012			Second quarter 2013				First half 2013			First half 2012
						$ million
						Opening balance
	46,471			46,425		Finance debt		48,800			44,208
	14,267			27,679		Less: cash and cash equivalents^(b)		19,635			14,177
	1,224			1,083		Less: FV asset of hedges related to finance debt		1,700			1,133

	30,980			17,663		Opening net debt		27,465			28,898


						Closing balance
	47,647			46,990		Finance debt		46,990			47,647
	15,075			28,313		Less: cash and cash equivalents		28,313			15,075
	1,067			460		Less: FV asset of hedges related to finance debt		460			1,067

	31,505			18,217		Closing net debt		18,217			31,505

	(525	)		(554	)	Decrease (increase) in net debt		9,248			(2,607	)


	1,157			622		Movement in cash and cash equivalents (excluding exchange adjustments)		8,915			1,129
	(1,663	)		(1,766	)	Net cash outflow (inflow) from financing (excluding share capital and dividends)		(50	)		(3,729	)
	—			632		Movement in finance debt relating to investing activities^(c)		632			—
	(4	)		20		Other movements		(106	)		(11	)

	(510	)		(492	)	Movement in net debt before exchange effects		9,391			(2,611	)
	(15	)		(62	)	Exchange adjustments		(143	)		4

	(525	)		(554	)	Decrease (increase) in net debt		9,248			(2,607	)

(a)	Net debt is a non-GAAP measure – see page 5 for further information.

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

At 30 June 2013, $139 million of finance debt ($133 million at 30 June 2012) was secured by the pledging of assets. The remainder of finance debt was unsecured.

At 30 June 2013, the company had in place committed bank standby facilities totalling $7.4 billion with $7 billion available to draw and repay until the first half of 2018 and $0.4 billion available to draw and repay until April 2016. No drawings have ever been made against any of the standby facilities.

9.	Inventory valuation

A provision of $229 million was held at 30 June 2013 to write inventories down to their net realizable value. The net movement in the provision during the second quarter 2013 was an increase of $35 million (second quarter 2012 was an increase of $398 million).

10.

Statutory accounts

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

Notes

11.

Condensed consolidating information

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

Issuer

Guarantor

Income statement

BP
Exploration
(Alaska) Inc.

BP p.l.c.

Other
subsidiaries

Eliminations
and
reclassifications

BP
group

$ million

First half 2013

Sales and other operating revenues

2,679

—

188,818

(2,679

)

188,818

Earnings from joint ventures – after interest and tax

—

227

—

227

Earnings from associates – after interest and tax

—

732

—

732

Equity-accounted income of subsidiaries – after interest and tax

—

19,110

—

(19,110

)

—

Interest and other income

406

(117

)

364

Gains on sale of businesses and fixed assets

—

12,777

—

12,777

Total revenues and other income

2,683

19,181

202,960

(21,906

)

202,918

Purchases

437

—

149,030

(2,679

)

146,788

Production and manufacturing expenses

697

—

13,297

—

13,994

Production and similar taxes

530

—

3,137

—

3,667

Depreciation, depletion and amortization

258

—

6,101

—

6,359

Impairment and losses on sale of businesses and fixed assets

(76

)

—

796

—

720

Exploration expense

—

756

—

756

Distribution and administration expenses

223

5,926

)

6,177

Fair value (gain) loss on embedded derivatives

—

(166

)

—

(166

)

Profit (loss) before interest and taxation

807

18,958

24,083

(19,225

)

24,623

Finance costs

607

(115

)

534

Net finance expense (income) relating to pensions and other post-retirement benefits

—

199

—

239

Profit (loss) before taxation

789

18,894

23,277

(19,110

)

23,850

Taxation

328

(11

)

4,465

—

4,782

Profit (loss) for the period

461

18,905

18,812

(19,110

)

19,068

Attributable to

BP shareholders

461

18,905

18,649

(19,110

)

18,905

Non-controlling interests

—

163

—

163

461

18,905

18,812

(19,110

)

19,068

Notes

11.

Condensed consolidating information (continued)


	Issuer		Guarantor
Statement of comprehensive income	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries			Eliminations and reclassifications			BP group
$ million
First half 2013
Profit (loss) for the period		461		18,905		18,812			(19,110	)		19,068

Other comprehensive income (expense)
Items that may be reclassified subsequently to profit or loss
Currency translation differences		—		97		(2,190	)		—			(2,093	)
Exchange gains 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	)		—			(172	)
Available-for-sale investments reclassified to the income statement		—		—		(523	)		—			(523	)
Cash flow hedges marked to market		—		—		(2,166	)		—			(2,166	)
Cash flow hedges reclassified to the income statement		—		—		(1	)		—			(1	)
Cash flow hedges reclassified to the balance sheet		—		—		15			—			15
Share of items relating to equity-accounted entities, net of tax		—		—		(55	)		—			(55	)
Income tax relating to items that may be reclassified		—		—		195			—			195

		—		97		(4,897	)		—			(4,800	)

Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post- retirement benefit liability or asset		—		1,010		1,146			—			2,156
Share of items relating to equity-accounted entities, net of tax		—		—		—			—			—
Income tax relating to items that will not be reclassified		—		—		(731	)		—			(731	)

		—		1,010		415			—			1,425

Other comprehensive income (expense)		—		1,107		(4,482	)		—			(3,375	)

Total comprehensive income (expense)		461		20,012		14,330			(19,110	)		15,693

Attributable to
BP shareholders		461		20,012		14,193			(19,110	)		15,556
Non-controlling interests		—		—		137			—			137

		461		20,012		14,330			(19,110	)		15,693

Notes

11.

