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 2014

Commission File Number 1-06262

BP p.l.c.

(Translation of registrant’s name into English)

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN POST-EFFECTIVE AMENDMENT NO. 2 TO THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-179953) OF BP CAPITAL MARKETS p.l.c. AND BP p.l.c.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

BP p.l.c. and subsidiaries

Form 6-K for the period ended 31 March 2014(a)


		Page

1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-March 2014_(b)		3 – 12, 27 – 32

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-March 2014		13 – 26

3.	Legal proceedings		33 – 34

4.	Other matters		34

5.	Cautionary statement		35

6.	Computation of Ratio of Earnings to Fixed Charges		36

7.	Capitalization and Indebtedness		37

8.	Signatures		38

(a)	In this Form 6-K, references to the first quarter 2014 and first quarter 2013 refer to the three-month periods ended 31 March 2014 and 31 March 2013 respectively.

(b)

This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2013.

Group results first quarter 2014


	First			First
	quarter			quarter
$ million	2014			2013
Profit for the period_(a)		3,528			16,863
Inventory holding (gains) losses*, net of tax		(53	)		(267	)

Replacement cost profit*		3,475			16,596
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*, net of tax		(250	)		(12,381	)

Underlying replacement cost profit*		3,225			4,215

Profit per ordinary share (cents)		19.09			88.07
Profit per ADS (dollars)		1.15			5.28
Replacement cost profit per ordinary share (cents)		18.80			86.67
Replacement cost profit per ADS (dollars)		1.13			5.20
Underlying replacement cost profit per ordinary share (cents)		17.45			22.01
Underlying replacement cost profit per ADS (dollars)		1.05			1.32

•

BP’s profit for the first quarter was $3,528 million, compared with $16,863 million a year ago. BP’s first-quarter replacement cost (RC) profit was $3,475 million, compared with $16,596 million a year ago. First quarter 2013 included a $12.5-billion gain relating to the disposal of our interest in TNK-BP. After adjusting for a net gain for non-operating items of $224 million and net favourable fair value accounting effects of $26 million (both on a post-tax basis), underlying RC profit for the first quarter 2014 was $3,225 million, compared with $4,215 million a year ago. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 5, 23 and 29.

•

All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $39 million for the quarter. For further information on the Gulf of Mexico oil spill and its consequences, including information on utilization of the Deepwater Horizon Oil Spill Trust fund, see page 12 and Note 2 on page 18. See also Legal proceedings on page 33.

•

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $8.2 billion, compared with $4.0 billion in the same period of 2013. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $8.8 billion, compared with $4.3 billion in the same period of 2013. First quarter 2013 net cash provided by operating activities was impacted by a significant increase in working capital which did not occur in 2014.

•

Gross debt at 31 March 2014 was $53.2 billion compared with $48.2 billion at 31 December 2013. The ratio of gross debt to gross debt plus equity was 29.0%, compared with 27.0% a year ago. Net debt at 31 March 2014 was $25.3 billion, compared with $25.2 billion at 31 December 2013. The ratio of net debt to net debt plus equity at 31 March 2014 was 16.2%, the same level as at 31 December 2013. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 26 for more information.

•

Total capital expenditure on an accruals basis for the first quarter was $6.1 billion, 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. BP has agreed around $3.0 billion of such further divestments to date. Disposal proceeds received in cash were $1.0 billion for the quarter.

•

The effective tax rate (ETR) on the profit for the first quarter was 31%, compared with 14% for the same period in 2013. The ETR on RC profit for the first quarter was 31% compared with 14% for the same period in 2013. The first quarter 2013 ETR was impacted by a lower ETR on non-operating items. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the first quarter was 33% compared with 39% for the same period in 2013. The underlying ETR on RC profit was lower in the first quarter of 2014 mainly due to foreign exchange effects on deferred tax and an increase in equity-accounted earnings (which are reported net of tax).

•

Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $367 million for the first quarter, compared with $404 million for the same period in 2013.

•

BP repurchased 245 million ordinary shares at a cost of $2.0 billion, including fees and stamp duty, during the first quarter of 2014. As at 31 March 2014, BP had bought back 997 million shares for a total amount of $7.5 billion, including fees and stamp duty, since the announcement on 22 March 2013 of a share repurchase programme with a total value of up to $8 billion expected to be fulfilled over 12-18 months from the date of the announcement.

•

BP today announced a quarterly dividend of 9.75 cents per ordinary share ($0.585 per ADS), which is expected to be paid on 20 June 2014. The corresponding amount in sterling will be announced on 9 June 2014. See page 25 for further information.

*	For items marked * throughout this document, definitions are provided in the Glossary on page 31.

(a)	Profit attributable to BP shareholders.

The commentaries above and following should be read in conjunction with the cautionary statement on page 35.

THIS PAGE IS INTENTIONALLY LEFT BLANK

Analysis of RC profit before interest and tax

and reconciliation to profit for the period


	First			First
	quarter			quarter
$ million	2014			2013
RC profit before interest and tax*
Upstream		4,659			5,562
Downstream		794			1,647
TNK-BP_(a)		—			12,500
Rosneft_(b)		518			85
Other businesses and corporate		(497	)		(467	)
Gulf of Mexico oil spill response_(c)		(29	)		(22	)
Consolidation adjustment - UPII*		90			427

RC profit before interest and tax		5,535			19,732
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(367	)		(404	)
Taxation on a RC basis		(1,602	)		(2,653	)
Non-controlling interests		(91	)		(79	)

RC profit attributable to BP shareholders		3,475			16,596

Inventory holding gains (losses)		102			406
Taxation (charge) credit on inventory holding gains and losses		(49	)		(139	)

Profit for the period attributable to BP shareholders		3,528			16,863

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

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

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

Analysis of underlying RC profit before interest and tax


	First			First
	quarter			quarter
$ million	2014			2013
Underlying RC profit before interest and tax*
Upstream		4,401			5,702
Downstream		1,011			1,641
Rosneft		271			85
Other businesses and corporate		(489	)		(461	)
Consolidation adjustment – UPII		90			427

Underlying RC profit before interest and tax		5,284			7,394
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(357	)		(394	)
Taxation on an underlying RC basis		(1,611	)		(2,706	)
Non-controlling interests		(91	)		(79	)

Underlying RC profit attributable to BP shareholders		3,225			4,215

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

Upstream


	First			First
	quarter			quarter
$ million	2014			2013
Profit before interest and tax		4,653			5,560
Inventory holding (gains) losses*		6			2

RC profit before interest and tax		4,659			5,562
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*		(258	)		140

Underlying RC profit before interest and tax*_(a)		4,401			5,702

(a)	See page 7 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 $4,659 million, compared with $5,562 million for the same period in 2013. The first quarter included a net non-operating gain of $276 million, compared with a net non-operating charge of $80 million a year ago. Fair value accounting effects in the first quarter had an unfavourable impact of $18 million, compared with an unfavourable impact of $60 million in the same period of 2013.

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 $4,401 million, compared with $5,702 million for the same period in 2013. The result for the first quarter reflected higher costs, predominantly exploration write-offs and depreciation, depletion and amortization, lower liquids realizations and lower production, partly offset by strong gas marketing and trading results and higher gas realizations.

