Edgar Filing: BP PLC

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 September 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333-186463) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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 SEPTEMBER 2013(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-September 2013(b)		3 – 14, 22 – 24

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-September 2013		15 – 21, 25 – 36

3.	Legal proceedings		37 – 40

4.	Cautionary statement		41

5.	Computation of Ratio of Earnings to Fixed Charges		42

6.	Capitalization and Indebtedness		43

7.	Signatures		44

(a)

In this Form 6-K, references to the nine months 2013 and nine months 2012 refer to the nine-month periods ended 30 September 2013 and 30 September 2012 respectively. References to third quarter 2013 and third quarter 2012 refer to the three-month periods ended 30 September 2013 and 30 September 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 third quarter and nine months 2013


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	5,281			3,504		Profit for the period(a)		22,409			9,529
	(747	)		(326	)	Inventory holding (gains) losses, net of tax		(235	)		(110	)

	4,534			3,178		Replacement cost profit(b)		22,174			9,419
	483			514		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax(c)		(11,555	)		3,800
	5,017			3,692		Underlying replacement cost profit(b)		10,619			13,219

	27.74			18.57		Profit per ordinary share (cents)		117.86			50.11
	1.66			1.11		Profit per ADS (dollars)		7.07			3.01
	23.82			16.84		Replacement cost profit per ordinary share (cents)		116.62			49.54
	1.43			1.01		Replacement cost profit per ADS (dollars)		7.00			2.97
	26.35			19.57		Underlying replacement cost profit per ordinary share (cents)		55.85			69.52
	1.58			1.17		Underlying replacement cost profit per ADS (dollars)		3.35			4.17

•

BP’s profit for the third quarter and nine months was $3,504 million and $22,409 million respectively, compared with $5,281 million and $9,529 million for the same periods a year ago. BP’s third-quarter replacement cost (RC) profit was $3,178 million, compared with $4,534 million a year ago. After adjusting for a net charge for non-operating items of $522 million and net favourable fair value accounting effects of $8 million (both on a post-tax basis), underlying RC profit for the third quarter was $3,692 million, compared with $5,017 million for the same period in 2012. For the nine months, RC profit was $22,174 million, compared with $9,419 million a year ago. After adjusting for a net gain for non-operating items of $11,536 million and net favourable fair value accounting effects of $19 million (both on a post-tax basis), underlying RC profit for the nine months was $10,619 million, compared with $13,219 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 5, 21 and 23.

•

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 $39 million for the quarter and $280 million for the nine months. 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 14 and Note 2 on pages 27 – 32. Information on the Gulf of Mexico oil spill is also included in Legal proceedings on pages 37 – 39.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and nine months was $6.3 billion and $15.7 billion respectively, compared with $6.2 billion and $14.1 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 third quarter and nine months was $6.3 billion and $15.9 billion respectively, compared with $6.4 billion and $17.1 billion in the same periods last year.

•

Gross debt at the end of the quarter was $50.3 billion compared with $49.1 billion a year ago. The ratio of gross debt to gross debt plus equity at the end of quarter was 27.7%, compared with 29.2% a year ago. Net debt at the end of the quarter was $20.1 billion, compared with $31.3 billion a year ago. The ratio of net debt to net debt plus equity at the end of the quarter was 13.3% compared with 20.9% a year ago. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 6 for more information.

•

Total capital expenditure for the third quarter was $5.9 billion, all of which was organic(d). For the nine months, total capital expenditure was $29.4 billion (including the Rosneft transaction), of which organic capital expenditure was $17.5 billion. Organic capital expenditure for the full year 2013 is expected to be $24 – $25 billion with a similar level of expenditure expected in 2014. Organic capital expenditure through 2020 is expected to be $24 – $27 billion per annum. Disposal proceeds received in cash were $0.4 billion for the quarter and $21.6 billion for the nine months. BP intends to continue to focus its global business portfolio around key assets and strategic strengths, and, as a result, expects to divest a further $10 billion of assets before the end of 2015. Post-tax proceeds from these divestments are expected to be used predominantly for additional distributions to shareholders, with a bias for share buybacks.

•

BP today announced a quarterly dividend of 9.5 cents per ordinary share ($0.57 per ADS), which is expected to be paid on 20 December 2013. The corresponding amount in sterling will be announced on 9 December 2013. See page 6 for further information. Moving forward, BP’s board intends to review the level of dividend with the first and the third quarter results each year.

(a)	Profit attributable to BP shareholders.

(b)	See page 5 for definitions of RC profit and underlying RC profit.

(c)	See pages 22 and 23 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 20 for further information.

The commentaries above and following should be read in conjunction with the cautionary statement on page 41.

Group results third quarter and nine months 2013

•

The effective tax rate (ETR) on the profit for the third quarter and nine months was 31% and 22% respectively, compared with 34% and 35% for the same periods in 2012. The ETR on RC profit for the third quarter and nine months was 31% and 22% respectively, compared with 34% and 35% for the same periods in 2012. Adjusting for non-operating items and fair value accounting effects, the ETR on underlying RC profit in the third quarter and nine months was 31% and 38% respectively, compared with 34% and 34% for the same periods in 2012. Recently enacted UK corporation tax rate changes have resulted in a $99-million deferred tax benefit in the third quarter. In the third quarter 2012 changes in the taxation of UK oil and gas production resulted in a $256-million deferred tax charge. The increase in the underlying ETR for the nine months is mainly due to a reduction in equity-accounted earnings (which are reported net of tax) and foreign exchange impacts on deferred tax, partly offset by the deferred tax adjustments for changes in UK taxation noted above.

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $397 million for the third quarter, compared with $376 million for the same period in 2012. For the nine months, the respective amounts were $1,170 million and $1,171 million.

•

As at 30 September 2013, BP had bought back 465 million shares for a total amount of $3.3 billion, including fees and stamp duty, since the announcement on 22 March 2013 of an $8-billion share repurchase programme expected to be fulfilled over 12 –18 months.

•

Total production for the third quarter, including Rosneft, was 3.17 million barrels of oil equivalent per day (mmboe/d). This comprised 1.83mmboe/d for subsidiaries and 1.34mmboe/d for equity-accounted entities. BP’s share of Rosneft production in the third quarter was 965 thousand barrels of oil equivalent per day.

Analysis of RC profit before interest and tax

and reconciliation to profit for the period


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						RC profit before interest and tax
	4,907			4,158		Upstream		14,120			14,803
	2,408			616		Downstream		3,279			1,535
	1,282			—		TNK-BP(a)		12,500			2,798
	—			792		Rosneft(b)		1,095			—
	(1,096	)		(674	)	Other businesses and corporate		(1,714	)		(2,289	)
	(56	)		(30	)	Gulf of Mexico oil spill response(c)		(251	)		(869	)
	(64	)		263		Consolidation adjustment – UPII(d)		819			(148	)

	7,381			5,125		RC profit before interest and tax		29,848			15,830
	(376	)		(397	)	Finance costs and net finance expense relating to pensions and other post-retirement benefits		(1,170	)		(1,171	)
	(2,405	)		(1,462	)	Taxation on a RC basis		(6,253	)		(5,068	)
	(66	)		(88	)	Non-controlling interests		(251	)		(172	)

	4,534			3,178		RC profit attributable to BP shareholders		22,174			9,419

	1,059			444		Inventory holding gains (losses)		344			172
	(312	)		(118	)	Taxation (charge) credit on inventory holding gains and losses		(109	)		(62	)

	5,281			3,504		Profit for the period attributable to BP shareholders		22,409			9,529

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See Note 3 on page 33 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See page 12 for further information.

(c)	See Note 2 on pages 27 – 32 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 21 for further information on RC profit or loss.

Analysis of underlying RC profit before interest and tax


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Underlying RC profit before interest and tax
	4,366			4,423		Upstream		14,413			15,061
	3,009			720		Downstream		3,562			5,069
	1,294			—		TNK-BP		—			2,903
	—			808		Rosneft		1,111			—
	(573	)		(385	)	Other businesses and corporate		(1,284	)		(1,548	)
	(64	)		263		Consolidation adjustment – UPII		819			(148	)

	8,032			5,829		Underlying RC profit before interest and tax		18,621			21,337
	(373	)		(388	)	Finance costs and net finance expense relating to pensions and other post-retirement benefits		(1,141	)		(1,158	)
	(2,576	)		(1,661	)	Taxation on an underlying RC basis		(6,610	)		(6,788	)
	(66	)		(88	)	Non-controlling interests		(251	)		(172	)

	5,017			3,692		Underlying RC profit attributable to BP shareholders		10,619			13,219

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 22 and 23 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 8 – 13 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

Third
quarter
2012

Third
quarter
2013

Nine
months
2013

Nine
months
2012

Per ordinary share (cents)

27.74

18.57

Profit for the period

117.86

50.11

23.82

16.84

RC profit for the period

116.62

49.54

26.35

19.57

Underlying RC profit for the period

55.85

69.52

Per ADS (dollars)

1.66

1.11

Profit for the period

7.07

3.01

1.43

1.01

RC profit for the period

7.00

2.97

1.58

1.17

Underlying RC profit for the period

3.35

4.17

The amounts shown above are calculated based on the basic weighted average number of shares outstanding. See Note 6 on page 35 for details of the calculation of earnings per share.