Condensed consolidating information (continued)


	Issuer			Guarantor
Income statement	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries			Eliminations and reclassifications			BP group
$ million
First half 2012
Sales and other operating revenues		2,877			—			189,853			(2,877	)		189,853
Earnings from joint ventures – after interest and tax		—			—			115			—			115
Earnings from associates – after interest and tax		—			—			1,805			—			1,805
Equity-accounted income of subsidiaries – after interest and tax		(331	)		4,477			—			(4,146	)		—
Interest and other income		6			104			437			(157	)		390
Gains on sale of businesses and fixed assets		—			—			1,675			—			1,675

Total revenues and other income		2,552			4,581			193,885			(7,180	)		193,838

Purchases		441			—			151,730			(2,877	)		149,294
Production and manufacturing expenses		680			—			13,936			—			14,616
Production and similar taxes		741			—			3,432			—			4,173
Depreciation, depletion and amortization		235			—			5,951			—			6,186
Impairment and losses on sale of businesses and fixed assets		957			—			4,004			—			4,961
Exploration expense		—			—			876			—			876
Distribution and administration expenses		13			483			5,871			(26	)		6,341
Fair value (gain) loss on embedded derivatives		—			—			(171	)		—			(171	)

Profit (loss) before interest and taxation		(515	)		4,098			8,256			(4,277	)		7,562
Finance costs		24			27			602			(131	)		522
Net finance expense (income) relating to pensions and other post-retirement benefits		—			(215	)		488			—			273

Profit (loss) before taxation		(539	)		4,286			7,166			(4,146	)		6,767
Taxation		(31	)		38			2,406			—			2,413

Profit (loss) for the period		(508	)		4,248			4,760			(4,146	)		4,354

Attributable to
BP shareholders		(508	)		4,248			4,654			(4,146	)		4,248
Non-controlling interests		—			—			106			—			106

		(508	)		4,248			4,760			(4,146	)		4,354

Notes

11.

Condensed consolidating information (continued)


	Issuer			Guarantor
Statement of comprehensive income	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries			Eliminations and reclassifications			BP group
$ million
First half 2012
Profit (loss) for the period		(508	)		4,248			4,760			(4,146	)		4,354

Other comprehensive income (expense)
Items that may be reclassified subsequently to profit or loss
Currency translation differences		—			67			(537	)		—			(470	)
Exchange gains on translation of foreign operations reclassified to gain or loss on sales of businesses and fixed assets		—			—			(12	)		—			(12	)
Available-for-sale investments marked to market		—			—			(45	)		—			(45	)
Available-for-sale investments reclassified to the income statement		—			—			—			—			—
Cash flow hedges marked to market		—			—			(21	)		—			(21	)
Cash flow hedges reclassified to the income statement		—			—			30			—			30
Cash flow hedges reclassified to the balance sheet		—			—			9			—			9
Share of items relating to equity-accounted entities, net of tax		—			—			(126	)		—			(126	)
Income tax relating to items that may be reclassified		—			—			(25	)		—			(25	)

		—			67			(727	)		—			(660	)

Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset		—			(78	)		(423	)		—			(501	)
Share of items relating to equity-accounted entities, net of tax		—			—			(5	)		—			(5	)
Income tax relating to items that will not be reclassified		—			—			151			—			151

		—			(78	)		(277	)		—			(355	)

Other comprehensive income (expense)		—			(11	)		(1,004	)		—			(1,015	)

Total comprehensive income (expense)		(508	)		4,237			3,756			(4,146	)		3,339

Attributable to
BP shareholders		(508	)		4,237			3,655			(4,146	)		3,238
Non-controlling interests		—			—			101			—			101

		(508	)		4,237			3,756			(4,146	)		3,339

Notes

11.

Condensed consolidating information (continued)

Issuer

Guarantor

Balance sheet

BP
Exploration
(Alaska)
Inc.

BP p.l.c.

Other
subsidiaries

Eliminations
and
reclassifications

BP
group

$ million

At 30 June 2013

Non-current assets

Property, plant and equipment

8,634

—

119,736

—

128,370

Goodwill

—

11,936

—

11,936

Intangible assets

398

—

24,962

—

25,360

Investments in joint ventures

—

8,719

—

8,719

Investments in associates

—

14,922

—

14,924

Other investments

—

1,732

—

1,732

Subsidiaries – equity-accounted basis

—

151,118

—

(151,118

)

—

Fixed assets

9,032

151,120

182,007

(151,118

)

191,041

Loans

—

5,237

(4,633

)

604

Trade and other receivables

—

5,538

—

5,538

Derivative financial instruments

—

3,548

—

3,548

Prepayments

—

826

—

859

Deferred tax assets

—

855

—

855

Defined benefit pension plan surpluses

—

9,065

151,120

198,022

(155,751

)

202,456

Current assets

Loans

—

188

—

188

Inventories

172

—

28,142

—

28,314

Trade and other receivables

8,855

10,850

42,303

(19,627

)

42,381

Derivative financial instruments

—

2,748

—

2,748

Prepayments

163

—

1,410

—

1,573

Current tax receivable

—

555

—

567

Other investments

—

712

—

712

Cash and cash equivalents

—

28,256

—

28,313

9,190

10,919

104,314

(19,627

)

