Edgar Filing: BP PLC

bp201410286k.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

for the period ended October, 2014

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 Form 20-F or Form 40-F.

Form 20-F        |X|          Form 40-F
     ---------------               ----------------

Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of
     1934.

Yes                            No        |X|
      ---------------           ----------------

BP p.l.c.

Group results

Third quarter and nine months 2014

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FOR IMMEDIATE RELEASE London 28 October 2014

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
3,504	3,369	1,290	Profit for the period(a)	8,187	22,409
(326)	(187)	1,095	Inventory holding (gains) losses*, net of tax	855	(235)
3,178	3,182	2,385	Replacement cost profit*	9,042	22,174
			Net (favourable) unfavourable impact of non-operating
514	453	652	items* and fair value accounting effects*, net of tax	855	(11,555)
3,692	3,635	3,037	Underlying replacement cost profit*	9,897	10,619
			Replacement cost profit
16.84	17.25	12.97	per ordinary share (cents)	49.04	116.62
1.01	1.03	0.78	per ADS (dollars)	2.94	7.00
			Underlying replacement cost profit
19.57	19.71	16.51	per ordinary share (cents)	53.67	55.85
1.17	1.18	0.99	per ADS (dollars)	3.22	3.35

BP’s third-quarter replacement cost (RC) profit was $2,385 million, compared with $3,178 million a year ago. After adjusting for a net charge for non-operating items of $798 million and net favourable fair value accounting effects of $146 million (both on a post-tax basis), underlying RC profit for the third quarter 2014 was $3,037 million, compared with $3,692 million for the same period in 2013. For the nine months, RC profit was $9,042 million, compared with $22,174 million a year ago which included a $12.5-billion gain relating to the disposal of our interest in TNK-BP. After adjusting for a net charge for non-operating items of $1,055 million and net favourable fair value accounting effects of $200 million (both on a post-tax basis), underlying RC profit for the nine months was $9,897 million, compared with $10,619 million for the same period last year. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 3 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 $43 million for the quarter and $342 million for the nine months. In its decision on 4 September 2014 in the Trial of Phase 1 of MDL 2179, the federal district court in New Orleans ruled that under the US Clean Water Act, the discharge of oil was the result of the gross negligence and wilful misconduct of BP Exploration & Production Inc. (BPXP) and that BPXP is therefore subject to enhanced civil penalties. BP intends to appeal this ruling. For the reasons described in Note 2, no adjustment has been made to the provision previously recognized for the liability under the Clean Water Act.

As at 30 September 2014, the cumulative charges to be paid from the Deepwater Horizon Oil Spill Trust fund reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, will be charged to the income statement as they arise. For further information on the Gulf of Mexico oil spill and its consequences see page 10 and Note 2 on page 16. 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 quarter and nine months was $9.4 billion and $25.5 billion respectively, compared with $6.3 billion and $15.7 billion for the same periods in 2013. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the third quarter and nine months was $9.4 billion and $25.8 billion respectively, compared with $6.3 billion and $15.9 billion respectively for the same periods in 2013.

Net debt at 30 September 2014 was $22.4 billion, compared with $20.1 billion a year ago. The ratio of net debt to net debt plus equity at 30 September 2014 was 15.0%, compared with 13.3% a year ago. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 25 for more information.

Total capital expenditure on an accruals basis for the third quarter was $5.3 billion, almost all of which was organic*. For the nine months, total capital expenditure on an accruals basis was $17.0 billion, of which organic capital expenditure was $16.3 billion. Organic capital expenditure for the full year 2014 is expected to be around $23 billion.

In October 2013, BP announced plans to divest a further $10 billion of assets before the end of 2015, having completed its earlier divestment programme of $38 billion in 2012. BP has agreed around $4.0 billion of such further divestments to date. Disposal proceeds received in cash were $0.6 billion for the quarter and $2.4 billion for the nine months.

·	BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 19 December 2014. The corresponding amount in sterling will be announced on 8 December 2014. See page 25 for further information.

*	For items marked with an asterisk 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 37.

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Group headlines (continued)

The effective tax rate (ETR) on RC profit for the third quarter and nine months was 42% and 35% respectively, compared with 31% and 22% for the same periods in 2013. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the third quarter and nine months was 41% and 36% respectively, compared with 31% and 38% for the same periods in 2013. The underlying ETR was higher for the third quarter 2014 due to a lower level of equity-accounted earnings (which are reported net of tax) and foreign exchange impacts on deferred tax, compared to the corresponding period in 2013.