Production

Reported production for the quarter was 2,131mboe/d, 8.5% lower than the first quarter of 2013. After adjusting for the effects of the Abu Dhabi onshore concession expiry in January, divestments and entitlement impacts in our production-sharing agreements (PSAs), underlying production was slightly lower. With new major project volumes in the North Sea, Angola and the Gulf of Mexico, we have grown our total underlying production in higher-margin areas.

Key events

During the first quarter, three major projects started up: the Chirag Oil project (BP 35.8%) in Azerbaijan and the Na Kika Phase 3 (BP 50%) and Mars B (BP 28.5%) projects in the Gulf of Mexico. We have now also commenced production from the Atlantis North expansion Phase 2 project, also in the Gulf of Mexico.

In March, the Shah Deniz and South Caucasus Pipeline consortia announced the award of further key contracts for the development of the Shah Deniz Stage 2 and South Caucasus Pipeline expansion projects. The contracts, covering both project management services and construction, follow the final investment decisions made in December 2013.

Also in March, we announced that in the US lower 48 – which excludes our Alaska business – we intend to create a separate BP business to manage our onshore oil and gas assets. We believe this will help unlock the significant value associated with our extensive resource position there.

In the recent Gulf of Mexico lease sales, BP was the apparent high bidder on 24 out of 31 blocks, with final award subject to regulatory approval.

On 22 April, we announced that we have agreed to sell interests in four BP-operated oilfields on the North Slope of Alaska to Hilcorp. The sale agreement includes all of BP’s interests in the Endicott and Northstar oilfields and a 50% interest in each of the Liberty and Milne Point fields, together with BP’s interests in the oil and gas pipelines associated with these fields. The sale, for $1.25 billion plus an additional carry of up to $250 million if the Liberty field is developed, will be subject to state and federal regulatory approval and is expected to be complete by the end of the year. See Note 3 on page 23 for further information.

Outlook

Looking ahead, we expect second quarter 2014 reported production to be lower than the first quarter primarily driven by planned major turnaround activity, mainly in the higher-margin North Sea and Gulf of Mexico regions. We expect the turnaround impact on production to be slightly less than the impact experienced in the second quarter of 2013.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 35.

Upstream


	First			First
	quarter			quarter
$ million	2014			2013
Underlying RC profit before interest and tax_(a)
US		731			954
Non-US		3,670			4,748

		4,401			5,702

Non-operating items
US		(59	)		(6	)
Non-US		335			(74	)

		276			(80	)

Fair value accounting effects
US		(49	)		(40	)
Non-US		31			(20	)

		(18	)		(60	)

RC profit before interest and tax_(a)
US		623			908
Non-US		4,036			4,654

		4,659			5,562

Exploration expense
US_(b)		659			80
Non-US		289			242

		948			322

Production (net of royalties)_(c)
Liquids* (mb/d)
US		396			366
Europe		106			115
Rest of World		582			712

		1,085			1,193

Of which equity-accounted entities		182			298

Natural gas (mmcf/d)
US		1,478			1,532
Europe		199			329
Rest of World		4,390			4,733

		6,067			6,593

Of which equity-accounted entities		449			398

Total hydrocarbons* (mboe/d)
US		651			631
Europe		140			171
Rest of World		1,339			1,528

		2,131			2,330

Of which equity-accounted entities		260			367

Average realizations_(d)
Total liquids ($/bbl)		97.16			103.11
Natural gas ($/mcf)		6.20			5.52
Total hydrocarbons ($/boe)		66.16			65.11

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

(b)

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

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

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

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

Downstream


	First			First
	quarter			quarter
$ million	2014			2013
Profit (loss) before interest and tax		871			2,055
Inventory holding (gains) losses*		(77	)		(408	)

RC profit (loss) before interest and tax		794			1,647
Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*		217			(6	)

Underlying RC profit before interest and tax*_(a)		1,011			1,641

(a)	See page 9 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 $794 million for the first quarter, compared with $1,647 million for the same period in 2013.

The first-quarter result included a net non-operating charge of $278 million, compared with a net non-operating gain of $19 million for the same period in 2013 (see pages 9 and 28 for further information on non-operating items). The charge for the quarter principally reflects an impairment relating to the announced cessation of operations at Bulwer refinery in Australia. Fair value accounting effects had a favourable impact of $61 million for the first quarter, compared with an unfavourable impact of $13 million in the same period of 2013.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $1,011 million, compared with $1,641 million for the same period in 2013, with the reduction in profit mainly arising in the fuels business.

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

Fuels business

The fuels business delivered an underlying replacement cost profit before interest and tax of $700 million for the first quarter, compared with $1,237 million for the same period in 2013. The lower result is principally due to a reduction in refining margins, including compression in heavy Canadian crude differentials relative to the very high levels seen in the same period of last year. This was partially offset by the return to operations of the largest crude unit at the Whiting refinery which had a planned outage in the same period of 2013 as part of the modernization project at the facility. Solomon availability was strong at 95%, though slightly below the level achieved in the first quarter of 2013. In addition, the supply and trading result was strong for the first quarter, similar to levels achieved in the same period of 2013. Heavy crude processing continues to increase at Whiting, and reached about 200,000 barrels per day at the end of the quarter, and is expected to reach about 280,000 barrels per day during the second quarter. The positive impact on the second quarter is expected to be partially offset by an increase in turnaround activity across the portfolio.

Lubricants business

The lubricants business delivered an underlying replacement cost profit before interest and tax of $307 million in the first quarter, compared with $345 million in the same period last year, with the difference being primarily due to exchange rate effects in the Indian rupee, the pound sterling and the South African rand. This performance reflects continued delivery of our strategy focused on quality premium lubricants, leading brands and high growth markets.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $4 million in the first quarter, compared with $59 million in the same period of 2013. We acquired the remaining 50% joint venture interests in our purified terephthalic acid (PTA) plant in Indonesia, consistent with the strategy of growing our PTA business in chosen markets. The March shut-down of the SECCO site in China for a two-month turnaround negatively impacted the results. The petrochemicals environment continues to be challenging with excess supply affecting product margins, particularly in the aromatics business.

Outlook

In the second quarter we expect seasonally stronger refining margins supported by low product stocks, particularly in the US, and increased global turnaround activity. Low petrochemicals margins are expected to continue.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 35.