Net debt ratio – net debt: net debt + equity


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	49,071			50,284		Gross debt		50,284			49,071
	1,572			734		Less: fair value asset of hedges related to finance debt		734			1,572

	47,499			49,550				49,550			47,499
	16,174			29,499		Less: cash and cash equivalents		29,499			16,174

	31,325			20,051		Net debt		20,051			31,325

	118,883			131,251		Equity		131,251			118,883
	20.9	%		13.3	%	Net debt ratio		13.3	%		20.9	%

See Note 7 on page 36 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 9.5 cents per ordinary share expected to be paid in December. The corresponding amount in sterling will be announced on 9 December 2013, calculated based on the average of the market exchange rates for the four dealing days commencing on 3 December 2013. Holders of American Depositary Shares (ADSs) will receive $0.57 per ADS. The dividend is due to be paid on 20 December 2013 to shareholders and ADS holders on the register on 8 November 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 third-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

Third
quarter
2012

Third
quarter
2013

Nine
months
2013

Nine
months
2012

Dividends paid per ordinary share

8.000

9.000

cents

27.000

24.000

5.017

5.763

pence

17.598

15.263

48.00

54.00

Dividends paid per ADS (cents)

162.00

144.00

Scrip dividends

15.0

65.7

Number of shares issued (millions)

124.0

65.7

105

452

Value of shares issued ($ million)

868

484

THIS PAGE IS INTENTIONALLY LEFT BLANK

Upstream


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	4,919			4,165		Profit before interest and tax		14,121			14,695
	(12	)		(7	)	Inventory holding (gains) losses		(1	)		108

	4,907			4,158		RC profit before interest and tax		14,120			14,803
	(541	)		265		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		293			258

	4,366			4,423		Underlying RC profit before interest and tax(a)		14,413			15,061

(a)	See page 5 for information on underlying RC profit and see page 9 for a reconciliation to segment RC profit before interest and tax by region.

The replacement cost profit before interest and tax for the third quarter and nine months was $4,158 million and $14,120 million respectively, compared with $4,907 million and $14,803 million for the same periods in 2012. The third quarter and nine months included net non-operating charges of $226 million and $163 million respectively, primarily related to impairment charges partly offset by disposal gains and fair value gains on embedded derivatives. A year ago, there was a net non-operating gain of $516 million in the third quarter and a net non-operating charge of $157 million for the nine months. Fair value accounting effects in the third quarter and nine months had unfavourable impacts of $39 million and $130 million respectively, compared with a favourable impact of $25 million and an unfavourable impact of $101 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 third quarter and nine months was $4,423 million and $14,413 million respectively, compared with $4,366 million and $15,061 million a year ago. The result for the third quarter reflected lower production due to divestments and higher exploration write-offs and depreciation, depletion and amortization, offset by higher liquids and gas realizations, an increase in underlying volumes and a one-off benefit, mainly in respect of prior years, resulting from the US Federal Energy Regulatory Commission approval of cost pooling settlement agreements between the owners of the Trans Alaska Pipeline System (TAPS). The result for the nine months reflected the same factors as the third quarter with the exception of liquids realizations, which were lower, and a benefit from stronger gas marketing and trading activities, mainly in the first quarter.

Production for the quarter was 2,207mboe/d, 2.3% lower than the third quarter of 2012. After adjusting for the effects of divestments and entitlement impacts in our production-sharing agreements (PSAs), underlying production increased by 3.4%. This primarily reflects new major project volumes in the North Sea and Angola and the absence of seasonal weather-related downtime in the Gulf of Mexico. For the nine months, production was 2,259mboe/d, 3.0% lower than in the same period last year. After adjusting for the effect of divestments and entitlement impacts in our PSAs, underlying production for the nine months was 3.1% higher than in 2012.

On the back of stronger-than-expected third-quarter production, which benefited from the absence of seasonal adverse weather in the Gulf of Mexico, we expect fourth-quarter reported production to be broadly flat with the third quarter and costs to be higher with the absence of the one-off TAPS pooling benefit. Full-year reported production is expected to be lower than 2012, mainly due to the impact of divestments. The actual reported outcome will also depend on 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 underlying production in 2013 to increase compared with 2012.

We continued to make strategic progress. In August, BP and its partners ConocoPhillips, Chevron and Shell confirmed the installation of the Clair Ridge platform jackets (the steel support structure), a major milestone in the Clair Ridge project in the North Sea.

Also in August, a new gas condensate discovery in the Cauvery basin off the east coast of India was announced by Reliance Industries Limited and BP.

In September, we announced a significant gas discovery, Salamat, in the East Nile Delta. The deepwater exploration well is the deepest well ever drilled in the Nile Delta and the first well in the North Damietta Offshore concession, granted in 2010 and operated by BP.

BP also announced that over $1.5 billion has been awarded in contracts to UK-based companies to provide services and equipment for the major redevelopment of the Schiehallion and Loyal oil fields to the west of Shetland.

Also in September, the Shah Deniz consortium announced that 25-year sales agreements have been concluded for over 10 billion cubic metres of gas per annum to be produced from the Shah Deniz field in Azerbaijan as a result of the development of Stage 2 of the Shah Deniz project. Nine companies will purchase this gas in Italy, Greece and Bulgaria.

At the end of September, gas production started at the Woodside-operated North Rankin 2 project in Australia’s North West Shelf, in which BP has a 16.67% interest.

After the end of the quarter, BP entered into three farm-out agreements with Kosmos Energy covering three blocks in the Agadir Basin, offshore Morocco. Under the terms of the agreements, which are subject to government approval, BP will acquire a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks.

BP also announced that it will appoint Richard Herbert as its new head of exploration. He will succeed Mike Daly who has chosen to retire from BP at the end of 2013 after a career of 28 years with the company, eight leading BP’s exploration function.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 41.

Upstream


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Underlying RC profit before interest and tax
	741			1,301		US		2,910			3,027
	3,625			3,122		Non-US		11,503			12,034

	4,366			4,423				14,413			15,061

						Non-operating items
	465			5		US		61			(861	)
	51			(231	)	Non-US		(224	)		704

	516			(226	)			(163	)		(157	)

						Fair value accounting effects(a)
	(28	)		(84	)	US		(157	)		(38	)
	53			45		Non-US		27			(63	)

	25			(39	)			(130	)		(101	)

						RC profit before interest and tax
	1,178			1,222		US		2,814			2,128
	3,729			2,936		Non-US		11,306			12,675

	4,907			4,158				14,120			14,803

						Exploration expense
	35			147		US(b)		312			510
	255			364		Non-US		955			656

	290			511				1,267			1,166

						Production (net of royalties)(c)
						Liquids (mb/d)(d)
	356			356		US		353			387
	95			75		Europe		95			112
	697			716		Rest of World		720			683

	1,148			1,147				1,168			1,182

	289			303		Of which equity-accounted entities		299			284

						Natural gas (mmcf/d)
	1,545			1,546		US		1,550			1,670
	339			146		Europe		253			439
	4,559			4,458		Rest of World		4,524			4,541

	6,443			6,150				6,327			6,650

	430			409		Of which equity-accounted entities		405			414

						Total hydrocarbons (mboe/d)(e)
	622			622		US		620			675
	153			100		Europe		139			188
	1,483			1,485		Rest of World		1,500			1,466

	2,259			2,207				2,259			2,328

	363			373		Of which equity-accounted entities		369			355

						Average realizations(f)
	99.00			100.66		Total liquids ($/bbl)		99.59			102.79
	4.77			5.01		Natural gas ($/mcf)		5.31			4.67
	60.68			62.80		Total hydrocarbons ($/boe)		63.09			61.69

(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 23.

(b)	Nine months 2012 includes $308 million classified within the ‘other’ category of non-operating items (see page 22).

(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


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	3,390			1,009		Profit before interest and tax		3,565			1,813
	(982	)		(393	)	Inventory holding (gains) losses		(286	)		(278	)

	2,408			616		RC profit before interest and tax		3,279			1,535
	601			104		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects		283			3,534

	3,009			720		Underlying RC profit before interest and tax(a)		3,562			5,069

(a)	See page 5 for information on underlying RC profit and see page 11 for a reconciliation to segment RC profit before interest and tax by region and by business.

The replacement cost profit before interest and tax for the third quarter and nine months was $616 million and $3,279 million respectively, compared with $2,408 million and $1,535 million for the same periods in 2012.

The 2013 results included net non-operating charges of $157 million for the third quarter principally reflecting the reassessment of environmental provisions, and $461 million for the nine months mainly relating to impairment charges in our fuels business, compared with $315 million and $3,099 million for the same periods a year ago (see pages 11 and 22 for further information on non-operating items). Fair value accounting effects had favourable impacts of $53 million for the third quarter and $178 million for the nine months, compared with unfavourable impacts of $286 million and $435 million for the same periods a year ago.

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

The fuels business reported underlying replacement cost profit before interest and tax of $344 million for the third quarter and $2,434 million for the nine months, compared with $2,718 million and $3,993 million in the same periods in 2012. Compared with 2012, the third-quarter result was significantly impacted by weaker refining margins (particularly in the US) as well as the absence of earnings from the divested Texas City and Carson refineries, each of which delivered unusually strong results in the third quarter of 2012 given the favourable environment. The nine months’ result was impacted by weaker refining margins and reduced throughput due to the planned crude unit outage at our Whiting refinery as part of the modernization project, partly offset by a strong supply and trading contribution as compared to the same period in 2012.

The Whiting refinery modernization project, which re-started the upgraded crude unit in the second quarter, remains on track to commission the remaining new units associated with the investment by the end of the fourth quarter. We will progressively introduce heavy feedstock once the coker is operational during the fourth quarter, and expect to achieve full run-rate capacity during the first quarter of 2014.

Looking ahead to the fourth quarter, we expect refining margins to remain under significant pressure due to very high gasoline stocks and new competitor capacity additions as well as lower seasonal demand.

The lubricants business delivered an underlying replacement cost profit before interest and tax of $325 million in the third quarter and $1,042 million in the nine months, compared with $311 million and $956 million in the same periods last year. The lubricants environment is challenging; however our investment in technology and our targeted marketing programmes are contributing to the strong position of our premium Castrol brands and this continues to benefit overall business performance. In the third quarter approximately 50% of our lubricants sales revenues were from countries which we define as growth markets, such as China, Australia and India.