·	Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $358 million for the third quarter, compared with $397 million for the same period in 2013. For the nine months, the respective amounts were $1,081 million and $1,170 million.

BP repurchased 209 million ordinary shares at a cost of $1.6 billion, including fees and stamp duty, during the third quarter of 2014. For the nine months, BP repurchased 507 million ordinary shares at a cost of $4.1 billion, including fees and stamp duty. The $8-billion share repurchase programme announced on 22 March 2013 was completed in July 2014. Ongoing share repurchases continue to be funded from the $10-billion divestment programme described above.

Reported production for the third quarter, including BP’s share of Rosneft’s production, was 3,149 thousand barrels of oil equivalent per day (mboe/d), compared with 3,172mboe/d for the same period in 2013. This reflected the Abu Dhabi onshore concession expiry, partly offset by increased production from higher-margin areas in Upstream and higher production in Rosneft. Reported production for the nine months, including BP’s share of Rosneft’s production, was 3,130mboe/d, compared with 2,938mboe/d for the same period in 2013 which includes Rosneft production for the period 21 March to 30 September averaged over the nine months.

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Analysis of RC profit before interest and tax

and reconciliation to profit for the period

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			RC profit before interest and tax*
4,158	4,049	3,311	Upstream	12,019	14,120
616	933	1,231	Downstream	2,958	3,279
–	–	–	TNK-BP(a)	–	12,500
792	1,024	107	Rosneft(b)	1,649	1,095
(674)	(434)	(432)	Other businesses and corporate	(1,363)	(1,714)
(30)	(251)	(33)	Gulf of Mexico oil spill response(c)	(313)	(251)
263	(76)	370	Consolidation adjustment – UPII*	384	819
5,125	5,245	4,554	RC profit before interest and tax	15,334	29,848
			Finance costs and net finance expense relating to
(397)	(356)	(358)	pensions and other post-retirement benefits	(1,081)	(1,170)
(1,462)	(1,643)	(1,777)	Taxation on a RC basis	(5,022)	(6,253)
(88)	(64)	(34)	Non-controlling interests	(189)	(251)
3,178	3,182	2,385	RC profit attributable to BP shareholders	9,042	22,174
444	258	(1,585)	Inventory holding gains (losses)	(1,225)	344
			Taxation (charge) credit on inventory holding gains
(118)	(71)	490	and losses	370	(109)
3,504	3,369	1,290	Profit for the period attributable to BP shareholders	8,187	22,409

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. Nine months 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 8 for further information.
(c)	See Note 2 on page 16 for further information on the accounting for the Gulf of Mexico oil spill response.

Analysis of underlying RC profit before interest and tax

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Underlying RC profit before interest and tax*
4,423	4,655	3,899	Upstream	12,955	14,413
720	733	1,484	Downstream	3,228	3,562
808	1,024	110	Rosneft	1,405	1,111
(385)	(438)	(293)	Other businesses and corporate	(1,220)	(1,284)
263	(76)	370	Consolidation adjustment - UPII	384	819
5,829	5,898	5,570	Underlying RC profit before interest and tax	16,752	18,621
			Finance costs and net finance expense relating to
(388)	(347)	(348)	pensions and other post-retirement benefits	(1,052)	(1,141)
(1,661)	(1,852)	(2,151)	Taxation on an underlying RC basis	(5,614)	(6,610)
(88)	(64)	(34)	Non-controlling interests	(189)	(251)
3,692	3,635	3,037	Underlying RC profit attributable to BP shareholders	9,897	10,619

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 4-9 for the segments.