Downstream


	First			First
	quarter			quarter
$ million	2014			2013
Underlying RC profit (loss) before interest and tax - by region
US		412			750
Non-US		599			891

		1,011			1,641

Non-operating items
US		(1	)		28
Non-US		(277	)		(9	)

		(278	)		19

Fair value accounting effects
US		91			(65	)
Non-US		(30	)		52

		61			(13	)

RC profit (loss) before interest and tax
US		502			713
Non-US		292			934

		794			1,647

Underlying RC profit (loss) before interest and tax - by business_(a)(b)
Fuels		700			1,237
Lubricants		307			345
Petrochemicals		4			59

		1,011			1,641

Non-operating items and fair value accounting effects_(c)
Fuels		(217	)		11
Lubricants		—			(5	)
Petrochemicals		—			—

		(217	)		6

RC profit (loss) before interest and tax_(a)(b)
Fuels		483			1,248
Lubricants		307			340
Petrochemicals		4			59

		794			1,647

BP average refining marker margin (RMM)* ($/bbl)		13.3			17.4

Refinery throughputs (mb/d)
US		614			937
Europe		798			806
Rest of World		308			322

		1,720			2,065

Refining availability* (%)		95.0			95.1

Marketing sales of refined products (mb/d)
US		1,120			1,402
Europe		1,139			1,158
Rest of World		545			557

		2,804			3,117
Trading/supply sales of refined products		2,416			2,308

Total sales volumes of refined products		5,220			5,425

Petrochemicals production (kte)
US		1,071			1,076
Europe		972			1,014
Rest of World		1,422			1,417

		3,465			3,507

(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


	First			First
	quarter			quarter
$ million	2014_(a)			2013_(b)
Profit before interest and tax_(c)		549			85
Inventory holding (gains) losses*		(31	)		—

RC profit before interest and tax		518			85
Net charge (credit) for non-operating items*		(247	)		—

Underlying RC profit before interest and tax*		271			85

Replacement cost profit before interest and tax for the first quarter was $518 million, compared with $85 million for the same period in 2013. First quarter 2013 reflected BP’s share of Rosneft’s earnings from 21 March 2013, the date of completion of the further investment in Rosneft, to 31 March 2013, as estimated by BP.

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

After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the first quarter was $271 million, compared with $85 million in the first quarter of 2013. This reflected the comparison of a full quarter to the 11 days reported in the same period last year, partly offset by the impact of the weakening rouble.


	First		First
	quarter		quarter
	2014_(a)		2013_(d)
Production (net of royalties) (BP share)
Liquids* (mb/d)		827		102
Natural gas (mmcf/d)		987		89
Total hydrocarbons* (mboe/d)		997		117

(a)

The operational and financial information of the Rosneft segment for the first quarter 2014 is based on preliminary operational and financial results of Rosneft for the period ended 31 March 2014. Actual results may differ from these amounts. Any adjustments to this operational and financial information based on BP’s review of actual reported results will be reflected in BP’s second quarter results.

(b)	First quarter 2013 was BP’s estimate based on Rosneft and TNK-BP historical financial data, adjusted for oil and gas prices and exchange rates.

(c)

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.

(d)	First quarter 2013 was based on BP’s estimate of production for the period 21-31 March, averaged over the full quarter.

Other businesses and corporate


	First			First
	quarter			quarter
$ million	2014			2013
Profit (loss) before interest and tax		(497	)		(467	)
Inventory holding (gains) losses*		—			—

RC profit (loss) before interest and tax		(497	)		(467	)
Net charge (credit) for non-operating items*		8			6

Underlying RC profit (loss) before interest and tax*		(489	)		(461	)

Underlying RC profit (loss) before interest and tax
US		(99	)		(121	)
Non-US		(390	)		(340	)

		(489	)		(461	)

Non-operating items
US		(1	)		(4	)
Non-US		(7	)		(2	)

		(8	)		(6	)

RC profit (loss) before interest and tax
US		(100	)		(125	)
Non-US		(397	)		(342	)

		(497	)		(467	)

Other businesses and corporate comprises the Alternative Energy business, Shipping, Treasury (which includes interest income on the group’s cash and cash equivalents), and corporate activities including centralized functions.

Financial results

The replacement cost loss before interest and tax for the first quarter was $497 million, compared with $467 million for the same period in 2013.

The first-quarter result included a net non-operating charge of $8 million, compared with a net charge of $6 million for the same period in 2013.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the first quarter was $489 million, compared with $461 million for the same period last year.

Alternative Energy

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. In the UK, the Vivergo joint venture (BP 47%) had first-quarter 2014 ethanol production of 17 million litres (36 million litres gross).

Wind

Net wind generation capacity*_(a) was 1,590MW (2,619MW) at 31 March 2014, the same level as at 31 March 2013. BP’s net share of wind generation for the first quarter was 1,292GWh (2,221GWh gross), compared with 1,144GWh (2,063GWh gross) in the same period of 2013.

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

Gulf of Mexico oil spill

On 15 April 2014 the US. Coast Guard ended patrols and operations on the final three shoreline miles in Louisiana. The Coast Guard has now transitioned all shoreline areas to the National Response Center process and has indicated that if oil is later discovered in a shoreline segment where removal actions have been deemed complete, it will follow long-standing response protocols established under the law and contact whoever it believes is the responsible party or parties.

BP also continues to facilitate economic restoration through claims processes, and environmental restoration through natural resource damage assessment and early restoration projects relating to the Gulf of Mexico oil spill.

Financial update

The replacement cost loss before interest and tax for the first quarter was $29 million, compared with a $22 million loss for the same period last year. The first-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $42.7 billion.

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities in Note 2 on page 20, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed, as further described under Risk factors on pages 51-55 of BP Annual Report and Form 20-F 2013.

Trust update

During the first quarter, $173 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $149 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $24 million for natural resource damage assessment and early restoration. In addition, $19 million was paid to claimants from the seafood compensation fund, for which the related provision and reimbursement asset had been previously derecognized upon funding of the QSF. At 31 March 2014, the aggregate cash balances in the Trust and the QSFs amounted to $6.6 billion, including $1.2 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration projects.

As at 31 March 2014, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, amounted to $19.3 billion. No amount is provided for business economic loss claims not yet received, processed, and paid by the DHCSSP. See Note 2 on page 18 and Legal proceedings on page 33 for further details.

Legal proceedings

The federal district court in New Orleans (the District Court) scheduled the penalty phase (the Penalty Phase) in the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 to commence on 20 January 2015. In the Penalty Phase, the District Court will determine the amount of civil penalties arising under the Clean Water Act based on the court’s rulings as to the presence of negligence, gross negligence or wilful misconduct in the first two phases of the trial (Phases 1 and 2), the court’s rulings as to quantification of discharge in Phase 2 and the application of the penalty factors under the Clean Water Act. BP does not know when the District Court will rule on the issues presented in Phase 1 or Phase 2 and the court could issue its decision at any time. For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013.

On 3 March 2014, the US Court of Appeals for the Fifth Circuit (in a 2 to 1 decision) affirmed the District Court’s ruling that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement and denied BP’s motion for a permanent injunction. On 17 March 2014, BP filed a petition that all the active judges of the Fifth Circuit review the decision. Under the terms of the Fifth Circuit’s ruling, the District Court injunction temporarily suspending issuance of final determination notices and payments of business economic loss claims will be lifted when the matter is transferred back to the District Court, the timing of which is subject to the outcome of BP’s 17 March 2014 petition.

The Medical Benefits Class Action Settlement provides for claims to be paid to qualifying class members from the Settlement Agreement’s effective date. Following the resolution of all appeals relating to this settlement, the agreement’s effective date was 12 February 2014. The deadline for submitting claims under the settlement is one year from the effective date.

