UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

for the period ended 30 June 2014

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333-186463) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

 

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BP p.l.c. AND SUBSIDIARIES

FORM 6-K FOR THE PERIOD ENDED 30 JUNE 2014^(a)

 

				Page
1.		Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June  2014(b)			3 –12, 35 – 40
2.		Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2014			13 – 34
3.		Principal risks and uncertainties			41 – 47
4.		Legal proceedings			48 – 50
5.		Other matters			50
6.		Cautionary statement			51
7.		Computation of Ratio of Earnings to Fixed Charges			52
8.		Capitalization and Indebtedness			53
9.		Signatures			54

 

(a)	In this Form 6-K, references to the first half 2014 and first half 2013 refer to the six-month periods ended 30 June 2014 and 30 June 2013 respectively. References to second quarter 2014 and second quarter 2013 refer to the three-month periods ended 30 June 2014 and 30 June 2013 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 2013.

 

 

 

2

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Group results second quarter and half year 2014

 

 

 

Second quarter 2013				Second quarter 2014				$ million		First half 2014				First half 2013
	94,711				93,957			Sales and other operating revenues			185,667				188,818
	2,042				3,369			Profit for the period(a)			6,897				18,905
	358				(187	)		Inventory holding (gains) losses*, net of tax			(240	)			91
	2,400				3,182			Replacement cost profit*			6,657				18,996
	312				453			Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*, net of tax			203				(12,069	)
	2,712				3,635			Underlying replacement cost profit*			6,860				6,927
	10.73				18.26			Profit per ordinary share (cents)			37.35				99.07
	0.64				1.10			Profit per ADS (dollars)			2.24				5.94
	12.62				17.25			Replacement cost profit per ordinary share (cents)			36.05				99.55
	0.76				1.03			Replacement cost profit per ADS (dollars)			2.16				5.97
	14.26				19.71			Underlying replacement cost profit per ordinary share (cents)			37.15				36.30
	0.86				1.18			Underlying replacement cost profit per ADS (dollars)			2.23				2.18

 

•

BP’s profit for the second quarter and half year was $3,369 million and $6,897 million respectively, compared with $2,042 million and $18,905 million for the same periods a year ago. BP’s second-quarter replacement cost (RC) profit was $3,182 million, compared with $2,400 million a year ago. After adjusting for a net charge for non-operating items of $481 million and net favourable fair value accounting effects of $28 million (both on a post-tax basis), underlying RC profit for the second quarter 2014 was $3,635 million, compared with $2,712 million for the same period in 2013. For the half year, RC profit was $6,657 million, compared with $18,996 million a year ago which included a $12.5-billion gain relating to the disposal of our interest in TNK-BP. After adjusting for a net charge for non-operating items of $257 million and net favourable fair value accounting effects of $54 million (both on a post-tax basis), underlying RC profit for the half year was $6,860 million, compared with $6,927 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 and 37.

 

•

All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $260 million for the quarter and $299 million for the half year. For further information on the Gulf of Mexico oil spill and its consequences, including information on utilization of the Deepwater Horizon Oil Spill Trust fund, see page 12 and Note 2 on page 18. See also Principal risks and uncertainties on page 41 and Legal proceedings on page 48.

 

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and half year was $7.9 billion and $16.1 billion respectively, compared with $5.4 billion and $9.4 billion for the same periods in 2013. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the second quarter and half year was $7.6 billion and $16.5 billion respectively, compared with $5.2 billion and $9.5 billion respectively for the same periods in 2013.

 

•

Gross debt at the end of the quarter was $52.9 billion compared with $47.0 billion a year ago. The ratio of gross debt to gross debt plus equity was 28.5%, compared with 26.5% a year ago. Net debt at 30 June 2014 was $24.4 billion, compared with $18.2 billion a year ago. The ratio of net debt to net debt plus equity at 30 June 2014 was 15.5%, compared with 12.3% a year ago. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 27 for more information.

 

•

Total capital expenditure on an accruals basis for the second quarter was $5.6 billion, almost all of which was organic*. For the half year, total capital expenditure on an accruals basis was $11.7 billion, of which organic capital expenditure was $11.0 billion.

 

•

In October 2013, BP announced plans to divest a further $10 billion of assets before the end of 2015, having completed its earlier divestment programme of $38 billion in 2012. BP has agreed around $3.4 billion of such further divestments to date. Disposal proceeds received in cash were $0.8 billion for the quarter and $1.8 billion for the half year.

 

•

BP today announced a quarterly dividend of 9.75 cents per ordinary share ($0.585 per ADS), which is expected to be paid on 19 September 2014. The corresponding amount in sterling will be announced on 9 September 2014. See page 27 for further information.

 

*	For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 39.

(a)	Profit attributable to BP shareholders.

 

 

The commentaries above and following should be read in conjunction with the cautionary statement on page 51.

 

 

 

 

3

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Group headlines (continued)

 

 

 

•

The effective tax rate (ETR) on the profit for the second quarter and half year was 33% and 32% respectively, compared with 48% and 20% for the same periods in 2013. The ETR on RC profit for the second quarter and half year was 34% and 32% respectively, compared with 46% and 20% for the same periods in 2013. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the second quarter and half year was 33% for both periods, compared with 45% and 41% for the same periods in 2013. The underlying ETR was higher in 2013 due to foreign exchange impacts on deferred tax and a lower level of equity-accounted earnings (which are reported net of tax), compared with the corresponding periods in 2014.

 

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $356 million for the second quarter, compared with $369 million for the same period in 2013. For the half year, the respective amounts were $723 million and $773 million.

 

•

BP repurchased 53 million ordinary shares at a cost of $0.5 billion, including fees and stamp duty, during the second quarter of 2014. For the half year, BP repurchased 298 million ordinary shares at a cost of $2.4 billion, including fees and stamp duty. As at 30 June 2014, BP had bought back 1,051 million shares for a total amount of $7.9 billion, including fees and stamp duty, since the announcement on 22 March 2013 of a share repurchase programme with a total value of up to $8 billion. The $8-billion share repurchase programme was completed in July 2014.

 

 

 

4

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Analysis of RC profit before interest and tax

and reconciliation to profit for the period

 

 

 

Second quarter 2013				Second quarter 2014				$ million		First half 2014				First half 2013
								RC profit before interest and tax*
	4,400				4,049			Upstream			8,708				9,962
	1,016				933			Downstream			1,727				2,663
	—				—			TNK-BP(a)			—				12,500
	218				1,024			Rosneft(b)			1,542				303
	(573	)			(434	)		Other businesses and corporate			(931	)			(1,040	)
	(199	)			(251	)		Gulf of Mexico oil spill response(c)			(280	)			(221	)
	129				(76	)		Consolidation adjustment – UPII*			14				556
	4,991				5,245			RC profit before interest and tax			10,780				24,723
	(369	)			(356	)		Finance costs and net finance expense relating to pensions and other post-retirement benefits			(723	)			(773	)
	(2,138	)			(1,643	)		Taxation on a RC basis			(3,245	)			(4,791	)
	(84	)			(64	)		Non-controlling interests			(155	)			(163	)
	2,400				3,182			RC profit attributable to BP shareholders			6,657				18,996
	(506	)			258			Inventory holding gains (losses)			360				(100	)
	148				(71	)		Taxation (charge) credit on inventory holding gains and losses			(120	)			9
	2,042				3,369			Profit for the period attributable to BP shareholders			6,897				18,905

 

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. First half 2013 includes the gain arising on disposal of BP’s interest in TNK-BP.

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

(c)	See Note 2 on page 18 for further information on the accounting for the Gulf of Mexico oil spill response.

Analysis of underlying RC profit before interest and tax

 

 

 

Second quarter 2013				Second quarter 2014				$ million		First half 2014				First half 2013
								Underlying RC profit before interest and tax*
	4,288				4,655			Upstream			9,056				9,990
	1,201				733			Downstream			1,744				2,842
	218				1,024			Rosneft			1,295				303
	(438	)			(438	)		Other businesses and corporate			(927	)			(899	)
	129				(76	)		Consolidation adjustment – UPII			14				556
	5,398				5,898			Underlying RC profit before interest and tax			11,182				12,792
	(359	)			(347	)		Finance costs and net finance expense relating to pensions and other post-retirement benefits			(704	)			(753	)
	(2,243	)			(1,852	)		Taxation on an underlying RC basis			(3,463	)			(4,949	)
	(84	)			(64	)		Non-controlling interests			(155	)			(163	)
	2,712				3,635			Underlying RC profit attributable to BP shareholders			6,860				6,927

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 6-11 for the segments.

 

 

 

5

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Upstream

 

 

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
	16,418				16,739			Sales and other operating revenues			33,745				34,636
	4,396				4,048			Profit before interest and tax			8,701				9,956
	4				1			Inventory holding (gains) losses*			7				6
	4,400				4,049			RC profit before interest and tax			8,708				9,962
	(112	)			606			Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*			348				28
	4,288				4,655			Underlying RC profit before interest and tax*(a)			9,056				9,990

 

(a)	See page 7 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

Sales and other operating revenues for the second quarter and half year were $17 billion and $34 billion respectively, compared with $16 billion and $35 billion for the corresponding periods in 2013. For the second quarter, revenues were higher mainly due to higher realizations and higher gas marketing and trading revenues, partially offset by lower volumes. For the half year, the reduction was mainly due to lower volumes partially offset by higher gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $4,049 million and $8,708 million respectively, compared with $4,400 million and $9,962 million for the same periods in 2013. The second quarter and half year included a net non-operating charge of $516 million and $240 million respectively, compared with a net non-operating gain of $143 million and $63 million a year ago. Fair value accounting effects in the second quarter and half year had unfavourable impacts of $90 million and $108 million respectively, compared with unfavourable impacts of $31 million and $91 million in the same periods of 2013.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $4,655 million and $9,056 million respectively, compared with $4,288 million and $9,990 million for the same periods in 2013. The result for the second quarter reflected higher production in higher-margin areas and higher liquids and gas realizations, partly offset by higher costs, primarily depreciation, depletion and amortization and wellwork, and the impact of divestments. The result for the first half reflected the same factors as the second quarter, with the exception of liquids realizations, which were lower, the impact of higher exploration write-offs, mainly in the first quarter, and a benefit from stronger gas marketing and trading activities, again mainly in the first quarter.

Production

Reported production for the quarter was 2,106mboe/d, 6% lower than the second quarter of 2013. Underlying production* for the quarter was 3.1% higher. This reflected growth in production from higher-margin areas, mainly driven by strong performance in the Gulf of Mexico. For the first half, production was 2,118mboe/d, 7.3% lower than in the same period of 2013. First-half underlying production was 1.4% higher than in 2013.

Key events

In May, Rosneft and BP signed a heads of agreement that provides for implementation of a joint pilot project relating to the Domanik formations in Central Russia’s Volga-Urals region and, in the event of success, the possible development of unconventional Domanik resources.

In June, production commenced from the CLOV (Cravo, Lirio, Orquidea and Violeta) major project in Angola (BP 16.67%). This is the fifth major project start-up in 2014.

Also in June, BP and the China National Offshore Oil Corporation (CNOOC) announced a heads of agreement for BP to supply up to 1.5 million tonnes of liquefied natural gas (LNG) per year over 20 years starting in 2019.

Furthermore, BP and Pantera Acquisition Group, LLC (Pantera) signed an agreement under which Pantera has agreed to acquire BP’s interests in the Panhandle West and Texas Hugoton gas fields for a purchase price of $390 million.

Outlook

Looking ahead, we expect third-quarter 2014 reported production to be lower than the second quarter, primarily reflecting planned major turnaround and seasonal maintenance activities in Alaska and the Gulf of Mexico. We expect the seasonal reduction to be slightly larger than we experienced in the same quarters of 2013 due to phasing of these activities.

See also Note 1 on page 18.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 51.

 

 

 

 

6

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Upstream

 

 

 

Second quarter 2013				Second quarter 2014				$ million		First half 2014				First half 2013
								Underlying RC profit before interest and tax(a)
	561				1,419			US(b)			2,150				1,515
	3,727				3,236			Non-US(c)			6,906				8,475
	4,288				4,655						9,056				9,990
								Non-operating items
	62				(72	)		US			(131	)			56
	81				(444	)		Non-US			(109	)			7
	143				(516	)					(240	)			63
								Fair value accounting effects
	(33	)			(31	)		US			(80	)			(73	)
	2				(59	)		Non-US			(28	)			(18	)
	(31	)			(90	)					(108	)			(91	)
								RC profit before interest and tax(a)
	590				1,316			US			1,939				1,498
	3,810				2,733			Non-US			6,769				8,464
	4,400				4,049						8,708				9,962
								Exploration expense
	85				68			US(d)			727				165
	349				321			Non-US			610				591
	434				389						1,337				756
								Production (net of royalties)(e)
								Liquids* (mb/d)
	335				429			US			413				351
	97				92			Europe			99				106
	732				562			Rest of World			572				722
	1,165				1,083						1,084				1,179
	297				160			Of which equity-accounted entities			171				297
								Natural gas (mmcf/d)
	1,573				1,525			US			1,502				1,553
	286				166			Europe			182				307
	4,386				4,244			Rest of World			4,317				4,558
	6,244				5,936						6,001				6,418
	423				422			Of which equity-accounted entities			435				410
								Total hydrocarbons* (mboe/d)
	606				692			US			672				618
	147				121			Europe			130				159
	1,488				1,293			Rest of World			1,316				1,508
	2,241				2,106						2,118				2,285
	370				233			Of which equity-accounted entities			246				368
								Average realizations(f)
	94.92				96.90			Total liquids ($/bbl)			97.03				99.08
	5.37				5.67			Natural gas ($/mcf)			5.94				5.45
	61.27				64.90			Total hydrocarbons ($/boe)			65.53				63.23

 

(a)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.