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Upstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
4,165	4,048	3,312	Profit before interest and tax	12,013	14,121
(7)	1	(1)	Inventory holding (gains) losses*	6	(1)
4,158	4,049	3,311	RC profit before interest and tax	12,019	14,120
			Net (favourable) unfavourable impact of non-operating
265	606	588	items* and fair value accounting effects*	936	293
4,423	4,655	3,899	Underlying RC profit before interest and tax*(a)	12,955	14,413

(a)	See page 5 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 third quarter and nine months was $3,311 million and $12,019 million respectively, compared with $4,158 million and $14,120 million for the same periods in 2013. The third quarter and nine months included a net non-operating charge of $501 million and $741 million respectively. This includes a $770-million charge related to Block KG D6 in India. A year ago, the net non-operating charge for the third quarter and nine months was $226 million and $163 million, respectively. Fair value accounting effects in the third quarter and nine months had unfavourable impacts of $87 million and $195 million respectively, compared with unfavourable impacts of $39 million and $130 million in the same periods of 2013.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $3,899 million and $12,955 million respectively, compared with $4,423 million and $14,413 million for the same periods in 2013. The result for the third quarter reflected lower oil realizations, the absence of a one-off benefit in 2013 related to cost pooling settlement agreements between the owners of the Trans Alaska Pipeline System (TAPS) and higher costs, primarily depreciation, depletion and amortization, partly offset by higher production in higher-margin areas and higher gas realizations. The result for the nine months reflected the same factors as the third quarter and in addition, higher exploration write-offs, mainly in the first quarter, the impact of divestments, mainly on the first half of the year, and a benefit from stronger gas marketing and trading activities, mainly in the first quarter.

Production

Reported production for the quarter was 2,147mboe/d, 2.7% lower than the third quarter of 2013. Underlying production* for the quarter was 4.1% higher. This reflected growth in production from higher-margin areas, mainly driven by strong performance in the Gulf of Mexico. For the nine months, production was 2,128mboe/d, 5.8% lower than in the same period of 2013. Nine months underlying production was 2.3% higher than in 2013.

Key events

In August, we announced that the government of Indonesia, through the Ministry of Environment, has approved the Tangguh Expansion project integrated environment and social impact assessment (AMDAL) and issued the project (BP 37.16%) an environmental permit. This was followed by the award of the onshore Front End Engineering and Design (FEED) to two consortia. In addition, BP and the Tangguh partners signed a sales and purchase agreement with Indonesia’s state-owned electricity company, PT. PLN (Persero) to supply up to 1.5 million tonnes of LNG each year from 2015 to 2033. In Trinidad, the Juniper project was sanctioned and subsequently a key contract for the development of the project was awarded. Offshore Egypt, first gas from the DEKA project was achieved with the start of production from the Denise South-6 well. The DEKA project is centered on the Denise and Karawan fields in the Temsah concession (BP 50%). BP also announced that it had named David Lawler chief executive officer of its US lower 48 onshore business.

In September, BP and Tokyo Electric Power Company (TEPCO) signed an agreement for TEPCO to purchase from BP up to 1.2 million tonnes of LNG per year for 17 years starting in 2017. In Azerbaijan, a ceremony to mark the groundbreaking for the Southern Gas Corridor was held as part of the BP-operated Azerbaijan International Operating Company celebration of the 20th anniversary of the Azeri-Chirag-Gunashli production-sharing agreement.

During the quarter we had a discovery at Xerelete in Brazil’s Campos basin, operated by Total, and a further two discoveries were announced in October: Vorlich in the central North Sea, which spans the GDF SUEZ E&P UK Ltd-operated block 30/1f and the BP-operated block 30/1c, and Guadalupe in the deepwater Gulf of Mexico, operated by Chevron. We accessed new acreage in the Outer Offshore Canning basin in Western Australia by farming in to two exploration permits (BP 21%), subject to regulatory approval, and we were apparent high bidder on 27 out of 32 blocks in the Gulf of Mexico western lease sale. We have already been awarded a number of these blocks and the remainder are subject to regulatory approval. In Egypt, we accessed the El Matariya and Karawan concessions in the recent Egyptian Natural Gas Holding Company’s bid rounds through partnering (50%) with Dana Gas and ENI respectively, subject to final regulatory approvals.

After the end of the quarter, we announced the award of two long-term drilling contracts for the Oman Khazzan project in Block 61. Additionally, operations at the Rhum gas field in the central North Sea recommenced in mid-October in accordance with the temporary management scheme announced by the UK government in October 2013. The start-up of the Kinnoull major project, also in the North Sea, is now in progress.

The third-quarter result included a $770-million charge (which we classify as a non-operating item) to write down the value ascribed to Block KG D6 in India as part of the acquisition of upstream interests from Reliance Industries in 2011. The charge arises as a result of uncertainty in the future long-term gas price outlook, following the introduction of a new formula for Indian gas prices, although we do see the commencement of a transition to market-based pricing as a step in the right direction. We expect further clarity on the new pricing policy and the premiums for future developments to emerge in due course.