104,796

Total assets

18,255

162,039

302,336

(175,378

)

307,252

Current liabilities

Trade and other payables

672

435

66,351

(19,627

)

47,831

Derivative financial instruments

—

2,365

—

2,365

Accruals

123

444

6,244

—

6,811

Finance debt

—

8,725

—

8,725

Current tax payable

181

—

2,668

—

2,849

Provisions

—

6,892

—

6,893

977

879

93,245

(19,627

)

75,474

Non-current liabilities

Other payables

4,799

4,664

(4,633

)

4,841

Derivative financial instruments

—

2,483

—

2,483

Accruals

—

464

—

505

Finance debt

—

38,265

—

38,265

Deferred tax liabilities

1,693

—

15,434

—

17,127

Provisions

2,082

—

25,316

—

27,398

Defined benefit pension plan and other post-retirement benefit plan deficits

—

819

10,207

—

11,026

3,786

5,659

96,833

(4,633

)

101,645

Total liabilities

4,763

6,538

190,078

(24,260

)

177,119

Net assets

13,492

155,501

112,258

(151,118

)

130,133

Equity

BP shareholders’ equity

13,492

155,501

111,116

(151,118

)

128,991

Non-controlling interests

—

1,142

—

1,142

Total Equity

13,492

155,501

112,258

(151,118

)

130,133

Notes

11.

Condensed consolidating information (continued)


	Issuer		Guarantor
Balance sheet	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries		Eliminations and reclassifications			BP group
$ million
At 30 June 2012
Non-current assets
Property, plant and equipment		8,137		—		113,823		—			121,960
Goodwill		—		—		12,160		—			12,160
Intangible assets		356		—		22,563		—			22,919
Investments in joint ventures		—		—		8,532		—			8,532
Investments in associates		—		2		13,875		—			13,877
Other investments		—		—		2,439		—			2,439
Subsidiaries – equity-accounted basis		4,471		132,671		—		(137,142	)		—

Fixed assets		12,964		132,673		173,392		(137,142	)		181,887
Loans		—		—		5,051		(4,274	)		777
Trade and other receivables		—		—		8,110		—			8,110
Derivative financial instruments		—		—		5,142		—			5,142
Prepayments		44		—		730		—			774
Deferred tax assets		—		—		683		—			683
Defined benefit pension plan surpluses		—		—		22		—			22

		13,008		132,673		193,130		(141,416	)		197,395

Current assets
Loans		—		—		242		—			242
Inventories		177		—		26,616		—			26,793
Trade and other receivables		3,904		14,856		44,785		(24,962	)		38,583
Derivative financial instruments		—		—		3,770		—			3,770
Prepayments		172		—		1,201		—			1,373
Current tax receivable		—		11		361		—			372
Other investments		—		—		319		—			319
Cash and cash equivalents		—		5		15,070		—			15,075

		4,253		14,872		92,364		(24,962	)		86,527

Assets classified as held for sale		—		—		8,910		—			8,910

		4,253		14,872		101,274		(24,962	)		95,437

Total assets		17,261		147,545		294,404		(166,378	)		292,832

Current liabilities
Trade and other payables		4,684		2,428		64,819		(24,962	)		46,969
Derivative financial instruments		—		—		3,417		—			3,417
Accruals		115		23		6,109		—			6,247
Finance debt		—		—		7,198		—			7,198
Current tax payable		158		—		1,734		—			1,892
Provisions		4		—		7,825		—			7,829

		4,961		2,451		91,102		(24,962	)		73,552

Liabilities directly associated with assets classified as held for sale		—		—		2,524		—			2,524

		4,961		2,451		93,626		(24,962	)		76,076

Non-current liabilities
Other payables		10		4,265		2,630		(4,274	)		2,631
Derivative financial instruments		—		—		3,682		—			3,682
Accruals		—		29		443		—			472
Finance debt		—		—		40,449		—			40,449
Deferred tax liabilities		1,637		—		12,846		—			14,483
Provisions		1,839		—		27,440		—			29,279
Defined benefit pension plan and other post-retirement benefit plan deficits		—		1,966		10,379		—			12,345

		3,486		6,260		97,869		(4,274	)		103,341

Total liabilities		8,447		8,711		191,495		(29,236	)		179,417

Net assets		8,814		138,834		102,909		(137,142	)		113,415

Equity
BP shareholders’ equity		8,814		138,834		101,818		(137,142	)		112,324
Non-controlling interests		—		—		1,091		—			1,091

Total Equity		8,814		138,834		102,909		(137,142	)		113,415

Notes

11.

Condensed consolidating information (continued)

Issuer

Guarantor

Cash flow statement

BP
Exploration
(Alaska)
Inc.

BP p.l.c.