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $51 million in the third quarter and $86 million in the nine months, compared with an underlying replacement cost loss before interest and tax of $20 million and an underlying replacement cost profit before interest and tax of $120 million respectively in the same periods last year. Margins and volumes continue to be under pressure, however, margins and utilization improved slightly in the third quarter, resulting in increased profitability compared with the third quarter of 2012.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 41.

Downstream


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Underlying RC profit before interest and tax by region
	1,723			(22	)	US		1,285			2,462
	1,286			742		Non-US		2,277			2,607

	3,009			720				3,562			5,069

						Non-operating items
	(229	)		(145	)	US		(134	)		(2,750	)
	(86	)		(12	)	Non-US		(327	)		(349	)

	(315	)		(157	)			(461	)		(3,099	)

						Fair value accounting effects(a)
	(388	)		81		US		235			(432	)
	102			(28	)	Non-US		(57	)		(3	)

	(286	)		53				178			(435	)

						RC profit (loss) before interest and tax
	1,106			(86	)	US		1,386			(720	)
	1,302			702		Non-US		1,893			2,255

	2,408			616				3,279			1,535

						Underlying RC profit (loss) before interest and tax – by business(b)(c)
	2,718			344		Fuels		2,434			3,993
	311			325		Lubricants		1,042			956
	(20	)		51		Petrochemicals		86			120

	3,009			720				3,562			5,069

						Non-operating items and fair value accounting effects(a)
	(592	)		(105	)	Fuels		(282	)		(3,523	)
	(8	)		4		Lubricants		2			(10	)
	(1	)		(3	)	Petrochemicals		(3	)		(1	)

	(601	)		(104	)			(283	)		(3,534	)

						RC profit (loss) before interest and tax(b)(c)
	2,126			239		Fuels		2,152			470
	303			329		Lubricants		1,044			946
	(21	)		48		Petrochemicals		83			119

	2,408			616				3,279			1,535

	22.6			13.6		BP average refining marker margin (RMM) ($/bbl)(d)		16.8			18.7

						Refinery throughputs (mb/d)
	1,403			618		US		755			1,306
	791			772		Europe		774			757
	318			312		Rest of World		295			292

	2,512			1,702				1,824			2,355

	95.0			95.3		Refining availability (%)(e)		95.2			94.8

						Marketing sales of refined products (mb/d)
	1,432			1,211		US		1,317			1,397
	1,247			1,284		Europe(f)		1,253			1,228
	571			551		Rest of World		552			583

	3,250			3,046				3,122			3,208
	2,393			2,596		Trading/supply sales of refined products		2,478			2,447

	5,643			5,642		Total sales volumes of refined products		5,600			5,655

						Petrochemicals production (kte)
	900			1,114		US		3,272			3,088
	993			999		Europe(c)		2,827			3,002
	1,686			1,538		Rest of World		4,474			5,253

	3,579			3,651				10,573			11,343

(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 23.

(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


Third quarter 2012		Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	—		836		Profit before interest and tax(a)(b)		1,152			—
	—		(44	)	Inventory holding (gains) losses		(57	)		—

	—		792		RC profit before interest and tax(b)		1,095			—
	—		16		Net charge (credit) for non-operating items		16			—

	—		808		Underlying RC profit before interest and tax(b)(c)		1,111			—

(a)	BP’s share of Rosneft’s earnings after finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation.

(b)	Third quarter and nine months 2013 include $5 million of foreign exchange losses arising on the dividend received.

(c)	See page 5 for information on underlying RC profit.

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 33 for further information.

Replacement cost profit before interest and tax for the third quarter and nine months was $792 million and $1,095 million respectively. The results included a non-operating item of $16 million relating to an impairment charge. After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $808 million and $1,111 million respectively.

The dividend declared by Rosneft in the second quarter of 2013 was paid during the third quarter of 2013. BP received $456 million after the deduction of withholding tax. No further dividends are expected in 2013.

The Rosneft segment result included equity-accounted earnings from Rosneft, representing BP’s 19.75% share in Rosneft. BP’s share of the components of Rosneft’s net income is shown in the table below.


Third quarter 2012		Third quarter 2013			$ million	Nine months 2013			Nine months 2012
					Income statement (BP share)
	—		1,197		Profit before interest and tax		1,724			—
	—		(18	)	Finance costs		(148	)		—
	—		(272	)	Taxation		(325	)		—
	—		(66	)	Non-controlling interests		(94	)		—

	—		841		Net income		1,157			—
	—		(44	)	Inventory holding (gains) losses, net of tax		(57	)		—

	—		797		Net income on a RC basis		1,100			—
	—		16		Net charge (credit) for non-operating items, net of tax		16			—

	—		813		Net income on an underlying RC basis		1,116			—


Balance sheet	30 September		31 December
	2013		2012
$ million
Investments in associates		12,165		—

Third
quarter
2012

Third
quarter
2013

$ million

Nine
months
2013

Nine
months
2012

Production (net of royalties) (BP share)(d)(e)

—

828

Liquids (mb/d)(f)

588

—

793

Natural gas (mmcf/d)

526

—

965

Total hydrocarbons (mboe/d)(g)

679

—

(d)	Information on BP’s share of TNK-BP’s production for comparative periods is provided on page 24.

(e)	Nine months 2013 reflects production for the period 21 March – 30 September, averaged over the nine months.

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

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

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 41.

Other businesses and corporate


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	(1,096	)		(674	)	Profit (loss) before interest and tax		(1,714	)		(2,289	)
	—			—		Inventory holding (gains) losses		—			—

	(1,096	)		(674	)	RC profit (loss) before interest and tax		(1,714	)		(2,289	)
	523			289		Net charge (credit) for non-operating items		430			741

	(573	)		(385	)	Underlying RC profit (loss) before interest and tax(a)		(1,284	)		(1,548	)

						Underlying RC profit (loss) before interest and tax(a)
	(218	)		(309	)	US		(572	)		(568	)
	(355	)		(76	)	Non-US		(712	)		(980	)

	(573	)		(385	)			(1,284	)		(1,548	)

						Non-operating items
	(494	)		(297	)	US		(435	)		(728	)
	(29	)		8		Non-US		5			(13	)

	(523	)		(289	)			(430	)		(741	)

						RC profit (loss) before interest and tax
	(712	)		(606	)	US		(1,007	)		(1,296	)
	(384	)		(68	)	Non-US		(707	)		(993	)

	(1,096	)		(674	)			(1,714	)		(2,289	)

(a)	See page 5 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 third quarter and nine months was $674 million and $1,714 million respectively, compared with $1,096 million and $2,289 million for the same periods last year.

The third-quarter result included a net non-operating charge of $289 million, primarily relating to environmental provisions, compared with a net charge of $523 million a year ago. For the nine months, the net non-operating charge was $430 million, compared with a net charge of $741 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter was $385 million compared with $573 million for the same period in 2012, primarily reflecting lower corporate costs. For the nine months, the underlying replacement cost loss before interest and tax was $1,284 million compared with $1,548 million a year ago.

In Alternative Energy, net wind generation capacity(b) at the end of the third 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 for the third quarter was 714GWh (1,236GWh gross), compared with 628GWh (964GWh gross) in the same period a year ago. For the nine months, BP’s net share was 3,001GWh (5,257GWh gross), compared with 2,572GWh (4,061GWh gross), a year ago.

In our biofuels business, we have three operating mills in Brazil where ethanol-equivalent production(c) for the third quarter was 248 million litres compared with 206 million litres in the same period a year ago. For the nine months, ethanol-equivalent production was 364 million litres compared with 304 million litres a year ago.

(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.

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.

Financial update

The replacement cost loss before interest and tax for the third quarter was $30 million, compared with a $56 million loss for the same period last year. The third-quarter charge primarily reflects the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $42.5 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 29, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the 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 of our second-quarter results announcement.

Trust update

During the third quarter, $1,048 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $1,003 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $45 million for natural resource damage assessment. In addition, $102 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 September 2013, the aggregate cash balances in the Trust and the QSFs amounted to $7.1 billion, including $1.3 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration.

As at 30 September 2013, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, amounted to $19.3 billion. This represents a decrease of $0.4 billion for the quarter which relates primarily to the derecognition of provisions in respect of business economic loss claims processed by the DHCSSP but not yet paid which can no longer be measured reliably as a result of the decision of the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) on 2 October 2013 (see Legal proceedings and investigations below). No amount is provided for business economic loss claims not yet received, processed and paid by the DHCSSP. The DHCSSP has issued eligibility notices in respect of business economic loss claims amounting to $1,029 million which have not yet been paid. See Note 2 on pages 27 – 32 and Legal proceedings on pages 37 – 39 for further details.

Legal proceedings and investigations

Phase 2 of the Trial of Liability, Limitation, Exoneration and Fault Allocation in the multi-district litigation proceedings in federal District Court (the District Court) in New Orleans (MDL 2179) commenced on 30 September 2013 to consider the issues of source control efforts and volume of oil spilled as a result of the incident. That phase completed on 18 October 2013. Post-trial briefing is scheduled for 20 December 2013 with replies due by 24 January 2014. BP does not know when the court will rule on the issues presented in either this phase or the previous phase of that trial.