On 13 March 2014, BP p.l.c., BP Exploration & Production (BPXP), and all other temporarily suspended BP entities entered into an administrative agreement with the US Environmental Protection Agency (EPA) resolving all issues related to suspension or debarment arising from the Deepwater Horizon incident. The administrative agreement restores the eligibility of BP entities to enter into new contracts or leases with the United States Government. Under the terms and conditions of the administrative agreement, which will apply for five years, BP has agreed to a set of safety and operations, ethics and compliance and corporate governance requirements. As a result of the agreement, on 19 March 2014, BP dismissed its lawsuit against the EPA filed in the Southern District of Texas.

For further details, see Legal proceedings on page 33.

Group income statement


	First			First
	quarter			quarter
$ million	2014			2013
Sales and other operating revenues (Note 5)		91,710			94,107
Earnings from joint ventures – after interest and tax		115			125
Earnings from associates – after interest and tax		783			284
Interest and other income		331			157
Gains on sale of businesses and fixed assets		49			12,541

Total revenues and other income		92,988			107,214
Purchases		71,468			71,661
Production and manufacturing expenses		6,831			6,868
Production and similar taxes (Note 6)		986			1,995
Depreciation, depletion and amortization		3,590			3,197
Impairment and losses on sale of businesses and fixed assets		426			110
Exploration expense		948			322
Distribution and administration expenses		3,200			2,954
Fair value gain on embedded derivatives		(98	)		(31	)

Profit before interest and taxation		5,637			20,138
Finance costs		287			282
Net finance expense relating to pensions and other post-retirement benefits		80			122

Profit before taxation		5,270			19,734
Taxation		1,651			2,792

Profit for the period		3,619			16,942

Attributable to
BP shareholders		3,528			16,863
Non-controlling interests		91			79

		3,619			16,942

Earnings per share (Note 7)
Profit for the period attributable to BP shareholders
Per ordinary share (cents)
Basic		19.09			88.07
Diluted		18.97			87.61
Per ADS (dollars)
Basic		1.15			5.28
Diluted		1.14			5.26

Group statement of comprehensive income


	First			First
	quarter			quarter
$ million	2014			2013
Profit for the period		3,619			16,942

Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences		(913	)		(587	)
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets		—			—
Available-for-sale investments marked to market		(3	)		(172	)
Available-for-sale investments reclassified to the income statement		—			(523	)
Cash flow hedges marked to market_(a)		23			(2,141	)
Cash flow hedges reclassified to the income statement		(20	)		—
Cash flow hedges reclassified to the balance sheet		(1	)		3
Share of items relating to equity-accounted entities, net of tax		(73	)		33
Income tax relating to items that may be reclassified		—			169

		(987	)		(3,218	)

Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset		(936	)		(50	)
Share of items relating to equity-accounted entities, net of tax		5			—
Income tax relating to items that will not be reclassified		294			1

		(637	)		(49	)

Other comprehensive income		(1,624	)		(3,267	)

Total comprehensive income		1,995			13,675

Attributable to
BP shareholders		1,903			13,600
Non-controlling interests		92			75

		1,995			13,675

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

Group statement of changes in equity


	BP
	shareholders’			Non-controlling			Total
$ million	equity			interests			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


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

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

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

Group balance sheet


	31 March		31 December
$ million	2014		2013
Non-current assets
Property, plant and equipment		133,199		133,690
Goodwill		12,168		12,181
Intangible assets		21,696		22,039
Investments in joint ventures		9,136		9,199
Investments in associates		16,245		16,636
Other investments		1,357		1,565

Fixed assets		193,801		195,310
Loans		682		763
Trade and other receivables		5,953		5,985
Derivative financial instruments		3,395		3,509
Prepayments		965		922
Deferred tax assets		1,184		985
Defined benefit pension plan surpluses		706		1,376

		206,686		208,850

Current assets
Loans		410		216
Inventories		28,843		29,231
Trade and other receivables		40,092		39,831
Derivative financial instruments		2,886		2,675
Prepayments		1,554		1,388
Current tax receivable		523		512
Other investments		428		467
Cash and cash equivalents		27,358		22,520

		102,094		96,840
Assets classified as held for sale (Note 3)		1,494		—

		103,588		96,840

Total assets		310,274		305,690

Current liabilities
Trade and other payables		49,637		47,159
Derivative financial instruments		2,280		2,322
Accruals		6,770		8,960
Finance debt		8,663		7,381
Current tax payable		2,194		1,945
Provisions		4,352		5,045

		73,896		72,812
Liabilities directly associated with assets classified as held for sale (Note 3)		374		—

		74,270		72,812

Non-current liabilities
Other payables		3,655		4,756
Derivative financial instruments		1,984		2,225
Accruals		746		547
Finance debt		44,586		40,811
Deferred tax liabilities		17,907		17,439
Provisions		26,939		26,915
Defined benefit pension plan and other post-retirement benefit plan deficits		9,987		9,778

		105,804		102,471

Total liabilities		180,074		175,283

Net assets		130,200		130,407

Equity
BP shareholders’ equity		129,080		129,302
Non-controlling interests		1,120		1,105

		130,200		130,407

Condensed group cash flow statement


	First			First
	quarter			quarter
$ million	2014			2013
Operating activities
Profit before taxation		5,270			19,734
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		4,422			3,369
Impairment and (gain) loss on sale of businesses and fixed assets		377			(12,431	)
Earnings from equity-accounted entities, less dividends received		(684	)		(200	)
Net charge for interest and other finance expense, less net interest paid		170			172
Share-based payments		106			46
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(102	)		(284	)
Net charge for provisions, less payments		(193	)		197
Movements in inventories and other current and non-current assets and liabilities_(a)		(315	)		(5,345	)
Income taxes paid		(820	)		(1,291	)

Net cash provided by operating activities		8,231			3,967

Investing activities
Capital expenditure		(5,891	)		(5,729	)
Acquisitions, net of cash acquired		(10	)		—
Investment in joint ventures		(33	)		(51	)
Investment in associates		(88	)		(4,883	)
Proceeds from disposal of fixed assets		978			16,780
Proceeds from disposal of businesses, net of cash disposed		26			1,501
Proceeds from loan repayments		17			22

Net cash provided by (used in) investing activities		(5,001	)		7,640

Financing activities
Net issue (repurchase) of shares		(1,726	)		55
Proceeds from long-term financing		5,979			63
Repayments of long-term financing		(1,237	)		(288	)
Net increase (decrease) in short-term debt		77			(1,491	)
Net increase (decrease) in non-controlling interests		—			—
Dividends paid – BP shareholders		(1,427	)		(1,622	)
– non-controlling interests		(13	)		(31	)

Net cash provided by (used in) financing activities		1,653			(3,314	)

Currency translation differences relating to cash and cash equivalents		(45	)		(249	)

Increase (decrease) in cash and cash equivalents		4,838			8,044

Cash and cash equivalents at beginning of period		22,520			19,635
Cash and cash equivalents at end of period		27,358			27,679


(a) Includes

Inventory holding (gains) losses		(74	)		(407	)
Fair value gain on embedded derivatives		(98	)		(31	)
Movements related to Gulf of Mexico oil spill response		(578	)		(828	)

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

Notes

1.	Basis of preparation

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

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2013 included in the BP Annual Report and Form 20-F 2013.

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

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2014, which do not differ significantly from those used in BP Annual Report and Form 20-F 2013.