(b)	The increase in the second quarter 2014 compared with the second quarter 2013 primarily reflects higher production in the Gulf of Mexico and higher realizations.

(c)	The decrease in the second quarter 2014 compared with the second quarter 2013 primarily reflects higher costs, mainly depreciation, depletion and amortization, and the impact of divestments, partly offset by higher realizations.

(d)

Following on from the decision to create a separate BP business around our US lower 48 onshore oil and gas activities, and as a consequence of disappointing appraisal results, we have decided not to proceed with development plans in the Utica shale. First half 2014 includes a $521-million write-off relating to the Utica acreage.

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

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

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

 

 

 

7

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Downstream

 

 

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
	88,348				86,871			Sales and other operating revenues			171,169				175,132
	501				1,166			Profit before interest and tax			2,037				2,556
	515				(233	)		Inventory holding (gains) losses*			(310	)			107
	1,016				933			RC profit before interest and tax			1,727				2,663
	185				(200	)		Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*			17				179
	1,201				733			Underlying RC profit before interest and tax*(a)			1,744				2,842

 

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

Financial results

Sales and other operating revenues for the second quarter and half year were $87 billion and $171 billion respectively, compared with $88 billion and $175 billion for the corresponding periods in 2013. The reduction in the second quarter and half year was mainly due to lower sales volumes. In the second quarter these were largely offset by higher prices.

The replacement cost profit before interest and tax for the second quarter and half year was $933 million and $1,727 million respectively, compared with $1,016 million and $2,663 million for the same periods in 2013.

The 2014 results included net non-operating gains of $50 million for the second quarter and a net non-operating charge of $228 million for the half year, compared with net non-operating charges of $323 million and $304 million for the same periods a year ago (see pages 9 and 36 for further information on non-operating items). The second-quarter net non-operating gains are principally associated with divestments in the fuels and lubricants businesses, and the charges for the half year reflect an impairment relating to the announced halt of the refining operations at the Bulwer refinery in Australia, planned for 2015. Fair value accounting effects had favourable impacts of $150 million for the second quarter and $211 million for the half year, compared with $138 million for the second quarter and $125 million for the half year of 2013.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $733 million and $1,744 million respectively, compared with $1,201 million and $2,842 million a year ago.

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

Fuels business

The fuels business delivered an underlying replacement cost profit before interest and tax of $516 million for the second quarter and $1,216 million for the half year, compared with $853 million and $2,090 million for the same periods in 2013. The lower result in the first half was principally due to significantly weaker refining margins in both the quarter and half year and a lower contribution from supply and trading in the second quarter. These impacts were partially offset by significantly higher production at the Whiting refinery due to the commissioning of its largest crude unit which had a planned outage in the same period last year, and associated processing of heavy crude. Heavy crude processing reached a peak of 270,000 barrels per day during the quarter.

Lubricants business

The lubricants business delivered an underlying replacement cost profit before interest and tax of $315 million in the second quarter and $622 million in the half year, compared with $372 million and $717 million in the same periods last year. The lower result was due to restructuring programmes and foreign exchange effects. The positive long-term performance trend continues to reflect execution of our strategy, including delivery from our premium brands and focus on high growth markets.

Petrochemicals business

The petrochemicals business incurred an underlying replacement cost loss before interest and tax of $98 million in the second quarter and $94 million in the half year, compared with $24 million and an underlying replacement cost profit before interest and tax of $35 million, respectively, in the same periods last year. The loss was principally due to environmental factors, especially in the aromatics business, as excess supply in Asia and high xylene prices in the US created downward pressures on product margins.

Outlook

In the third quarter, in the fuels business we expect stronger margin capture relative to the second quarter, driven by a lower level of turnarounds and Whiting operations. In the petrochemicals business the challenging environment is expected to continue, but we should benefit from a lower level of turnarounds.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 51.

 

 

 

 

8

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Downstream

 

 

 

Second quarter 2013				Second quarter 2014				$ million		First half 2014				First half 2013
								Underlying RC profit before interest and tax – by region
	557				331			US			743				1,307
	644				402			Non-US			1,001				1,535
	1,201				733						1,744				2,842
								Non-operating items
	(17	)			180			US			179				11
	(306	)			(130	)		Non-US			(407	)			(315	)
	(323	)			50						(228	)			(304	)
								Fair value accounting effects
	219				206			US			297				154
	(81	)			(56	)		Non-US			(86	)			(29	)
	138				150						211				125
								RC profit before interest and tax
	759				717			US			1,219				1,472
	257				216			Non-US			508				1,191
	1,016				933						1,727				2,663
								Underlying RC profit (loss) before interest and tax – by business(a)(b)
	853				516			Fuels			1,216				2,090
	372				315			Lubricants			622				717
	(24	)			(98	)		Petrochemicals			(94	)			35
	1,201				733						1,744				2,842
								Non-operating items and fair value accounting effects(c)
	(188	)			15			Fuels			(202	)			(177	)
	3				186			Lubricants			186				(2	)
	—				(1	)		Petrochemicals			(1	)			—
	(185	)			200						(17	)			(179	)
								RC profit (loss) before interest and tax(a)(b)
	665				531			Fuels			1,014				1,913
	375				501			Lubricants			808				715
	(24	)			(99	)		Petrochemicals			(95	)			35
	1,016				933						1,727				2,663
	19.1				15.4			BP average refining marker margin (RMM)* ($/bbl)			14.4				18.2
								Refinery throughputs (mb/d)
	711				645			US			630				824
	745				757			Europe			777				775
	252				250			Rest of World			279				287
	1,708				1,652						1,686				1,886
	95.3				95.3			Refining availability* (%)			95.1				95.2
								Marketing sales of refined products (mb/d)
	1,340				1,183			US			1,152				1,371
	1,316				1,154			Europe			1,146				1,237
	549				515			Rest of World			530				553
	3,205				2,852						2,828				3,161
	2,527				2,468			Trading/supply sales of refined products			2,442				2,418
	5,732				5,320			Total sales volumes of refined products			5,270				5,579
								Petrochemicals production (kte)
	1,081				969			US			2,040				2,157
	814				895			Europe			1,867				1,828
	1,519				1,501			Rest of World			2,923				2,936
	3,414				3,365						6,830				6,921

 

(a)	Segment-level overhead expenses are included in the fuels business result.

(b)	BP’s share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.

(c)	For Downstream, fair value accounting effects arise solely in the fuels business.

 

 

 

9

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Rosneft

 

 

 

Second quarter 2013(a)				Second quarter 2014						First half 2014				First half 2013
								$ million
	231				1,050			Profit before interest and tax(b)			1,599				316
	(13)				(26	)		Inventory holding (gains) losses*			(57	)			(13	)
	218				1,024			RC profit before interest and tax			1,542				303
	—				—			Net charge (credit) for non-operating items*			(247	)			—
	218				1,024			Underlying RC profit before interest and tax*			1,295				303

Replacement cost profit before interest and tax for the second quarter and half year was $1,024 million and $1,542 million respectively, compared with $218 million and $303 million for the same periods in 2013.

There were no non-operating items in the second quarter of 2014 and a non-operating gain of $247 million in the first half of 2014, relating to Rosneft’s sale of its interest in the Yugragazpererabotka joint venture. There were no non-operating items in the first half of 2013.

After adjusting for non-operating items, the underlying replacement cost profit for the second quarter and half year was $1,024 million and $1,295 million respectively, compared with $218 million and $303 million for the same periods in 2013. The primary factor impacting the second-quarter result, compared with the same period last year, was favourable foreign exchange effects. The half-year result reflected a full six months this year compared with 11 days of the first quarter and three months of the second quarter reported in the same period last year as well as favourable foreign exchange effects.

On 27 June 2014, Rosneft’s Annual General Meeting of Shareholders approved the distribution of a dividend of 12.85 roubles per share. We received our share of this dividend in July 2014, which amounted to $693 million after the deduction of withholding tax.

See also Principal risks and uncertainties – Rosneft investment on page 42 and Other matters on page 50 for information on sanctions.

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013(c)
								Production (net of royalties) (BP share)
	826				816			Liquids* (mb/d)			822				466
	689				1,000			Natural gas (mmcf/d)			993				391
	945				988			Total hydrocarbons* (mboe/d)			993				533

 

(a)	Second quarter 2013 as reported includes an amendment to first-quarter profit, which was reported based on a BP estimate.

(b)

The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s interest in TNK-BP. BP’s share of Rosneft’s earnings after their finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.

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

 

 

 

10

---

Other businesses and corporate

 

 

 

Second quarter				Second quarter						First half				First half
2013				2014						2014				2013
								$ million
	414				412			Sales and other operating revenues			843				834
	(573	)			(434	)		Profit (loss) before interest and tax			(931	)			(1,040	)
	—				—			Inventory holding (gains) losses*			—				—
	(573	)			(434	)		RC profit (loss) before interest and tax			(931	)			(1,040	)
	135				(4	)		Net charge (credit) for non-operating items*			4				141
	(438	)			(438	)		Underlying RC profit (loss) before interest and tax*			(927	)			(899	)
								Underlying RC profit (loss) before interest and tax
	(142	)			(226	)		US			(325	)			(263	)
	(296	)			(212	)		Non-US			(602	)			(636	)
	(438	)			(438	)					(927	)			(899	)
								Non-operating items
	(134	)			4			US			3				(138	)
	(1	)			—			Non-US			(7	)			(3	)
	(135	)			4						(4	)			(141	)
								RC profit (loss) before interest and tax
	(276	)			(222	)		US			(322	)			(401	)
	(297	)			(212	)		Non-US			(609	)			(639	)
	(573	)			(434	)					(931	)			(1,040	)

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.

Financial results

The replacement cost loss before interest and tax for the second quarter and half year was $434 million and $931 million respectively, compared with $573 million and $1,040 million for the same periods last year.

The second-quarter result included a net non-operating gain of $4 million, compared with a net non-operating charge of $135 million a year ago. The charge in the second quarter last year related principally to impairments of assets in our wind business. For the half year, the net non-operating charge was $4 million, compared with a net non-operating charge of $141 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $438 million and $927 million respectively, compared with $438 million and $899 million for the same periods last year.

Alternative Energy

Biofuels

In our biofuels business we have three operating mills in Brazil where ethanol-equivalent production (which includes ethanol and sugar) for the second quarter was 113 million litres compared with 116 million litres in the same period a year ago. There was no production at our Brazilian mills in the first quarter of 2014 or 2013 due to the inter-harvest season. In the UK, the Vivergo joint venture (BP 47%) had ethanol production of 26 million litres (54 million litres gross) for the second quarter and 43 million litres (90 million litres gross) for the first half of 2014.

Wind

Net wind generation capacity*^(a) was 1,590MW (2,619MW gross) at 30 June 2014, the same level as at 30 June 2013. BP’s net share of wind generation for the second quarter and half year was 1,248GWh (2,082GWh gross) and 2,540GWh (4,303GWh gross) respectively, compared with 1,143GWh (1,957GWh gross) and 2,287GWh (4,021GWh gross) for the same periods of 2013.

 

(a)	Capacity figures include 32MW in the Netherlands managed by our Downstream segment.

 

 

 

11

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Gulf of Mexico oil spill

 

 

In April 2014, the US Coast Guard ended patrols and operations on the final three shoreline miles in Louisiana. The Coast Guard has now transitioned all shoreline areas to the National Response Center process and has indicated that if oil is later discovered in a shoreline segment where removal actions have been deemed complete, it will follow long-standing response protocols established under the law and contact whoever it believes is the responsible party or parties.

Financial update

The replacement cost loss before interest and tax for the second quarter and half year was $251 million and $280 million respectively, compared with a $199 million loss and a $221 million loss for the same periods last year. The second-quarter charge reflects an increase in the provision for legal costs and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $43.0 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 18, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results 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 page 41.

Trust update

During the second quarter, $219 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $201 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $18 million for natural resource damage assessment. In addition, $15 million was paid to claimants from the seafood compensation fund, for which the related provision and reimbursement asset had been previously derecognized upon funding of the QSF. At 30 June 2014, the aggregate cash balances in the Trust and the QSFs amounted to $6.3 billion, including $1.1 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration projects.

As at 30 June 2014, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, amounted to $19.3 billion. No amount is provided for business economic loss claims not yet received, processed, and paid by the DHCSSP. See Note 2 on page 18 and Legal proceedings on page 48 for further details.

Legal proceedings

The federal district court in New Orleans (the District Court) scheduled the penalty phase in MDL 2179 to commence in January 2015. In this phase, the District Court will determine the amount of civil penalties owed to the United States under the Clean Water Act based on the court’s rulings as to the presence of negligence, gross negligence or wilful misconduct and quantification of discharge in the earlier phases of the trial and the application of the penalty factors under the Clean Water Act. The District Court could issue its decision on the issues presented in the earlier trial phases at any time.