Outlook

Third-quarter production benefited from the absence of seasonal adverse weather in the Gulf of Mexico. Depending on weather and the closing of the Alaska package sale to Hilcorp, we expect fourth-quarter reported production to be slightly lower.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Upstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Underlying RC profit before interest and tax(a)
1,271	1,419	1,181	US	3,331	2,786
3,152	3,236	2,718	Non-US	9,624	11,627
4,423	4,655	3,899		12,955	14,413
			Non-operating items
5	(72)	125	US	(6)	61
(231)	(444)	(626)	Non-US(b)	(735)	(224)
(226)	(516)	(501)		(741)	(163)
			Fair value accounting effects
(84)	(31)	(49)	US	(129)	(157)
45	(59)	(38)	Non-US	(66)	27
(39)	(90)	(87)		(195)	(130)
			RC profit before interest and tax(a)
1,192	1,316	1,257	US	3,196	2,690
2,966	2,733	2,054	Non-US	8,823	11,430
4,158	4,049	3,311		12,019	14,120
			Exploration expense
147	68	142	US(c)	869	312
364	321	698	Non-US(b)	1,308	955
511	389	840		2,177	1,267
			Production (net of royalties)(d)
			Liquids* (mb/d)
356	429	410	US	412	353
75	92	91	Europe	96	95
716	562	605	Rest of World	583	720
1,147	1,083	1,106		1,091	1,168
			Natural gas (mmcf/d)
1,546	1,525	1,546	US	1,517	1,550
146	166	164	Europe	176	253
4,458	4,244	4,328	Rest of World	4,321	4,524
6,150	5,936	6,038		6,014	6,327
			Total hydrocarbons* (mboe/d)
622	692	676	US	673	620
100	121	119	Europe	127	139
1,485	1,293	1,352	Rest of World	1,328	1,500
2,207	2,106	2,147		2,128	2,259
			Average realizations(e)
100.66	96.90	91.42	Total liquids ($/bbl)	95.09	99.59
5.01	5.67	5.40	Natural gas ($/mcf)	5.75	5.31
62.80	64.90	61.61	Total hydrocarbons ($/boe)	64.19	63.09

(a)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.
(b)	Third quarter and nine months 2014 include a $375-million write-off relating to Block KG D6 in India. This is classified in the ‘other’ category of non-operating items. In addition, an impairment charge of $395 million was also recorded in relation to this block. See pages 4 and 28.
(c)	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. Third quarter and nine months 2014 include write-offs of $23 million and $544 million respectively, relating to the Utica acreage.
(d)	Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(e)	Based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
Because of rounding, some totals may not agree exactly with the sum of their component parts.

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Downstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
1,009	1,166	(335)	Profit (loss) before interest and tax	1,702	3,565
(393)	(233)	1,566	Inventory holding (gains) losses*	1,256	(286)
616	933	1,231	RC profit before interest and tax	2,958	3,279
			Net (favourable) unfavourable impact of non-operating
104	(200)	253	items* and fair value accounting effects*	270	283
720	733	1,484	Underlying RC profit before interest and tax*(a)	3,228	3,562

(a)	See page 7 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 for the third quarter and nine months was $1,231 million and $2,958 million respectively, compared with $616 million and $3,279 million for the same periods in 2013.

The 2014 results included net non-operating charges of $552 million for the third quarter and $780 million for the nine months, compared with net non-operating charges of $157 million and $461 million for the same periods a year ago (see pages 7 and 28 for further information on non-operating items). The third quarter and the nine months net non-operating charges are mainly related to impairment charges in our petrochemicals business following a strategic business review. Fair value accounting effects had favourable impacts of $299 million for the third quarter and $510 million for the nine months, compared with $53 million for the third quarter and $178 million for the nine months of 2013.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 7.