Other
subsidiaries

Eliminations
and
reclassifications

BP
group

$ million

First half 2013

Net cash provided by (used in) operating activities

336

5,358

3,726

(66

)

9,354

Net cash provided by (used in) investing activities

(336

)

4,789

—

4,482

Net cash provided by (used in) financing activities

—

(5,339

)

352

(4,921

)

Currency translation differences relating to cash and cash equivalents

—

(237

)

—

(237

)

Increase in cash and cash equivalents

—

8,630

—

8,678

Cash and cash equivalents at beginning of period

—

19,626

—

19,635

Cash and cash equivalents at end of period

—

28,256

—

28,313


	Issuer			Guarantor
Cash flow statement	BP Exploration (Alaska) Inc.			BP p.l.c.			Other subsidiaries			Eliminations and reclassifications		BP group
$ million
First half 2012
Net cash provided by (used in) operating activities		362			2,842			4,650			—		7,854
Net cash provided by (used in) investing activities		(361	)		—			(7,420	)		—		(7,781	)
Net cash provided by (used in) financing activities		—			(2,844	)		3,900			—		1,056
Currency translation differences relating to cash and cash equivalents		—			7			(238	)		—		(231	)

Increase in cash and cash equivalents		1			5			892			—		898
Cash and cash equivalents at beginning of period		(1	)		—			14,178			—		14,177

Cash and cash equivalents at end of period		—			5			15,070			—		15,075

Principal risks and uncertainties

We urge you to consider carefully the risks described below. The potential impact of the occurrence, or reoccurrence, of any of the risks described below could have a material adverse effect on BP’s business, financial position, results of operations, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda.

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

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

While significant charges have been recognized in the income statement since the Incident occurred in 2010, there is significant uncertainty regarding the extent and timing of the remaining costs and liabilities relating to the Incident, the potential changes in applicable regulations and the operating environment that may result from the Incident, the impact of the Incident on our reputation and the resulting possible impact on our licence to operate including our ability to access new opportunities. The amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any potential determination of BP’s negligence or gross negligence), the outcome of litigation, the terms of any further settlements including the amount and timing of any payments thereunder, and any costs arising from any longer-term environmental consequences of the Incident, will also impact upon the ultimate cost for BP. Although the provisions recognized represent the current best estimates of expenditures required to settle certain present obligations that can be reasonably estimated at the end of the reporting period, there are future expenditures for which it is not possible to measure our obligations reliably and the total amounts paid by BP in relation to all obligations relating to the Incident are subject to significant uncertainty. These uncertainties are likely to continue for a significant period and may cause our costs to increase. Thus, the Incident has had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. The risks associated with the Incident could also heighten the impact of the other risks to which the group is exposed as further described below. See, in particular, Access and renewal; Liquidity, financial capacity and financial, including credit, exposure; Insurance; US government settlements and debarment; Regulatory; Liabilities and provisions; Reporting; and Process safety, personal safety and environmental risks below.

Strategic and commercial risks

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

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

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

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

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

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

Principal risks and uncertainties (continued)

Refining profitability can be volatile, with both periodic over-supply and supply tightness in various regional markets, coupled with fluctuations in demand. Sectors of the petrochemicals industry are also subject to fluctuations in supply and demand, with a consequent effect on prices and profitability. Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.

Governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks of the oil and gas industry, including the risk of increased taxation, nationalization and expropriation.

The global financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. In particular, ongoing instability in or a collapse of the eurozone could trigger a new wave of financial crises and push the world back into recession, leading to lower demand and lower oil and gas prices.

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

Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, potential restrictions on our ability to progress upstream resources and reserves and impacts on revenue generation and strategic growth opportunities. In addition, the reduced level of our participation in alternative energies could carry reputational, economic and technology risks.

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

We have operations, and are seeking new opportunities, in countries and regions where political, economic and social transition is taking place. Some countries have experienced, or may experience in the future, political instability, changes to the regulatory environment, changes in taxation, expropriation or nationalization of property, civil strife, strikes, acts of terrorism, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, could limit our ability to pursue new opportunities, could affect the recoverability of our assets and could cause us to incur additional costs. In particular, our investments in the US, Russia, the Middle East region, North Africa, Bolivia, Argentina, Angola, Azerbaijan and other countries could be adversely affected by heightened political and economic environment risks. See pages 6 – 7 of BP Annual Report and Form 20-F 2012 for information on the locations of our major areas of operation and activities.

We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate or that we have not satisfactorily addressed all relevant stakeholder concerns in respect of our operations, our reputation and shareholder value could be damaged and development opportunities may be precluded.

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

The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on the terms of access to new opportunities, licence costs and product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency, while ensuring safety and operational risk is not compromised. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we require, if our innovation lagged the industry, or if we fail to adequately protect our company brands and trade marks. Our competitive position in comparison to our peers could be adversely affected if competitors offer superior terms for access rights or licences, if we fail to control our operating costs or manage our margins, or if we fail to sustain, develop and operate efficiently a high quality portfolio of assets.

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

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

Principal risks and uncertainties (continued)

Rosneft investment – any future erosion of our relationship with Rosneft could adversely impact our business, the level of our reserves and our reputation.

On 21 March 2013, we completed the sale of our 50% interest in TNK-BP and the purchase of additional shares in Rosneft. We now own a total shareholding in Rosneft of 19.75%. To the extent we fail to maintain a good commercial relationship with Rosneft in the future, or to the extent that as a minority shareholder in Rosneft we are unable in the future to exercise influence over our investment in Rosneft or other growth opportunities in Russia, our business and strategic objectives in Russia and our ability to recognize our share of Rosneft’s reserves as expected may be adversely impacted.

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

Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective group strategy, investment selection and/or subsequent execution could lead to loss of opportunity, loss of value and higher capital expenditure.

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

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

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

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

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

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

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

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

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

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

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

Successful recruitment of new staff, employee training, development and continuing enhancement of skills, in particular technical capabilities such as petroleum engineers and scientists, are key to implementing our plans. Inability to develop human capacity and capability, both across the organization and in specific operating locations, could jeopardize performance delivery. The group relies on recruiting and retaining high-quality employees to execute its strategic plans and to operate its business. The reputational damage suffered by the group as a result of the Incident and any consequent adverse impact on our business could affect employee recruitment and retention.

