Edgar Filing: BP PLC

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

for the period ended 31 March 2015

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 PRE-EFFECTIVE AMENDMENT NO. 1 TO THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-201894 AND 333-201894-01) OF BP CAPITAL MARKETS p.l.c. AND 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. 333-79399) 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. 333-173136) 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., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200796) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

BP p.l.c. and subsidiaries

Form 6-K for the period ended 31 March 2015^(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-March 2015^(b)		3 – 11, 26 – 31

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-March 2015		12 – 25

3.	Legal proceedings		32 – 33

4.	Cautionary statement		34

5.	Computation of Ratio of Earnings to Fixed Charges		35

6.	Capitalization and Indebtedness		36

7.	Signatures		37

(a)	In this Form 6-K, references to the first quarter 2015 and first quarter 2014 refer to the three-month periods ended 31 March 2015 and 31 March 2014 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 2014.

Group results first quarter 2015


$ million	First quarter 2015			First quarter 2014
Profit for the period^(a)		2,602			3,528
Inventory holding (gains) losses*, net of tax		(499	)		(53	)

Replacement cost profit*		2,103			3,475
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*, net of tax		474			(250	)

Underlying replacement cost profit*		2,577			3,225

Profit per ordinary share (cents)		14.28			19.09
Profit per ADS (dollars)		0.86			1.15
Replacement cost profit per ordinary share (cents)		11.54			18.80
Replacement cost profit per ADS (dollars)		0.69			1.13
Underlying replacement cost profit per ordinary share (cents)		14.14			17.45
Underlying replacement cost profit per ADS (dollars)		0.85			1.05

•

BP’s profit for the first quarter was $2,602 million, compared with $3,528 million a year ago. BP’s first-quarter replacement cost (RC) profit was $2,103 million, compared with $3,475 million a year ago. After adjusting for a net charge for non-operating items of $413 million and net unfavourable fair value accounting effects of $61 million (both on a post-tax basis), underlying RC profit for the first quarter was $2,577 million, compared with $3,225 million for the same period in 2014. The underlying result for the group was lower, mainly due to reduced profit in Upstream, which was partly offset by an improved result in Downstream, as well as certain favourable tax impacts. The Upstream result for the first quarter was a profit of $604 million comprising a loss of $545 million in the US and a profit of $1,149 million for non-US. This compares with a profit of $4,401 million for Upstream for the first quarter of 2014. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 4 and 28.

•

All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $332 million for the first quarter. For further information on the Gulf of Mexico oil spill and its consequences see page 11 and Note 2 on page 17. See also Legal proceedings on page 32.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $1.9 billion, compared with $8.2 billion for the same period in 2014. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $2.5 billion, compared with $8.8 billion for the same period in 2014.

•

Gross debt at 31 March 2015 was $57.7 billion compared with $53.2 billion a year ago. The ratio of gross debt to gross debt plus equity was 34%, compared with 29% a year ago. Net debt* at 31 March 2015 was $25.1 billion, compared with $25.3 billion a year ago. The net debt ratio* at 31 March 2015 was 18.4%, compared with 16.2% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 25 for more information.

•

Total capital expenditure on an accruals basis for the first quarter was $4.5 billion, of which organic capital expenditure* was $4.4 billion, compared with $6.1 billion for the same period in 2014, of which organic capital expenditure was $5.4 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. Transactions to date have reached around $7.1 billion. Disposal proceeds were $1.7 billion for the first quarter. The amounts include proceeds from our Toledo refinery partner, Husky Energy, in place of capital commitments relating to the original divestment transaction that have not been subsequently sanctioned.

•

The effective tax rate (ETR) on the profit for the first quarter was -16%, compared with 31% for the same period in 2014. The ETR on RC profit for the first quarter was -42%, compared with 31% for the same period in 2014. Adjusting for non-operating items and fair value accounting effects, the underlying ETR for the first quarter was -21%, compared with 33% for the same period in 2014. The tax credit for the quarter reflects a one-off deferred tax adjustment as a result of the reduction in the rate of the UK North Sea supplementary charge. The opposite effect was reported in 2011 when the supplementary charge was increased. In the near term we do not expect that there will be any cash flow impact from this change. Excluding this one-off adjustment for the North Sea, the underlying ETR for the first quarter would have been 21% compared with 33% a year ago mainly due to changes in the mix of our profits and certain one-off items, partly offset by foreign exchange effects from a stronger US dollar.

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $358 million for the first quarter, compared with $367 million for the same period in 2014.

•

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 19 June 2015. The corresponding amount in sterling will be announced on 8 June 2015. See page 24 for further information.

*	For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 30.

(a)	Profit attributable to BP shareholders.

The commentaries above should be read in conjunction with the cautionary statement on page 34.

Analysis of RC profit before interest and tax

and reconciliation to profit for the period


$ million	First quarter 2015			First quarter 2014
RC profit (loss) before interest and tax*
Upstream		372			4,659
Downstream		2,083			794
Rosneft		183			518
Other businesses and corporate		(308	)		(497	)
Gulf of Mexico oil spill response^(a)		(323	)		(29	)
Consolidation adjustment – UPII*		(129	)		90

RC profit before interest and tax		1,878			5,535
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(358	)		(367	)
Taxation on a RC basis		632			(1,602	)
Non-controlling interests		(49	)		(91	)

RC profit attributable to BP shareholders		2,103			3,475

Inventory holding gains (losses)		756			102
Taxation (charge) credit on inventory holding gains and losses		(257	)		(49	)

Profit for the period attributable to BP shareholders		2,602			3,528

(a)	See Note 2 on page 17 for further information on the accounting for the Gulf of Mexico oil spill response.

Analysis of underlying RC profit before interest and tax


$ million	First quarter 2015			First quarter 2014
Underlying RC profit before interest and tax*
Upstream		604			4,401
Downstream		2,158			1,011
Rosneft		183			271
Other businesses and corporate		(290	)		(489	)
Consolidation adjustment – UPII		(129	)		90

Underlying RC profit before interest and tax		2,526			5,284
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(349	)		(357	)
Taxation on an underlying RC basis		449			(1,611	)
Non-controlling interests		(49	)		(91	)

Underlying RC profit attributable to BP shareholders		2,577			3,225

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 5-10 for the segments.

Upstream


$ million	First quarter 2015			First quarter 2014
Profit before interest and tax		390			4,653
Inventory holding (gains) losses*		(18	)		6

RC profit before interest and tax		372			4,659
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*		232			(258	)

Underlying RC profit before interest and tax*^(a)		604			4,401

(a)	See page 6 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost profit before interest and tax for the first quarter was $372 million, compared with $4,659 million for the same period in 2014. The first quarter included a net non-operating charge of $242 million, compared with a net non-operating gain of $276 million a year ago. Fair value accounting effects in the first quarter had a favourable impact of $10 million, compared with an unfavourable impact of $18 million in the same period of 2014.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $604 million, compared with $4,401 million for the same period in 2014. The result for the first quarter reflected significantly lower liquids and gas realizations, and lower gas marketing and trading results compared with strong results in the first quarter last year, partly offset by increased production and lower costs. Costs were lower, mainly due to lower exploration write-offs, and also reflecting simplification and efficiency activities, but this was partially offset by rig cancellation costs of $375 million for two deepwater rigs in the Gulf of Mexico. These factors contributed to a $545-million first-quarter loss in the US.