On 8 July 2013, the Fifth Circuit heard BP’s appeal regarding the claims administrator’s implementation of the DHCSSP for the Economic and Property Damages Settlement with respect to business economic loss claims. On 2 October 2013, the Fifth Circuit (by a 2-1 vote) reversed the District Court’s denial of BP’s motion for a preliminary injunction and the District Court’s order affirming the claims administrator’s interpretation of the settlement, remanded the case for further proceedings, to be concluded by 2 December 2013, and ordered the District Court to enter a “narrowly-tailored” injunction that suspends payment to claimants affected by the misinterpretation issue and who do not have “actual injury traceable to loss from the Deepwater Horizon accident.” The Fifth Circuit also retained jurisdiction to review the District Court’s conclusions on remand.

On 18 October 2013, the District Court issued a preliminary injunction that, amongst other things, requires the claims administrator to temporarily suspend payments of business economic loss claims other than those claims supported by sufficiently matched accrual-basis accounting or any other business economic loss claim for which the claims administrator determines that the matching of revenue and expenses is not an issue. On 25 October 2013, the claims administrator provided a declaration outlining the criteria that the claims administrator’s office will use to determine the eligibility of claims for payment. BP is reviewing this declaration and the next steps in the process.

For further details, see Legal proceedings on pages 37 – 39.

Group income statement


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	92,002			96,601		Sales and other operating revenues (Note 4)		285,419			281,855
	107			119		Earnings from joint ventures – after interest and tax		346			222
	1,548			1,010		Earnings from associates – after interest and tax		1,742			3,353
	158			178		Interest and other income		542			548
	610			295		Gains on sale of businesses and fixed assets		13,072			2,285

	94,425			98,203		Total revenues and other income		301,121			288,263
	69,419			76,603		Purchases		223,391			218,713
	7,070			6,276		Production and manufacturing expenses(a)		20,270			21,686
	1,912			1,889		Production and similar taxes (Note 5)		5,556			6,085
	3,253			3,415		Depreciation, depletion and amortization		9,774			9,439
	486			767		Impairment and losses on sale of businesses and fixed assets		1,487			5,447
	290			511		Exploration expense		1,267			1,166
	3,627			3,411		Distribution and administration expenses		9,588			9,968
	(72	)		(238	)	Fair value gain on embedded derivatives		(404	)		(243	)

	8,440			5,569		Profit before interest and taxation		30,192			16,002
	243			279		Finance costs(a)		813			765
	133			118		Net finance expense relating to pensions and other post-retirement benefits		357			406

	8,064			5,172		Profit before taxation		29,022			14,831
	2,717			1,580		Taxation(a)		6,362			5,130

	5,347			3,592		Profit for the period		22,660			9,701

						Attributable to
	5,281			3,504		BP shareholders		22,409			9,529
	66			88		Non-controlling interests		251			172

	5,347			3,592				22,660			9,701


						Earnings per share – cents (Note 6)
						Profit for the period attributable to BP shareholders
	27.74			18.57		Basic		117.86			50.11
	27.59			18.47		Diluted		117.20			49.78

(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


Third quarter 2012			Third quarter 2013				Nine months 2013			Nine months 2012
						$ million
	5,347			3,592		Profit for the period		22,660			9,701

						Other comprehensive income (expense)
						Items that may be reclassified subsequently to profit or loss
	762			662		Currency translation differences		(1,431	)		292
	12			9		Exchange gains on translation of foreign operations reclassified to gain or loss on sales of businesses and fixed assets		9			—
	61			—		Available-for-sale investments marked to market		(172	)		16
	—			—		Available-for-sale investments reclassified to the income statement		(523	)		—
	48			104		Cash flow hedges marked to market(a)		(2,062	)		27
	29			2		Cash flow hedges reclassified to the income statement		1			59
	3			10		Cash flow hedges reclassified to the balance sheet		25			12
	74			31		Share of items relating to equity-accounted entities, net of tax		(24	)		(52	)
	100			(25	)	Income tax relating to items that may be reclassified		170			75

	1,089			793				(4,007	)		429

						Items that will not be reclassified to profit or loss
	382			310		Remeasurements of the net pension and other post-retirement benefit liability or asset		2,466			(119	)
	(1	)		—		Share of items relating to equity-accounted entities, net of tax		—			(6	)
	(78	)		(114	)	Income tax relating to items that will not be reclassified		(845	)		73

	303			196				1,621			(52	)

	1,392			989		Other comprehensive income (expense)		(2,386	)		377

	6,739			4,581		Total comprehensive income		20,274			10,078

						Attributable to
	6,662			4,485		BP shareholders		20,041			9,900
	77			96		Non-controlling interests		233			178

	6,739			4,581				20,274			10,078

(a)	Nine months 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		20,041			233			20,274
Dividends		(4,266	)		(331	)		(4,597	)
Repurchases of ordinary share capital		(3,963	)		—			(3,963	)
Share-based payments (net of tax)		477			—			477
Share of equity-accounted entities’ changes in equity		(761	)		—			(761	)
Transactions involving non-controlling interests		—			69			69

At 30 September 2013		130,074			1,177			131,251


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


Total comprehensive income		9,900			178			10,078
Dividends		(4,077	)		(72	)		(4,149	)
Share-based payments (net of tax)		338			—			338
Transactions involving non-controlling interests		—			31			31

At 30 September 2012		117,729			1,154			118,883

Group balance sheet


$ million	30 September 2013		31 December 2012
Non-current assets
Property, plant and equipment		130,153		125,331
Goodwill		12,075		12,190
Intangible assets		25,822		24,632
Investments in joint ventures		8,838		8,614
Investments in associates		15,211		2,998
Other investments		1,670		2,704

Fixed assets		193,769		176,469
Loans		644		642
Trade and other receivables		5,928		5,961
Derivative financial instruments		3,583		4,294
Prepayments		887		830
Deferred tax assets		881		874
Defined benefit pension plan surpluses		13		12

		205,705		189,082

Current assets
Loans		188		247
Inventories		29,389		28,203
Trade and other receivables		40,853		37,611
Derivative financial instruments		2,877		4,507
Prepayments		1,832		1,091
Current tax receivable		510		456
Other investments		536		319
Cash and cash equivalents		29,499		19,635

		105,684		92,069

Assets classified as held for sale		—		19,315

		105,684		111,384

Total assets		311,389		300,466

Current liabilities
Trade and other payables		48,309		46,673
Derivative financial instruments		2,296		2,658
Accruals		7,495		6,875
Finance debt		8,620		10,033
Current tax payable		2,509		2,503
Provisions		5,405		7,587

		74,634		76,329
Liabilities directly associated with assets classified as held for sale		—		846

		74,634		77,175

Non-current liabilities
Other payables		4,804		2,292
Derivative financial instruments		2,137		2,723
Accruals		432		491
Finance debt		41,664		38,767
Deferred tax liabilities		17,407		15,243
Provisions		28,014		30,396
Defined benefit pension plan and other post-retirement benefit plan deficits		11,046		13,627

		105,504		103,539

Total liabilities		180,138		180,714

Net assets		131,251		119,752

Equity
BP shareholders’ equity		130,074		118,546
Non-controlling interests		1,177		1,206

		131,251		119,752

Condensed group cash flow statement


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Operating activities
	8,064			5,172		Profit before taxation		29,022			14,831
						Adjustments to reconcile profit before taxation to net cash provided by operating activities
	3,371			3,765		Depreciation, depletion and amortization and exploration expenditure written off		10,587			10,029
	(124	)		472		Impairment and (gain) loss on sale of businesses and fixed assets		(11,585	)		3,162
	(1,377	)		(489	)	Earnings from equity-accounted entities, less dividends received		(943	)		(2,107	)
	122			170		Net charge for interest and other finance expense, less net interest paid		363			259
	132			153		Share-based payments		374			265
	(53	)		(67	)	Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(437	)		(424	)
	972			(360	)	Net charge for provisions, less payments		1,145			1,400
	(2,901	)		(812	)	Movements in inventories and other current and non-current assets and liabilities(a)		(7,953	)		(8,102	)
	(1,960	)		(1,672	)	Income taxes paid		(4,887	)		(5,213	)

	6,246			6,332		Net cash provided by operating activities		15,686			14,100

						Investing activities
	(5,773	)		(5,882	)	Capital expenditure		(17,722	)		(16,163	)
	—			—		Acquisitions, net of cash acquired		—			(116	)
	(380	)		(54	)	Investment in joint ventures		(152	)		(1,069	)
	(3	)		(64	)	Investment in associates		(4,955	)		(37	)
	1,400			307		Proceeds from disposal of fixed assets		17,743			3,188
	32			94		Proceeds from disposal of businesses, net of cash disposed		3,879			1,539
	22			36		Proceeds from loan repayments		126			175

	(4,702	)		(5,563	)	Net cash used in investing activities		(1,081	)		(12,483	)

						Financing activities
	23			(1,258	)	Net issue (repurchase) of shares		(3,093	)		61
	1,206			3,245		Proceeds from long-term financing		6,347			8,056
	(556	)		(568	)	Repayments of long-term financing		(1,747	)		(3,585	)
	94			122		Net increase (decrease) in short-term debt		(1,751	)		2
	—			29		Net increase (decrease) in non-controlling interests		29			—
	(1,418	)		(1,247	)	Dividends paid – BP shareholders		(4,267	)		(4,077	)
	(20	)		(140	)	– non-controlling interests		(256	)		(72	)

	(671	)		183		Net cash provided by (used in) financing activities		(4,738	)		385

	226			234		Currency translation differences relating to cash and cash equivalents		(3	)		(5	)

	1,099			1,186		Increase in cash and cash equivalents		9,864			1,997

	15,075			28,313		Cash and cash equivalents at beginning of period		19,635			14,177
	16,174			29,499		Cash and cash equivalents at end of period		29,499			16,174

(a)

Includes


(979	)	(394	)	Inventory holding gains	(292	)	(203	)
(72	)	(238	)	Fair value gain on embedded derivatives	(404	)	(243	)
(2,017	)	192		Movements related to Gulf of Mexico oil spill response	(2,066	)	(5,317	)

Inventory holding gains 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


Third quarter 2012			Third quarter 2013		$ million	Nine months 2013		Nine months 2012
					By business
					Upstream
	1,747			1,611	US(a)		4,712		4,542
	3,025			3,124	Non-US		8,925		8,790

	4,772			4,735			13,637		13,332

					Downstream
	960			559	US		2,175		2,573
	375			438	Non-US		1,050		975

	1,335			997			3,225		3,548

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

	—			—			11,941		—

					Other businesses and corporate
	127			54	US		146		538
	100			136	Non-US		444		359

	227			190			590		897

	6,334			5,922			29,393		17,777

					By geographical area
	2,834			2,224	US(a)		7,033		7,653
	3,500			3,698	Non-US(b)		22,360		10,124

	6,334			5,922			29,393		17,777

					Included above:
	(19	)		—	Acquisitions and asset exchanges		—		155
	200			—	Other inorganic capital expenditure(a)(b)		11,941		511

(a)	Third quarter and nine months 2012 includes $200 million and $511 million respectively associated with deepening our natural gas asset base.