Fuels business

The fuels business reported an underlying replacement cost profit before interest and tax of $1,078 million for the third quarter and $2,294 million for the nine months, compared with $344 million and $2,434 million for the same periods in 2013. Compared with 2013, the third-quarter result benefited from significantly stronger refining margins, a stronger contribution from supply and trading and improved margin delivery in our fuels business, underpinned by the Whiting refinery. The year-to-date result was negatively affected by significantly weaker refining margins, partially offset by increased production at the Whiting refinery, which was ramping up operations of the newly commissioned units throughout the period.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $336 million in the third quarter and $958 million in the nine months, compared with $325 million and $1,042 million in the same periods last year. The third-quarter result reflects steady performance with continued gross margin improvement in growth markets; the decrease in the nine months reflects the impact of previously announced restructuring programme charges and foreign exchange effects.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $70 million in the third quarter and an underlying replacement cost loss before interest and tax of $24 million in the nine months, compared with an underlying replacement cost profit before interest and tax of $51 million and $86 million respectively in the same periods last year. The third-quarter increase reflects a slight margin improvement in the acetyls market; however, the decrease in the nine months was mainly due to lower aromatics margins resulting from ongoing oversupply in the market.

Outlook

Looking to the fourth quarter, in the fuels business we expect a similar low level of turnarounds as in the third quarter of this year. Additionally, we anticipate lower seasonal demand versus third quarter levels to negatively impact margins in both the fuels and petrochemicals businesses.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Downstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Underlying RC profit before interest and tax -
			by region
(22)	331	603	US	1,346	1,285
742	402	881	Non-US	1,882	2,277
720	733	1,484		3,228	3,562
			Non-operating items
(145)	180	(181)	US	(2)	(134)
(12)	(130)	(371)	Non-US	(778)	(327)
(157)	50	(552)		(780)	(461)
			Fair value accounting effects
81	206	238	US	535	235
(28)	(56)	61	Non-US	(25)	(57)
53	150	299		510	178
			RC profit before interest and tax
(86)	717	660	US	1,879	1,386
702	216	571	Non-US	1,079	1,893
616	933	1,231		2,958	3,279
			Underlying RC profit (loss) before interest and tax -
			by business(a)(b)
344	516	1,078	Fuels	2,294	2,434
325	315	336	Lubricants	958	1,042
51	(98)	70	Petrochemicals	(24)	86
720	733	1,484		3,228	3,562
			Non-operating items and fair value accounting
			effects(c)
(105)	15	196	Fuels	(6)	(282)
4	186	(5)	Lubricants	181	2
(3)	(1)	(444)	Petrochemicals	(445)	(3)
(104)	200	(253)		(270)	(283)
			RC profit (loss) before interest and tax(a)(b)
239	531	1,274	Fuels	2,288	2,152
329	501	331	Lubricants	1,139	1,044
48	(99)	(374)	Petrochemicals	(469)	83
616	933	1,231		2,958	3,279

13.6	15.4	15.6	BP average refining marker margin (RMM)* ($/bbl)	14.8	16.8
			Refinery throughputs (mb/d)
618	645	651	US	636	755
772	757	766	Europe	774	774
312	250	312	Rest of World	290	295
1,702	1,652	1,729		1,700	1,824
95.3	95.3	94.8	Refining availability* (%)	95.0	95.2
			Marketing sales of refined products (mb/d)
1,211	1,183	1,197	US	1,167	1,317
1,284	1,154	1,240	Europe	1,178	1,253
551	515	522	Rest of World	527	552
3,046	2,852	2,959		2,872	3,122
2,596	2,468	2,439	Trading/supply sales of refined products	2,441	2,478
5,642	5,320	5,398	Total sales volumes of refined products	5,313	5,600
			Petrochemicals production (kte)
1,114	969	932	US	2,972	3,272
999	895	1,048	Europe	2,915	2,827
1,538	1,501	1,676	Rest of World	4,599	4,474
3,651	3,365	3,656		10,486	10,573

(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.

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Rosneft

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014(a)	$ million	2014(a)	2013
836	1,050	87	Profit before interest and tax(b)(c)	1,686	1,152
(44)	(26)	20	Inventory holding (gains) losses*	(37)	(57)
792	1,024	107	RC profit before interest and tax	1,649	1,095
16	–	3	Net charge (credit) for non-operating items*	(244)	16
808	1,024	110	Underlying RC profit before interest and tax*	1,405	1,111

Replacement cost profit before interest and tax for the third quarter and nine months was $107 million and $1,649 million respectively, compared with $792 million and $1,095 million for the same periods in 2013.

The 2014 results included a non-operating charge of $3 million for the third quarter and a gain of $244 million for the nine months relating to Rosneft’s sale of its interest in the Yugragazpererabotka joint venture, compared with a non-operating charge of $16 million for the same periods in 2013.