2.	Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur various costs and has also recognized liabilities for future costs. The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2013 – Financial statements – Note 2 and Legal proceedings on pages 257-265 and from page 33 of this report.

The group income statement includes a pre-tax charge of $39 million for the first quarter in relation to the Gulf of Mexico oil spill. The first-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $42,715 million.

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information, including developments in relation to the interpretation of business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement, see Provisions below.

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further described under Risk factors on pages 51-55 of BP Annual Report and Form 20-F 2013.

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.


	First			First
	quarter			quarter
$ million	2014			2013
Income statement
Production and manufacturing expenses		29			22

Profit (loss) before interest and taxation		(29	)		(22	)
Finance costs		10			10

Profit (loss) before taxation		(39	)		(32	)
Taxation		10			(5	)

Profit (loss) for the period		(29	)		(37	)

Notes

2.	Gulf of Mexico oil spill (continued)


$ million	31 March 2014			31 December 2013
Balance sheet
Current assets
Trade and other receivables		1,931			2,457
Current liabilities
Trade and other payables		(887	)		(1,030	)
Provisions		(2,375	)		(2,951	)

Net current assets (liabilities)		(1,331	)		(1,524	)

Non-current assets
Other receivables		2,799			2,442
Non-current liabilities
Other payables		(2,404	)		(2,986	)
Accruals		(161	)		—
Provisions		(6,701	)		(6,395	)
Deferred tax		2,638			2,748

Net non-current assets (liabilities)		(3,829	)		(4,191	)

Net assets (liabilities)		(5,160	)		(5,715	)


	First			First
	quarter			quarter
$ million	2014			2013
Cash flow statement - Operating activities
Profit (loss) before taxation		(39	)		(32	)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Net charge for interest and other finance expense, less net interest paid		10			10
Net charge for provisions, less payments		(97	)		304
Movements in inventories and other current and non-current assets and liabilities		(578	)		(828	)

Pre-tax cash flows		(704	)		(546	)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $584 million in the first quarter of 2014. For the first quarter of 2013, the amount was an outflow of $331 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 the fourth quarter of 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income statement. An asset has been recognized representing BP’s right to receive reimbursement from the trust fund. This is the portion of the estimated future expenditure provided for that will be settled by payments from the trust fund. At 31 March 2014, $4,679 million of the provisions, and $51 million of the payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements.

Notes

2.	Gulf of Mexico oil spill (continued)

The table below shows movements in the reimbursement asset during the period to 31 March 2014. For more information about the movement in provisions for items covered by the trust fund, see Provisions below. The amount of the reimbursement asset at 31 March 2014 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund –see below.


	First
	quarter
$ million	2014
Opening balance		4,899
Net increase (decrease) in provision for items covered by the trust fund		4
Amounts paid directly by the trust fund		(173	)

At 31 March 2014		4,730

Of which – current		1,931
– non-current		2,799

Any increases in estimated future expenditure that will be covered by the trust fund (up to an aggregate of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 31 March 2014, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,342 million. Thus, a further $658 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. Additional liabilities in excess of this amount regarding claims under the Oil Pollution Act of 1990 (OPA 90), claims that are currently administered by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), or otherwise, including the various claims described in Legal proceedings on page 33 of this report and on pages 257-265 of BP Annual Report and Form 20-F 2013, would be expensed to the income statement. Information on those items that currently cannot be estimated reliably is provided under Provisions and contingent liabilities below.

As at 31 March 2014, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $6.6 billion, including $1.2 billion remaining in the seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. Should the cash balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.

(b) Provisions and contingent liabilities

BP has recorded certain provisions and disclosed certain contingent liabilities as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 2013 – Financial statements – Note 2.

Provisions

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

Litigation

Clean

and

Water Act

$ million

Environmental

claims

penalties

Total

At 1 January 2014

1,679

4,157

3,510

9,346

Increase in provision – items covered by the trust fund

—

Utilization – paid by BP

(28

)

(73

)

—

(101

)

– paid by the trust fund

(24

)

(149

)

—

(173

)

At 31 March 2014

1,627

3,939

3,510

9,076

Of which – current

521

1,854

—

2,375

– non-current

1,106

2,085

3,510

6,701

Notes

2	Gulf of Mexico oil spill (continued)

Environmental

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

Spill response provisions are now included within environmental provisions as they are no longer individually significant.

Litigation and claims

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

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic loss claims. As disclosed in BP Annual Report and Form 20-F 2013, as part of its monitoring of payments made by the DHCSSP, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. See Legal proceedings on page 33 of this report and pages 257-265 of BP Annual Report and Form 20-F 2013 for further details on the settlements with the PSC and related matters.

Until the uncertainties described below are resolved, management is unable to estimate reliably the value and volume of future business economic loss claims and whether, and to what extent, received or processed but unpaid business economic loss claims will be paid. Firstly, the inherent uncertainty as to the interpretation of the EPD Settlement Agreement in respect of matching and causation issues will continue until more detailed matching requirements are finalized and approved and are implemented by the DHCSSP; the issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal; and the impact of any new policies and procedures in response to these issues on the value and volume of business economic loss claims becomes clear. Furthermore, the Fifth Circuit has yet to decide whether to grant the petitions seeking review of its decision affirming approval of the EPD Settlement and, if granted, whether to alter its decision in that appeal. Secondly, uncertainty arises from the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends – the number of business economic loss claims received and the average amounts paid in respect of such claims prior to the district court’s injunction were higher than previously assumed by BP. This inability to extrapolate any reliable trends may or may not continue once the uncertainties concerning the interpretation of the EPD Settlement Agreement described above have been resolved. Thirdly, there is uncertainty as to the ultimate deadline for filing business economic loss claims, which is dependent on the date on which all relevant appeals are concluded. Management believes, therefore, that no reliable estimate can currently be made of any business economic loss claims not yet received, processed and paid by the DHCSSP. A provision for business economic loss claims will be established when a reliable estimate can be made of the liability.

The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated is $9.2 billion. The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.2 billion because the current estimate does not reflect business economic loss claims not yet received, processed and paid. The DHCSSP has issued eligibility notices, disputed by BP, in respect of business economic loss claims of $1,017 million which have not yet been paid. These claims will be re-assessed using the new matching requirements when these are finalized and approved. The claims administrator’s proposed matching policy is currently under consideration by the District Court. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received.

The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP’s current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and Contingent liabilities below for further details.

Notes

2	Gulf of Mexico oil spill (continued)

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 33 and the outcomes of any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise.

Clean Water Act penalties

A provision was recognized in 2010 for the estimated civil penalties for strict liability under the Clean Water Act, which are based on a specified range per barrel of oil released. No adjustments have been made subsequently to this estimate. The penalty rate per barrel used to calculate the provision is based upon the company’s conclusion, amongst other things, that it did not act with gross negligence or engage in wilful misconduct. The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court in the federal multi-district litigation proceedings in New Orleans (MDL 2179) as to negligence, gross negligence or wilful misconduct, the volume of oil spilled and the application of statutory penalty factors. The trial court could issue its decision on the first two phases of the trial at any time and has scheduled a trial on the subsequent phase regarding the application of statutory penalty factors starting on 20 January 2015. The court has wide discretion in its determination as to whether a defendant’s conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors. See BP Annual Report and Form 20-F 2013 – Financial statements – Note 2 for further details and Legal Proceedings on pages 257-265 and on page 33 of this report.