The District Court ruled in December 2013 requiring the claims administrator, in administering business economic loss claims, to match a claimant’s revenue with corresponding variable expenses and develop a revised matching policy accordingly. In March 2014, the claims administrator issued a revised matching policy reflecting this order and in May 2014 it was approved by the District Court. The Plaintiffs’ Steering Committee has filed a motion seeking to amend the revised policy.

In March 2014, the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) affirmed the District Court’s ruling that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. In March 2014, BP filed a petition that all the active judges of the Fifth Circuit review the decision; in May 2014 this was denied. The District Court dissolved the injunction that had halted the processing and payment of business economic loss claims and instructed the claims administrator to resume the processing and payment of claims. BP has announced it will seek review by the US Supreme Court of the Fifth Circuit’s decisions relating to compensation of claims for losses with no apparent connection to the Deepwater Horizon spill. In June 2014, BP also asked the District Court to order the return of excessive payments made by the DHCSSP under the matching policy in effect before the December 2013 Ruling.

The Medical Benefits Class Action Settlement Agreement provides for claims to be paid to qualifying class members for one year from the agreement’s effective date, which was February 2014.

In March 2014, BP p.l.c., BP Exploration & Production and all other temporarily suspended BP entities entered into an agreement with the US Environmental Protection Agency resolving all issues related to suspension or debarment arising from the Deepwater Horizon incident, allowing BP entities to enter into new contracts or leases with the US Government. Under the terms and conditions of the agreement, which will apply for five years, BP has agreed to a set of safety and operations, ethics and compliance and corporate governance requirements.

In May 2014, the judge denied plaintiffs’ motion in the multi-district litigation proceeding in federal district court in Houston (MDL 2185) to certify a proposed class of ADS purchasers before the explosion (from 8 November 2007 to 20 April 2010) and granted plaintiffs’ motion to certify a class of post-explosion ADS purchasers (from 26 April 2010 to 28 May 2010). Both defendants and plaintiffs were granted permission by the Fifth Circuit to appeal from that decision in July 2014.

For further details, see Legal proceedings on page 48.

 

 

 

12

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Financial statements

 

 

Group income statement

 

Second quarter				Second quarter						First half				First half
2013				2014						2014				2013
								$ million
	94,711				93,957			Sales and other operating revenues (Note 5)			185,667				188,818
	102				155			Earnings from joint ventures – after interest and tax			270				227
	448				1,228			Earnings from associates – after interest and tax			2,011				732
	207				157			Interest and other income			488				364
	236				330			Gains on sale of businesses and fixed assets			379				12,777
	95,704				95,827			Total revenues and other income			188,815				202,918
	75,127				74,536			Purchases			146,004				146,788
	7,126				6,980			Production and manufacturing expenses			13,811				13,994
	1,672				816			Production and similar taxes (Note 6)			1,802				3,667
	3,162				3,751			Depreciation, depletion and amortization			7,341				6,359
	610				774			Impairment and losses on sale of businesses and fixed assets			1,200				720
	434				389			Exploration expense			1,337				756
	3,223				3,110			Distribution and administration expenses			6,310				6,177
	(135	)			(32	)		Fair value gain on embedded derivatives			(130	)			(166	)
	4,485				5,503			Profit before interest and taxation			11,140				24,623
	252				277			Finance costs			564				534
	117				79			Net finance expense relating to pensions and other post-retirement benefits			159				239
	4,116				5,147			Profit before taxation			10,417				23,850
	1,990				1,714			Taxation			3,365				4,782
	2,126				3,433			Profit for the period			7,052				19,068
								Attributable to
	2,042				3,369			BP share holders			6,897				18,905
	84				64			Non-controlling interests			155				163
	2,126				3,433						7,052				19,068
								Earnings per share (Note 7)
								Profit for the period attributable to BP share holders
								Per ordinary share (cents)
	10.73				18.26			Basic			37.35				99.07
	10.68				18.15			Diluted			37.11				98.53
								Per ADS (dollars)
	0.64				1.10			Basic			2.24				5.94
	0.64				1.09			Diluted			2.23				5.91

 

 

 

13

---

Financial statements (continued)

 

 

 

Group statement of comprehensive income

 

Second quarter				Second quarter						First half				First half
2013				2014						2014				2013
								$ million
	2,126				3,433			Profit for the period			7,052				19,068
								Other comprehensive income
								Items that may be reclassified subsequently to profit or loss
	(1,506	)			1,005			Currency translation differences			92				(2,093	)
	—				2			Available-for-sale investments marked to market			(1	)			(172	)
	—				1			Available-for-sale investments reclassified to the income statement			1				(523	)
	(25	)			77			Cash flow hedges marked to market(a)			100				(2,166	)
	(1	)			(49	)		Cash flow hedges reclassified to the income statement			(69	)			(1	)
	12				(2	)		Cash flow hedges reclassified to the balance sheet			(3	)			15
	(88	)			51			Share of items relating to equity-accounted entities, net of tax			(22	)			(55	)
	26				9			Income tax relating to items that may be reclassified			9				195
	(1,582	)			1,094						107				(4,800	)
								Items that will not be reclassified to profit or loss
	2,206				222			Remeasurements of the net pension and other post-retirement benefit liability or asset			(714	)			2,156
	—				—			Share of items relating to equity-accounted entities, net of tax			5				—
	(732	)			(73	)		Income tax relating to items that will not be reclassified			221				(731	)
	1,474				149						(488	)			1,425
	(108	)			1,243			Other comprehensive income			(381	)			(3,375	)
	2,018				4,676			Total comprehensive income			6,671				15,693
								Attributable to
	1,956				4,606			BP shareholders			6,509				15,556
	62				70			Non-controlling interests			162				137
	2,018				4,676						6,671				15,693

 

(a)	First half 2013 includes $2,061 million loss relating to the contracts to acquire Rosneft shares.

 

 

 

14

---

Financial statements (continued)

 

 

 

Group statement of changes in equity

 

		BP shareholders’ equity				Non-controlling interests				Total equity
$ million
At 1 January 2014			129,302				1,105				130,407
Total comprehensive income			6,509				162				6,671
Dividends			(2,999	)			(153	)			(3,152	)
Repurchases of ordinary share capital			(1,527	)			—				(1,527	)
Share-based payments, net of tax			576				—				576
Transactions involving non-controlling interests			—				3				3
At 30 June 2014			131,861				1,117				132,978
		BP shareholders’ equity				Non-controlling interests				Total equity
$ million
At 1 January 2013			118,546				1,206				119,752
Total comprehensive income			15,556				137				15,693
Dividends			(3,020	)			(236	)			(3,256	)
Repurchases of ordinary share capital			(2,469	)			—				(2,469	)
Share-based payments, net of tax			378				—				378
Transactions involving non-controlling interests			—				35				35
At 30 June 2013			128,991				1,142				130,133

 

 

 

15

---

Financial statements (continued)

 

 

 

Group balance sheet

 

		30 June 2014				31 December 2013
$ million
Non-current assets
Property, plant and equipment			135,854				133,690
Goodwill			12,197				12,181
Intangible assets			21,931				22,039
Investments in joint ventures			9,173				9,199
Investments in associates			17,370				16,636
Other investments			1,270				1,565
Fixed assets			197,795				195,310
Loans			681				763
Trade and other receivables			5,782				5,985
Derivative financial instruments			3,609				3,509
Prepayments			983				922
Deferred tax assets			1,308				985
Defined benefit pension plan surpluses			978				1,376
			211,136				208,850
Current assets
Loans			334				216
Inventories			29,442				29,231
Trade and other receivables			40,056				39,831
Derivative financial instruments			2,852				2,675
Prepayments			1,630				1,388
Current tax receivable			648				512
Other investments			376				467
Cash and cash equivalents			27,506				22,520
			102,844				96,840
Assets classified as held for sale (Note 3)			1,475				—
			104,319				96,840
Total assets			315,455				305,690
Current liabilities
Trade and other payables			50,025				47,159
Derivative financial instruments			2,323				2,322
Accruals			7,245				8,960
Finance debt			7,570				7,381
Current tax payable			2,386				1,945
Provisions			4,454				5,045
			74,003				72,812
Liabilities directly associated with assets classified as held for sale (Note 3)			428				—
			74,431				72,812
Non-current liabilities
Other payables			3,652				4,756
Derivative financial instruments			1,765				2,225
Accruals			807				547
Finance debt			45,336				40,811
Deferred tax liabilities			18,328				17,439
Provisions			28,204				26,915
Defined benefit pension plan and other post-retirement benefit plan deficits			9,954				9,778
			108,046				102,471
Total liabilities			182,477				175,283
Net assets			132,978				130,407
Equity
BP shareholders’ equity			131,861				129,302
Non-controlling interests			1,117				1,105
			132,978				130,407

 

 

 

16

---

Financial statements (continued)

 

 

 

Condensed group cash flow statement

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Operating activities
	4,116				5,147			Profit before taxation			10,417				23,850
								Adjustments to reconcile profit before taxation to net cash provided by operating activities
	3,453				3,953			Depreciation, depletion and amortization and exploration expenditure written off			8,375				6,822
	374				444			Impairment and (gain) loss on sale of businesses and fixed assets			821				(12,057	)
	(254	)			(1,080	)		Earnings from equity-accounted entities, less dividends received			(1,764	)			(454	)
	21				(3	)		Net charge for interest and other finance expense, less net interest paid			167				193
	175				178			Share-based payments			284				221
	(86	)			(105	)		Net operating charge for pensions and other post- retirement benefits, less contributions and benefit payments for unfunded plans			(207	)			(370	)
	1,308				56			Net charge for provisions, less payments			(137	)			1,505
	(1,796	)			654			Movements in inventories and other current and non-current assets and liabilities(a)			339				(7,141	)
	(1,924	)			(1,367	)		Income taxes paid			(2,187	)			(3,215	)
	5,387				7,877			Net cash provided by operating activities			16,108				9,354
								Investing activities
	(6,111	)			(5,499	)		Capital expenditure			(11,390	)			(11,840	)
	—				—			Acquisitions, net of cash acquired			(10	)			—
	(47	)			(3	)		Investment in joint ventures			(36	)			(98	)
	(8	)			(47	)		Investment in associates			(135	)			(4,891	)
	656				227			Proceeds from disposal of fixed assets			1,205				17,436
	2,284				571			Proceeds from disposal of businesses, net of cash disposed			597				3,785
	68				53			Proceeds from loan repayments			70				90
	(3,158	)			(4,698	)		Net cash provided by (used in) investing activities			(9,699	)			4,482
								Financing activities
	(1,890	)			(447	)		Net issue (repurchase) of shares			(2,173	)			(1,835	)
	3,039				856			Proceeds from long-term financing			6,835				3,102
	(891	)			(1,720	)		Repayments of long-term financing			(2,957	)			(1,179	)
	(382	)			(57	)		Net increase (decrease) in short-term debt			20				(1,873	)
	(1,398	)			(1,572	)		Dividends paid – BP shareholders			(2,999	)			(3,020	)
	(85	)			(140	)		– non-controlling interests			(153	)			(116	)
	(1,607	)			(3,080	)		Net cash provided by (used in) financing activities			(1,427	)			(4,921	)
	12				49			Currency translation differences relating to cash and cash equivalents			4				(237	)
	634				148			Increase (decrease) in cash and cash equivalents			4,986				8,678
	27,679				27,358			Cash and cash equivalents at beginning of period			22,520				19,635
	28,313				27,506			Cash and cash equivalents at end of period			27,506				28,313

 

(a)

Includes

	509				(233	)		Inventory holding (gains) losses			(307	)			102
	(135	)			(32	)		Fair value gain on embedded derivatives			(130	)			(166	)
	(1,430	)			(33	)		Movements related to the Gulf of Mexico oil spill response			(611	)			(2,258	)

Inventory holding gains and losses and fair value gains on embedded derivatives are also included within profit before taxation. See Note 2 for further information on the cash flow impacts of the Gulf of Mexico oil spill.

 

 

 

17

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Financial statements (continued)

 

 

 

Notes

 

1.	Basis of preparation

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

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. 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 2013 included in the BP Annual Report and Form 20-F 2013.

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

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

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 2014, which do not differ significantly from those used in BP Annual Report and Form 20-F 2013.

In BP Annual Report and Form 20-F 2013 we disclosed a significant estimate or judgement in relation to exploration and appraisal expenditure which is capitalized and is subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Under IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’, one of the facts and circumstances which indicates that an entity should test such assets for impairment, is that the period for which the entity has a right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed.

BP has leases in the Gulf of Mexico making up a prospect, some with terms which were scheduled to expire at the end of last year and some with terms which are scheduled to expire in the near future. A significant proportion of our capitalized exploration and appraisal costs in the Gulf of Mexico relate to this prospect. This prospect requires the development of subsea technology to ensure that the hydrocarbons can be extracted safely. BP is in correspondence with the US Bureau of Safety and Environmental Enforcement in relation to seeking extension of these leases so that the discovered hydrocarbons can be developed. BP remains committed to developing this prospect and expects that the lease terms will be extended and therefore continues to carry the capitalized costs on its balance sheet. See also Notes 10 and 16 in BP Annual Report and Form 20-F 2013 – Financial statements.

 

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 2013 – Financial statements – Note 2 and Legal proceedings on pages 257-265 and page 48 of this report.