Production

Production for the quarter was 2,307mboe/d, 8.3% higher than the first quarter of 2014. Underlying production* increased by 3.7%, mainly due to the ramp-up of major projects which started up in 2014.

Key events

In March, BP announced a gas discovery in the North Damietta Offshore Concession in the East Nile Delta in Egypt at the Atoll-1 Deepwater exploration well (BP 100%). In addition, BP signed final agreements for two West Nile Delta projects Taurus/Libra and Giza/Fayoum/Raven (BP 65%) with an estimated investment of around $12 billion by BP and its partner. Production from West Nile Delta is expected to start in 2017.

Following the start of steam generation at the Sunrise Phase 1 in-situ oil sands project in Alberta, Canada (BP 50%) in December 2014, oil production began in March. Production is expected to ramp up to full capacity of 60,000 barrels per day around the end of 2016.

On 23 April, BP announced the sale of its equity in the Central Area Transmission System (CATS) business in the UK North Sea to Antin Infrastructure Partners for $486 million. BP is currently the operator of CATS. Subject to the receipt of regulatory and other third-party approvals, BP aims to complete the sale and transfer of operatorship before the end of 2015.

Outlook

Looking ahead, we expect second-quarter 2015 reported production to be lower than the first quarter, reflecting significant seasonal turnaround and maintenance activity, primarily in the Gulf of Mexico, and PSA* entitlement impacts.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

Upstream


$ million	First quarter 2015			First quarter 2014
Underlying RC profit (loss) before interest and tax
US		(545	)		731
Non-US		1,149			3,670

		604			4,401

Non-operating items
US		(68	)		(59	)
Non-US		(174	)		335

		(242	)		276

Fair value accounting effects
US		(3	)		(49	)
Non-US		13			31

		10			(18	)

RC profit (loss) before interest and tax
US		(616	)		623
Non-US		988			4,036

		372			4,659

Exploration expense
US^(a)		78			659
Non-US		94			289

		172			948

Production (net of royalties)^(b)
Liquids* (mb/d)
US		392			396
Europe		112			106
Rest of World		754			582

		1,258			1,085

Of which equity-accounted entities^(c)		170			186

Natural gas (mmcf/d)
US		1,517			1,478
Europe		264			199
Rest of World		4,307			4,390

		6,088			6,067

Of which equity-accounted entities		440			449

Total hydrocarbons* (mboe/d)
US		653			651
Europe		158			140
Rest of World		1,496			1,339

		2,307			2,131

Of which equity-accounted entities^(c)		246			263

Average realizations*^(d)
Total liquids ($/bbl)		46.79			97.16
Natural gas ($/mcf)		4.44			6.20
Total hydrocarbons ($/boe)		37.00			66.16

(a)	First quarter 2014 includes a $521-million write-off relating to the Utica shale acreage in Ohio, following the decision not to proceed with development plans.

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

(c)	A minor amendment has been made to the equity-accounted entities production volumes for the first quarter 2014.

(d)	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.

Downstream


$ million	First quarter 2015			First quarter 2014
Profit before interest and tax		2,783			871
Inventory holding (gains) losses*		(700	)		(77	)

RC profit before interest and tax		2,083			794
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*		75			217

Underlying RC profit before interest and tax*^(a)		2,158			1,011

(a)	See page 8 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results

The replacement cost profit before interest and tax was $2,083 million for the first quarter, compared with $794 million for the same period in 2014.

The first-quarter result includes a net non-operating gain of $37 million, compared with a net non-operating charge of $278 million for the same period in 2014 (see pages 8 and 27 for further information on non-operating items). Fair value accounting effects had unfavourable impacts of $112 million for the first quarter, compared with favourable impacts of $61 million in the same period of 2014.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $2,158 million, compared with $1,011 million for the same period in 2014.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 8.

Fuels business

The fuels business reported an underlying replacement cost profit before interest and tax of $1,796 million for the first quarter compared with $700 million for the same period in 2014. The result reflects a stronger overall refining environment, despite weaker crude oil differentials in the US, increased refining optimization and production and improved marketing performance. Additionally, the first quarter saw a stronger contribution from oil supply and trading as well as the benefits of our simplification and efficiency programmes resulting in lower costs.

In the quarter we announced the sale of our bitumen business in Australia and completed the sale of our interest in UTA, a European fuel cards business.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $345 million in the first quarter compared with $307 million in the same period last year. This performance reflects continued momentum in growth markets and improved efficiency resulting in lower costs, partially offset by adverse foreign exchange impacts.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $17 million in the first quarter, compared with $4 million in the same period last year. The benefit from lower costs was partially offset by a slightly weaker environment.

In March, we started up the new advanced technology purified terephthalic acid (PTA) plant in Zhuhai, China which will add over one million tonnes of PTA capacity per year.

Outlook

In the second quarter we expect refining margins to be similar to the first quarter and a significantly higher level of turnaround activity.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

Downstream


$ million	First quarter 2015			First quarter 2014
Underlying RC profit before interest and tax - by region
US		661			412
Non-US		1,497			599

		2,158			1,011

Non-operating items
US		(4	)		(1	)
Non-US		41			(277	)

		37			(278	)

Fair value accounting effects
US		(127	)		91
Non-US		15			(30	)

		(112	)		61

RC profit before interest and tax
US		530			502
Non-US		1,553			292

		2,083			794

Underlying RC profit before interest and tax - by business^(a)(b)
Fuels		1,796			700
Lubricants		345			307
Petrochemicals		17			4

		2,158			1,011

Non-operating items and fair value accounting effects^(c)
Fuels		(60	)		(217	)
Lubricants		(14	)		—
Petrochemicals		(1	)		—

		(75	)		(217	)

RC profit before interest and tax^(a)(b)
Fuels		1,736			483
Lubricants		331			307
Petrochemicals		16			4

		2,083			794

BP average refining marker margin (RMM)* ($/bbl)		15.2			13.3

Refinery throughputs (mb/d)
US		623			614
Europe		805			798
Rest of World		324			308

		1,752			1,720

Refining availability* (%)		94.3			95.0

Marketing sales of refined products (mb/d)
US		1,098			1,120
Europe		1,174			1,139
Rest of World		607			545

		2,879			2,804
Trading/supply sales of refined products		2,544			2,416

Total sales volumes of refined products		5,423			5,220

Petrochemicals production (kte)
US		905			1,071
Europe		972			972
Rest of World		1,663			1,422

		3,540			3,465

(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.

Rosneft


$ million	First quarter 2015^(a)			First quarter 2014
Profit before interest and tax^(b)		221			549
Inventory holding (gains) losses*		(38	)		(31	)

RC profit before interest and tax		183			518
Net charge (credit) for non-operating items*		—			(247	)

Underlying RC profit before interest and tax*		183			271

Replacement cost profit before interest and tax for the first quarter was $183 million, compared with $518 million for the same period in 2014.

There were no non-operating items in the first quarter of 2015 and a non-operating gain of $247 million in the first quarter of 2014.