Provision movements and analysis of income statement charge

An increase in the provision for the estimated cost of the settlement with the PSC of $4 million for the first quarter was recognized. The total charge in the income statement is analysed in the table below.


$ million	First quarter 2014			Cumulative since the incident
Environmental costs		—			3,031
Spill response costs		—			14,304
Litigation and claims costs		4			25,647
Clean Water Act penalties – amount provided		—			3,510
Other costs charged directly to the income statement		29			1,172
Recoveries credited to the income statement		—			(5,681	)
Charge (credit) related to the trust fund		(4	)		521
Other costs of the trust fund		—			8

Loss before interest and taxation		29			42,512
Finance costs – related to the trust funds		—			137
Finance costs – not related to the trust funds		10			66

Loss before taxation		39			42,715

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

Contingent liabilities

BP considers that it is not possible, at this time, to measure reliably other obligations arising from the incident, namely any obligation in relation to natural resource damages claims or associated legal costs (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings on page 33 of this report and pages 257-265 of BP Annual Report and Form 20-F 2013, the cost of business economic loss claims under the PSC settlement not yet received, processed and paid by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90, any obligation that may arise from securities-related litigation, and any obligation in relation to other potential private or governmental litigation, fines or penalties (except for the Clean Water Act civil penalty claims and State and Local Claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment.

The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty.

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

Notes

3.	Non-current assets held for sale

On 22 April 2014, BP announced that it had reached agreement to sell its interests in the Northstar and Endicott oilfields and 50% of its interests in each of the Milne Point and Liberty oilfields on the North Slope of Alaska to Hilcorp Alaska LLC, a subsidiary of Hilcorp Energy for $1.25 billion plus an additional carry of up to $250 million if the Liberty field is developed. The sale also includes BP’s interests in the oil and gas pipelines associated with these fields. These assets, amounting to $1,494 million, and associated liabilities of $374 million, have been classified as held for sale in the group balance sheet at 31 March 2014. The sale is expected to be complete by the end of the year, subject to state and federal regulatory approval.

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


$ million	First quarter 2014			First quarter 2013
Upstream		4,659			5,562
Downstream		794			1,647
TNK-BP_(a)		—			12,500
Rosneft_(b)		518			85
Other businesses and corporate		(497	)		(467	)

		5,474			19,327
Gulf of Mexico oil spill response		(29	)		(22	)
Consolidation adjustment – UPII*		90			427

RC profit before interest and tax		5,535			19,732
Inventory holding gains (losses)*
Upstream		(6	)		(2	)
Downstream		77			408
Rosneft (net of tax)		31			—

Profit before interest and tax		5,637			20,138
Finance costs		287			282
Net finance expense relating to pensions and other post-retirement benefits		80			122

Profit before taxation		5,270			19,734

RC profit before interest and tax*_(c)
US		1,125			1,727
Non-US		4,410			18,005

		5,535			19,732

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

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

^(c)	A minor amendment has been made to the analysis by region for the comparative period.

Notes

5.	Sales and other operating revenues


$ million	First quarter 2014		First quarter 2013
By segment
Upstream		17,006		18,218
Downstream		84,298		86,784
Other businesses and corporate		431		420

		101,735		105,422

Less: sales and other operating revenues between segments
Upstream		9,217		10,861
Downstream		562		240
Other businesses and corporate		246		214

		10,025		11,315

Third party sales and other operating revenues
Upstream		7,789		7,357
Downstream		83,736		86,544
Other businesses and corporate		185		206

Total third party sales and other operating revenues		91,710		94,107

By geographical area_(a)
US		34,825		35,195
Non-US		66,305		68,367

		101,130		103,562
Less: sales and other operating revenues between areas		9,420		9,455

		91,710		94,107

^(a)	A minor amendment has been made to the analysis by region for the comparative period.

6.	Production and similar taxes


$ million	First quarter 2014		First quarter 2013
US		279		372
Non-US		707		1,623

		986		1,995

Notes

7.	Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 245 million ordinary shares at a cost of $1,968 million as part of the share repurchase programme announced on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period. The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

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


	First		First
	quarter		quarter
$ million	2014		2013
Results for the period
Profit for the period attributable to BP shareholders		3,528		16,863
Less: preference dividend		—		—

Profit attributable to BP ordinary shareholders		3,528		16,863

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding		18,480,826		19,147,437
ADS equivalent		3,080,137		3,191,239

Weighted average number of shares outstanding used to calculate diluted earnings per share		18,594,518		19,247,671
ADS equivalent		3,099,086		3,207,945

Shares in issue at period-end		18,457,009		19,153,586
ADS equivalent		3,076,168		3,192,264

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

8.	Dividends

Dividends payable

BP today announced a dividend of 9.75 cents per ordinary share expected to be paid in June. The corresponding amount in sterling will be announced on 9 June 2014, calculated based on the average of the market exchange rates for the four dealing days commencing on 3 June 2014. Holders of American Depositary Shares (ADSs) will receive $0.585 per ADS. The dividend is due to be paid on 20 June 2014 to shareholders and ADS holders on the register on 9 May 2014. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the 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		First
	quarter		quarter
	2014		2013
Dividends paid per ordinary share
cents		9.500		9.000
pence		5.707		6.001
Dividends paid per ADS (cents)		57.00		54.00

Scrip dividends
Number of shares issued (millions)		40.2		14.5
Value of shares issued ($ million)		326		101

Notes

Net debt*

Net debt ratio*


	First			First
	quarter			quarter
$ million	2014			2013
Gross debt		53,249			46,425
Fair value (asset) liability of hedges related to finance debt		(633	)		(1,083	)

		52,616			45,342
Less: cash and cash equivalents		27,358			27,679

Net debt_(a)		25,258			17,663

Equity		130,200			131,085
Net debt ratio_(a)		16.2	%		11.9	%

Analysis of changes in net debt


	First			First
	quarter			quarter
$ million	2014			2013
Opening balance
Finance debt		48,192			48,800
Fair value (asset) liability of hedges related to finance debt		(477	)		(1,700	)
Less: cash and cash equivalents		22,520			19,635

Opening net debt		25,195			27,465

Closing balance
Finance debt		53,249			46,425
Fair value (asset) liability of hedges related to finance debt		(633	)		(1,083	)
Less: cash and cash equivalents		27,358			27,679

Closing net debt		25,258			17,663

Decrease (increase) in net debt		(63	)		9,802

Movement in cash and cash equivalents (excluding exchange adjustments)		4,883			8,293
Net cash outflow (inflow) from financing (excluding share capital and dividends)		(4,819	)		1,716
Other movements		(118	)		(126	)

Movement in net debt before exchange effects		(54	)		9,883
Exchange adjustments		(9	)		(81	)

Decrease (increase) in net debt		(63	)		9,802

(a)	Net debt and net debt ratio are non-GAAP measures.

10.