In addition, significant board and management focus continues to be required in responding to matters related to the Incident. Although BP set up the Gulf Coast Restoration Organization to manage the group’s long-term response, other key management personnel will need to continue to devote substantial attention to addressing the associated consequences for the group, which may negatively impact our staff’s capability to address and respond to other operational matters affecting the group but unrelated to the Incident.

Principal risks and uncertainties (continued)

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

The group seeks to maintain a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity. This framework constrains the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to accurately forecast or maintain sufficient liquidity and credit to meet these needs (including a failure to understand and respond to potential liabilities) could impact our ability to operate and result in a financial loss. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. Trade and other receivables, including overdue receivables, may not be recovered whether an impairment provision has been recognized or not. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth, to maintain our long-term investment programme and to meet our obligations, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements. The group’s financial framework may not be sufficient to respond to a substantial and unexpected cash call or funding request, and external events may materially impact the effectiveness of the group’s financial framework. In addition, operational challenges could impact the availability of the group’s assets, which could adversely affect the group’s operating cash flows.

BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements and enforcement actions relating to the Gulf of Mexico oil spill, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had, and could continue to have, a material adverse impact on the group’s financial performance and liquidity. Further potential liabilities may continue to have a material adverse effect on the group’s results of operations and financial condition. See Note 2 on pages 25 – 30 and Legal proceedings on pages 50 – 52 herein, and Financial statements – Note 43 on page 253 and Legal proceedings on pages 162 – 171 of BP Annual Report and Form 20-F 2012.

Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. In addition, a high proportion of our major project development costs are denominated in local currencies, which may be subject to volatile fluctuations against the US dollar. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues. See Prices and markets above.

See Financial statements – Note 26 on page 220 of BP Annual Report and Form 20-F 2012 for more information on financial instruments and financial risk factors.

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

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

Compliance and control risks

US government settlements and debarment – our settlement with the US Department of Justice and the SEC in respect of federal criminal charges and US securities law violations related to the Gulf of Mexico oil spill may expose us to further penalties, liabilities and private litigation, and may impact our operations and adversely affect our ability to quickly and efficiently access US capital markets.

On 15 November 2012, BP reached an agreement with the US government to resolve all federal criminal and securities claims arising out of the Incident and comprising settlements with the US Department of Justice (DoJ) and the SEC. For a description of the terms of the DoJ and SEC settlements, see Legal proceedings on page 163 of BP Annual Report and Form 20-F 2012. Under the DoJ settlement, BP has agreed to hire an independent third-party auditor who will review and report to the probation officer, the DoJ, and BP regarding BP’s implementation of key terms of the settlement, including procedures and systems related to safety and environmental management, operational oversight, and oil spill response training and drills. The DoJ criminal and SEC settlements impose significant compliance and remedial obligations on BP and its directors, officers and employees. Failure to comply with the terms of these settlements could result in further enforcement action by the DoJ and the SEC, expose BP to severe penalties, financial or otherwise, and subject BP to further private litigation, each of which could impact our operations and have a material adverse effect on the group’s business.

On 28 November 2012, the US Environmental Protection Agency (EPA) notified BP that it had temporarily suspended BP p.l.c., BP Exploration & Production Inc. (BPXP) and a number of other BP subsidiaries from participating in new federal contracts. As a result of the temporary suspension, the BP entities listed in the EPA notice are ineligible to receive any US government contracts either through the award of a new contract, or the extension of the term or renewal of an expiring contract. The suspension does not affect existing contracts the company has with the US government, including those relating to current and ongoing drilling and production operations in the Gulf of Mexico. The EPA may elect to issue a notice of proposed discretionary debarment to some or all of the entities named in the temporary suspension. Like suspension, a discretionary debarment

Principal risks and uncertainties (continued)

would preclude BP entities listed in the notice from receiving new federal fuel contracts, as well as new oil and gas leases, although existing contracts and leases would continue. Discretionary debarment typically lasts three to five years and may be imposed for a longer period, unless it is resolved through an administrative agreement.

The charges to which BPXP pleaded guilty under the DoJ criminal settlement included one misdemeanour count under the Clean Water Act which, by operation of law following the court’s acceptance of BP’s plea, triggers a statutory debarment, also referred to as mandatory debarment, of the BPXP facility where the Clean Water Act violation occurred.

On 1 February 2013, the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. Mandatory debarment prevents a company from entering into new contracts or new leases with the US government that would be performed at the facility where the Clean Water Act violation occurred. A mandatory debarment does not affect any existing contracts or leases a company has with the US government and will remain in place until such time as the debarment is lifted through an agreement with the EPA.

Prolonged suspension or debarment from entering new federal contracts, or further suspension or debarment proceedings against BP and/or its subsidiaries as a result of violations of the terms of the DoJ or SEC settlements or otherwise, could have a material adverse impact on the group’s operations in the US. In particular, prolonged suspension or debarment could prevent BP from accessing and developing material new oil and gas resources located in the US, or prevent BP from engaging in certain development arrangements with third parties that are standard in the oil and gas industry, which could make the development of certain of BP’s existing reserves located in the US less commercially attractive than if relevant BP entities were not suspended or debarred. See Legal proceedings on pages 163 – 164 of BP Annual Report and Form 20-F 2012.