After adjusting for non-operating items, the underlying replacement cost profit for the first quarter was $183 million, compared with $271 million for the same period in 2014. Compared with the first quarter 2014, the result was affected by lower oil prices and the unfavourable impact of changes in minerals extraction tax and export duty rates offset by favourable foreign exchange effects.

See also Group statement of comprehensive income – Share of items relating to equity-accounted entities, net of tax, and footnote (a), on page 13 for other foreign exchange effects.


	First quarter 2015^(a)		First quarter 2014
Production (net of royalties) (BP share)
Liquids* (mb/d)		816		829
Natural gas (mmcf/d)		1,225		1,023
Total hydrocarbons* (mboe/d)		1,027		1,006

(a)	The operational and financial information of the Rosneft segment for the first quarter is based on preliminary operational and financial results of Rosneft for the three months ended 31 March 2015. Actual results may differ from these amounts.

(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 finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation. These adjustments have increased the reported profit for the first quarter 2015, as shown in the table above, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. BP’s share of Rosneft’s profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.

Other businesses and corporate


$ million	First quarter 2015			First quarter 2014
Profit (loss) before interest and tax		(308	)		(497	)
Inventory holding (gains) losses*		—			—

RC profit (loss) before interest and tax		(308	)		(497	)
Net charge (credit) for non-operating items*		18			8

Underlying RC profit (loss) before interest and tax*		(290	)		(489	)

Underlying RC profit (loss) before interest and tax
US		(62	)		(99	)
Non-US		(228	)		(390	)

		(290	)		(489	)

Non-operating items
US		(1	)		(1	)
Non-US		(17	)		(7	)

		(18	)		(8	)

RC profit (loss) before interest and tax
US		(63	)		(100	)
Non-US		(245	)		(397	)

		(308	)		(497	)

Other businesses and corporate comprises biofuels and wind businesses, 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 first quarter was $308 million, compared with $497 million for the same period in 2014.

The first-quarter result included a net non-operating charge of $18 million, compared with a net charge of $8 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the first quarter was $290 million, compared with $489 million for the same period in 2014.

The lower charge in the first quarter results from improved business performance and lower corporate and functional costs compared with the same period in 2014.

Biofuels

The first quarter is the inter-harvest period in Brazil so our three operating mills were on planned turnaround; hence there was no production.

Wind

Net wind generation capacity*(a) was 1,588MW at 31 March 2015, compared with 1,590MW at 31 March 2014. BP’s net share of wind generation for the first quarter was 1,128GWh, compared with 1,292GWh for the same period in 2014.

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

Gulf of Mexico oil spill

Financial update

The replacement cost loss before interest and tax for the first quarter was $323 million, compared with $29 million for the same period last year. The first-quarter loss reflects additional business economic loss claims under the Plaintiffs’ Steering Committee settlement, as well as the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $43.8 billion.

The cumulative income statement charge does not include amounts for obligations that BP currently considers are not possible to measure reliably. The total amounts that will ultimately be paid by BP in relation 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 19. These could have a material impact on our consolidated financial position, results and cash flows.

Trust update

As previously disclosed, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, reached $20 billion during 2014. Subsequent additional costs are being charged to the income statement as incurred. See Note 2 on page 17 for further details.

During the first quarter, $472 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $435 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $37 million for natural resource damage early restoration projects and assessment. At 31 March 2015, the aggregate cash balances in the Trust and the QSFs amounted to $4.3 billion, including $0.8 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.4 billion held for natural resource damage early restoration projects.

Legal proceedings

In March 2015, following a detailed review of internal controls and fraud prevention and detection measures at the DHCSSP, which was facilitated by Special Master Louis Freeh, BP withdrew its appeal related to its motion to remove the claims administrator. This action is contributing to a more constructive relationship with the claims programme.

The penalty phase of the Trial of Liability, Limitation, Exoneration and Fault Allocation in the Federal multi-district litigation proceeding in New Orleans (MDL 2179) concluded in February 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 (or ultimate determinations on appeal) in Phases 1 and 2, and the application of the penalty factors under the Clean Water Act. Post-trial briefing on the penalty phase concluded on 24 April 2015 and the court could issue its decision at any time.

For further details, see Legal proceedings on page 32.

Financial statements

Group income statement


$ million	First quarter 2015			First quarter 2014
Sales and other operating revenues (Note 4)		54,196			91,710
Earnings from joint ventures – after interest and tax		104			115
Earnings from associates – after interest and tax		362			783
Interest and other income		120			331
Gains on sale of businesses and fixed assets		138			49

Total revenues and other income		54,920			92,988
Purchases		37,936			71,468
Production and manufacturing expenses		7,000			6,831
Production and similar taxes (Note 5)		362			986
Depreciation, depletion and amortization		3,836			3,590
Impairment and losses on sale of businesses and fixed assets		197			426
Exploration expense		172			948
Distribution and administration expenses		2,783			3,102

Profit before interest and taxation		2,634			5,637
Finance costs		281			287
Net finance expense relating to pensions and other post-retirement benefits		77			80

Profit before taxation		2,276			5,270
Taxation		(375	)		1,651

Profit for the period		2,651			3,619

Attributable to
BP shareholders		2,602			3,528
Non-controlling interests		49			91

		2,651			3,619

Earnings per share (Note 6)
Profit for the period attributable to BP shareholders
Per ordinary share (cents)
Basic		14.28			19.09
Diluted		14.21			18.97
Per ADS (dollars)
Basic		0.86			1.15
Diluted		0.85			1.14

Financial statements (continued)

Group statement of comprehensive income


$ million	First quarter 2015			First quarter 2014
Profit for the period		2,651			3,619

Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences		(1,612	)		(913	)
Available-for-sale investments marked to market		—			(3	)
Cash flow hedges marked to market		(212	)		23
Cash flow hedges reclassified to the income statement		74			(20	)
Cash flow hedges reclassified to the balance sheet		5			(1	)
Share of items relating to equity-accounted entities, net of tax^(a)		(80	)		(73	)
Income tax relating to items that may be reclassified		124			—

		(1,701	)		(987	)

Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset		(568	)		(936	)
Share of items relating to equity-accounted entities, net of tax		—			5
Income tax relating to items that will not be reclassified		158			294

		(410	)		(637	)

Other comprehensive income		(2,111	)		(1,624	)

Total comprehensive income		540			1,995

Attributable to
BP shareholders		513			1,903
Non-controlling interests		27			92

		540			1,995

(a)	Includes the effects of hedge accounting adopted by Rosneft from 1 October 2014 in relation to a portion of future export revenue denominated in US dollars. For further information see BP Annual Report and Form 20-F 2014 – Financial statements – Note 15.