(b)	Nine months 2013 includes $11,941 million relating to our investment in Rosneft – see Note 3 for further information.

Exchange rates

Third
quarter
2012

Third
quarter
2013

Nine
months
2013

Nine
months
2012

1.58

1.55

US dollar/sterling average rate for the period

1.54

1.58

1.62

1.61

US dollar/sterling period-end rate

1.61

1.62

1.25

1.32

US dollar/euro average rate for the period

1.32

1.28

1.29

1.35

US dollar/euro period-end rate

1.35

1.29

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
	4,907			4,158		Upstream		14,120			14,803
	2,408			616		Downstream		3,279			1,535
	1,282			—		TNK-BP(a)		12,500			2,798
	—			792		Rosneft(b)		1,095			—
	(1,096	)		(674	)	Other businesses and corporate		(1,714	)		(2,289	)

	7,501			4,892				29,280			16,847
	(56	)		(30	)	Gulf of Mexico oil spill response		(251	)		(869	)
	(64	)		263		Consolidation adjustment – UPII		819			(148	)

	7,381			5,125		RC profit before interest and tax		29,848			15,830
						Inventory holding gains (losses)
	12			7		Upstream		1			(108	)
	982			393		Downstream		286			278
	65			—		TNK-BP (net of tax)		—			2
	—			44		Rosneft (net of tax)		57			—

	8,440			5,569		Profit before interest and tax		30,192			16,002
	243			279		Finance costs		813			765
	133			118		Net finance expense relating to pensions and other post-retirement benefits		357			406

	8,064			5,172		Profit before taxation		29,022			14,831


						RC profit before interest and tax
	1,422			560		US		3,537			(889	)
	5,959			4,565		Non-US		26,311			16,719

	7,381			5,125				29,848			15,830

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. See Note 3 on page 33 for further information.

(b)	BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 12 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 5 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)


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Upstream
	492			(374	)	Impairment and gain (loss) on sale of businesses and fixed assets		(411	)		(35	)
	(48	)		(21	)	Environmental and other provisions		(21	)		(48	)
	—			—		Restructuring, integration and rationalization costs		—			—
	73			238		Fair value gain (loss) on embedded derivatives		404			244
	(1	)		(69	)	Other		(135	)		(318	)

	516			(226	)			(163	)		(157	)

						Downstream
	(115	)		(11	)	Impairment and gain (loss) on sale of businesses and fixed assets		(287	)		(2,853	)
	(171	)		(132	)	Environmental and other provisions		(141	)		(171	)
	(21	)		—		Restructuring, integration and rationalization costs		(4	)		(45	)
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	(8	)		(14	)	Other		(29	)		(30	)

	(315	)		(157	)			(461	)		(3,099	)

						TNK-BP
	38			—		Impairment and gain (loss) on sale of businesses and fixed assets		12,500			(55	)
	(50	)		—		Environmental and other provisions		—			(50	)
	—			—		Restructuring, integration and rationalization costs		—			—
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	—			—		Other		—			—

	(12	)		—				12,500			(105	)

						Rosneft
	—			(16	)	Impairment and gain (loss) on sale of businesses and fixed assets		(16	)		—
	—			—		Environmental and other provisions		—			—
	—			—		Restructuring, integration and rationalization costs		—			—
	—			—		Fair value gain (loss) on embedded derivatives		—			—
	—			—		Other		—			—

	—			(16	)			(16	)		—

						Other businesses and corporate
	(253	)		(87	)	Impairment and gain (loss) on sale of businesses and fixed assets		(217	)		(274	)
	(246	)		(216	)	Environmental and other provisions		(222	)		(261	)
	—			(4	)	Restructuring, integration and rationalization costs		(6	)		(1	)
	(1	)		—		Fair value gain (loss) on embedded derivatives		—			(1	)
	(23	)		18		Other		15			(204	)

	(523	)		(289	)			(430	)		(741	)

	(56	)		(30	)	Gulf of Mexico oil spill response		(251	)		(869	)

	(390	)		(718	)	Total before interest and taxation		11,179			(4,971	)
	(3	)		(9	)	Finance costs(b)		(29	)		(13	)

	(393	)		(727	)	Total before taxation		11,150			(4,984	)
	72			205		Taxation credit (charge)(c)		386			1,509

	(321	)		(522	)	Total after taxation for period		11,536			(3,475	)

(a)

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

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

(c)

For the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, 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, equity-accounted earnings and the deferred tax adjustments relating to a reduction in UK corporation tax rates ($99 million for the third quarter 2013) and changes in the taxation of UK oil and gas production ($256 million for the third quarter 2012)). Non-operating items reported within the equity-accounted earnings of TNK-BP and Rosneft are reported net of tax.

Non-GAAP information on fair value accounting effects


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Favourable (unfavourable) impact relative to management’s measure of performance
	25			(39	)	Upstream		(130	)		(101	)
	(286	)		53		Downstream		178			(435	)

	(261	)		14				48			(536	)
	99			(6	)	Taxation credit (charge)(a)		(29	)		211

	(162	)		8				19			(325	)

(a)

Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, equity-accounted earnings, certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives and the deferred tax adjustments relating to a reduction in UK corporation tax rates ($99 million for the third quarter 2013) and changes in the taxation of UK oil and gas production ($256 million for the third quarter 2012)).

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 and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period, the fair values of certain derivative instruments used to risk manage LNG and oil and gas processing contracts are deferred to match with the underlying exposure 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.


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Upstream
	4,882			4,197		Replacement cost profit before interest and tax adjusted for fair value accounting effects		14,250			14,904
	25			(39	)	Impact of fair value accounting effects		(130	)		(101	)

	4,907			4,158		Replacement cost profit before interest and tax		14,120			14,803

						Downstream
	2,694			563		Replacement cost profit before interest and tax adjusted for fair value accounting effects		3,101			1,970
	(286	)		53		Impact of fair value accounting effects		178			(435	)

	2,408			616		Replacement cost profit before interest and tax		3,279			1,535

						Total group
	8,701			5,555		Profit before interest and tax adjusted for fair value accounting effects		30,144			16,538
	(261	)		14		Impact of fair value accounting effects		48			(536	)

	8,440			5,569		Profit before interest and tax		30,192			16,002

Realizations and marker prices

Third
quarter
2012

Third
quarter
2013

Nine
months
2013

Nine
months
2012

Average realizations(a)

Liquids ($/bbl)(b)

90.62

91.20

92.68

97.05

108.74

107.78

Europe

104.61

110.25

104.39

107.21

Rest of World

104.07

106.25

99.00

100.66

BP Average

99.59

102.79

Natural gas ($/mcf)

2.54

2.91

3.07

2.22

8.46

9.72

Europe

9.61

8.44

5.31

5.67

Rest of World

5.90

5.25

4.77

5.01

BP Average

5.31

4.67

Total hydrocarbons ($/boe)

59.36

59.24

60.29

61.29

86.88

95.00

Europe

89.58

85.48

57.64

61.74

Rest of World

61.17

57.84

60.68

62.80

BP Average

63.09

61.69

Average oil marker prices ($/bbl)

109.50

110.29

Brent

108.46

112.21

92.10

105.79

West Texas Intermediate

98.13

96.13

109.04

110.52

Alaska North Slope

108.62

112.42

104.17

104.77

Mars

104.33

107.87

108.69

109.36

Urals (NWE – cif)

107.29

110.71

55.24

57.11

Russian domestic oil

54.63

53.86

Average natural gas marker prices

2.80

3.58

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

3.67

2.58

56.79

65.21

UK Gas – National Balancing Point (p/therm)

68.17

57.86

(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


Third quarter 2012		Third quarter 2013		$ million	Nine months 2013		Nine months 2012
				Production (net of royalties) (BP share)(a)(b)
	876		—	Crude oil (mb/d)		250		879
	728		—	Natural gas (mmcf/d)		246		773
	1,002		—	Total hydrocarbons (mboe/d)(c)		292		1,012

(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 nine months 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full nine months.

(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 12.

(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.

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 so 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 was a reduction in investments in joint ventures of approximately $7 billion as at 31 December 2012, which has been 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 $749 million lower for full year 2012 and the first nine months 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 September 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 37 – 39 of this report.

The group income statement includes a pre-tax charge of $39 million for the third quarter in relation to the Gulf of Mexico oil spill and $280 million for the first nine months of 2013. The third-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident amounts to $42,487 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, including developments in relation to the interpretation of business economic loss claims under the PSC settlement and the derecognition of the provision for those claims which can no longer be measured reliably, 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 of our second-quarter 2013 results announcement.