After adjusting for non-operating items, the underlying replacement cost profit for the third quarter and nine months was $110 million and $1,405 million respectively, compared with $808 million and $1,111 million for the same periods in 2013. Compared with the same period last year, the third-quarter result was principally affected by adverse foreign exchange movements. It was also affected by an unfavourable duty lag effect and lower oil prices.

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

See also Other matters on page 36 for information on sanctions.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014(d)	2014(a)		2014(a)(d)	2013(e)
			Production (net of royalties) (BP share)
828	820	817	Liquids* (mb/d)	822	588
793	1,036	1,073	Natural gas (mmcf/d)	1,044	526
965	999	1,002	Total hydrocarbons* (mboe/d)	1,002	679

(a)	The operational and financial information of the Rosneft segment for the third quarter and nine months 2014 is based on preliminary operational and financial results of Rosneft for the three months ended 30 September 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 fourth quarter results.
(b)	The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s interest in TNK-BP. BP's share of Rosneft’s earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.
(c)	Third quarter and nine months 2014 include $25 million of foreign exchange losses arising on the dividend received ($5 million loss in the third quarter and nine months 2013).
(d)	A minor amendment has been made to the production volumes for the second quarter and nine months 2014.
(e)	Nine months 2013 reflects production for the period 21 March – 30 September averaged over the nine months.

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Other businesses and corporate

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
(674)	(434)	(432)	Profit (loss) before interest and tax	(1,363)	(1,714)
–	–	–	Inventory holding (gains) losses*	–	–
(674)	(434)	(432)	RC profit (loss) before interest and tax	(1,363)	(1,714)
289	(4)	139	Net charge (credit) for non-operating items*	143	430
(385)	(438)	(293)	Underlying RC profit (loss) before interest and tax*	(1,220)	(1,284)
			Underlying RC profit (loss) before interest and tax
(309)	(226)	(102)	US	(427)	(572)
(76)	(212)	(191)	Non-US	(793)	(712)
(385)	(438)	(293)		(1,220)	(1,284)
			Non-operating items
(297)	4	(144)	US	(141)	(435)
8	–	5	Non-US	(2)	5
(289)	4	(139)		(143)	(430)
			RC profit (loss) before interest and tax
(606)	(222)	(246)	US	(568)	(1,007)
(68)	(212)	(186)	Non-US	(795)	(707)
(674)	(434)	(432)		(1,363)	(1,714)

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 third quarter and nine months was $432 million and $1,363 million respectively, compared with $674 million and $1,714 million for the same periods last year.

The third-quarter result included a net non-operating charge of $139 million, primarily relating to environmental provisions, compared with a net charge of $289 million a year ago. For the nine months, the net non-operating charge was $143 million, compared with a net charge of $430 million a year ago.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter was $293 million, reflecting certain one-off benefits, compared with $385 million for the same period in 2013. For the nine months, the underlying replacement cost loss before interest and tax was $1,220 million compared with $1,284 million a year ago.

Alternative Energy

Biofuels

In our biofuels business the net ethanol-equivalent production (which includes ethanol and sugar) for the third quarter and nine months was 255 million litres and 411 million litres respectively, compared with 248 million litres and 364 million litres for the same periods of 2013.

Wind

Net wind generation capacity*(a) was 1,590MW at 30 September 2014, the same level as at 30 September 2013. BP’s net share of wind generation for the third quarter and nine months was 837GWh and 3,377GWh respectively, compared with 714GWh and 3,001GWh for the same periods of 2013.

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

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Gulf of Mexico oil spill

Financial update

The replacement cost loss before interest and tax for the third quarter and nine months was $33 million and $313 million respectively, compared with $30 million and $251 million for the same periods last year. The third-quarter charge reflects adjustments to provisions and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $43.0 billion.

The cumulative income statement charge does not include amounts for obligations that BP currently considers are not possible to measure reliably. The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities in Note 2 on page 18. These could have a material impact on our consolidated financial position, results and cash flows.

As described under Legal proceedings below, the federal district court in New Orleans (the district court) has ruled on Phase 1 of MDL 2179. For the reasons described in Note 2, no adjustment has been made to the provision previously recognized for the liability under the Clean Water Act.