Financial statements (continued)

Group statement of changes in equity


$ million	BP shareholders’ equity			Non-controlling interests			Total equity
At 1 January 2015		111,441			1,201			112,642


Total comprehensive income		513			27			540
Dividends		(1,709	)		(12	)		(1,721	)
Share-based payments, net of tax		51			—			51
Transactions involving non-controlling interests		—			(3	)		(3	)

At 31 March 2015		110,296			1,213			111,509


$ million	BP shareholders’ equity			Non-controlling interests			Total equity
At 1 January 2014		129,302			1,105			130,407


Total comprehensive income		1,903			92			1,995
Dividends		(1,426	)		(79	)		(1,505	)
Repurchases of ordinary share capital		(1,026	)		—			(1,026	)
Share-based payments, net of tax		327			—			327
Transactions involving non-controlling interests		—			2			2

At 31 March 2014		129,080			1,120			130,200

Financial statements (continued)

Group balance sheet


$ million	31 March 2015		31 December 2014
Non-current assets
Property, plant and equipment		129,113		130,692
Goodwill		11,633		11,868
Intangible assets		20,809		20,907
Investments in joint ventures		8,871		8,753
Investments in associates		10,312		10,403
Other investments		1,133		1,228

Fixed assets		181,871		183,851
Loans		599		659
Trade and other receivables		4,334		4,787
Derivative financial instruments		4,829		4,442
Prepayments		968		964
Deferred tax assets		2,349		2,309
Defined benefit pension plan surpluses		31		31

		194,981		197,043

Current assets
Loans		374		333
Inventories		18,925		18,373
Trade and other receivables		28,756		31,038
Derivative financial instruments		4,103		5,165
Prepayments		1,736		1,424
Current tax receivable		793		837
Other investments		309		329
Cash and cash equivalents		32,434		29,763

		87,430		87,262

Total assets		282,411		284,305

Current liabilities
Trade and other payables		37,817		40,118
Derivative financial instruments		3,167		3,689
Accruals		5,777		7,102
Finance debt		8,538		6,877
Current tax payable		1,977		2,011
Provisions		3,495		3,818

		60,771		63,615

Non-current liabilities
Other payables		2,941		3,587
Derivative financial instruments		4,425		3,199
Accruals		858		861
Finance debt		49,193		45,977
Deferred tax liabilities		12,903		13,893
Provisions		28,569		29,080
Defined benefit pension plan and other post-retirement benefit plan deficits		11,242		11,451

		110,131		108,048

Total liabilities		170,902		171,663

Net assets		111,509		112,642

Equity
BP shareholders’ equity		110,296		111,441
Non-controlling interests		1,213		1,201

		111,509		112,642

Financial statements (continued)

Condensed group cash flow statement


$ million	First quarter 2015			First quarter 2014
Operating activities
Profit before taxation		2,276			5,270
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		3,928			4,422
Impairment and loss on sale of businesses and fixed assets		59			377
Earnings from equity-accounted entities, less dividends received		(276	)		(684	)
Net charge for interest and other finance expense, less net interest paid		129			170
Share-based payments		(238	)		106
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(57	)		(102	)
Net charge for provisions, less payments		388			(193	)
Movements in inventories and other current and non-current assets and liabilities		(3,858	)		(315	)
Income taxes paid		(493	)		(820	)

Net cash provided by operating activities		1,858			8,231

Investing activities
Capital expenditure		(4,636	)		(5,891	)
Acquisitions, net of cash acquired		—			(10	)
Investment in joint ventures		(69	)		(33	)
Investment in associates		(87	)		(88	)
Proceeds from disposal of fixed assets		653			978
Proceeds from disposal of businesses, net of cash disposed		1,087			26
Proceeds from loan repayments		3			17

Net cash used in investing activities		(3,049	)		(5,001	)

Financing activities
Net repurchase of shares		—			(1,726	)
Proceeds from long-term financing		7,788			5,979
Repayments of long-term financing		(2,307	)		(1,237	)
Net increase in short-term debt		725			77
Net increase in non-controlling interests		—			—
Dividends paid – BP shareholders		(1,709	)		(1,427	)
– non-controlling interests		(12	)		(13	)

Net cash provided by financing activities		4,485			1,653

Currency translation differences relating to cash and cash equivalents		(623	)		(45	)

Increase in cash and cash equivalents		2,671			4,838

Cash and cash equivalents at beginning of period		29,763			22,520
Cash and cash equivalents at end of period		32,434			27,358

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 2014 included in the BP Annual Report and Form 20-F 2014.

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. 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 2015, which do not differ significantly from those used in BP Annual Report and Form 20-F 2014.

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 2014 – Financial statements – Note 2 and Legal proceedings on page 228 and on page 32 of this report.

The group income statement includes a pre-tax charge of $332 million for the first quarter in relation to the Gulf of Mexico oil spill. The first-quarter charge reflects additional business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement 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 $43,827 million.

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

The total amounts that will ultimately be paid by BP in relation to 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 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.


$ million	First quarter 2015			First quarter 2014
Income statement
Production and manufacturing expenses		323			29

Profit (loss) before interest and taxation		(323	)		(29	)
Finance costs		9			10

Profit (loss) before taxation		(332	)		(39	)
Taxation		112			10

Profit (loss) for the period		(220	)		(29	)

Financial statements (continued)

Notes

2.	Gulf of Mexico oil spill (continued)


$ million	31 March 2015			31 December 2014
Balance sheet
Current assets
Trade and other receivables		1,079			1,154
Current liabilities
Trade and other payables		(724	)		(655	)
Provisions		(1,562	)		(1,702	)

Net current assets (liabilities)		(1,207	)		(1,203	)

Non-current assets
Trade and other receivables		2,304			2,701
Non-current liabilities
Other payables		(2,098	)		(2,412	)
Accruals		(154	)		(169	)
Provisions		(6,472	)		(6,903	)
Deferred tax		1,835			1,723

Net non-current assets (liabilities)		(4,585	)		(5,060	)

Net assets (liabilities)		(5,792	)		(6,263	)


$ million	First quarter 2015			First quarter 2014
Cash flow statement - Operating activities
Profit (loss) before taxation		(332	)		(39	)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Net charge for interest and other finance expense, less net interest paid		9			10
Net charge for provisions, less payments		227			(97	)
Movements in inventories and other current and non-current assets and liabilities		(595	)		(578	)

Pre-tax cash flows		(691	)		(704	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $691 million in the first quarter. For the first quarter of 2014, the amount was an outflow of $584 million.

Trust fund

BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. Fines and penalties are not covered by the trust fund.

The funding of the Trust was completed in 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. During 2014, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, are expensed to the income statement as incurred.

At 31 March 2015, $3,383 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet, of which $1,079 million is classified as current and $2,304 million as non-current. During the first quarter of 2015, $470 million of provisions and $2 million of payables were paid from the Trust.

At 31 March 2015, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $4.3 billion, including $0.8 billion remaining in the seafood compensation fund which has yet to be distributed and $0.4 billion held for natural resource damage early restoration projects. When the cash balances in the trust fund are exhausted, payments in respect of legitimate claims and other costs will be made directly by BP.

Financial statements (continued)

Notes

2.	Gulf of Mexico oil spill (continued)

(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 2014 – 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 first quarter are presented in the table below.