As a result of the SEC settlement, as of 5 February 2013 and for a period of three years thereafter, we are no longer qualified as a ‘well known seasoned issuer’ (WKSI) as defined in Rule 405 of the Securities Act of 1933, as amended (Securities Act), and therefore will not be able to take advantage of the benefits available to a WKSI, including engaging in delayed or continuous offerings of securities using an automatic shelf registration statement. In addition, as of the SEC settlement date of 15 November 2012 and for a period of five years thereafter, we are no longer able to utilize certain registration exemptions provided by the Securities Act in connection with certain securities offerings. We also may be denied certain trading authorizations under the rules of the US Commodities Futures Trading Commission, which may prevent us in the future from entering certain routine swap transactions for an indefinite period of time.

Regulatory – BP, and the oil industry in general, face increased regulation in the US and elsewhere that could increase the cost of regulatory compliance and limit our access to new exploration properties.

Due to the Gulf of Mexico oil spill and any remedial provisions contained in or resulting from the DoJ and SEC settlements (see Legal proceedings on pages 162 – 169 of BP Annual Report and Form 20-F 2012), it is likely that there will be more stringent regulation of BP’s oil and gas activities in the US and elsewhere, particularly relating to environmental, health and safety controls and oversight of drilling operations, as well as access to new drilling areas. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards BP. New regulations and legislation, the terms of BP’s settlements with US government authorities and future settlements or litigation outcomes related to the Incident, and/or evolving practices could increase the cost of compliance and may require changes to our drilling operations, exploration, development and decommissioning plans, and could impact our ability to capitalize on our assets and limit our access to new exploration properties or operatorships, particularly in the deepwater Gulf of Mexico. In addition, increases in taxes, royalties and other amounts payable to governments or governmental agencies, or restrictions on availability of tax relief, could also be imposed as a response to the Incident.

In addition, the oil industry in general is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental, health and safety controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights.

We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs. See pages 94 – 97 of BP Annual Report and Form 20-F 2012 for more information on environmental regulation.

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

Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, diversity, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Our values are intended to guide the way we and our employees behave and do business. Under the terms of the DoJ settlement (see Legal proceedings on page 163 of BP Annual Report and Form 20-F 2012), an ethics monitor

Principal risks and uncertainties (continued)

will review and provide recommendations for the improvement of our code of conduct and its implementation and enforcement. Incidents of ethical misconduct, non-compliance with the recommendations of the ethics monitor or non-compliance with applicable laws and regulations, including non-compliance with anti-bribery, anti-corruption, anti-manipulation and other applicable laws could be damaging to our reputation and shareholder value and could subject us to litigation and regulatory action or penalties under the terms of the DoJ settlement or otherwise. Multiple events of non-compliance could call into question the integrity of our operations. For example, in our trading businesses, there is the risk that a determined individual could operate as a ‘rogue trader’, acting outside BP’s delegations, controls or code of conduct and in contravention of our values in pursuit of personal objectives that could be to the detriment of BP and its shareholders.

For certain legal proceedings involving the group, see Legal proceedings on pages 50 – 52 herein and Legal proceedings on pages 162-171 of BP Annual Report and Form 20-F 2012. For further information on the risks involved in BP’s trading activities, see Treasury and trading activities below.

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

Under the Oil Pollution Act of 1990 (OPA 90), BP Exploration & Production Inc. and BP Corporation North America are among the parties financially responsible for the clean-up of the Gulf of Mexico oil spill and for certain economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages.

BP and certain of its subsidiaries have also been named as defendants in numerous lawsuits in the US arising out of the Incident, including actions for personal injury and wrongful death, purported class actions for commercial or economic injury, actions for breach of contract, violations of statutes, property and other environmental damage, securities law claims and various other claims, and additional lawsuits or private claims arising out of the Incident may be brought in the future. See Legal proceedings on pages 50 –52 herein and on pages 162 – 169 of BP Annual Report and Form 20-F 2012.

The first phase of the Trial of Liability, Limitation, Exoneration, and Fault Allocation in the federal multi-district litigation proceeding in New Orleans (MDL 2179) commenced on 25 February 2013. This first 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. The trial court has wide discretion in its determination as to whether a defendant’s conduct involved gross negligence. Under the Clean Water Act, any finding of gross negligence for purposes of penalties sought against BP would result in significantly higher fines and penalties than the amounts for which we have provided and would also have a material adverse impact on the group’s reputation, would affect our ability to recover costs relating to the Incident from other parties responsible under OPA 90 and could affect the fines and penalties payable by BP with respect to the Incident under enforcement actions outside the Clean Water Act context. The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court in MDL 2179 as to gross negligence, the volume of oil spilled and the application of penalty factors, or upon any settlement, if one were to be reached.

On 3 March 2012, BP reached an agreement (comprising two separate settlement agreements) with the Plaintiffs’ Steering Committee (PSC) in MDL 2179 to resolve the substantial majority of legitimate private economic and property damages claims and medical benefits claims stemming from the Incident. The settlement agreement in respect of economic and property damages claims was approved by the Court on 21 December 2012, and the settlement agreement in respect of medical benefits claims was approved on 11 January 2013. For further information on the PSC settlements, see Legal proceedings on pages 166 – 168 of BP Annual Report and Form 20-F 2012.