Inventory valuation

A provision of $410 million was held at 31 March 2014 ($194 million at 31 March 2013) to write inventories down to their net realizable value. The net movement charged to the income statement during the first quarter 2014 was $88 million (first quarter 2013 was a charge of $70 million).

11.

Statutory accounts

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

Additional non-GAAP and other information

Capital expenditure and acquisitions


	First		First
	quarter		quarter
$ million	2014		2013
By segment
Upstream_(a)
US		1,698		1,530
Non-US_(b)		3,699		2,966

		5,397		4,496

Downstream
US		206		839
Non-US		344		215

		550		1,054

Rosneft
Non-US_(c)		—		11,941

		—		11,941

Other businesses and corporate
US		3		24
Non-US		135		136

		138		160

		6,085		17,651

By geographical area_(a)
US		1,907		2,393
Non-US_(b)_(c)		4,178		15,258

		6,085		17,651

Included above:
Acquisitions and asset exchanges		236		—
Other inorganic capital expenditure_(b)(c)		442		11,941

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

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

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

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

Additional non-GAAP and other information (continued)

Non-operating items*


	First			First
	quarter			quarter
$ million	2014			2013
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets		(116	)		(102	)
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		—			—
Fair value gain (loss) on embedded derivatives		98			31
Other		294			(9	)

		276			(80	)

Downstream
Impairment and gain (loss) on sale of businesses and fixed assets		(255	)		34
Environmental and other provisions		—			(9	)
Restructuring, integration and rationalization costs		(1	)		(2	)
Fair value gain (loss) on embedded derivatives		—			—
Other		(22	)		(4	)

		(278	)		19

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

		—			12,500

Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets		247			—
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		—			—
Fair value gain (loss) on embedded derivatives		—			—
Other		—			—

		247			—

Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets		(6	)		(1	)
Environmental and other provisions		—			—
Restructuring, integration and rationalization costs		(1	)		(2	)
Fair value gain (loss) on embedded derivatives		—			—
Other		(1	)		(3	)

		(8	)		(6	)

Gulf of Mexico oil spill response		(29	)		(22	)

Total before interest and taxation		208			12,411
Finance costs_(a)		(10	)		(10	)

Total before taxation		198			12,401
Taxation credit (charge)_(b)		26			23

Total after taxation for period		224			12,424

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

(b)

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

Additional non-GAAP and other information (continued)

Non-GAAP information on fair value accounting effects


	First			First
	quarter			quarter
$ million	2014			2013
Favourable (unfavourable) impact relative to management’s measure of performance
Upstream		(18	)		(60	)
Downstream		61			(13	)

		43			(73	)
Taxation credit (charge)_(a)		(17	)		30

		26			(43	)

(a)

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

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

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

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

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

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


	First			First
	quarter			quarter
$ million	2014			2013
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects		4,677			5,622
Impact of fair value accounting effects		(18	)		(60	)

Replacement cost profit before interest and tax		4,659			5,562

Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects		733			1,660
Impact of fair value accounting effects		61			(13	)

Replacement cost profit (loss) before interest and tax		794			1,647

Total group
Profit before interest and tax adjusted for fair value accounting effects		5,594			20,211
Impact of fair value accounting effects		43			(73	)

Profit before interest and tax		5,637			20,138

Additional non-GAAP and other information (continued)

Realizations and marker prices


	First		First
	quarter		quarter
	2014		2013
Average realizations_(a)
Liquids* ($/bbl)
US		89.81		96.11
Europe		104.10		107.15
Rest of World		102.69		108.04
BP Average		97.16		103.11

Natural gas ($/mcf)
US		4.62		2.92
Europe		9.76		9.78
Rest of World		6.62		6.12
BP Average		6.20		5.52

Total hydrocarbons* ($/boe)
US		65.70		62.94
Europe		92.63		90.93
Rest of World		62.76		62.22
BP Average		66.16		65.11

Average oil marker prices ($/bbl)
Brent		108.21		112.57
West Texas Intermediate		98.69		94.29
Alaska North Slope		105.73		110.97
Mars		100.83		109.10
Urals (NWE – cif)		106.24		110.53
Russian domestic oil		54.55		55.24

Average natural gas marker prices
Henry Hub gas price ($/mmBtu)_(b)		4.95		3.34
UK Gas – National Balancing Point (p/therm)		60.28		73.83

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

(b)	Henry Hub First of Month Index.

Exchange rates


	First		First
	quarter		quarter
	2014		2013
US dollar/sterling average rate for the period		1.65		1.55
US dollar/sterling period-end rate		1.66		1.51
US dollar/euro average rate for the period		1.37		1.32
US dollar/euro period-end rate		1.38		1.28
Rouble/US dollar average rate for the period		35.07		30.40
Rouble/US dollar period-end rate		35.69		31.06

Glossary

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

Fair value accounting effects are non-GAAP adjustments to our IFRS profit relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information and a reconciliation to GAAP information is provided on page 29.

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

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

Liquids comprise crude oil, condensate and natural gas liquids.

Net debt and net debt ratio are non-GAAP measures. Net debt includes the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. We believe that net debt and net debt ratio provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The net debt ratio is defined as the ratio of finance debt (borrowings, including the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, plus obligations under finance leases) to the total of finance debt plus shareholders’ interest.

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.

Non-operating items are charges and credits arising in consolidated entities and in TNK-BP and Rosneft that are included in the financial statements and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. An analysis of non-operating items by region is shown on pages 7, 9 and 11.

Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. An analysis of capital expenditure by segment and region is shown on page 27.

Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime.

The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.

Replacement cost (RC) profit or loss reflects the replacement cost of supplies and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. Management believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure.

Glossary (continued)

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 28 and 29 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.

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 257-267 of BP Annual Report and Form 20-F 2013.

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

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

Trial Phases. Following a status conference on 21 March 2014, the federal district court in New Orleans (the District Court) scheduled the penalty phase (the Penalty Phase) in the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 to commence on 20 January 2015. The Penalty Phase is expected to last three weeks. The District Court also addressed the scope of discovery under certain of the statutory penalty factors. In the Penalty Phase, the District Court will determine the amount of civil penalties arising under the Clean Water Act based on the court’s rulings as to the presence of negligence, gross negligence or wilful misconduct in Phases 1 and 2, the court’s rulings as to quantification of discharge in Phase 2 and the application of the penalty factors under the Clean Water Act.

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

Plaintiffs’ Steering Committee (PSC) Settlements – Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages Settlement Agreement. As disclosed in BP Annual Report and Form 20-F 2013, on 24 December 2013, the District Court ruled on the issues remanded to it by the business economic loss panel of the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), ordering that the claims administrator, in administering business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed matching requirements, and on 13 March 2014, the claims administrator issued a revised policy addressing the matching of revenue and expenses for business economic loss claims. On 19 March 2014, BP submitted its response to the revised matching policy, and on 25 March 2014 the claims administrator submitted the policy to the District Court for consideration. The policy remains under consideration by the Court. The PSC have objected to the revised policy.