Trust update

As at 30 September 2014, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, reached $20 billion. Subsequent additional costs will be charged to the income statement as they arise. See Note 2 on page 16 and Legal proceedings on page 33 for further details.

During the third quarter, $314 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $289 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $25 million for natural resource damage assessment. At 30 September 2014, the aggregate cash balances in the Trust and the QSFs amounted to $6.0 billion, including $1.1 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration projects.

In October 2014 federal and state Trustees issued final approval for the third phase of Gulf of Mexico restoration projects, totalling $627 million for 44 projects, funded as part of BP’s commitment to provide up to $1 billion for early restoration to expedite recovery of natural resources injured as a result of the oil spill. These projects are in addition to 10 other early restoration projects that are in place or under way.

Legal proceedings

The district court issued its ruling on Phase 1 in the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 on 4 September 2014. It found that BP Exploration & Production Inc. (BPXP), BP America Production Company (BPAPC) and various other parties are each liable under general maritime law for the blowout, explosion and oil spill from the Macondo well. With respect to the United States’ claim against BPXP under the Clean Water Act, the district court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP is therefore subject to enhanced civil penalties, which may be up to $4,300 per barrel.

BPXP and BPAPC intend to appeal the Phase 1 ruling to the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). In the meantime, on 2 October 2014, BPXP and BPAPC filed a motion with the district court to amend the findings in the Phase 1 ruling, to alter or amend the judgment, or for a new trial, on the grounds that the district court allocation of fault and findings of gross negligence and wilful misconduct relied upon testimony which had been excluded from the evidence presented at the Phase 1 trial.

The penalty phase trial in MDL 2179 is scheduled to commence in January 2015. In this phase, the district court will determine the amount of civil penalties owed to the United States under the Clean Water Act based on the court’s rulings or ultimate determinations on appeal as to the presence of negligence, gross negligence or wilful misconduct and quantification of discharge in the earlier phases of the trial and the application of the penalty factors under the Clean Water Act.

With regard to the Plaintiffs’ Steering Committee (PSC) settlement, on 24 September 2014, the district court denied BP’s motion to order the return of excessive payments made by the DHCSSP under the matching policy in effect before the district court’s December 2013 ruling requiring a claimant’s revenue to be matched with variable expenses. BP has filed a notice of appeal of this decision to the Fifth Circuit.

In March 2014, the Fifth Circuit affirmed the district court’s ruling that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. BP filed a petition that all the active judges of the Fifth Circuit review the decision; in May 2014 this was denied. The district court dissolved the injunction that had halted the processing and payment of business economic loss claims and instructed the claims administrator to resume the processing and payment of claims. In August 2014, BP petitioned for review by the US Supreme Court of the Fifth Circuit’s decisions relating to compensation of claims for losses with no apparent connection to the Deepwater Horizon spill.

In August 2014, the final instalment of $175 million, plus accrued interest, was paid under the civil penalty of $525 million to which BP agreed in resolving the SEC’s Deepwater Horizon-related claims.

For further details, see Legal proceedings on page 33.

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Financial statements

Group income statement

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013

96,601	93,957	93,904	Sales and other operating revenues (Note 5)	279,571	285,419
119	155	119	Earnings from joint ventures – after interest and tax	389	346
1,010	1,228	272	Earnings from associates – after interest and tax	2,283	1,742
178	157	117	Interest and other income	605	542
295	330	355	Gains on sale of businesses and fixed assets	734	13,072
98,203	95,827	94,767	Total revenues and other income	283,582	301,121
76,603	74,536	75,492	Purchases	221,496	223,391
6,276	6,980	6,562	Production and manufacturing expenses	20,373	20,270
1,889	816	744	Production and similar taxes (Note 6)	2,546	5,556
3,415	3,751	3,956	Depreciation, depletion and amortization	11,297	9,774
			Impairment and losses on sale of businesses and
767	774	997	fixed assets	2,197	1,487
511	389	840	Exploration expense	2,177	1,267
3,411	3,110	3,320	Distribution and administration expenses	9,630	9,588
(238)	(32)	(113)	Fair value gain on embedded derivatives	(243)	(404)
5,569	5,503	2,969	Profit before interest and taxation	14,109	30,192
279	277	285	Finance costs	849	813
			Net finance expense relating to pensions and other
118	79	73	post-retirement benefits	232	357
5,172	5,147	2,611	Profit before taxation	13,028	29,022
1,580	1,714	1,287	Taxation	4,652	6,362
3,592	3,433	1,324	Profit for the period	8,376	22,660
			Attributable to
3,504	3,369	1,290	BP shareholders	8,187	22,409
88	64	34	Non-controlling interests	189	251
3,592	3,433	1,324		8,376	22,660