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.


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Income statement
	56			30		Production and manufacturing expenses		251			869

	(56	)		(30	)	Profit (loss) before interest and taxation		(251	)		(869	)
	3			9		Finance costs		29			13

	(59	)		(39	)	Profit (loss) before taxation		(280	)		(882	)
	(51	)		(44	)	Taxation		(7	)		25

	(110	)		(83	)	Profit (loss) for the period		(287	)		(857	)


$ million	Total			30 September 2013 Of which: amount related to the trust fund			Total			31 December 2012 Of which: amount related to the trust fund
Balance sheet
Current assets
Trade and other receivables		2,861			2,861			4,239			4,178
Current liabilities
Trade and other payables		(1,029	)		(1	)		(522	)		(22	)
Provisions		(3,457	)		—			(5,449	)		—

Net current assets (liabilities)		(1,625	)		2,860			(1,732	)		4,156

Non-current assets
Other receivables		2,286			2,286			2,264			2,264
Non-current liabilities
Other payables		(2,977	)		—			(175	)		—
Provisions		(6,159	)		—			(9,751	)		—
Deferred tax		2,989			—			4,002			—

Net non-current assets (liabilities)		(3,861	)		2,286			(3,660	)		2,264

Net assets (liabilities)		(5,486	)		5,146			(5,392	)		6,420

Notes

2.	Gulf of Mexico oil spill (continued)


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Cash flow statement – Operating activities
	(59	)		(39	)	Profit (loss) before taxation		(280	)		(882	)
						Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
	3			9		Net charge for interest and other finance expense, less net interest paid		29			13
	546			(576	)	Net charge for provisions, less payments		1,118			1,216
	(2,017	)		192		Movements in inventories and other current and non-current assets and liabilities		(2,066	)		(5,317	)

	(1,527	)		(414	)	Pre-tax cash flows		(1,199	)		(4,970	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $4 million and $193 million in the third quarter and nine months of 2013 respectively. For the same periods in 2012, the amounts were an outflow of $134 million and $3,011 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 September 2013. The increase in the provision of $1,888 million for the first nine months relates principally to business economic loss claims processed by the DHCSSP between finalization of the BP Annual Report and Form 20-F 2012 and finalization of the second-quarter 2013 provisions, as well as increases in the provision for claims administration costs. Since the second-quarter results announcement dated 30 July 2013, a provision of $379 million has been derecognized relating to business economic loss claims that can no longer be estimated reliably (for further details, see Provisions below). The amount of the reimbursement asset at 30 September 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund – see below.


$ million	Third quarter 2013			Nine months 2013
Opening balance		6,597			6,442
Net increase (decrease) in provision for items covered by the trust fund		(23	)		1,888
Derecognition of provision for items that can no longer be estimated reliably		(379	)		(379	)
Amounts paid directly by the trust fund		(1,048	)		(2,804	)

At 30 September 2013		5,147			5,147

Of which – current		2,861			2,861
– non-current		2,286			2,286

Notes

2.	Gulf of Mexico oil spill (continued)

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 September 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,305 million. Thus, a further $695 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, including the various claims described in Legal proceedings on pages 37 – 39 of 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 estimated reliably is provided under Provisions below.

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 September 2013, the aggregate cash balances in the Trust and the QSFs amounted to $7.1 billion, including $1.3 billion remaining in the seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. 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. See Provisions below for further information on the current status of the EPD Settlement Agreement. 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 37 – 39 of this report and on pages 166 – 168 of 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 third quarter and first nine months of 2013 are presented in the tables below.

$ million

Environmental

Spill
response

Litigation
and
claims

Clean
Water Act
penalties

Total

At 1 July 2013

1,663

205

5,862

3,510

11,240

Decrease in provision – items covered by the trust fund

—

(23

)

—

(23

)

Derecognition of provision for items that can no longer be estimated reliably

—

(379

)

—

(379

)

Utilization – paid by BP

)

(49

)

(116

)

—

(174

)

– paid by the trust fund

(45

)

—

(1,003

)

—

(1,048

)

At 30 September 2013

1,609

156

4,341

3,510

9,616

Of which – current

275

3,084

—

3,457

– non-current

1,334

1,257

3,510

6,159

Of which – payable from the trust fund

1,253

3,796

—

5,096

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		24			—			1,864			—		1,888
Derecognition of provision for items that can no longer be estimated reliably		—			—			(379	)		—		(379	)
Unwinding of discount		1			—			—			—		1
Reclassified to other payables		—			—			(3,933	)		—		(3,933	)
Utilization – paid by BP		(46	)		(123	)		(390	)		—		(559	)
– paid by the trust fund		(208	)		—			(2,562	)		—		(2,770	)

At 30 September 2013		1,609			156			4,341			3,510		9,616

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 estimated reliably 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 the cost of business economic loss claims. 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 appealed to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit). On 2 October 2013, the Fifth Circuit (by a 2-1 vote) reversed the District Court’s denial of BP’s motion for a preliminary injunction and the District Court’s order affirming the claims administrator’s interpretation of the settlement, remanded the case for further proceedings, to be concluded by 2 December 2013, and ordered the District Court to enter a “narrowly-tailored” injunction that suspends payment to claimants affected by the misinterpretation issue and who do not have “actual injury traceable to loss from the Deepwater Horizon accident.” The Fifth Circuit also retained jurisdiction to review the District Court’s conclusions on remand.

As at 30 June 2013, BP held a provision for business economic loss claims which had been processed and for which eligibility notices had been issued but had not yet been paid by the DHCSSP. Pending the implementation of the Fifth Circuit’s directions to the District Court on remand, there is now significant uncertainty as to the amount of claims which have been processed but not yet paid by the DHCSSP that will be determined to be payable in the future. BP has derecognized the remaining provision for business economic loss claims which have been processed but not yet paid, as BP considers that no reliable estimate can now be made for these claims.

Notes

2.	Gulf of Mexico oil spill (continued)

Given: (i) the inherent uncertainty as to the interpretation of the EPD Settlement Agreement that currently exists and will continue until new policies and procedures are implemented in response to the Fifth Circuit’s ruling and thereafter until the impact of such policies and procedures 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 either future claims based on the claims data received to date, or whether and to what extent determined but unpaid claims will be paid, and therefore believes that no reliable estimate can currently be made of any business economic loss claims not yet received, processed and paid by the DHCSSP. A provision will be established when a reliable estimate can be made of the liability as explained more fully below.

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 estimate at the time of the second-quarter results announcement dated 30 July 2013 of the total cost of those elements of the PSC settlement that it considered could be reliably estimated, which for business economic loss claims included only those claims for which eligibility notices had been issued by the DHCSSP prior to finalization of the second-quarter 2013 provisions, was $9.6 billion. Following the derecognition of the provision in respect of processed but unpaid business economic loss claims, the current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated is $9.2 billion.

The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.2 billion because the current estimate does not reflect business economic loss claims not yet received, processed and paid. The DHCSSP has issued eligibility notices in respect of business economic loss claims of $1,029 million which have not yet been paid. Of this amount, eligibility notices in respect of claims amounting to $650 million have been issued since the second-quarter 2013 provisions were finalized. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received.

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 page 166 of BP Annual Report and Form 20-F 2012 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 as well as in its determinations on the volume of oil spilled and the application of penalty factors. 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 decrease in the provision for the estimated cost of the settlement with the PSC and various other costs of $402 million for the third quarter and a net increase of $1,677 million for the nine months was recognized. These amounts included the derecognition of $379 million relating to business economic loss claims that can no longer be estimated reliably. 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 $3,329 million during the first nine months of 2013 included $2,451 million paid out under the PSC settlement from the Trust.

Notes

2.	Gulf of Mexico oil spill (continued)

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


$ million	Third quarter 2013			Nine months 2013
Net increase (decrease) in provisions		(23	)		2,056
Derecognition of provision for items that can no longer be estimated reliably		(379	)		(379	)
Recognition of reimbursement asset, net		402			(1,509	)
Other net costs charged (credited) directly to the income statement		30			83

Loss before interest and taxation		30			251
Finance costs		9			29

Loss before taxation		39			280

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 37 – 39 of this report and pages 161 – 171 of BP Annual Report and Form 20-F 2012, the cost of business economic loss claims under the PSC settlement not yet received, processed and paid by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private or governmental litigation, fines or penalties (except for the Clean Water Act civil penalty claims and governmental claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment. These items are therefore disclosed as contingent liabilities – see below and 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 the new policies and procedures to be implemented relating to business economic loss claims in response to the Fifth Circuit’s 2 October 2013 decision (see Litigation and claims above and Legal Proceedings on pages 37 – 39) 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

As described above, business economic loss claims that have not yet been received, processed and paid are not provided for.

Furthermore, 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 page 50 of our second-quarter results announcement dated 30 July 2013 for further information. Until further fact and expert disclosures occur, court rulings clarify 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 September 2013.

At 30 September 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. 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 is released to BP’s income statement over time as the TNK-BP assets are depreciated or amortized.

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.

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.

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 for BP to acquire shares in Rosneft 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 September. BP has not yet completed its fair value exercise associated with its acquisition of shares in Rosneft. Any adjustments required following completion of this work will be reported in a future period.