As previously disclosed, as part of its monitoring of payments made by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. On 5 March 2013, the federal district court in New Orleans (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 subsequently appealed the District Court’s 5 March 2013 rulings to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), and a hearing was held before the Fifth Circuit on 8 July 2013. For further information, see Legal proceedings on pages 50 – 52 herein.

BP’s current estimate of the total cost of those elements of the PSC settlement that can be estimated reliably, which for business economic loss claims only includes claims for which eligibility notices have been issued by the DHCSSP, is $9.6 billion. This provision excludes any future business economic loss claims not yet received or not yet processed by the DHCSSP. If BP is successful in challenging the claims administrator’s interpretation of the EPD Settlement Agreement, the total cost of the PSC settlement will, nevertheless, be significantly higher than the current estimate of $9.6 billion because the current estimate does not reflect business economic loss claims not yet received or not yet processed. There are a significant number of business economic loss claims which have been received but have not yet been processed, and further claims are likely to be received. If BP is ultimately unsuccessful in challenging the claims administrator’s interpretation of the EPD Settlement Agreement, a further significant increase to the

Principal risks and uncertainties (continued)

total cost of the PSC settlement will be required. In addition to the current challenge before the Fifth Circuit, BP is continuing to evaluate available further legal options to challenge the District Court’s rulings and their effect. However, there can be no certainty as to how the dispute will ultimately be resolved or determined. To the extent that the costs of the PSC settlement cause the aggregate amounts provided for under the Trust to exceed $20 billion, such costs will be charged to the income statement. The PSC settlement is uncapped except for economic loss claims related to the Gulf seafood industry. See Note 2 on pages 25 – 30 for further information.

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

See Legal proceedings on pages 50 – 52 and Note 2 on pages 25 – 30 herein, and Legal proceedings on pages 162 – 170 and Financial statements – Note 2 on page 194 of BP Annual Report and Form 20-F 2012.

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

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

As of the date of the SEC settlement, 10 December 2012, and for a period of three years thereafter, we are unable to rely on the safe harbor provisions regarding forward-looking statements provided by the regulations issued under the Securities Act, and the Securities Exchange Act of 1934, as amended. Our inability to rely on these safe harbor provisions may expose us to future litigation and liabilities in connection with forward-looking statements in our public disclosures.

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

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

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

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation. See Legal proceedings on pages 50 – 52 herein.

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

Safety and operational risks

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

Principal risks and uncertainties (continued)

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

The nature of the group’s operations exposes us to a wide range of significant health, safety, security and environmental risks. The scope of these risks is influenced by the geographic range, operational diversity and technical complexity of our activities. In addition, in many of our major projects and operations, risk allocation and management is shared with third parties such as contractors, sub-contractors, joint venture partners and associates. See Strategic and commercial risks – Joint ventures and other contractual arrangements above.

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

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

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

Under the terms of the DoJ settlement (see Legal proceedings on page 163 of BP Annual Report and Form 20-F 2012), a process safety monitor will review, evaluate, and provide recommendations for the improvement of BP’s process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico. Incidents of non-compliance with the recommendations of the process safety monitor could be damaging to our reputation and shareholder value and could subject us to further regulatory action or penalties under the terms of the DoJ settlement. Multiple events of non-compliance could call into question the integrity of our operations.

BP’s group-wide operating management system (OMS) intends to address health, safety, security, environmental and operations risks, and to provide a consistent framework within which the group can analyse the performance of its activities and identify and remediate shortfalls. There can be no assurance that OMS will adequately identify all process safety, personal safety and environmental risk or provide the correct mitigations, or that all operations will be in conformance with OMS at all times.

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

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

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

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

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

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

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

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

Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the half year 2013. 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. The parties completed post-trial briefing in respect of Phase 1 on 12 July 2013. BP is not currently aware of the timing of the court’s ruling in respect of issues addressed in the first trial phase. The trial court has wide discretion in its determination as to whether a defendant’s conduct involved gross negligence. The second trial phase is now scheduled to commence on 30 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 164 of BP Annual Report and Form 20-F 2012.

Additional civil lawsuits and related OPA 90 matters

Since publication of BP Annual Report and Form 20-F 2012 on 6 March 2013, BP p.l.c., BP Exploration & Production Inc. (BPXP) and various other BP entities (collectively referred to as BP) have been among the companies named as defendants in more than 2,200 new civil lawsuits related to the Incident which have been brought in US federal and state courts, and further actions are likely to be brought. As a result of these new lawsuits being brought, BP is now among the companies named as defendants in a total of approximately 2,900 civil lawsuits resulting from the Incident. Plaintiffs in these new lawsuits include individuals, corporations, certain States and local government entities and a foreign government, and the vast majority of these new lawsuits assert claims under the Oil Pollution Act of 1990 (OPA 90). Certain of these new lawsuits relate to earlier submissions of claims to BP under OPA 90 by certain States and local governments, as disclosed in BP Annual Report and Form 20-F 2012. BP believes that claimants in these new 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. These 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 has applied to have these lawsuits consolidated with MDL 2179. For further information, see Contingent liabilities in Note 2 on page 30.

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. The State of Texas has also asserted similar claims. Since publication of BP Annual Report and Form 20-F 2012 on 6 March 2013, certain of these States (Alabama, Mississippi, Florida and Texas) and certain local governments have filed civil lawsuits that pertain to claims asserted by them under their earlier OPA 90 submissions to BP. The civil lawsuits filed by the states of Alabama, Mississippi, Florida and Texas have been consolidated with MDL 2179.