$ million

Environmental

Litigation
and claims

Clean Water
Act penalties

Total

At 1 January 2015

1,141

3,954

3,510

8,605

Net increase in provision

294

—

295

Unwinding of discount

—

Reclassified to other payables

(329

)

—

(329

)

Utilization

– paid by BP

(19

)

(49

)

—

(68

)

– paid by the trust fund

(35

)

(435

)

—

(470

)

At 31 March 2015

760

3,764

3,510

8,034

Of which

– current

405

1,157

—

1,562

– non-current

355

2,607

3,510

6,472

Environmental

The environmental provision includes amounts for estimated natural resource damage assessment costs and natural resource damage early 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 under the Oil Pollution Act of 1990 and other legislation (State and Local Claims). Amounts that cannot be measured reliably and which have therefore not been provided for are described under Contingent liabilities below. Claims administration costs and legal costs have also been provided for. The timing of payment of litigation and claims provisions classified as non-current is dependent upon ongoing legal and claims facility activity and is therefore uncertain.

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, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility. As disclosed in BP Annual Report and Form 20-F 2014, as part of its monitoring of payments made by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. See Legal proceedings on pages 228-237 of BP Annual Report and Form 20-F 2014 and page 32 of this report for further details on the settlements with the PSC and related matters.

Management believes that no reliable estimate can currently be made of any business economic loss claims (i) not yet received; (ii) received, but not yet processed; or (iii) processed, but not yet paid, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility. The inability to estimate reliably such claims is due to uncertainty regarding both the volume of such claims and the average value per claim, as described further below.

In respect of uncertainty regarding the volume of claims, in December 2014, the US Supreme Court declined to hear BP’s appeal of the district court ruling that the EPD Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in that agreement. This resolution, however, does not reduce uncertainty in the short term regarding the volume of claims, since it is possible that additional claims will be made. In addition, a claims submission deadline of 8 June 2015 has now been set, which may lead to an increase in the rate of claims received until the deadline, compounding management’s inability to estimate the total volume of claims that will be made.

Financial statements (continued)

Notes

2.	Gulf of Mexico oil spill (continued)

In respect of uncertainty regarding the average value per claim, a small proportion of the filed claims have been determined under the revised policy for the matching of revenue and expenses for business economic loss claims (introduced in May 2014) and disputes, disagreements and uncertainties regarding the proper application of the revised policy to particular claims and categories of claims continue to arise as the claims administrator has begun applying the revised policy. Furthermore, there have been no, or only a small number of, claim determinations made under some of the specialized frameworks that have been put in place for particular industries and so determinations to date may not be representative of the total population of claims. In addition, due to a data secrecy order, detailed data about claims that have not yet been determined is not currently available to BP and so it is not possible to review claim demographics or identify potential populations for each category of claim.

There is therefore very little data to build up a track record of claims determinations under the policies and protocols that are now being applied following resolution of the matching and causation issues. We therefore cannot estimate future trends of the number and proportion of claims that will be determined to be eligible, nor can we estimate the value of such claims. A provision for such business economic loss claims will be established when these uncertainties are resolved and a reliable estimate can be made of the liability.

The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated, including amounts already paid, is $10.3 billion. The DHCSSP has issued eligibility notices, most of which are disputed by BP, in respect of business economic loss claims of approximately $377 million which have not been provided for. 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 $10.3 billion because the current estimate does not reflect business economic loss claims not yet received, or received but not yet processed, or processed but not yet paid, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility.

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 228-237 of BP Annual Report and Form 20-F 2014 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 32 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 and in relation to future legal costs.

Clean Water Act penalties

A provision of $3,510 million was recognized in 2010 for estimated civil penalties under Section 311 of the Clean Water Act. The Clean Water Act penalty is calculated by multiplying the number of barrels of oil spilled by a penalty rate per barrel. The number of barrels of oil spilled was determined by using the mid-point in the range of estimates (3.2 million barrels). A penalty rate of $1,100 per barrel was applied, the statutory maximum penalty in the absence of gross negligence or wilful misconduct.

In September 2014, the district court issued its decision in the Phase 1 trial that the discharge of oil was the result of the gross negligence and wilful misconduct of BP Exploration & Production Inc. (BPXP) and that BPXP is therefore subject to enhanced civil penalties. The statutory maximum penalty is up to $4,300 per barrel of oil discharged where gross negligence or wilful misconduct is proven. BP does not believe that the evidence at trial supports the finding of gross negligence and wilful misconduct and in December 2014 filed notice of appeal of the Phase 1 ruling.

In January 2015, the district court issued its decision in the Phase 2 trial that 3.19 million barrels of oil were discharged into the Gulf of Mexico and therefore subject to a Clean Water Act penalty. This amount is consistent with the number of barrels BP has used to calculate the provision. In addition, the district court found that BP was not grossly negligent in its source control efforts. The estimates of cumulative discharge presented by experts testifying in the Phase 2 trial varied significantly. BPXP and the Department of Justice have appealed the district court’s ruling with regard to the quantity of oil discharged. Other parties have also appealed the Phase 2 ruling. Therefore, the findings from the Phase 2 trial remain subject to uncertainty.

BP continues to believe that a provision of $3,510 million represents a reliable estimate of the amount of the liability if the appeal of the Phase 1 ruling is successful and this provision, calculated on the basis of the previous assumptions, has been maintained in the accounts.

Financial statements (continued)

Notes

2.	Gulf of Mexico oil spill (continued)

If BP is unsuccessful in its appeal, and the ruling of gross negligence and wilful misconduct is upheld, the maximum penalty that could be imposed is up to $4,300 per barrel. Based upon this penalty rate and the district court’s ruling on the number of barrels spilled, which as noted above is also subject to appeal, the maximum penalty could be up to $13.7 billion.

However, in assessing the amount of the penalty, the court is directed to consider the following statutory penalty factors: ‘the seriousness of the violation or violations, the economic benefit to the violator, if any, resulting from the violation, the degree of culpability involved, any other penalty for the same incident, any history of prior violations, the nature, extent, and degree of success of any efforts of the violator to minimize or mitigate the effects of the discharge, the economic impact of the penalty on the violator, and any other matters as justice may require’. The court has wide discretion in deciding how to apply these factors to determine the penalty and what weighting to ascribe to different factors. BP is therefore unable to ascribe probabilities to possible outcomes within the range of potential penalties and cannot determine a reliable estimate for any additional penalty which might apply should the gross negligence finding be upheld. Post-trial briefing on the trial phase to determine the amount of the Clean Water Act penalty concluded on 24 April 2015 and the court could issue its decision at any time.

The amount that may become payable by BP is subject to a very high level of uncertainty since it will depend on the outcome of the pending appeals as well as what is determined by the district court with respect to the application of statutory penalty factors as noted above. The court has wide discretion in the application of statutory penalty factors. The timing of any payment is also uncertain.

Given the significant uncertainty, the very wide range of possible outcomes if BP is unsuccessful in its appeal of the September ruling, and the inability to ascribe probabilities to possible outcomes within the range, management is not able to estimate reliably any further liability for the Clean Water Act penalty arising in the event that BP is not successful in its appeal. A contingent liability is therefore disclosed. See Contingent liabilities below for further information.

See BP Annual Report and Form 20-F 2014 – Financial statements – Note 2 for further details and Legal proceedings on pages 228-237 and on page 32 of this report.

Provision movements and analysis of income statement charge

A net increase in provisions of $295 million for the first quarter arises primarily due to increases in the provision for business economic loss claims. The following table shows an analysis of the income statement charge.