As to the issue of causation, the District Court ruled that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. The District Court also held that the absence of a further causation requirement does not defeat class certification nor invalidate the settlement under the federal class certification rule or Article III of the US Constitution. On 26 December 2013, BP filed with the Fifth Circuit a protective notice of appeal from the District Court’s 24 December 2013 order. BP subsequently filed a renewed motion for a permanent injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not traceable to the spill. On 3 March 2014, the business economic loss panel (in a 2 to 1 decision) affirmed the District Court’s ruling on causation and denied BP’s motion for a permanent injunction. On 17 March 2014, BP filed a petition that all the active judges of the Fifth Circuit review the 3 March 2014 decision. Under the terms of the business economic loss panel’s ruling, the District Court injunction temporarily suspending issuance of final determination notices and payments of business economic loss claims will be lifted when the matter is transferred back to the District Court, the timing of which is subject to the outcome of BP’s 17 March 2014 petition.

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

US Environmental Protection Agency (EPA) matters

On 28 November 2012, the EPA notified BP that it had temporarily suspended BP p.l.c., BPXP and a number of other BP subsidiaries from participating in new federal contracts. In addition, as a result of BP’s agreement with the Department of Justice to resolve all federal criminal charges against BP, on 1 February 2013 the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. On 12 August 2013, BP filed a lawsuit in the US District Court for the Southern District of Texas challenging the EPA’s suspension and mandatory debarment decisions. On 26 November 2013, the EPA suspended two additional BP entities (BP Alternative Energy and BP Pipelines (Alaska) Inc.) and proposed discretionary debarment of all suspended BP entities. For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013.

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

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

Legal proceedings (continued)

MDL 2185 and other securities-related litigation

Securities class action – On 6 December 2013, the judge in the multi-district litigation proceeding in federal district court in Houston (MDL 2185) denied the plaintiffs’ motion for class certification and gave the plaintiffs 30 days to renew that motion. The plaintiffs renewed their motion on 6 January 2014. A hearing on this motion was held on 21 April 2014 and the decision of the judge is awaited.

Individual securities litigation – The judge in the MDL 2185 proceedings granted in part and denied in part the defendants’ motion to dismiss three of the remaining 15 cases filed by certain pension funds, investment funds or advisers against BP entities and current and former officers and directors seeking damages for alleged losses suffered as a result of purchases of BP ordinary shares or ADSs. A subset of the claims was dismissed. The judge held that English law governs the plaintiffs’ remaining claims (with the exception of the federal law claims based on purchases of ADSs and a potential claim under Ohio state law against BP p.l.c. by certain Ohio funds). On 11 December 2013, defendants moved to dismiss 10 of the remaining cases and answered the complaints in two others. On 5 December 2013, the Ohio funds filed an amended complaint withdrawing their English law claim and asserting only a claim under Ohio state law. On 6 January 2014, BP moved to dismiss that case, and on 7 April 2014, the judge dismissed the Ohio action with leave to replead English common law claims within 30 days.

Eleven additional cases have been filed in the Texas federal court, three cases have been filed in Texas state court and one case was filed in the New York federal court, by pension or investment funds or advisers against BP entities and current and former officers and directors, asserting state, federal, and foreign law claims and seeking damages for alleged losses that those funds suffered because of their purchases of BP ordinary shares and/or ADSs.

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

Pending investigations and reports relating to the Deepwater Horizon oil spill

CSB investigation – The US Chemical Safety and Hazard Investigation Board (CSB) has announced that it plans to release the first two volumes of its four-volume report on its investigation into the incident at a public hearing in Houston on 5 June 2014. The first two volumes will cover technical, regulatory and organizational issues. The CSB has stated that it will consider Volume 3 (concerning the role of the regulator in the oversight of the offshore industry) and Volume 4 (concerning organizational and cultural factors) later in 2014.

Other matters

Following recent events relating to Russia and the Ukraine, on 11 April and 28 April 2014, the US Office of Foreign Assets Control added the name of certain individuals and entities to its list of Specially Designated Nationals. It is too early to assess the impact on BP.

Cautionary statement

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operation and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, plans regarding future divestment of $10 billion in assets by 2015; BP’s intentions in respect of its announced share repurchase programme, including the total value of shares expected to be purchased in connection therewith and programme timing; the expected quarterly dividend payment and timing of the payment; expectations regarding BP’s plans to separate its US lower 48 oil and gas businesses; the expected timing of completion of the sale of BP’s interests in the North Slope of Alaska oil fields; the expected level of reported production in the second quarter of 2014 and the expected impact of turnaround activity thereon; the expected increase in heavy crude processing rates to about 280,000 barrels per day at the Whiting refinery in the second quarter of 2014; expectations regarding the impact of Downstream turnaround activity on refinery throughput in the second quarter of 2014; BP’s expectations regarding a continuation of low petrochemicals margins, particularly in the aromatics business, seasonally stronger refining margins particularly in the US and increased global turnaround activity in the second quarter of 2014; and certain statements regarding the legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties, and the risks associated with such proceedings; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of maintenance and/or turnaround activity; the nature, timing and volume of refinery additions and outages; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including court decisions, the types of enforcement action pursued and the nature of remedies sought or imposed; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism, cyber-attacks or sabotage; and other factors discussed under “Risk factors” in BP Annual Report and Form 20-F 2013 as filed with the US Securities and Exchange Commission.

Computation of ratio of earnings to fixed charges


$ million except ratio	First quarter 2014
Earnings available for fixed charges:
Pre-tax income from continuing operations before adjustment for income or loss from joint ventures and associated		4,372
Fixed charges		727
Amortization of capitalized interest		60
Distributed income of joint ventures and associates		214
Interest capitalized		(44	)
Preference dividend requirements, gross of tax		(1	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges		(3	)

Total earnings available for fixed charges		5,325

Fixed charges:
Interest expensed		206
Interest capitalized		44
Rental expense representative of interest		476
Preference dividend requirements, gross of tax		1

Total fixed charges		727

Ratio of earnings to fixed charges		7.3

Capitalization and indebtedness

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 March 2014 in accordance with IFRS:


$ million	31 March 2014
Share capital and reserves
Capital shares (1-2)		5,084
Paid-in surplus (3)		11,625
Merger reserve (3)		27,206
Own shares		(479	)
Treasury shares		(20,345	)
Available-for-sale investments		(2	)
Cash flow hedge reserve		(693	)
Foreign currency translation reserve		2,611
Share-based payment reserve		1,538
Profit and loss account		102,535

BP shareholders’ equity		129,080

Finance debt (4-6)
Due within one year		8,663
Due after more than one year		44,586

Total finance debt		53,249

Total capitalization (7)		182,329

(1)

Issued share capital as of 31 March 2014 comprised 18,461,657,130 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,785,706,603 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 2014.

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

(6)

As of 31 March 2014, the parent company, BP p.l.c., had outstanding guarantees totalling $52,137 million, of which $52,107 million related to guarantees in respect of liabilities of subsidiary undertakings, including $50,479 million relating to finance debt of subsidiaries. Thus 95% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 31 March 2014, $138 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 2014 in the consolidated capitalization and indebtedness of BP.

Signatures

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

BP p.l.c.

(Registrant)

Dated: 29 April 2014

/s/ J Bertelsen

J BERTELSEN

Deputy Secretary