The group income statement includes a pre-tax charge of $260 million for the second quarter and $299 million for the first half of 2014 in relation to the Gulf of Mexico oil spill. The second-quarter charge reflects an increase in the provision for legal costs and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $42,975 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 Plaintiffs’ Steering Committee (PSC) settlement, 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 and contingent liabilities below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results 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 page 41.

 

 

 

18

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Financial statements (continued)

 

 

Notes

 

2.	Gulf of Mexico oil spill (continued)

 

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

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Income statement
	199				251			Production and manufacturing expenses			280				221
	(199	)			(251	)		Profit (loss) before interest and taxation			(280	)			(221	)
	10				9			Finance costs			19				20
	(209	)			(260	)		Profit (loss) before taxation			(299	)			(241	)
	42				44			Taxation			54				37
	(167	)			(216	)		Profit (loss) for the period			(245	)			(204	)

 

		30 June 2014				31 December 2013
$ million
Balance sheet
Current assets
Trade and other receivables			1,944				2,457
Current liabilities
Trade and other payables			(838	)			(1,030	)
Provisions			(2,345	)			(2,951	)
Net current assets (liabilities)			(1,239	)			(1,524	)
Non-current assets
Other receivables			2,569				2,442
Non-current liabilities
Other payables			(2,397	)			(2,986	)
Accruals			(170	)			—
Provisions			(6,653	)			(6,395	)
Deferred tax			2,285				2,748
Net non-current assets (liabilities)			(4,366	)			(4,191	)
Net assets (liabilities)			(5,605	)			(5,715	)

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Cash flow statement - Operating activities
	(209)				(260	)		Profit (loss) before taxation			(299	)			(241	)
								Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
	10				9			Net charge for interest and other finance expense, less net interest paid			19				20
	1,390				116			Net charge for provisions, less payments			19				1,694
	(1,430	)			(33	)		Movements in inventories and other current and non-current assets and liabilities			(611	)			(2,258	)
	(239)				(168	)		Pre-tax cash flows			(872	)			(785	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an inflow of $229 million and outflow of $355 million in the second quarter and first half of 2014 respectively. For the same periods in 2013, the amounts were an inflow of $142 million and an outflow of $189 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. Fines and penalties are not covered by the trust fund.

 

 

 

19

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Financial statements (continued)

 

 

Notes

 

2.	Gulf of Mexico oil spill (continued)

 

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.

The table below shows movements in the reimbursement asset during the period to 30 June 2014. For more information about the movement in provisions for items covered by the trust fund, see Provisions below. At 30 June 2014, $4,487 million of the provisions, and $26 million of the payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements.

 

		Second quarter 2014				First half 2014
$ million
Opening balance			4,730				4,899
Net increase in provision for items covered by the trust fund			2				6
Amounts paid directly by the trust fund			(219	)			(392	)
At 30 June 2014			4,513				4,513
Of which – current			1,944				1,944
– non-current			2,569				2,569

Increases in estimated future expenditure that will be covered by the trust fund up to an aggregate of $20 billion have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 30 June 2014, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,344 million. Thus, a further $656 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 Deepwater Horizon Court Supervised Settlement Program (DHCSSP), or otherwise, including the various claims described in Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 48 of this report, would be expensed to the income statement. Information on those items that currently cannot be estimated reliably is provided under Provisions and contingent liabilities below.

As at 30 June 2014, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $6.3 billion, including $1.1 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.

(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 2013 – Financial statements – Note 2.

Provisions

BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, litigation and claims, and Clean Water Act penalties. Movements in each class of provision during the second quarter and first half are presented in the tables below.

 

				Environmental				Litigation and claims				Clean Water Act penalties				Total
$ million
At 1 April 2014					1,627				3,939				3,510				9,076
Increase in provision – items not covered by the trust fund					—				224				—				224
Net increase in provision – items covered by the trust fund					—				2				—				2
Utilization		– paid by BP			(16	)			(94	)			—				(110	)
		– paid by the trust fund			(18	)			(176	)			—				(194	)
At 30 June 2014					1,593				3,895				3,510				8,998
Of which		– current			747				1,598				—				2,345
		– non-current			846				2,297				3,510				6,653

 

 

 

20

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Financial statements (continued)

 

 

Notes

 

2.	Gulf of Mexico oil spill (continued)

 

				Environmental				Litigation and claims				Clean Water Act penalties				Total
$ million
At 1 January 2014					1,679				4,157				3,510				9,346
Increase (decrease) in provision – items not covered by the trust fund					—				224				—				224
Net increase in provision – items covered by the trust fund					—				6				—				6
Utilization		– paid by BP			(44	)			(167	)			—				(211	)
		– paid by the trust fund			(42	)			(325	)			—				(367	)
At 30 June 2014					1,593				3,895				3,510				8,998

Environmental

The environmental provision includes amounts for BP’s commitment to fund the Gulf of Mexico Research Initiative, estimated natural resource damage assessment costs and early natural resource damage restoration projects under the $1-billion framework agreement with natural resource trustees for the US and five Gulf coast states. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably the amounts or timing of any further natural resource damages claims, therefore no additional amounts have been provided for these items and they are disclosed as a contingent liability.

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 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), and claims by state and local government entities for removal costs, damage to real or personal property, loss of government revenue and increased public services costs (State and Local Claims) under OPA 90 and other legislation, except as described under Contingent liabilities below. Claims administration costs and legal costs 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 2013, 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 Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 48 of this report for further details on the settlements with the PSC and related matters.

Until the uncertainties described below are resolved, management is unable to estimate reliably the value and volume of future business economic loss claims and whether, and to what extent, received or processed but unpaid business economic loss claims will be paid. Firstly, the inherent uncertainty as to the interpretation of the EPD Settlement Agreement in respect of causation issues will continue until the issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal, if an appeal to the Supreme Court is allowed, and until the impact of any new policies and procedures implemented in response to these issues and of the revised policy for the matching of revenue and expenses for business economic loss claims on the value and volume of business economic loss claims becomes clear. Secondly, uncertainty arises from the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends – the number of business economic loss claims received and the average amounts paid in respect of such claims prior to the district court’s injunction were higher than previously assumed by BP. This inability to extrapolate any reliable trends may or may not continue once claims have been assessed against the revised policy for the matching of revenue and expenses for business economic loss claims (implemented in May 2014) and uncertainties concerning interpretation of the EPD Settlement Agreement described above have been resolved. Reassessment of existing claims by the DHCSSP under the revised matching policy is ongoing. The PSC has filed a motion seeking to amend the revised matching policy. Thirdly, the ultimate deadline for filing business economic loss claims is uncertain as claims can be brought at any point up to six months after the date on which all relevant appeals are concluded and the date when all relevant appeals will be concluded is not yet known. Management believes, therefore, 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 for business economic loss claims will be established when a reliable estimate can be made of the liability.

 

 

 

21

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Financial statements (continued)

 

 

Notes

 

2.	Gulf of Mexico oil spill (continued)

 

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 DHCSSP has issued eligibility notices, most of which are disputed by BP, in respect of business economic loss claims of $987 million which have not yet been paid. The majority of these claims are being re-assessed using the new matching policy. 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 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 provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP’s current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and Contingent liabilities below for further details.

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 as described above and in Legal proceedings on page 48 and the outcomes of any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise. There is also uncertainty as to the cost of administering the claims process under the DHCSSP.

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 negligence, gross negligence or wilful misconduct, the volume of oil spilled and the application of statutory penalty factors. The trial court could issue its decision on the first two phases of the trial at any time and has scheduled a trial on the subsequent phase regarding the application of statutory penalty factors starting on 20 January 2015. The court has wide discretion in its determination as to whether a defendant’s conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors. See BP Annual Report and Form 20-F 2013 – Financial statements – Note 2 for further details and Legal proceedings on pages 257-265 and on page 48 of this report.

Provision movements and analysis of income statement charge

An increase in the provision for the estimated cost of the settlement with the PSC of $32 million for the second quarter and $36 million for the first half was recognized, partially offset by other provision reductions. The second-quarter income statement charge reflects an increase in the provision for legal costs and the ongoing costs of the Gulf Coast Restoration Organization. The total charge in the income statement is analysed in the table below.

 

				Second quarter 2014				First half 2014				Cumulative since the incident
$ million
Environmental costs					—				—				3,031
Spill response costs					—				—				14,304
Litigation and claims costs					226				230				25,873
Clean Water Act penalties – amount provided					—				—				3,510
Other costs charged directly to the income statement					27				56				1,199
Recoveries credited to the income statement					—				—				(5,681	)
Charge (credit) related to the trust fund					(2	)			(6	)			519
Other costs of the trust fund					—				—				8
Loss before interest and taxation					251				280				42,763
Finance costs		– related to the trust fund			—				—				137
		– not related to the trust fund			9				19				75
Loss before taxation					260				299				42,975

Further information on provisions is provided in BP Annual Report and Form 20-F 2013 – Financial statements – Note 2.

 

 

 

22

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Financial statements (continued)

 

 

Notes

 

2.	Gulf of Mexico oil spill (continued)

 

Contingent liabilities

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 or associated legal costs (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 257-265 of BP Annual Report and Form 20-F 2013 and page 48 of this report, 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, any obligation that may arise from securities-related litigation, 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 State and Local Claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment.

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.

See also BP Annual Report and Form 20-F 2013 – Financial statements – Note 2.

 

3.	Non-current assets held for sale

On 22 April 2014, BP announced that it had reached agreement to sell its interests in the Northstar and Endicott oilfields and 50% of its interests in each of the Milne Point and Liberty oilfields on the North Slope of Alaska to Hilcorp Alaska LLC, a subsidiary of Hilcorp Energy for $1.25 billion plus an additional carry of up to $250 million if the Liberty field is developed. The sale also includes BP’s interests in the oil and gas pipelines associated with these fields. These assets, amounting to $1,475 million, and associated liabilities of $428 million, have been classified as held for sale in the group balance sheet at 30 June 2014. The sale is expected to be complete by the end of the year, subject to state and federal regulatory approval.

 

 

 

23

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Financial statements (continued)

 

 

Notes

 

4.	Analysis of replacement cost profit before interest and tax and reconciliation to profit before taxation

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
	4,400				4,049			Upstream			8,708				9,962
	1,016				933			Downstream			1,727				2,663
	—				—			TNK-BP(a)			—				12,500
	218				1,024			Rosneft(b)			1,542				303
	(573	)			(434	)		Other businesses and corporate			(931	)			(1,040	)
	5,061				5,572						11,046				24,388
	(199	)			(251	)		Gulf of Mexico oil spill response			(280	)			(221	)
	129				(76	)		Consolidation adjustment – UPII*			14				556
	4,991				5,245			RC profit before interest and tax			10,780				24,723
								Inventory holding gains (losses)*
	(4	)			(1	)		Upstream			(7	)			(6	)
	(515	)			233			Downstream			310				(107	)
	13				26			Rosneft (net of tax)			57				13
	4,485				5,503			Profit before interest and tax			11,140				24,623
	252				277			Finance costs			564				534
	117				79			Net finance expense relating to pensions and other post-retirement benefits			159				239
	4,116				5,147			Profit before taxation			10,417				23,850
								RC profit before interest and tax*(c)
	1,156				1,643			US			2,768				2,883
	3,835				3,602			Non-US			8,012				21,840
	4,991				5,245						10,780				24,723

 

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. First half 2013 includes the gain arising on disposal of BP’s interest in TNK-BP.

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

(c)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.

 

 

 

24

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Financial statements (continued)

 

 

Notes

 

5.	Sales and other operating revenues

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								By segment
	16,418				16,739			Upstream			33,745				34,636
	88,348				86,871			Downstream			171,169				175,132
	414				412			Other businesses and corporate			843				834
	105,180				104,022						205,757				210,602
								Less: sales and other operating revenues between segments
	10,116				9,729			Upstream			18,946				20,977
	109				152			Downstream			714				349
	244				184			Other businesses and corporate			430				458
	10,469				10,065						20,090				21,784
								Third party sales and other operating revenues
	6,302				7,010			Upstream			14,799				13,659
	88,239				86,719			Downstream			170,455				174,783
	170				228			Other businesses and corporate			413				376
	94,711				93,957			Total third party sales and other operating revenues			185,667				188,818
								By geographical area(a)
	34,536				35,507			US			70,332				69,731
	69,919				67,303			Non-US			133,608				138,286
	104,455				102,810						203,940				208,017
	9,744				8,853			Less: sales and other operating revenues between areas			18,273				19,199
	94,711				93,957						185,667				188,818

 

(a)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.

 

6.	Production and similar taxes

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
	218				215			US			494				590
	1,454				601			Non-US			1,308				3,077
	1,672				816						1,802				3,667

 

 

 

25

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Financial statements (continued)

 

 

Notes

 

 

7.	Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 53 million ordinary shares at a cost of $450 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. 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.

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Results for the period
	2,042				3,369			Profit for the period attributable to BP shareholders			6,897				18,905
	1				1			Less: preference dividend			1				1
	2,041				3,368			Profit attributable to BP ordinary shareholders			6,896				18,904
								Number of shares (thousand)(a)
	19,015,720				18,440,909			Basic weighted average number of shares outstanding			18,460,787				19,081,305
	3,169,287				3,073,484			ADS equivalent			3,076,797				3,180,218
	19,108,668				18,556,789			Weighted average number of shares outstanding used to calculate diluted earnings per share			18,580,165				19,185,749
	3,184,778				3,092,798			ADS equivalent			3,096,694				3,197,625
	18,935,572				18,435,266			Shares in issue at period-end			18,435,266				18,935,572
	3,155,929				3,072,544			ADS equivalent			3,072,544				3,155,929

 

(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-based payment plans.