Notes

4.	Sales and other operating revenues

Third
quarter
2012

Third
quarter
2013

$ million

Nine
months
2013

Nine
months
2012

By business

16,851

16,810

Upstream

51,446

52,796

85,299

90,481

Downstream

265,613

260,249

460

454

Other businesses and corporate

1,288

1,415

102,610

107,745

318,347

314,460

Less: sales and other operating revenues between businesses

9,767

10,512

Upstream

31,489

30,772

595

440

Downstream

789

1,178

246

192

Other businesses and corporate

650

655

10,608

11,144

32,928

32,605

Third party sales and other operating revenues

7,084

6,298

Upstream

19,957

22,024

84,704

90,041

Downstream

264,824

259,071

214

262

Other businesses and corporate

638

760

92,002

96,601

Total third party sales and other operating revenues

285,419

281,855

By geographical area

33,782

35,619

105,524

104,656

67,917

71,843

Non-US

210,022

206,036

101,699

107,462

315,546

310,692

9,697

10,861

Less: sales and other operating revenues between areas

30,127

28,837

92,002

96,601

285,419

281,855

5.	Production and similar taxes

Third
quarter
2012

Third
quarter
2013

$ million

Nine
months
2013

Nine
months
2012

237

223

813

1,034

1,675

1,666

Non-US

4,743

5,051

1,912

1,889

5,556

6,085

Notes

6.	Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 176 million ordinary shares at a cost of $1,236 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 $580 million has been accrued at 30 September 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.


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Results for the period
	5,281			3,504		Profit for the period attributable to BP shareholders		22,409			9,529
	—			—		Less: preference dividend		1			1

	5,281			3,504		Profit attributable to BP ordinary shareholders		22,408			9,528

	(747	)		(326	)	Inventory holding (gains) losses, net of tax		(235	)		(110	)

	4,534			3,178		RC profit attributable to BP ordinary shareholders		22,173			9,418
	483			514		Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, net of tax		(11,555	)		3,800

	5,017			3,692		Underlying RC profit attributable to BP shareholders		10,618			13,218


						Number of shares (thousand)(a)
	19,037,433			18,867,320		Basic weighted average number of shares outstanding		19,012,247			19,012,634
	3,172,905			3,144,553		ADS equivalent		3,168,708			3,168,772


	19,139,830			18,967,190		Weighted average number of shares outstanding used to calculate diluted earnings per share		19,120,033			19,140,343
	3,189,972			3,161,198		ADS equivalent		3,186,672			3,190,057


	19,051,867			18,821,216		Shares in issue at period-end		18,821,216			19,051,867
	3,175,311			3,136,869		ADS equivalent		3,136,869			3,175,311

(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

7.	Analysis of changes in net debt(a)


Third quarter 2012			Third quarter 2013			$ million	Nine months 2013			Nine months 2012
						Opening balance
	47,647			46,990		Finance debt		48,800			44,208
	15,075			28,313		Less: cash and cash equivalents(b)		19,635			14,177
	1,067			460		Less: FV asset of hedges related to finance debt		1,700			1,133

	31,505			18,217		Opening net debt		27,465			28,898

						Closing balance
	49,071			50,284		Finance debt		50,284			49,071
	16,174			29,499		Less: cash and cash equivalents		29,499			16,174
	1,572			734		Less: FV asset of hedges related to finance debt		734			1,572

	31,325			20,051		Closing net debt		20,051			31,325

	180			(1,834	)	Decrease (increase) in net debt		7,414			(2,427	)

	873			952		Movement in cash and cash equivalents (excluding exchange adjustments)		9,867			2,002
	(744	)		(2,799	)	Net cash inflow from financing (excluding share capital and dividends)		(2,849	)		(4,473	)
	—			—		Movement in finance debt relating to investing activities(c)		632			—
	—			(17	)	Other movements		(123	)		(11	)

	129			(1,864	)	Movement in net debt before exchange effects		7,527			(2,482	)
	51			30		Exchange adjustments		(113	)		55

	180			(1,834	)	Decrease (increase) in net debt		7,414			(2,427	)

(a)	Net debt is a non-GAAP measure – see page 6 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 third quarter 2013 no disposal transactions were completed in respect of which deposits had been received in advance (third quarter 2012 nil), and no deposits were received in respect of disposals expected to complete within the next year. At 30 September 2013, finance debt includes no deposits received in advance relating to disposal transactions ($30 million at 30 September 2012).

At 30 September 2013, $144 million of finance debt ($142 million at 30 September 2012) was secured by the pledging of assets. The remainder of finance debt was unsecured.

At 30 September 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.

8.	Inventory valuation

A provision of $636 million was held at 30 September 2013 to write inventories down to their net realizable value. The net movement in the provision during the third quarter 2013 was an increase of $407 million (third quarter 2012 was a decrease of $373 million).

9.	Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 28 October 2013, is unaudited and does not constitute statutory financial statements.

Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see 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 (Phase 1) of a Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 commenced in the federal district court in New Orleans (the District Court). The presentation of evidence in Phase 1, 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. On 13 August 2013, BP moved for leave to supplement the Phase 1 record to include Halliburton’s agreement to plead guilty to destroying evidence relating to Halliburton’s internal examination of the Incident and the US government’s press release announcing the Halliburton plea agreement. The US government, the Plaintiffs’ Steering Committee and Halliburton have also submitted briefs addressing the implications of Halliburton’s plea agreement. The District Court has yet to rule on BP’s motion. BP is not currently aware of the timing of the court’s ruling in respect of issues addressed in Phase 1.

The second trial phase (Phase 2), which commenced on 30 September 2013, addressed the amount of oil that was spilled as a result of the Incident and source control efforts. Phase 2 completed on 18 October 2013. Post-trial briefing is scheduled for 20 December 2013 with replies due by 24 January 2014. BP is not currently aware of the timing of the court’s ruling in respect of issues addressed in Phase 2.

The District Court has wide discretion in its determination as to whether a defendant’s conduct involved gross negligence as well as in its determinations on the volume of oil spilled and the application of penalty factors.

For further information, see page 164 of BP Annual Report and Form 20-F 2012.

US Environmental Protection Agency (EPA) matters

On 28 November 2012, the 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. 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. 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. On 12 August 2013, BP filed a lawsuit in the US District Court for the Southern District of Texas challenging the EPA’s suspension and debarment decisions. BP plans to continue to work with the EPA in preparing an administrative agreement that will resolve these suspension and debarment issues.

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, 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 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 29 July 2013, the Fifth Circuit dismissed the appeal of the group that had failed to file a brief and, on 31 July 2013, the Fifth Circuit granted the other group’s motion to voluntarily dismiss its appeal. On 2 August 2013, BP filed a motion with the Fifth Circuit requesting that it expedite the appeal from the Economic and Property Damages Settlement, and the court granted BP’s motion on 6 September 2013. On 12 September 2013, one additional group of appellants moved to voluntarily dismiss its appeal. Following the Fifth Circuit’s 2 October 2013 ruling in respect of business economic loss claims (discussed below), the Fifth Circuit directed the parties to submit letter briefs addressing the implications of the 2 October 2013 decision for the appeal from the Economic and Property Damages Settlement, and the parties submitted their letter briefs on 11 October 2013. Briefing in the appeal from the Economic and Property Damages Settlement case is otherwise complete, and oral argument is currently scheduled for 4 November 2013.

Legal proceedings (continued)

Two groups of purported members of the Medical Benefits Settlement Class have 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. On 11 July 2013, the one remaining group appealing from the Medical Benefits Class Action Settlement case filed its opening brief, and BP filed its brief on appeal on 3 September 2013. On 30 September 2013, the Fifth Circuit remanded the appeal to the District Court for the limited purpose of allowing the District Court to determine whether the appellants are members of the Medical Benefits Settlement Class.

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, 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 District Court on this matter and 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 (the March Ruling).

BP appealed the District Court’s March Ruling and related rulings to the Fifth Circuit. On 2 October 2013, the Fifth Circuit (by a 2-1 vote) reversed the District Court’s denial of BP’s motion for a preliminary injunction and the District Court’s order affirming the claims administrator’s interpretation of the settlement, remanded the case for further proceedings, to be concluded by 2 December 2013, and ordered the District Court to enter a “narrowly-tailored” injunction that suspends payment to claimants affected by the misinterpretation issue and who do not have “actual injury traceable to loss from the Deepwater Horizon accident.” The Fifth Circuit also retained jurisdiction to review the District Court’s conclusions on remand.

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 6 September 2013, Judge Freeh submitted a report to the District Court in which he found that the conduct of two attorneys in the office of the claims administrator may have violated federal criminal statutes regarding fraud, money laundering, conspiracy or perjury. In an order issued the same day, the District Court instructed Judge Freeh to promptly recommend, design, and test enhanced internal compliance, anti-corruption, anti-fraud and conflicts of interest policies and procedures to ensure the integrity of the DHCSSP, and to assist the claims administrator in the implementation of such policies and procedures. On 23 September 2013, BP filed a response to Judge Freeh’s report and requested that the District Court enter a preliminary injunction temporarily suspending all payments from the DHCSSP until such time as improved anti-fraud and other efficiency controls are implemented at the DHCSSP to the satisfaction of Judge Freeh, the claims administrator and the District Court. The District Court has not yet ruled on BP’s request for a preliminary injunction.

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

MDL 2185 and other securities-related litigation

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 and state 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, to the judge presiding over the federal multi-district litigation proceeding in Houston (MDL 2185). One case was voluntarily dismissed on 9 May 2013. On 3 October 2013, the judge granted in part and denied in part the defendants’ motion to dismiss three of the remaining 13 cases. A subset of the claims was dismissed. The judge held that English law governs the plaintiffs’ remaining claims (with the exception of federal law claims based on purchases of ADSs and a potential claim under Ohio state law against BP p.l.c. by certain Ohio funds). Such claims will therefore proceed against the BP entities and five individual defendants.

Legal proceedings (continued)

On 20 July 2012, a BP entity received an amended statement of claim for an action in Alberta, Canada, filed by three plaintiffs seeking to assert claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ordinary shares and ADSs. This case was dismissed on jurisdictional grounds on 14 November 2012. On 15 November 2012, one of the plaintiffs re-filed a statement of claim against BP in Ontario, Canada, seeking to assert the same claims under Canadian law against BP on behalf of a class of Canadian residents. BP moved to dismiss that action for lack of jurisdiction, and on 9 October 2013 the court denied BP’s motion.