US Environmental Protection Agency (EPA) matters

On 28 November 2012, the EPA notified BP that it had temporarily suspended BP p.l.c., BPXP and a number of other BP subsidiaries from participating in new federal contracts. In addition, as a result of BP’s agreement with the Department of Justice to resolve all federal criminal charges against BP, on 1 February 2013 the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. For further information, see page 163 of BP Annual Report and Form 20-F 2012. BP continues to work with the EPA in preparing an administrative agreement that will resolve these suspension and debarment issues. On 15 February 2013, BP filed an administrative challenge with the EPA seeking to lift the 28 November 2012 suspension of 22 BP entities and the 1 February 2013 statutory debarment of BPXP at its Houston headquarters. On 19 July 2013, the EPA affirmed its suspension and debarment decisions. BP maintains that the EPA’s actions do not have an adequate legal basis and do not reflect BP’s present status as a responsible government contractor. Decisions reached by the EPA can be challenged in federal court.

Legal proceedings (continued)

Plaintiffs’ Steering Committee (PSC) Settlements

The Economic and Property Damages Settlement was approved by the District Court in a final order and judgment on 21 December 2012, and the Medical Benefits Class Action Settlement was approved by the District Court in a final order and judgment on 11 January 2013. For further information, see page 166 – 168 of BP Annual Report and Form 20-F 2012. Since 17 January 2013, eight groups of purported members of the Economic and Property Damages Settlement Class have filed notices of appeal to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) of the final order and judgment approving the Economic and Property Damages Settlement. On 14 June 2013, the Fifth Circuit dismissed one of the eight groups from the Economic and Property Damages Settlement case for want of prosecuting its appeal. Two groups of purported members of the Medical Benefits Settlement Class have also appealed from the final order and judgment approving the Medical Benefits Class Action Settlement. On 25 June 2013, one of the groups of appellants voluntarily dismissed its appeal of the Medical Benefits Class Action Settlement. Additionally, a coalition of fishing and community groups has appealed from an order of the District Court denying it permission to intervene in the civil action serving as the vehicle for the Economic and Property Damages Settlement and further denying it permission to take discovery regarding the fairness of that settlement. On 12 July 2013, five of the seven remaining groups appealing from the Economic and Property Damages Settlement filed their opening briefs, one group filed a motion to voluntarily dismiss its appeal, and one group failed to file a brief. On 11 July 2013, the one remaining group appealing from the Medical Benefits Class Action Settlement case filed its opening brief.

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.

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 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, and oral argument was heard on 8 July 2013. BP is continuing to evaluate other available legal options to challenge the District Court rulings.

On 2 July 2013, the District Court appointed Judge Louis Freeh as Special Master to lead an independent investigation of the DHCSSP in connection with allegations of potential ethical violations or misconduct within the DHCSSP. On 16 July 2013, BP filed a motion with the District Court to temporarily pause all payments from the DHCSSP until Judge Freeh has completed the independent investigation ordered by the District Court. On 19 July 2013, the District Court denied this motion.

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.

Legal proceedings (continued)

MDL 2185 and other securities-related litigation

In April and May 2012, six cases (three of which were consolidated into one action) were filed in state and federal courts by one or more state, county or municipal pension funds against BP entities and several current and former officers and directors seeking damages for alleged losses those funds suffered because of their purchases of BP ordinary shares and, in two cases, ADSs. The funds assert various state law and federal law claims. From July 2012 to April 2013, 12 additional cases were filed in Texas state and federal courts (later consolidated into nine 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, and one case was filed in New York federal court by funds that purchased BP ordinary shares and ADSs, asserting federal law claims. All of the cases have been transferred to federal court in Houston and, with the exception of one case that has been stayed, the judge presiding over the federal multi-district litigation proceeding in Houston (MDL 2185). One case was voluntarily dismissed on 9 May 2013. Oral argument on a motion to dismiss three of the remaining 13 cases proceeded on 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.

Other legal proceedings

On 14 May 2013, European Commission officials made a series of unannounced inspections at the offices of BP and other companies involved in the oil industry acting on concerns that anticompetitive practices may have occurred in connection with oil price reporting practices and the reference price assessment process. Such inspections are a preliminary step in investigations. There is no deadline for the completion of the inquiries. Related inquiries and requests for information have also been received from US and other regulators following the European Commission’s actions. Purported class actions related to these matters have been filed in US District Courts alleging manipulation and antitrust violations under the Commodity Exchange Act and US antitrust laws.

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 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 quarterly dividend payment; the expected level of reported production in the third quarter of 2013; the expected level of costs in the third quarter of 2013; the expected level of reported and underlying production for the full year 2013; the expected timing for the completion of BP’s sale of its 60% interest in the Polvo oil field; BP’s plans to operate two deepwater blocks offshore Brazil; BP’s plans to add $1 billion of new investment and two drilling rigs to the Alaska North Slope fields over the next five years; the expected timing of the completion of the Whiting refinery modernization project; BP’s intentions to invest over $500 million in southern African refining and infrastructure projects; the expected level of refining margins in the third quarter of 2013; the expected level of fuels profitability in the third quarter of 2013; prospects for petrochemicals margins and volumes to the end of 2013; the expected timing of receipt of the next dividend payment from Rosneft; 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 maintenance and/or turnaround activity; the nature, timing and volume of refinery additions and outages; 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 court decisions, the types of enforcement action pursued and the nature of remedies sought or imposed; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed under “Principal risks and uncertainties” herein.

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)