 

 

 

26

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Financial statements (continued)

 

 

Notes

 

 

8.

Dividends

Dividends payable

BP today announced a dividend of 9.75 cents per ordinary share expected to be paid in September. The corresponding amount in sterling will be announced on 9 September 2014, calculated based on the average of the market exchange rates for the four dealing days commencing on 3 September 2014. Holders of American Depositary Shares (ADSs) will receive $0.585 per ADS. The dividend is due to be paid on 19 September 2014 to shareholders and ADS holders on the register on 8 August 2014. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

Dividends paid

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								Dividends paid per ordinary share
	9.000				9.750			cents			19.250				18.000
	5.834				5.807			pence			11.514				11.835
	54.00				58.50			Dividends paid per ADS (cents)			115.50				108.00
								Scrip dividends
	43.8				26.5			Number of shares issued (millions)			66.7				58.3
	315				225			Value of shares issued ($ million)			551				416

 

9.

Net debt*

Net debt ratio*

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
	46,990				52,906			Gross debt			52,906				46,990
	(460	)			(1,001	)		Fair value (asset) liability of hedges related to finance debt			(1,001	)			(460	)
	46,530				51,905						51,905				46,530
	28,313				27,506			Less: cash and cash equivalents			27,506				28,313
	18,217				24,399			Net debt			24,399				18,217
	130,133				132,978			Equity			132,978				130,133
	12.3	%			15.5	%		Net debt ratio			15.5	%			12.3	%

 

 

 

27

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Financial statements (continued)

 

 

Notes

 

9.	Net debt* (continued)

 

Analysis of changes in net debt

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Opening balance
	46,425				53,249			Finance debt			48,192				48,800
	(1,083	)			(633	)		Fair value (asset) liability of hedges related to finance debt			(477	)			(1,700	)
	27,679				27,358			Less: cash and cash equivalents			22,520				19,635
	17,663				25,258			Opening net debt			25,195				27,465
								Closing balance
	46,990				52,906			Finance debt			52,906				46,990
	(460	)			(1,001	)		Fair value (asset) liability of hedges related to finance debt			(1,001	)			(460	)
	28,313				27,506			Less: cash and cash equivalents			27,506				28,313
	18,217				24,399			Closing net debt			24,399				18,217
	(554	)			859			Decrease (increase) in net debt			796				9,248
	622				99			Movement in cash and cash equivalents (excluding exchange adjustments)			4,982				8,915
	(1,766	)			921			Net cash outflow (inflow) from financing (excluding share capital and dividends)			(3,898	)			(50	)
	632				—			Movement in finance debt relating to investing activities			—				632
	20				(276	)		Other movements			(394	)			(106	)
	(492	)			744			Movement in net debt before exchange effects			690				9,391
	(62	)			115			Exchange adjustments			106				(143	)
	(554	)			859			Decrease (increase) in net debt			796				9,248

 

10.	Inventory valuation

A provision of $468 million was held at 30 June 2014 to write inventories down to their net realizable value. The net movement charged to the income statement during the second quarter 2014 was $59 million (second quarter 2013 was a charge of $35 million).

 

11.	Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 28 July 2014, is unaudited and does not constitute statutory financial statements.

 

 

 

28

---

Financial statements (continued)

 

 

Notes

 

 

12.	Condensed consolidating information

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

 

		Issuer				Guarantor
Income statement		BP Exploration (Alaska) Inc.				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2014
Sales and other operating revenues			3,545				—				185,667				(3,545	)			185,667
Earnings from joint ventures – after interest and tax			—				—				270				—				270
Earnings from associates – after interest and tax			—				—				2,011				—				2,011
Equity-accounted income of subsidiaries – after interest and tax			—				7,290				—				(7,290	)			—
Interest and other income			1				96				511				(120	)			488
Gains on sale of businesses and fixed assets			—				—				379				—				379
Total revenues and other income			3,546				7,386				188,838				(10,955	)			188,815
Purchases			1,298				—				148,251				(3,545	)			146,004
Production and manufacturing expenses			829				—				12,982				—				13,811
Production and similar taxes			433				—				1,369				—				1,802
Depreciation, depletion and amortization			313				—				7,028				—				7,341
Impairment and losses on sale of businesses and fixed assets			69				—				1,131				—				1,200
Exploration expense			—				—				1,337				—				1,337
Distribution and administration expenses			18				487				5,830				(25	)			6,310
Fair value gain on embedded derivatives			—				—				(130	)			—				(130	)
Profit before interest and taxation			586				6,899				11,040				(7,385	)			11,140
Finance costs			29				12				618				(95	)			564
Net finance expense (income) relating to pensions and other post-retirement benefits			—				(25	)			184				—				159
Profit before taxation			557				6,912				10,238				(7,290	)			10,417
Taxation			233				15				3,117				—				3,365
Profit for the period			324				6,897				7,121				(7,290	)			7,052
Attributable to
BP shareholders			324				6,897				6,966				(7,290	)			6,897
Non-controlling interests			—				—				155				—				155
			324				6,897				7,121				(7,290	)			7,052

 

 

 

29

---

Financial statements (continued)

 

 

Notes

 

12.	Condensed consolidating information (continued)

 

		Issuer				Guarantor
Statement of comprehensive income		BP Exploration (Alaska) Inc.				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2014
Profit for the period			324				6,897				7,121				(7,290	)			7,052
Other comprehensive income			—				(474	)			93				—				(381	)
Equity-accounted other comprehensive income of subsidiaries			—				86				—				(86	)			—
Total comprehensive income			324				6,509				7,214				(7,376	)			6,671
Attributable to
BP shareholders			324				6,509				7,052				(7,376	)			6,509
Non-controlling interests			—				—				162				—				162
			324				6,509				7,214				(7,376	)			6,671

 

		Issuer				Guarantor
Income statement		BP Exploration (Alaska) Inc.				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2013
Sales and other operating revenues			2,679				—				188,818				(2,679	)			188,818
Earnings from joint ventures – after interest and tax			—				—				227				—				227
Earnings from associates – after interest and tax			—				—				732				—				732
Equity-accounted income of subsidiaries – after interest and tax			—				19,110				—				(19,110	)			—
Interest and other income			4				71				406				(117	)			364
Gains on sale of businesses and fixed assets			—				—				12,777				—				12,777
Total revenues and other income			2,683				19,181				202,960				(21,906	)			202,918
Purchases			437				—				149,030				(2,679	)			146,788
Production and manufacturing expenses			697				—				13,297				—				13,994
Production and similar taxes			530				—				3,137				—				3,667
Depreciation, depletion and amortization			258				—				6,101				—				6,359
Impairment and losses on sale of businesses and fixed assets			(76	)			—				796				—				720
Exploration expense			—				—				756				—				756
Distribution and administration expenses			30				223				5,926				(2	)			6,177
Fair value gain loss on embedded derivatives			—				—				(166	)			—				(166	)
Profit before interest and taxation			807				18,958				24,083				(19,225	)			24,623
Finance costs			18				24				607				(115	)			534
Net finance expense relating to pensions and other post-retirement benefits			—				40				199				—				239
Profit before taxation			789				18,894				23,277				(19,110	)			23,850
Taxation			328				(11	)			4,465				—				4,782
Profit for the period			461				18,905				18,812				(19,110	)			19,068
Attributable to
BP shareholders			461				18,905				18,649				(19,110	)			18,905
Non-controlling interests			—				—				163				—				163
			461				18,905				18,812				(19,110	)			19,068

 

 

 

30

---

Financial statements (continued)

 

 

Notes

 

12.	Condensed consolidating information (continued)

 

		Issuer				Guarantor
Statement of comprehensive income		BP Exploration (Alaska) Inc.				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2013
Profit for the period			461				18,905				18,812				(19,110	)			19,068
Other comprehensive income			—				1,107				(4,482	)			—				(3,375	)
			461				20,012				14,330				(19,110	)			15,693
Equity-accounted other comprehensive income of subsidiaries(a)			—				(4,456	)			—				4,456				—
Total comprehensive income(a)			461				15,556				14,330				(14,654	)			15,693
Attributable to
BP shareholders			461				15,556				14,193				(14,654	)			15,556
Non-controlling interests			—				—				137				—				137
			461				15,556				14,330				(14,654	)			15,693

 

(a)

Total comprehensive income for BP p.l.c. has been amended to include equity-accounted other comprehensive income of subsidiaries with an offsetting adjustment in the eliminations and reclassifications column, with no overall impact for BP group. Total comprehensive income for BP p.l.c. on the same basis was $22,574 million for full year 2013, $11,988 million for full year 2012, and $20,613 million for full year 2011.

 

 

 

31

---

Financial statements (continued)

 

 

Notes

 

12.	Condensed consolidating information (continued)

 

		Issuer				Guarantor
Balance sheet		BP Exploration (Alaska) Inc				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
At 30 June 2014
Non-current assets
Property, plant and equipment			7,393				—				128,461				—				135,854
Goodwill			—				—				12,197				—				12,197
Intangible assets			432				—				21,499				—				21,931
Investments in joint ventures			—				—				9,173				—				9,173
Investments in associates			—				2				17,368				—				17,370
Other investments			—				—				1,270				—				1,270
Subsidiaries – equity-accounted basis			—				154,603				—				(154,603	)			—
Fixed assets			7,825				154,605				189,968				(154,603	)			197,795
Loans			3				—				5,280				(4,602	)			681
Trade and other receivables			—				—				5,782				—				5,782
Derivative financial instruments			—				—				3,609				—				3,609
Prepayments			17				—				966				—				983
Deferred tax assets			—				—				1,308				—				1,308
Defined benefit pension plan surpluses			—				852				126				—				978
			7,845				155,457				207,039				(159,205	)			211,136
Current assets
Loans			—				—				334				—				334
Inventories			466				—				28,976				—				29,442
Trade and other receivables			9,661				13,499				44,917				(28,021	)			40,056
Derivative financial instruments			—				—				2,852				—				2,852
Prepayments			161				—				1,469				—				1,630
Current tax receivable			—				5				643				—				648
Other investments			—				—				376				—				376
Cash and cash equivalents			—				52				27,454				—				27,506
			10,288				13,556				107,021				(28,021	)			102,844
Assets classified as held for sale			1,343				—				132				—				1,475
			11,631				13,556				107,153				(28,021	)			104,319
Total assets			19,476				169,013				314,192				(187,226	)			315,455
Current liabilities
Trade and other payables			1,201				5,122				71,723				(28,021	)			50,025
Derivative financial instruments			—				—				2,323				—				2,323
Accruals			105				551				6,589				—				7,245
Finance debt			—				—				7,570				—				7,570
Current tax payable			210				—				2,176				—				2,386
Provisions			2				—				4,452				—				4,454
			1,518				5,673				94,833				(28,021	)			74,003
Liabilities directly associated with assets classified as held for sale			359				—				69				—				428
			1,877				5,673				94,902				(28,021	)			74,431
Non-current liabilities
Other payables			11				4,590				3,653				(4,602	)			3,652
Derivative financial instruments			—				—				1,765				—				1,765
Accruals			—				91				716				—				807
Finance debt			—				—				45,336				—				45,336
Deferred tax liabilities			1,584				—				16,744				—				18,328
Provisions			1,764				—				26,440				—				28,204
Defined benefit pension plan and other post-retirement benefit plan deficits			—				288				9,666				—				9,954
			3,359				4,969				104,320				(4,602	)			108,046
Total liabilities			5,236				10,642				199,222				(32,623	)			182,477
Net assets			14,240				158,371				114,970				(154,603	)			132,978
Equity
BP shareholders’ equity			14,240				158,371				113,853				(154,603	)			131,861
Non-controlling interests			—				—				1,117				—				1,117
			14,240				158,371				114,970				(154,603	)			132,978

 

 

 

32

---

Financial statements (continued)

 

 

Notes

 

12.	Condensed consolidating information (continued)

 