$ million		First quarter 2015		Cumulative since the incident
Environmental costs			1		3,224
Spill response costs			—		14,304
Litigation and claims costs			294		27,074
Clean Water Act penalties – amount provided			—		3,510
Other costs charged directly to the income statement			28		1,285
Recoveries credited to the income statement			—		(5,681	)
Charge (credit) related to the trust fund			—		(137	)
Other costs of the trust fund			—		8

Loss before interest and taxation			323		43,587
Finance costs	– related to the trust funds		—		137
	– not related to the trust funds		9		103

Loss before taxation			332		43,827

Further information on provisions is provided in BP Annual Report and Form 20-F 2014 – Financial statements – Note 2.

Financial statements (continued)

Notes

2.	Gulf of Mexico oil spill (continued)

Contingent liabilities

BP currently considers that it is not possible 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 228-237 of BP Annual Report and Form 20-F 2014 and page 32 of this report.

•

The cost of business economic loss claims under the PSC settlement not yet received, or received but not yet processed, or processed but not yet paid (except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility).

•

Any further obligation that may arise from State and Local Claims.

•

Any obligation that may arise from securities-related litigation.

•

Any obligation in relation to any further liability for the Clean Water Act penalty arising in the event that BP is not successful in its appeal of the Phase 1 ruling, or if any appeal of the Phase 2 ruling results in the determination of a higher volume of oil discharged.

•

Any obligation in relation to other potential private or governmental litigation, fines or penalties (except for those items provided for as described above under Provisions).

It is not practicable to estimate the magnitude or possible timing of payment of these contingent liabilities.

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 2014 – Financial statements – Note 2.

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


$ million	First quarter 2015			First quarter 2014
Upstream		372			4,659
Downstream		2,083			794
Rosneft		183			518
Other businesses and corporate		(308	)		(497	)

		2,330			5,474
Gulf of Mexico oil spill response		(323	)		(29	)
Consolidation adjustment – UPII*		(129	)		90

RC profit before interest and tax		1,878			5,535
Inventory holding gains (losses)*
Upstream		18			(6	)
Downstream		700			77
Rosneft (net of tax)		38			31

Profit before interest and tax		2,634			5,637
Finance costs		281			287
Net finance expense relating to pensions and other post-retirement benefits		77			80

Profit before taxation		2,276			5,270

RC profit (loss) before interest and tax*
US		(497	)		1,125
Non-US		2,375			4,410

		1,878			5,535

Financial statements (continued)

Notes

4.	Sales and other operating revenues


$ million	First quarter 2015		First quarter 2014
By segment
Upstream		11,630		17,006
Downstream		48,125		84,298
Other businesses and corporate		428		431

		60,183		101,735

Less: sales and other operating revenues between segments
Upstream		5,563		9,217
Downstream		176		562
Other businesses and corporate		248		246

		5,987		10,025

Third party sales and other operating revenues
Upstream		6,067		7,789
Downstream		47,949		83,736
Other businesses and corporate		180		185

Total third party sales and other operating revenues		54,196		91,710

By geographical area
US		18,841		34,825
Non-US		38,688		66,305

		57,529		101,130
Less: sales and other operating revenues between areas		3,333		9,420

		54,196		91,710

5.	Production and similar taxes


$ million	First quarter 2015		First quarter 2014
US		34		279
Non-US		328		707

		362		986

6.	Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

Financial statements (continued)

Notes

6.	Earnings per share and shares in issue (continued)

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


$ million	First quarter 2015		First quarter 2014
Results for the period
Profit for the period attributable to BP shareholders		2,602		3,528
Less: preference dividend		—		—

Profit attributable to BP ordinary shareholders		2,602		3,528


Number of shares (thousand)^(a)
Basic weighted average number of shares outstanding		18,220,486		18,480,826
ADS equivalent		3,036,747		3,080,137


Weighted average number of shares outstanding used to calculate diluted earnings per share		18,309,730		18,594,518
ADS equivalent		3,051,621		3,099,086


Shares in issue at period-end		18,249,422		18,457,009
ADS equivalent		3,041,570		3,076,168

(a)	Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.

7.	Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 19 June 2015 to shareholders and American Depositary Share (ADS) holders on the register on 8 May 2015. The corresponding amount in sterling is due to be announced on 8 June 2015, calculated based on the average of the market exchange rates for the four dealing days commencing on 2 June 2015. Holders of ADSs are expected to receive $0.600 per ADS. With effect from and including this dividend, an annual fee of $0.02 per ADS (or $0.005 per ADS per quarter) will be charged. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the first-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

Dividends paid


	First quarter 2015		First quarter 2014
Dividends paid per ordinary share
cents		10.000		9.500
pence		6.670		5.707
Dividends paid per ADS (cents)		60.00		57.00

Scrip dividends
Number of shares issued (millions)		15.7		40.2
Value of shares issued ($ million)		109		326

Financial statements (continued)

Notes

Net debt*

Net debt ratio*


$ million	First quarter 2015			First quarter 2014
Gross debt		57,731			53,249
Fair value asset of hedges related to finance debt^(a)		(174	)		(633	)

		57,557			52,616
Less: cash and cash equivalents		32,434			27,358

Net debt		25,123			25,258

Equity		111,509			130,200
Net debt ratio		18.4	%		16.2	%

Analysis of changes in net debt


$ million	First quarter 2015			First quarter 2014
Opening balance
Finance debt		52,854			48,192
Fair value asset of hedges related to finance debt^(a)		(445	)		(477	)
Less: cash and cash equivalents		29,763			22,520

Opening net debt		22,646			25,195

Closing balance
Finance debt		57,731			53,249
Fair value asset of hedges related to finance debt^(a)		(174	)		(633	)
Less: cash and cash equivalents		32,434			27,358

Closing net debt		25,123			25,258

Decrease (increase) in net debt		(2,477	)		(63	)

Movement in cash and cash equivalents (excluding exchange adjustments)		3,294			4,883
Net cash outflow (inflow) from financing (excluding share capital and dividends)		(6,206	)		(4,819	)
Other movements		11			(118	)

Movement in net debt before exchange effects		(2,901	)		(54	)
Exchange adjustments		424			(9	)

Decrease (increase) in net debt		(2,477	)		(63	)

(a)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $1,650 million (first quarter 2014 asset of $44 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.

9.	Inventory valuation

A provision of $797 million was held at 31 March 2015 ($410 million at 31 March 2014) to write inventories down to their net realizable value. The net movement credited to the income statement during the first quarter 2015 was $2,024 million (first quarter 2014 was a charge of $88 million).

10.

Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 27 April 2015, is unaudited and does not constitute statutory financial statements.