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

Insurance-related proceedings

On 1 March 2012, the District Court issued a partial final judgment dismissing with prejudice all claims by BP, Anadarko and MOEX for additional insured coverage under insurance policies issued to Transocean for the sub-surface pollution liabilities that BP, Anadarko and MOEX have incurred and will incur with respect to the Macondo well oil release. BP filed a notice of appeal from the District Court’s judgment to the Fifth Circuit and on 1 March 2013 the Fifth Circuit reversed the District Court’s judgment, rejecting the District Court’s ruling that the insurance that BP is entitled to receive as an additional insured under the Transocean insurance policies at issue is limited to the scope of the indemnity in the drilling contract between BP and Transocean. On 29 August 2013, the Fifth Circuit withdrew its 1 March 2013 opinion and certified two questions of Texas law at issue in the appeal to the Supreme Court of Texas. The Texas Supreme Court accepted the certification and announced the briefing schedule, with BP’s opening brief due on 6 November 2013. A date and time for the hearing on the certified questions has not yet been determined.

Foreign government lawsuits

On 15 September 2010, three Mexican states bordering the Gulf of Mexico (Veracruz, Quintana Roo, and Tamaulipas) filed lawsuits in federal court in Texas against several BP entities. These lawsuits were subsequently transferred to MDL 2179 on 4 November 2010. The lawsuits allege that the Incident harmed the states’ tourism, fishing, and commercial shipping industries (resulting in, among other things, diminished tax revenue), damaged natural resources and the environment, and caused the states to incur expenses in preparing a response to the Incident. On 9 December 2011, the District Court granted in part BP’s motion to dismiss the three Mexican states’ complaints, dismissing their claims under OPA 90 and for nuisance and negligence per se, and preserving their claims for negligence and gross negligence only to the extent there has been a physical injury to a proprietary interest of the states. BP, other defendants, and the three Mexican states filed cross-motions for summary judgment on 4 January 2013 on the issue of whether the Mexican states have a proprietary interest in the matters asserted in their complaints. The District Court heard oral argument on the cross-motions on 27 June 2013, and on 6 September 2013 the court granted defendants’ motions. On 12 September 2013, the District Court issued a final judgment dismissing the three Mexican states’ claims with prejudice. On 4 October 2013, the three Mexican states filed notices of appeal from the judgment to the Fifth Circuit.

On 5 April 2011, the State of Yucatan submitted a claim to the Gulf Coast Claims Facility (GCCF) alleging potential damage to its natural resources and environment, and seeking to recover the cost of assessing the alleged damage. On 18 September 2013, the State of Yucatan filed a lawsuit against BP in federal court in Florida, and on 10 October 2013 the lawsuit was stayed pending a decision by the Judicial Panel on Multi-district Litigation whether the State of Yucatan’s action will be transferred to MDL 2179.

Other legal proceedings

As disclosed in BP Annual Report and Form 20-F 2012, the US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) have been investigating several BP entities regarding trading in the next-day natural gas market at Houston Ship Channel during September, October and November 2008. On 28 July 2011, FERC issued a Notice of Alleged Violations stating that it had preliminarily determined that several BP entities fraudulently traded physical natural gas in the Houston Ship Channel and Katy markets and trading points to increase the value of their financial swing spread positions. On 5 August 2013, the FERC staff issued an Order to Show Cause and Notice of Proposed Penalty directing BP to respond to a FERC Enforcement Staff report, which FERC issued on the same day, alleging that BP manipulated the next-day, fixed price gas market at Houston Ship Channel from mid-September 2008 to 30 November 2008. The FERC Enforcement Staff report proposes a civil penalty of $28 million and the surrender of $800,000 of alleged profits. BP filed its answer on 4 October 2013 denying the allegations and moving for dismissal.

On 8 March 2010, the US Occupational Safety and Health Administration (OSHA) issued 65 citations to BP Products and BP-Husky for alleged violations of the PSM Standard at the Toledo refinery, with penalties of approximately $3 million. These citations resulted from an inspection conducted pursuant to OSHA’s Petroleum Refinery Process Safety Management National Emphasis Program. Following a trial in June 2012, on 31 July 2013, an Administrative Law Judge from the Occupational Safety and Health Review Commission (the Review Commission) rendered her decision. OSHA voluntarily dismissed one citation and the judge vacated 36 citations. Five citations were downgraded and assessed an aggregate penalty of $35,000. In addition, the judge accepted the parties’ pre-trial settlement of 23 citations. As a result of the settlement and the judge’s decision, the total penalty in respect of the citations was reduced from the original amount of approximately $3 million to $80,000. The Review Commission has granted OSHA’s petition for review of the judge’s decision and is expected to issue a briefing schedule during the fourth quarter of 2013.

Legal proceedings (continued)

A flaring event occurred at the Texas City refinery in April and May 2010. This flaring event is the subject of civil lawsuit claims for personal injury and, in some cases, property damage by roughly 50,000 individuals. These claims have been consolidated in a Texas multi-district litigation proceeding in Galveston, Texas. The first trial in the matter began in September 2013 and was completed in October 2013. Of the six plaintiffs initially scheduled for trial, two filed nonsuits before trial, the claims of one plaintiff were dismissed by the court on directed verdict, and the jury awarded no damages to the remaining three plaintiffs. In addition, this flaring event and other refinery emissions from December 2008 through 2010 are the subject of a purported class action, on behalf of some local residential property owners, filed in US federal district court in Galveston. The purported class plaintiffs claim that refinery emissions caused their residential properties to lose value. A class certification hearing was held on 4-5 April 2013, and the court denied the plaintiffs’ class certification motion on 2 October 2013. The flares involved in this event are also the subject of a federal government enforcement action. BP retained these liabilities when it sold the Texas City refinery.

As disclosed in BP Annual Report and Form 20-F 2012, BP has been in discussions with the EPA regarding alleged historic violations of the Clean Air Act (CAA) at the Texas City refinery. On 14 August 2013, BP, the EPA and Blanchard Refining Company (the current owner and operator of the Texas City refinery) lodged with the federal court an agreement to settle certain alleged CAA violations pursuant to which BP would pay a civil penalty of $950,000 and Blanchard would correct the alleged violations. This agreement remains subject to court approval.

Cautionary statement

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operation and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, certain statements regarding the expected level of organic capital expenditure in 2013 and per annum through 2020; BP’s intentions in respect of its announced share repurchase programme, including the total quantum of shares expected to be purchased in connection therewith and programme timing; BP’s plans to divest a further $10 billion in assets before the end of 2015 and plans for the use of proceeds of such divestments; the expected quarterly dividend payment and timing of the payment; the expected level of reported production and the expected level of costs in the fourth quarter of 2013; the expected level of reported and underlying production for the full year 2013; the expected identities of purchasers of gas from the Shah Deniz field; the expected timing of the completion of the Whiting refinery modernization project and future prospects for the Whiting refinery; the expected level of refining margins in the fourth quarter of 2013; the expected level of fuels profitability in the fourth quarter of 2013; the timing of future dividends from Rosneft; 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, and the risks associated with such proceedings; 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; economic and financial market conditions generally or in various countries and regions; 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; decisions by Rosneft’s management and board of directors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism, cyber-attacks or sabotage; and other factors discussed under “Principal risks and uncertainties” in our Form 6-K for the period ended 30 June 2013 and under “Risk factors” in BP Annual Report and Form 20-F 2012, each as filed with the US Securities and Exchange Commission.

Computation of ratio of earnings to fixed charges


	Nine months 2013
	$ million except ratio

Earnings available for fixed charges:
Pre-tax income from continuing operations before adjustment for income or loss from joint ventures and associates		26,934
Fixed charges		2,258
Amortization of capitalized interest		162
Distributed income of joint ventures and associates		1,145
Interest capitalized		(180	)
Preference dividend requirements, gross of tax		(2	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges		—

Total earnings available for fixed charges		30,317


Fixed charges:
Interest expensed		640
Interest capitalized		180
Rental expense representative of interest		1,436
Preference dividend requirements, gross of tax		2

Total fixed charges		2,258


Ratio of earnings to fixed charges		13.4

Capitalization and indebtedness

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 September 2013 in accordance with IFRS:


	30 September 2013
	$ million
Share capital and reserves

Capital shares (1-2)		5,181
Paid-in surplus (3)		11,268
Merger reserve (3)		27,206
Own shares		(347	)
Treasury shares		(20,443	)
Available-for-sale investments		—
Cash flow hedge reserve		(715	)
Foreign currency translation reserve		3,735
Share-based payment reserve		1,543
Profit and loss account		102,646

BP shareholders’ equity		130,074


Finance debt (4-6)
Due within one year		8,620
Due after more than one year		41,664

Total finance debt		50,284

Total capitalization (7)		180,358

(1)

Issued share capital as of 30 September 2013 comprised 18,842,008,218 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,794,336,641 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.

(2)	Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.

(3)	Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.

(4)	Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 September 2013.

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

(6)

As of 30 September 2013, the parent company, BP p.l.c., had outstanding guarantees totalling $47,762 million, of which $47,732 million related to guarantees in respect of liabilities of subsidiary undertakings, including $46,992 million relating to finance debt by subsidiaries. Thus 93% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 30 September 2013, $144 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

(7)	There has been no material change since 30 September 2013 in the consolidated capitalization and indebtedness of BP.

Signatures

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

BP p.l.c.

(Registrant)

Dated: 29 October 2013

/s/ J Bertelsen

J BERTELSEN

Deputy Secretary