		Issue				Guarantor
Balance sheet		BP Exploration (Alaska) Inc				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
At 30 June 2013
Non-current assets
Property, plant and equipment			8,634				—				119,736				—				128,370
Goodwill			—				—				11,936				—				11,936
Intangible assets			398				—				24,962				—				25,360
Investments in joint ventures			—				—				8,719				—				8,719
Investments in associates			—				2				14,922				—				14,924
Other investments			—				—				1,732				—				1,732
Subsidiaries – equity-accounted basis			—				151,118				—				(151,118	)			—
Fixed assets			9,032				151,120				182,007				(151,118	)			191,041
Loans			—				—				5,237				(4,633	)			604
Trade and other receivables			—				—				5,538				—				5,538
Derivative financial instruments			—				—				3,548				—				3,548
Prepayments			33				—				826				—				859
Deferred tax assets			—				—				855				—				855
Defined benefit pension plan surpluses			—				—				11				—				11
			9,065				151,120				198,022				(155,751	)			202,456
Current assets
Loans			—				—				188				—				188
Inventories			172				—				28,142				—				28,314
Trade and other receivables			8,855				10,850				42,303				(19,627	)			42,381
Derivative financial instruments			—				—				2,748				—				2,748
Prepayments			163				—				1,410				—				1,573
Current tax receivable			—				12				555				—				567
Other investments			—				—				712				—				712
Cash and cash equivalents			—				57				28,256				—				28,313
			9,190				10,919				104,314				(19,627	)			104,796
Total assets			18,255				162,039				302,336				(175,378	)			307,252
Current liabilities
Trade and other payables			672				435				66,351				(19,627	)			47,831
Derivative financial instruments			—				—				2,365				—				2,365
Accruals			123				444				6,244				—				6,811
Finance debt			—				—				8,725				—				8,725
Current tax payable			181				—				2,668				—				2,849
Provisions			1				—				6,892				—				6,893
			977				879				93,245				(19,627	)			75,474
Non-current liabilities
Other payables			11				4,799				4,664				(4,633	)			4,841
Derivative financial instruments			—				—				2,483				—				2,483
Accruals			—				41				464				—				505
Finance debt			—				—				38,265				—				38,265
Deferred tax liabilities			1,693				—				15,434				—				17,127
Provisions			2,082				—				25,316				—				27,398
Defined benefit pension plan and other post-retirement benefit plan deficits			—				819				10,207				—				11,026
			3,786				5,659				96,833				(4,633	)			101,645
Total liabilities			4,763				6,538				190,078				(24,260	)			177,119
Net assets			13,492				155,501				112,258				(151,118	)			130,133
Equity
BP shareholders’ equity			13,492				155,501				111,116				(151,118	)			128,991
Non-controlling interests			—				—				1,142				—				1,142
			13,492				155,501				112,258				(151,118	)			130,133

 

 

 

33

---

Financial statements (continued)

 

 

Notes

 

12.	Condensed consolidating information (continued)

 

		Issuer				Guarantor
Cash flow statement		BP Exploration (Alaska) Inc				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2014
Net cash provided by operating activities			361				10,218				5,535				(6	)			16,108
Net cash used in investing activities			(361	)			(5,000	)			(4,338	)			—				(9,699	)
Net cash provided by (used in) financing activities			—				(5,172	)			3,739				6				(1,427	)
Currency translation differences relating to cash and cash equivalents			—				—				4				—				4
Increase in cash and cash equivalents			—				46				4,940				—				4,986
Cash and cash equivalents at beginning of period			—				6				22,514				—				22,520
Cash and cash equivalents at end of period			—				52				27,454				—				27,506
		Issuer				Guarantor
Cash flow statement		BP Exploration (Alaska) Inc				BP p.l.c.				Other subsidiaries				Eliminations and reclassifications				BP group
$ million
First half 2013
Net cash provided by operating activities			336				5,358				3,726				(66	)			9,354
Net cash provided by (used in) investing activities			(336	)			29				4,789				—				4,482
Net cash provided by (used in) financing activities			—				(5,339	)			352				66				(4,921	)
Currency translation differences relating to cash and cash equivalents			—				—				(237	)			—				(237	)
Increase in cash and cash equivalents			—				48				8,630				—				8,678
Cash and cash equivalents at beginning of period			—				9				19,626				—				19,635
Cash and cash equivalents at end of period			—				57				28,256				—				28,313

 

 

 

34

---

Additional non-GAAP and other information

 

 

Capital expenditure and acquisitions

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								By segment Upstream(a)
	1,555				1,435			US			3,133				3,085
	2,851				3,351			Non-US(b)			7,050				5,817
	4,406				4,786						10,183				8,902
								Downstream
	777				232			US			438				1,616
	397				378			Non-US			722				612
	1,174				610						1,160				2,228
								Rosneft
	—				—			Non-US(c)			—				11,941
	—				—						—				11,941
								Other businesses and corporate
	68				13			US			16				92
	172				204			Non-US			339				308
	240				217						355				400
	5,820				5,613						11,698				23,471
								By geographical area(a)
	2,400				1,680			US			3,587				4,793
	3,420				3,933			Non-US(b)(c)			8,111				18,678
	5,820				5,613						11,698				23,471
								Included above:
	—				10			Acquisitions and asset exchanges			246				—
	—				—			Other inorganic capital expenditure(b)(c)			442				11,941

 

(a)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.

(b)	First half 2014 includes $442 million relating to the purchase of additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus Pipeline.

(c)	First half 2013 includes $11,941 million relating to our investment in Rosneft.

Capital expenditure shown in the table above is presented on an accruals basis.

 

 

 

35

---

Additional non-GAAP and other information (continued)

 

 

 

Non-operating items*

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Upstream
	65				(527	)		Impairment and gain (loss) on sale of businesses and fixed assets			(643	)			(37	)
	—				—			Environmental and other provisions			—				—
	—				—			Restructuring, integration and rationalization costs			—				—
	135				32			Fair value gain (loss) on embedded derivatives			130				166
	(57	)			(21	)		Other			273				(66	)
	143				(516	)					(240	)			63
								Downstream
	(310	)			79			Impairment and gain (loss) on sale of businesses and fixed assets			(176	)			(276	)
	—				—			Environmental and other provisions			—				(9	)
	(2	)			(1	)		Restructuring, integration and rationalization costs			(2	)			(4	)
	—				—			Fair value gain (loss) on embedded derivatives			—				—
	(11	)			(28	)		Other			(50	)			(15	)
	(323)				50						(228	)			(304	)
								TNK-BP
	—				—			Impairment and gain (loss) on sale of businesses and fixed assets			—				12,500
	—				—			Environmental and other provisions			—				—
	—				—			Restructuring, integration and rationalization costs			—				—
	—				—			Fair value gain (loss) on embedded derivatives			—				—
	—				—			Other			—				—
	—				—						—				12,500
								Rosneft
	—				—			Impairment and gain (loss) on sale of businesses and fixed assets			247				—
	—				—			Environmental and other provisions			—				—
	—				—			Restructuring, integration and rationalization costs			—				—
	—				—			Fair value gain (loss) on embedded derivatives			—				—
	—				—			Other			—				—
	—				—						247				—
								Other businesses and corporate
	(129	)			4			Impairment and gain (loss) on sale of businesses and fixed assets			(2	)			(130	)
	(6	)			—			Environmental and other provisions			—				(6	)
	—				—			Restructuring, integration and rationalization costs			(1	)			(2	)
	—				—			Fair value gain (loss) on embedded derivatives			—				—
	—				—			Other			(1	)			(3	)
	(135)				4						(4	)			(141	)
	(199	)			(251	)		Gulf of Mexico oil spill response			(280	)			(221	)
	(514	)			(713	)		Total before interest and taxation			(505	)			11,897
	(10	)			(9	)		Finance costs(a)			(19	)			(20	)
	(524	)			(722	)		Total before taxation			(524	)			11,877
	158				241			Taxation credit (charge)(b)			267				181
	(366	)			(481	)		Total after taxation for period			(257	)			12,058

 

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

(b)

From the first quarter 2014, tax is based on statutory rates except for non-deductible or non-taxable items. For earlier periods tax for the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, is based on statutory rates, except for non-deductible items; for other items reported for consolidated subsidiaries, tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the items noted above and equity-accounted earnings). Non-operating items reported within the equity-accounted earnings of Rosneft are reported net of income tax.

 

 

 

36

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Additional non-GAAP and other information (continued)

 

 

 

Non-GAAP information on fair value accounting effects

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Favourable (unfavourable) impact relative to management’s measure of performance
	(31)				(90	)		Upstream			(108	)			(91	)
	138				150			Downstream			211				125
	107				60						103				34
	(53)				(32	)		Taxation credit (charge)(a)			(49	)			(23	)
	54				28						54				11

 

(a)	From the first quarter 2014, tax is calculated using statutory rates. For earlier periods tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for certain non-operating items and equity-accounted earnings).

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.

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								$ million
								Upstream
	4,431				4,139			Replacement cost profit before interest and tax adjusted for fair value accounting effects			8,816				10,053
	(31)				(90	)		Impact of fair value accounting effects			(108	)			(91	)
	4,400				4,049			Replacement cost profit before interest and tax			8,708				9,962
								Downstream
	878				783			Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects			1,516				2,538
	138				150			Impact of fair value accounting effects			211				125
	1,016				933			Replacement cost profit (loss) before interest and tax			1,727				2,663
								Total group
	4,378				5,443			Profit before interest and tax adjusted for fair value accounting effects			11,037				24,589
	107				60			Impact of fair value accounting effects			103				34
	4,485				5,503			Profit before interest and tax			11,140				24,623

 

 

 

37

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Additional non-GAAP and other information (continued)

 

 

 

Realizations and marker prices

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
								Average realizations(a)
								Liquids* ($/bbl)
	90.51				89.61			US			89.71				93.44
	99.12				101.43			Europe			102.88				103.49
	97.26				103.37			Rest of World			103.04				102.50
	94.92				96.90			BP Average			97.03				99.08
								Natural gas ($/mcf)
	3.37				3.86			US			4.23				3.15
	9.37				8.07			Europe			8.99				9.59
	5.89				6.31			Rest of World			6.47				6.01
	5.37				5.67			BP Average			5.94				5.45
								Total hydrocarbons* ($/boe)
	58.62				63.83			US			64.74				60.82
	84.24				88.22			Europe			90.61				87.86
	59.53				62.89			Rest of World			62.83				60.90
	61.27				64.90			BP Average			65.53				63.23
								Average oil marker prices ($/bbl)
	102.43				109.67			Brent			108.93				107.50
	94.07				103.05			West Texas Intermediate			100.90				94.17
	77.43				82.66			Western Canadian Select			79.86				72.61
	104.53				108.05			Alaska North Slope			106.91				107.65
	99.41				100.70			Mars			100.76				104.10
	101.89				107.30			Urals (NWE – cif)			106.76				106.21
	51.28				57.51			Russian domestic oil			56.07				53.22
								Average natural gas marker prices
	4.10				4.68			Henry Hub gas price ($/mmBtu)(b)			4.81				3.72
	65.60				44.81			UK Gas – National Balancing Point (p/therm)			52.67				69.72

 

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

(b)	Henry Hub First of Month Index.

Exchange rates

 

Second quarter 2013				Second quarter 2014						First half 2014				First half 2013
	1.54				1.68			US dollar/sterling average rate for the period			1.67				1.54
	1.52				1.70			US dollar/sterling period-end rate			1.70				1.52
	1.31				1.37			US dollar/euro average rate for the period			1.37				1.31
	1.30				1.36			US dollar/euro period-end rate			1.36				1.30
	31.66				34.96			Rouble/US dollar average rate for the period			35.02				31.03
	32.78				33.73			Rouble/US dollar period-end rate			33.73				32.78

 

 

 

38

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Glossary

 

 

Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.

Fair value accounting effects are non-GAAP adjustments to our IFRS profit relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information and a reconciliation to GAAP information is provided on page 37.

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. See Replacement cost (RC) profit or loss below.

Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Liquids comprise crude oil, condensate and natural gas liquids.

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. The net debt ratio is defined as the ratio of finance debt (borrowings, including the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, plus obligations under finance leases) to the total of finance debt plus shareholders’ interest.

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.

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 7, 9 and 11.

Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. An analysis of capital expenditure by segment and region is shown on page 35.

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.

The Refining marker margin (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.

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. Management believes this measure 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 measure.

 

 

 

39

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Glossary (continued)

 

 

 

Underlying production – 2014 underlying production, when compared with 2013, is after adjusting for the effects of the Abu Dhabi onshore concession expiry in January 2014, divestments, and entitlement impacts in our production-sharing agreements.

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. See pages 36 and 37 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact.

BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects.

 

 

 

40

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Principal risks and uncertainties

 

 

We urge you to consider carefully the risks described below. The potential impact of the occurrence, or recurrence, of any of the risks described below could have a material adverse effect on BP’s business, financial position, results of operations, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, including the 10-point plan.

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

Gulf of Mexico oil spill

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

There is significant uncertainty regarding the extent and timing of the remaining costs and liabilities relating to the 2010 Gulf of Mexico oil spill (the Incident), the impact of the Incident on our reputation and the resulting possible impact on our licence to operate including our ability to access new opportunities. The amount of claims, fines and penalties that become payable by BP (including as a result of any potential determination of BP’s negligence or gross negligence), the outcome of litigation, the terms of any further settlements including the amount and timing of any payments thereunder, and any costs arising from any longer-term environmental consequences of the Incident, will also impact upon the ultimate cost for BP. These uncertainties are likely to continue for a significant period and may cause our costs to increase materially. Thus, the Incident has had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. The risks associated with the Incident could also heighten the impact of the other risks to which the group is exposed as further described below. See, in particular: Access and renewal; Liquidity, financial capacity and financial, including credit, exposure; Insurance; US government settlements and debarment; Regulatory; Liabilities and provisions; Reporting; and Process safety, personal safety and environmental risks below.

Strategic and commercial risks

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

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

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

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

Oil, gas and product prices and margins can be very volatile, and are subject to international supply and demand. Political developments (including conflict situations), increased supply from the development of new oil and gas sources, technological change, global economic conditions and the influence of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. Decreases in oil, gas or product prices are likely to have an adverse effect on revenues, margins and profitability, and a material rapid change, or a sustained change, in oil, gas or product prices may mean investment or other decisions need to be reviewed, assets may be impaired, and the viability of projects may be affected. A prolonged period of low oil prices may impact our cash flow, profit and ability to maintain our long-term investment programme with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price.