Additional information

Capital expenditure and acquisitions


$ million	First quarter 2015		First quarter 2014
By segment
Upstream
US		1,135		1,698
Non-US^(a)		2,896		3,699

		4,031		5,397

Downstream
US		145		206
Non-US		199		344

		344		550

Other businesses and corporate
US		16		3
Non-US		74		135

		90		138

		4,465		6,085

By geographical area
US		1,296		1,907
Non-US^(a)		3,169		4,178

		4,465		6,085

Included above:
Acquisitions and asset exchanges		28		236
Other inorganic capital expenditure^(a)		—		442

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

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

Additional information (continued)

Non-operating items*


$ million	First quarter 2015			First quarter 2014
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets		(113	)		(116	)
Environmental and other provisions		11			—
Restructuring, integration and rationalization costs		(181	)		—
Fair value gain (loss) on embedded derivatives		41			98
Other		—			294

		(242	)		276

Downstream
Impairment and gain (loss) on sale of businesses and fixed assets		66			(255	)
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		(28	)		(1	)
Fair value gain (loss) on embedded derivatives		—			—
Other		(1	)		(22	)

		37			(278	)

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
Impairment and gain (loss) on sale of businesses and fixed assets		(12	)		(6	)
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		(6	)		(1	)
Fair value gain (loss) on embedded derivatives		—			—
Other		—			(1	)

		(18	)		(8	)

Gulf of Mexico oil spill response		(323	)		(29	)

Total before interest and taxation		(546	)		208
Finance costs^(a)		(9	)		(10	)

Total before taxation		(555	)		198
Taxation credit (charge)^(b)		142			26

Total after taxation for period		(413	)		224

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

(b)	Non-operating items reported within the equity-accounted earnings of Rosneft are reported net of income tax.

Additional information (continued)

Non-GAAP information on fair value accounting effects


$ million	First quarter 2015			First quarter 2014
Favourable (unfavourable) impact relative to management’s measure of performance
Upstream		10			(18	)
Downstream		(112	)		61

		(102	)		43
Taxation credit (charge)		41			(17	)

		(61	)		26

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 historical 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 is 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.


$ million	First quarter 2015			First quarter 2014
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		362			4,677
Impact of fair value accounting effects		10			(18	)

Replacement cost profit before interest and tax		372			4,659

Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		2,195			733
Impact of fair value accounting effects		(112	)		61

Replacement cost profit before interest and tax		2,083			794

Total group
Profit before interest and tax adjusted for fair value accounting effects		2,736			5,594
Impact of fair value accounting effects		(102	)		43

Profit before interest and tax		2,634			5,637

Additional information (continued)

Realizations* and marker prices


	First quarter 2015		First quarter 2014
Average realizations^(a)
Liquids* ($/bbl)
US		46.24		89.81
Europe		52.28		104.10
Rest of World		46.13		102.69
BP Average		46.79		97.16

Natural gas ($/mcf)
US		2.39		4.62
Europe		7.32		9.76
Rest of World		5.05		6.62
BP Average		4.44		6.20

Total hydrocarbons* ($/boe)
US		33.20		65.70
Europe		49.35		92.63
Rest of World		37.41		62.76
BP Average		37.00		66.16

Average oil marker prices ($/bbl)
Brent		53.94		108.21
West Texas Intermediate		48.49		98.69
Western Canadian Select		36.69		76.98
Alaska North Slope		51.95		105.73
Mars		49.15		100.83
Urals (NWE – cif)		52.59		106.24

Average natural gas marker prices
Henry Hub gas price ($/mmBtu)^(b)		2.99		4.95
UK Gas – National Balancing Point (p/therm)		47.90		60.28

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

(b)	Henry Hub First of Month Index.

Exchange rates


	First quarter 2015		First quarter 2014
$/£ average rate for the period		1.51		1.65
$/£ period-end rate		1.48		1.66
$/€ average rate for the period		1.12		1.37
$/€ period-end rate		1.08		1.38
Rouble/$ average rate for the period		63.03		35.07
Rouble/$ period-end rate		57.79		35.69

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 (loss) 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 28.

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

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory 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 historical 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 based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. 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 definition below.

Liquids comprises crude oil, condensate and natural gas liquids.

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures 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 derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’.

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 included in the financial statements 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. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 6, 8 and 10, and by segment and type is shown on page 27.

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 26.

Production-sharing agreement (PSA) is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.

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 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.

Glossary (continued)

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period 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 that is required to be disclosed for each operating segment 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 to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of 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.

Underlying production is production after adjusting for 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 27 and 28 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. The nearest equivalent measure on an IFRS basis for the group is profit or loss for the year attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation.

Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see pages 228-238 of BP Annual Report and Form 20-F 2014.

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

US Department of Justice (DoJ) Action – Liability under Section 311(b)(7)(A) of the Clean Water Act – As previously disclosed, on 22 February 2012, the federal district court in New Orleans (the District Court) held that the subsurface discharge which occurred during the Incident was from the Macondo well, rather than from the Deepwater Horizon vessel, and that BP Exploration & Production Inc. (BPXP) and Anadarko Petroleum Company (Anadarko), and not Transocean Ltd., are liable for civil penalties under Section 311 of the Clean Water Act as owners of the well. Following an unsuccessful appeal to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), on 21 July 2014, Anadarko and BPXP filed petitions requesting that all active judges of the Fifth Circuit review the appeal. On 9 January 2015, the Fifth Circuit issued an order denying the petition for rehearing, on a 7-6 vote. On 24 March 2015 and 9 April 2015, Anadarko and BPXP, respectively, filed petitions for certiorari with the US Supreme Court seeking review of the Fifth Circuit’s order.

Trial Phases – As previously disclosed, on 4 September 2014, the District Court issued its ruling on Findings of Fact and Conclusion of Law for Phase 1 (Phase 1) of the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179. The court found that BPXP, BP America Production Company’s (BPAPC), Transocean Holdings LLC, Transocean Deepwater Inc., Transocean Offshore Deepwater Drilling Inc. (Transocean Entities), and Halliburton Energy Services, Inc. (Halliburton) are each liable under general maritime law for the blowout, explosion, and oil spill from the Macondo well. The court found that the conduct of BPXP and BPAPC was reckless, and apportioned the fault for the blowout, explosion, and oil spill among the liable parties.

The District Court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP is therefore subject to enhanced civil penalties. The court further found that BPXP was an ‘operator’ and ‘person in charge’ of the Macondo well and the Deepwater Horizon vessel for the purposes of the Clean Water Act. On 11 December 2014, BPXP and BPAPC filed a notice of appeal of the Phase 1 ruling to the Fifth Circuit, and subsequently notices of appeal were also filed by the PSC, Transocean, Halliburton and the State of Alabama. The Fifth Circuit has set a briefing schedule for the Phase 1 appeal under which BP’s opening brief is due on 11 May 2015 and briefing is to be completed by September 2015.

On 15 January 2015, the District Court issued its ruling for phase 2 of MDL 2179 (Phase 2) on the quantification of oil spilled and BP’s source control efforts following the accident. The District Court found that 3.19 million barrels of oil were discharged into the Gulf of Mexico and are therefore subject to a Clean Water Act penalty and that BP was not grossly negligent in its source control efforts. On 23 February 2015, BPXP filed a notice of appeal of the Phase 2 ruling to the Fifth Circuit. On 13 March 2015, the United States also filed a notice of appeal. Other parties have also appealed the Phase 2 ruling. No briefing schedule has yet been issued for the Phase 2 appeal.

Trial in the penalty phase of MDL 2179 (the Penalty Phase) commenced on 20 January 2015 and concluded on 2 February 2015. In the Penalty Phase, the District Court will determine the amount of civil penalties owed to the US under the Clean Water Act based on the court’s rulings (or ultimate determinations on appeal) in Phases 1 and 2, and the application of the penalty factors under the Clean Water Act. Post-trial briefing concluded on 24 April 2015. The District Court has wide discretion in its application of statutory penalty factors. BP is not aware of the timing of the District Court’s ruling in respect of the Penalty Phase and the District Court could issue its decision at any time.

For further information, see pages 228-237 of BP Annual Report and Form 20-F 2014 and Note 2 on page 17.

Plaintiffs’ Steering Committee (PSC) Settlements – Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages Settlement Agreement. On 24 December 2013, the District Court issued a ruling on the issues remanded to it in October 2013 by the business economic loss panel of the Fifth Circuit. Part of that ruling directed the claims administrator, in administering business economic loss claims, to match revenue with corresponding variable expenses. On 13 March 2014, the claims administrator issued a revised matching policy reflecting this order. 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. This motion was denied by the district court on 31 March 2015 and, on 23 April 2015, the PSC appealed this decision to the Fifth Circuit.

On 10 November 2014, the District Court denied BP’s motion seeking an order removing Patrick Juneau from his roles as claims administrator and settlement trustee for the Economic and Property Damages Settlement. BP appealed this decision to the Fifth Circuit on 18 November 2014. On 6 March 2015, BP gave notice that it was not proceeding with this appeal.

For information about BP’s current estimate of the total cost of the PSC settlements, see Note 2 on page 17.

Legal proceedings (continued)

Medical Benefits Class Action Settlement (Medical Settlement) – 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 and the deadline for submitting claims for Specified Physical Conditions (SPCs) under the MSA was 12 February 2015. As of 3 April 2015, the MSA claims administrator had received 16,274 claim forms, including 15,367 for certain SPCs, and has determined 1,453 claims to be eligible for monetary compensation totaling approximately $2.7 million. For those claimants seeking benefits under the Periodic Medical Consultation Program, approximately 9,850 claims have been determined to be eligible. A final count of total claim forms received by the bar date is expected shortly. Given the District Court’s decision to classify all physical conditions first diagnosed after 16 April 2012 as Later-Manifested Physical Conditions (LMPC), class members must pursue compensation for LMPCs by submitting a Notice of Intent to Sue (NOIS) under the Back-End Litigation Option (BELO). As of 15 April 2015, 16 compliant NOISs have been received by the MSA claims administrator, of which four have filed BELO lawsuits.

State and local civil claims, including under OPA 90 – State of Alabama Damages Case Proceedings. On 19 April 2013, the State of Alabama filed an action against BP alleging general maritime law claims of negligence, gross negligence, and wilful misconduct; claims under OPA 90 seeking damages for removal costs, natural resource damages, property damage, lost tax and other revenue and damages for providing increased public services during or after removal activities; and various state law claims. On 14 February 2014, BP moved to strike the State of Alabama’s jury trial demand as to its claim for compensatory damages under OPA 90. On 30 March 2015, the District Court denied BP’s motion and BP has asked the District Court to certify its ruling for appeal to the Fifth Circuit. On 16 March 2015 the District Court issued an amended scheduling order for the State of Alabama’s claims against BP and other parties under which the pre-trial matters will be concluded in April 2016.

MDL 2185 and other securities-related litigation

Canadian Class Action – On 26 March 2015, the Supreme Court of Canada dismissed the plaintiff’s appeal to the August 2014 decision by the Ontario Court of Appeal which held that claims made on behalf of Canadian residents who purchased BP ordinary shares and ADSs on exchanges outside of Canada should be litigated in those countries, and that only claims asserted on behalf of Canadian residents who purchased ADSs on the Toronto Stock Exchange could be litigated in Canada. On 27 March 2015, the plaintiff filed a complaint in Texas federal court asserting claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ADSs on the New York Stock Exchange. That action has been transferred to the judge presiding over MDL 2185.

Other legal proceedings

Scharfstein v. BP West Coast Products, LLC – A purported class action lawsuit was filed against BP West Coast Products, LLC in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO’s Oregon sites failed to provide sufficient notice of the 35 cents per transaction debit card fee. After a jury trial and subsequent hearing, in 2014 the jury rendered judgment against BP and determined that statutory damages of $200 per class member should be awarded. A post-trial claims process in late 2014 identified approximately 1.7 million class members, subject to final determination. BP disputes the judgment and intends to appeal. No provision has been made for damages arising out of this class action.

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 operations 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 the divestment of $10 billion in assets by the end of 2015; the expected quarterly dividend payment and timing of such payment; expectations regarding the underlying effective tax rate during 2015 and the effect of the change in the UK North Sea supplementary charge on cash flow; expectations regarding projects in Egypt and future investments in that region; expectations regarding projects in Alberta Canada; expectations regarding the level of reported production for second quarter 2015; expectations regarding second quarter refining margins and level of turnaround activity; expectations regarding the new plant in Zhuhai, China; and certain statements regarding the legal and trial proceedings, court decisions, claims, penalties, potential investigations and civil actions by regulators, government entities and/or other entities or parties, 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 and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; 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 the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; the impact on our reputation following the Gulf of Mexico oil spill; the timing and amount of future payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; 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 elsewhere in this report and under “Risk factors” in BP Annual Report and Form 20-F 2014 as filed with the US Securities and Exchange Commission.

Computation of ratio of earnings to fixed charges


$ million except ratio	First quarter 2015
Earnings available for fixed charges:
Pre-tax income from continuing operations before adjustment for income or loss from joint ventures and associates		1,810
Fixed charges		751
Amortization of capitalized interest		113
Distributed income of joint ventures and associates		190
Interest capitalized		(41	)
Preference dividend requirements, gross of tax		(1	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges		(12	)

Total earnings available for fixed charges		2,810


Fixed charges:
Interest expensed		217
Interest capitalized		41
Rental expense representative of interest		492
Preference dividend requirements, gross of tax		1

Total fixed charges		751


Ratio of earnings to fixed charges		3.74

Capitalization and indebtedness

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 March 2015 in accordance with IFRS:


$ million	31 March 2015
Share capital and reserves
Capital shares (1-2)		5,027
Paid-in surplus (3)		11,669
Merger reserve (3)		27,206
Treasury shares		(20,201	)
Available-for-sale investments		1
Cash flow hedge reserve		(1,007	)
Foreign currency translation reserve		(4,908	)
Profit and loss account		92,509

BP shareholders’ equity		110,296


Finance debt (4-6)
Due within one year		8,538
Due after more than one year		49,193

Total finance debt		57,731

Total capitalization (7)		168,027

(1)

Issued share capital as of 31 March 2015 comprised 18,255,327,058 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,766,341,557 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 31 March 2015.

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

(6)

As of 31 March 2015, the parent company, BP p.l.c., had outstanding guarantees totalling $56,033 million, of which $56,003 million related to guarantees in respect of liabilities of subsidiary undertakings, including $54,092 million relating to finance debt of subsidiaries. Thus 94% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 31 March 2015, $127 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 31 March 2015 in the consolidated capitalization and indebtedness of BP.

Signatures

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

BP p.l.c.

(Registrant)

Dated: 28 April 2015

/s/ J Bertelsen

J BERTELSEN

Deputy Secretary

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