Refining profitability can be volatile, with both periodic over-supply and supply tightness in various regional markets, coupled with fluctuations in demand. Sectors of the petrochemicals industry are also subject to fluctuations in supply and demand, with a consequent effect on prices and profitability.

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

Periods of global recession or prolonged instability in financial markets could negatively impact parties with whom we do or may do business, the demand for our products and the prices at which they can be sold and could affect the viability of the markets in which we operate.

 

 

 

41

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Principal risks and uncertainties (continued)

 

 

 

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

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

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

We have operations, and are seeking new opportunities, in countries and regions where political, economic and social transition is taking place. Some countries have experienced or been subject to, or may in the future experience or be subject to, political instability, changes to the regulatory environment, changes in taxation, expropriation or nationalization of property, civil strife, strikes, acts of terrorism, acts of war, international sanctions and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, could limit our ability to pursue new opportunities, could affect the recoverability of our assets and could cause us to incur additional costs. See page 4 of BP Annual Report and Form 20-F 2013 for information on the locations of our major areas of operation and activities.

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

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

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

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

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

Rosneft investment – any future erosion of our relationship with Rosneft, or the impact of further economic sanctions, could adversely impact our business and strategic objectives in Russia, the level of our income, production and reserves, our investment in Rosneft and our reputation.

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

 

 

 

42

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Principal risks and uncertainties (continued)

 

 

 

If further international sanctions are imposed on Rosneft or new sanctions are imposed on Russia or other Russian individuals or entities, this could have a material adverse impact on our relationship with and investment in Rosneft, our business and strategic objectives in Russia and our financial position and results of operations.

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

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

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

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

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

Successful execution of our group plan depends critically on implementing the activities to deliver major projects over the plan period. Poor delivery of or operational challenges at any major project that underpins production or production growth and/or any other major programme designed to enhance shareholder value, including maintenance turnaround programmes, could adversely affect our financial performance and our operating cash flows.

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

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

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

Crisis management and contingency plans are required to respond to, and to continue or recover operations following, a disruption or an incident. If we do not respond, or are perceived not to respond, in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect our business and operations.

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

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

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

Liquidity, financial capacity and financial, including credit, exposure – failure to operate within our financial framework could impact our ability to operate and result in financial loss.

The group seeks to maintain a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity, and commercial credit risk is measured and controlled to determine the group’s total credit risk. Failure to accurately forecast, manage or maintain sufficient liquidity and credit to meet our needs (including a failure to understand and respond to potential liabilities) could impact our ability to operate and result in a financial loss. Trade and other receivables, including overdue receivables, may not be recovered whether an impairment provision has been recognized or not. Inability to determine adequately our credit exposure could lead to financial loss. Furthermore, a substantial and unexpected cash call or funding request could disrupt our financial framework or overwhelm our capacity to meet our obligations.

External events could materially impact the effectiveness of the group’s financial framework. A credit crisis or significant economic shock affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth, to maintain our long-term investment programme and to meet our obligations, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.

 

 

 

43

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Principal risks and uncertainties (continued)

 

 

 

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

See Financial statements – Note 19 of BP Annual Report and Form 20-F 2013 for more information on financial instruments and financial risk factors.

Insurance – the limited capacity of the insurance market and BP’s insurance strategy could, from time to time, expose the group to material uninsured losses which could have a material adverse effect on BP’s financial condition and results of operations.

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

Compliance and control risks

US government settlements and debarment – our settlement with the US Department of Justice and the US Securities and Exchange Commission in respect of certain charges related to the Incident may expose us to further penalties, liabilities and private litigation, and may impact our operations and adversely affect our ability to quickly and efficiently access US capital markets.

On 15 November 2012, BP reached an agreement with the US government to resolve all federal criminal and securities claims arising out of the Incident and comprising settlements with the US Department of Justice (DoJ) and the US Securities and Exchange Commission (SEC). For a description of the terms of the DoJ and SEC settlements, see Legal proceedings on page 264 of BP Annual Report and Form 20-F 2013. Under the DoJ settlement, BP has agreed to retain an independent third-party auditor who will review and report to the probation officer, the DoJ, and BP regarding compliance by BP Exploration & Production (BPXP) with the key terms of the settlement including the completion of safety and environmental management systems audits, operational oversight enhancements, oil spill response training and drills and the implementation of best practices. The DoJ settlement also provides for the appointment of an ethics monitor and a process safety monitor. See Gulf of Mexico oil spill on page 39 of BP Annual Report and Form 20-F 2013. The DoJ criminal and SEC settlements impose significant compliance and remedial obligations on BP and its directors, officers and employees. Failure to comply with the terms of these settlements could result in further enforcement action by the DoJ and the SEC, expose BP to severe penalties, financial or otherwise, and subject BP to further private litigation, each of which could impact our operations and have a material adverse effect on the group’s business.

As previously disclosed, in November 2012 the US Environmental Protection Agency (EPA) temporarily suspended a number of BP entities from participating in new federal contracts, and subsequently in 2013, subjected BPXP to mandatory debarment at its Houston headquarters and issued suspensions to additional BP entities. See Legal proceedings on page 264 of BP Annual Report and Form 20-F 2013. On 13 March 2014, BP p.l.c., BPXP and all other temporarily suspended BP entities entered into an administrative agreement with the EPA resolving all issues related to suspension or debarment arising from the Incident, allowing BP entities to enter into new contracts or leases with the US government. Under the terms and conditions of the administrative agreement, which will apply for five years, BP has agreed to a set of safety and operations, ethics and compliance and corporate governance requirements. Failure to satisfy these requirements or otherwise comply with the terms of the administrative agreement could result in suspension or debarment of BP entities in the future. BP has a significant amount of operations in the US. See Upstream on page 25 and Oil and gas disclosures for the group on page 245 of BP Annual Report and Form 20-F 2013. Suspension or debarment from entering new federal contracts, or further suspension or debarment proceedings in the future against BP and/or its subsidiaries as a result of violations of the terms of the DoJ or SEC settlements, the administrative agreement with the EPA or otherwise, could have a material adverse impact on the group’s operations in the US in the future.

As a result of the SEC settlement, as of 5 February 2013 and for a period of three years thereafter, we are no longer qualified as a ‘well known seasoned issuer’ (WKSI) as defined in Rule 405 of the Securities Act of 1933, as amended (Securities Act), and

 

 

 

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therefore will not be able to take advantage of the benefits available to a WKSI, including engaging in delayed or continuous offerings of securities using an automatic shelf registration statement. In addition, as of the SEC settlement date of 10 December 2012 and for a period of five years thereafter, we are no longer able to utilize certain registration exemptions provided by the Securities Act in connection with certain securities offerings. We also may be denied certain trading authorizations under the rules of the US Commodities Futures Trading Commission, which may prevent us in the future from entering certain routine swap transactions for an indefinite period of time.

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

The oil industry in general is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental, health and safety controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. We remain exposed to changes in the regulatory and legislative environment, such as new laws and regulations (whether imposed by international treaty or by national or local governments in the jurisdictions in which we operate), changes in tax or royalty regimes, price controls, the imposition of trade or other sanctions, government actions to cancel or renegotiate contracts or other factors. Governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks of the oil and gas industry and we remain exposed to increases in amounts payable to governments or government agencies. Such factors could reduce our profitability from operations in certain jurisdictions, limit our opportunities for new access, require us to divest or write-down certain assets or curtail or cease certain operations, or affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities. Potential changes to pension or financial market regulation could also impact funding requirements of the group.

Due to the Incident and remedial provisions contained in or that may result from the DoJ and SEC settlements and other past events in the US, it is likely that there will be additional oversight and more stringent regulation of BP’s oil and gas activities in the US and elsewhere, particularly relating to environmental, health and safety controls and oversight of drilling operations, as well as access to new drilling areas. BP may be subjected to a higher number of citations and/or level of fines imposed in relation to any alleged breaches of safety or environmental regulations. New regulations and legislation, the terms of BP’s settlements with US government authorities and future settlements or litigation outcomes related to the Incident, and/or evolving practices could increase the cost of compliance, require changes to our drilling operations, exploration, development and decommissioning plans, impact our ability to capitalize on our assets and limit our access to new exploration properties or operatorships, particularly in the deepwater Gulf of Mexico.

We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in or to comply with trading regulations could result in regulatory action and damage to our reputation.

See page 254 of BP Annual Report and Form 20-F 2013 for more information on environmental regulation.

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

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

For certain legal proceedings involving the group, see Legal proceedings on page 48 herein and Legal proceedings on page 257 of BP Annual Report and Form 20-F 2013. For further information on the risks involved in BP’s trading activities, see Treasury and trading activities below.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements and enforcement actions relating to the Incident, together with the potential cost and burdens of implementing remedies sought in the various proceedings, have had and are expected to continue to have a material adverse impact on the group’s business.

Under the Oil Pollution Act of 1990 (OPA 90), BPXP and BP Corporation North America are among the parties financially responsible for the clean-up of the Incident and for certain economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. BP and certain of its subsidiaries have also been named as defendants in numerous lawsuits in the US arising out of the Incident, including actions for personal injury and wrongful death, purported class actions for commercial or economic injury, actions for breach of contract, violations of statutes, property and other environmental damage, securities law claims and various other claims, and additional lawsuits or private claims arising out of the Incident may be brought in the future.

 

 

 

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While significant charges have been recognized in the income statement since the Incident occurred in 2010, the provisions recognized represent only the current best estimates of expenditures required to settle certain present obligations that can be reasonably estimated at the end of the reporting period, and there are future expenditures for which it is not possible to measure our obligations reliably. BP’s total potential liabilities resulting from pending and future claims, lawsuits, settlements and enforcement actions relating to the Incident (including as a result of any potential determination of BP’s negligence or gross negligence), together with the potential cost and burdens of implementing remedies sought in the various proceedings, cannot be fully estimated at this time and are subject to significant uncertainty but they have had, and are expected to continue to have, a material adverse impact on the group’s business.

See Note 2 and Legal proceedings on page 48 herein, and Financial statements – Note 2 and Legal proceedings on page 257 of BP Annual Report and Form 20-F 2013.

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

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

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

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

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies.

Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation. See Legal proceedings on page 257 of BP Annual Report and Form 20-F 2013.

Safety and operational risks

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

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

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

There are risks of technical integrity failure as well as risk of natural disasters and other adverse conditions in many of the areas in which we operate, which could lead to loss of containment of hydrocarbons and other hazardous material, as well as the risk of fires, explosions or other incidents. In addition, inability to provide safe environments for our workforce and the public while at our facilities or premises could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.

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

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

 

 

 

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Under the terms of the DoJ settlement (see Legal proceedings on page 264 of BP Annual Report and Form 20-F 2013), a process safety monitor will review, evaluate, and provide recommendations concerning BPXP’s process safety and risk management procedures for deepwater drilling in the Gulf of Mexico. Incidents of non-compliance with the recommendations of the process safety monitor could be damaging to our reputation and shareholder value and could subject us to further regulatory action or penalties under the terms of the DoJ settlement. Multiple events of non-compliance could call into question the integrity of our operations.

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

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

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

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

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

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

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

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

 

 

 

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Legal proceedings

 

 

The following discussion sets out the material developments in the group’s material legal proceedings during the half year 2014. For a full discussion of the group’s material legal proceedings, see pages 257-267 of BP Annual Report and Form 20-F 2013.

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

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

Trial Phases. The federal district court in New Orleans (the District Court) scheduled the penalty phase (the Penalty Phase) in the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 to commence on 20 January 2015. Discovery in the Penalty Phase is currently in progress, and the Penalty Phase trial is expected to last three weeks. In the Penalty Phase, the District Court will determine the amount of civil penalties owed to the United States under the Clean Water Act based on the court’s rulings as to the presence of negligence, gross negligence or wilful misconduct in Phases 1 and 2, the court’s rulings as to quantification of discharge in Phase 2 and the application of the penalty factors under the Clean Water Act.

BP is not currently aware of the timing of the court’s rulings in respect of issues presented in Phase 1 or Phase 2 and the court could issue its decision on these phases at any time. The District Court has wide discretion in its determination as to whether a defendant’s conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors. For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013.

Plaintiffs’ Steering Committee (PSC) Settlements – Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages Settlement Agreement. As disclosed in BP Annual Report and Form 20-F 2013, on 24 December 2013, the District Court ruled (the December 2013 Ruling) on the two issues remanded to it in October 2013 by the business economic loss panel of the US Court of Appeals for the Fifth Circuit (the Fifth Circuit): (1) requiring the claims administrator, in administering business economic loss claims, to match revenue with corresponding variable expenses (the matching issue), and (2) determining whether the settlement agreement can properly be interpreted to permit payment to business economic loss claimants whose losses (if any) were not caused by the spill (the causation issue).

As to the matching issue, the District Court ordered the claims administrator to develop a revised policy addressing the matching of revenue and expenses for business economic loss claims, which would require the matching of revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded at different times. On 13 March 2014, the claims administrator issued a revised matching policy reflecting this order. On 19 March 2014, BP submitted its response to the revised matching policy, and the claims administrator submitted the policy to the District Court for consideration on 25 March 2014. On 5 May 2014, the District Court approved the revised policy. The PSC filed a motion on 27 May 2014 seeking to alter or amend the revised policy. On 27 June 2014, the District Court issued an order establishing the process for the parties and claims administrator to determine which already-determined but unpaid claims should be subject to the revised policy.

As to the causation issue, the District Court ruled that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in an exhibit to that agreement. The District Court also held that the absence of a further causation requirement does not defeat class certification or invalidate the settlement under the federal class certification rule or Article III of the US Constitution. On 30 December 2013, BP filed a motion with the Fifth Circuit requesting an injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not fairly traceable to the spill. In a 2-to-1 decision on 3 March 2014, the business economic loss panel affirmed the District Court’s ruling on causation and denied BP’s motion for a permanent injunction.

BP filed a petition on 17 March 2014 requesting that all active Fifth Circuit judges review the business economic loss panel’s 3 March 2014 decision. On 19 May 2014, the Fifth Circuit declined (in a 5-to-8 decision) to grant further review of the 3 March 2014 decision.

On 21 May 2014, BP asked the Fifth Circuit to stay the issuance of the mandate transferring the case back to the District Court until the Supreme Court could decide whether to review the Fifth Circuit’s decision. The Fifth Circuit denied BP’s request for a stay on 27 May 2014, and issued its mandate on 28 May 2014. On that same day, the District Court dissolved the injunction that had halted the processing and payment of business economic loss claims and instructed the claims administrator to resume the processing and payment of claims.

On 28 May 2014, BP filed an application with the Supreme Court seeking to recall and stay the Fifth Circuit’s mandate in order to halt the processing and payment of business economic loss claims pending further review. The Supreme Court denied BP’s application on 9 June 2014, and the claims administrator has continued to process and pay business economic loss claims while BP seeks Supreme Court review of the Fifth Circuit’s decision.

BP’s petition for review by the Supreme Court is due to be filed on or before 18 August 2014. BP intends to seek review of the Fifth Circuit’s decision, as well as a related decision by a different panel of the Fifth Circuit similarly interpreting the Economic and Property Damages Settlement Agreement to permit payment to business economic loss claimants whose losses (if any) were not caused by the spill.

 

 

 

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On 27 June 2014, BP asked the District Court to order the return of excessive payments made by the DHCSSP under the matching policy in effect before the December 2013 Ruling. BP has also requested that the District Court enter an injunction preventing the business economic loss claimants specified in its motion from spending the excessive payments until the correct compensation amount has been definitively determined under the revised matching policy. Even if the District Court enters such an order and injunction as requested by BP, there is significant uncertainty as to the amounts of any such excessive payments that may actually be recoverable by BP.

Medical Benefits Class Action Settlement (Medical Settlement) – As previously disclosed, the District Court approved the Medical Settlement Agreement (MSA) in a final order and judgment on 11 January 2013. The effective date was 12 February 2014. As of 27 June 2014, the claims administrator under the Medical Settlement (the Medical Claims Administrator) had received claim forms for certain Specified Physical Conditions from 9,974 claimants, and thus far has determined 189 claims to be eligible for monetary compensation totalling approximately $250,000. For those claimants seeking benefits under the Periodic Medical Consultation Program only, approximately 600 claims have been determined to be eligible. The deadline for submitting claims under the settlement is one year from the effective date. The Medical Claims Administrator has issued a policy statement, with which BP agrees, regarding the consistent treatment of all physical conditions first diagnosed after 16 April 2012 under the MSA. The PSC disagrees with the policy statement. The District Court ordered briefing on the issue, which was completed on 14 July 2014. The parties are awaiting a ruling.

US Department of Justice (DoJ) Action – Liability under Section 311(b)(7)(A) of the Clean Water Act (CWA) – As previously disclosed, on 8 December 2011, the United States brought a motion for partial summary judgment in the DoJ Action seeking, among other things, an order finding that BP Exploration & Production Inc. (BPXP), Transocean and Anadarko are strictly liable for a civil penalty under Section 311(b)(7)(A) of the CWA. On 22 February 2012, the District Court held that the subsurface discharge which occurred during the Incident was from the Macondo well, rather than from the Deepwater Horizon, and that BPXP and Anadarko, and not Transocean, are strictly liable for civil penalties under Section 311 of the CWA as owners of the well. Anadarko, BPXP and the United States each appealed to the Fifth Circuit, and on 4 June 2014 the Fifth Circuit unanimously affirmed the District Court’s 22 February 2012 decision. On 21 July 2014, Anadarko and BPXP filed petitions requesting that all active judges of the Fifth Circuit review the 4 June 2014 decision.

OPA Test Case Proceedings – On 3 June 2014 the District Court entered an Agreed Upon Scheduling Order (the OPA Scheduling Order) for seven test cases (OPA Test Cases) regarding claims under the Oil Pollution Act of 1990 (OPA 90). The OPA Test Cases will address certain OPA 90 liability questions for the District Court focusing on, among other issues, whether plaintiffs’ alleged losses tied to the 2010 federal government moratoria on deepwater drilling “arise from” or are “due to” the Incident. The OPA Scheduling Order provides for fact and expert discovery up to March 2015. At the conclusion of discovery, the parties will have an opportunity to file summary judgment briefs, followed by trial, if necessary, no earlier than the third quarter of 2015. The District Court has not yet set any trial dates for the OPA Test Cases.

State of Alabama Damages Case Proceedings – On 16 July 2014 the District Court issued a scheduling order for the State of Alabama’s OPA economic damages claims against BP and other parties, with fact and expert discovery into 2015 and a request by the District Court for the parties to set aside the month of November 2015 for a trial.

For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013. For information about BP’s current estimate of the total cost of the PSC settlements, see Note 2.

US Environmental Protection Agency (EPA) matters

On 28 November 2012, the EPA notified BP that it had temporarily suspended BP p.l.c., BPXP and a number of other BP subsidiaries from participating in new federal contracts. In addition, as a result of BP’s agreement with the Department of Justice to resolve all federal criminal charges against BP, on 1 February 2013 the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. 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 mandatory debarment decisions. On 26 November 2013, the EPA suspended two additional BP entities (BP Alternative Energy and BP Pipelines (Alaska) Inc.) and proposed discretionary debarment of all suspended BP entities. For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013.

On 13 March 2014, BP p.l.c., BPXP, and all other temporarily suspended BP entities entered into an administrative agreement with the EPA resolving all issues related to suspension or debarment arising from the Incident, allowing BP entities to enter into new contracts or leases with the United States Government. Under the terms and conditions of the administrative agreement, which will apply for five years, BP has agreed to a set of safety and operations, ethics and compliance and corporate governance requirements.

As a result of the agreement, on 19 March 2014, BP dismissed its lawsuit against the EPA filed in the Southern District of Texas.

MDL 2185 and other securities-related litigation

Securities class action – On 6 December 2013, the judge in the multi-district litigation proceeding in federal district court in Houston (MDL 2185) denied the plaintiffs’ motion for class certification and gave the plaintiffs 30 days to renew that motion. The plaintiffs renewed their motion on 6 January 2014. On 20 May 2014, the judge denied plaintiffs’ motion to certify a proposed class of ADS purchasers before the Deepwater Horizon explosion (from 8 November 2007 to 20 April 2010) and granted plaintiffs’ motion to certify a class of post-explosion ADS purchasers from 26 April 2010 to 28 May 2010. Both parties sought permission to appeal from that decision, and on 3 July 2014, the Fifth Circuit granted both parties’ requests. Briefing on that appeal is expected to proceed in the upcoming months.

 

 

 

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Individual securities litigation – The judge in the MDL 2185 proceedings granted in part and denied in part the defendants’ motion to dismiss three of the 29 cases filed by certain pension funds, investment funds or advisers against BP entities and current and former officers and directors seeking damages for alleged losses suffered as a result of purchases of BP ordinary shares or ADSs. A subset of the claims was dismissed. The judge held that English law governs the plaintiffs’ remaining claims (with the exception of the 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). On 11 December 2013, defendants moved to dismiss 10 of the cases and answered the complaints in two others. On 5 December 2013, the Ohio funds (plaintiffs in one of the first three cases defendants moved to dismiss) filed an amended complaint withdrawing their English law claim and asserting only a claim under Ohio state law. On 6 January 2014, BP moved to dismiss that case for the second time, and on 7 April 2014, the judge dismissed the Ohio action with leave to replead English law claims within 30 days. On 8 June 2014, the Ohio funds filed a second amended complaint asserting only English law claims. On 22 July 2014, BP moved to dismiss the case again.

ERISA – On 30 March 2012, the district court in MDL 2185 issued a decision granting the defendants’ motions to dismiss the ERISA case related to BP share funds in several employee benefit savings plans. Final judgment dismissing the case was entered on 4 September 2012 and, on 25 September 2012, the plaintiffs filed a notice of appeal to the Fifth Circuit. On 15 July 2014, the Fifth Circuit remanded the case to the district court in light of new pleading standards recently set forth by the Supreme Court. BP intends to renew its motion to dismiss in the district court.

For further information about MDL 2185 and other securities-related litigation, see pages 257-265 of BP Annual Report and Form 20-F 2013.

Pending investigations and reports relating to the Deepwater Horizon oil spill

CSB investigation – The US Chemical Safety and Hazard Investigation Board (CSB) released the first two volumes of its four-volume report on its investigation into the Incident at a public hearing in Houston on 5 June 2014. The first two volumes provide an introduction to the Incident as well as the CSB’s findings regarding the operation of the blowout preventer and other technical issues. The CSB has stated that it plans to release Volume 3 (concerning the role of the regulator in the oversight of the offshore industry) and Volume 4 (concerning organizational and cultural factors) later in 2014.

Other matters

 

 

In April 2014, the United States Office for Foreign Assets Control (OFAC) added the name of certain individuals and entities to its list of Specially Designated Nationals.

On 16 July 2014, OFAC created the Sectoral Sanctions Identification List (SSI List) and imposed limited, specific sanctions on certain Russian entities, including Rosneft, and their property. These sectoral sanctions prohibit the following transactions by US persons or within the United States: transacting in, providing financing for, or otherwise dealing in new debt of longer than 90 days maturity for entities on the SSI List. This prohibition also applies to entities owned 50% or more by any of the entities on the SSI List. Ruhr Oel GmbH (ROG) is a 50:50 joint operation with Rosneft, operated by BP, which holds interests in a number of refineries in Germany. The same prohibition applies to new debt of longer than 90 days maturity for ROG. OFAC has made it clear that these sectoral sanctions only apply to new debt issued on or after 16 July 2014; that all other transactions involving the covered Russian entities or their property are permitted unless otherwise prohibited by other US sanctions; and that these sectoral sanctions do not freeze the funds or assets of any of the covered entities.

To date, these sanctions have had no material adverse impact on BP or ROG. However, BP will continue to keep this under review.

 

 

 

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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, plans regarding future divestment of $10 billion in assets by 2015; the expected quarterly dividend payment and timing of the payment; expectations regarding BP’s plans to separate its US lower 48 oil and gas businesses; the expected level of reported production in the third quarter of 2014 and the expected impact of turnaround and seasonal maintenance activities thereon; the expected timing of the halt in refinery operations at the Bulwer refinery; the expected level of Downstream turnaround activity; the expected higher margin capture in the fuels business in the third quarter of 2014 and the drivers thereof; BP’s expectations regarding the continuation of a challenging environment and the expected impact of turnarounds in petrochemicals; and certain statements regarding the 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; 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” herein.

 

 

 

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Computation of ratio of earnings to fixed charges

 

 

 

		First half 2014
$ 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			8,136
Fixed charges			1,419
Amortization of capitalized interest			125
Distributed income of joint ventures and associates			517
Interest capitalized			(98	)
Preference dividend requirements, gross of tax			(1	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges			(3	)
Total earnings available for fixed charges			10,095
Fixed charges:
Interest expensed			408
Interest capitalized			98
Rental expense representative of interest			912
Preference dividend requirements, gross of tax			1
Total fixed charges			1,419
Ratio of earnings to fixed charges			7.1

 

 

 

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Capitalization and indebtedness

 

 

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2014 in accordance with IFRS:

 

		30 June 2014
$ million
Share capital and reserves
Capital shares (1-2)			5,077
Paid-in surplus (3)			11,632
Merger reserve (3)			27,206
Own shares			(301	)
Treasury shares			(20,296	)
Available-for-sale investments			1
Cash flow hedge reserve			(668	)
Foreign currency translation reserve			3,592
Share-based payment reserve			1,687
Profit and loss account			103,931
BP shareholders’ equity			131,861
Finance debt (4-6)
Due within one year			7,570
Due after more than one year			45,336
Total finance debt			52,906
Total capitalization (7)			184,767

 

(1)

Issued share capital as of 30 June 2014 comprised 18,439,045,651 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,781,417,411 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 June 2014.

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

(6)

As of 30 June 2014, the parent company, BP p.l.c., had outstanding guarantees totalling $51,327 million, of which $51,297 million related to guarantees in respect of liabilities of subsidiary undertakings, including $49,669 million relating to finance debt of subsidiaries. Thus 94% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2014, $145 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 June 2014 in the consolidated capitalization and indebtedness of BP.

 

 

 

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Signatures

 

 

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

BP p.l.c.

(Registrant)

 

Dated: 29 July 2014						/s/ J Bertelsen
						J BERTELSEN Deputy Secretary

 

 

 

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