			Earnings per share (Note 7)
			Profit for the period attributable to BP shareholders
			Per ordinary share (cents)
18.57	18.26	7.01	Basic	44.40	117.86
18.47	18.15	6.97	Diluted	44.14	117.20
			Per ADS (dollars)
1.11	1.10	0.42	Basic	2.66	7.07
1.11	1.09	0.42	Diluted	2.65	7.03

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Financial statements (continued)

Group statement of comprehensive income

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013

3,592	3,433	1,324	Profit for the period	8,376	22,660
			Other comprehensive income
			Items that may be reclassified subsequently to profit
			or loss
662	1,005	(3,434)	Currency translation differences	(3,342)	(1,431)
			Exchange gains (losses) on translation of foreign
			operations reclassified to gain or loss on sale of
9	–	(3)	business and fixed assets	(3)	9
–	2	–	Available-for-sale investments marked to market	(1)	(172)
			Available-for-sale investments reclassified to the
–	1	–	income statement	1	(523)
104	77	(144)	Cash flow hedges marked to market(a)	(44)	(2,062)
2	(49)	(21)	Cash flow hedges reclassified to the income statement	(90)	1
10	(2)	(8)	Cash flow hedges reclassified to the balance sheet	(11)	25
			Share of items relating to equity-accounted entities,
31	51	(144)	net of tax	(166)	(24)
(25)	9	(13)	Income tax relating to items that may be reclassified	(4)	170
793	1,094	(3,767)		(3,660)	(4,007)
			Items that will not be reclassified to profit or loss
			Remeasurements of the net pension and other post-
310	222	(1,051)	retirement benefit liability or asset	(1,765)	2,466
			Share of items relating to equity-accounted entities,
–	–	–	net of tax	5	–
(114)	(73)	257	Income tax relating to items that will not be reclassified	478	(845)
196	149	(794)		(1,282)	1,621
989	1,243	(4,561)	Other comprehensive income	(4,942)	(2,386)
4,581	4,676	(3,237)	Total comprehensive income	3,434	20,274
			Attributable to
4,485	4,606	(3,257)	BP shareholders	3,252	20,041
96	70	20	Non-controlling interests	182	233
4,581	4,676	(3,237)		3,434	20,274

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

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Financial statements (continued)

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	3,252	182	3,434
Dividends	(4,121)	(215)	(4,336)
Repurchases of ordinary share capital	(3,147)	–	(3,147)
Share-based payments, net of tax	452	–	452
Share of equity-accounted entities’ changes in equity	80	–	80
Transactions involving non-controlling interests	–	4	4
At 30 September 2014	125,818	1,076	126,894

	BP
	shareholders’	Non-controlling	Total
$ million	equity	interests	equity

At 1 January 2013	118,546	1,206	119,752

Total comprehensive income	20,041	233	20,274
Dividends	(4,266)	(331)	(4,597)
Repurchases of ordinary share capital	(3,963)	–	(3,963)
Share-based payments, net of tax	477	–	477
Share of equity-accounted entities’ changes in equity	(761)	–	(761)
Transactions involving non-controlling interests	–	69	69
At 30 September 2013	130,074	1,177	131,251

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Financial statements (continued)

Group balance sheet

	30 September	31 December
$ million	2014	2013
Non-current assets
Property, plant and equipment	134,726	133,690
Goodwill	11,971	12,181
Intangible assets	21,483	22,039
Investments in joint ventures	9,091	9,199
Investments in associates	15,460	16,636
Other investments	1,169	1,565
Fixed assets	193,900	195,310
Loans	668	763
Trade and other receivables	6,414	5,985
Derivative financial instruments	3,536	3,509
Prepayments	997	922
Deferred tax assets	1,583	985
Defined benefit pension plan surpluses	77	1,376
	207,175	208,850
Current assets
Loans	421	216
Inventories	26,581	29,231
Trade and other receivables	38,011	39,831
Derivative financial instruments	2,551	2,675
Prepayments	1,614	1,388
Current tax receivable	930	512
Other investments	296	467
Cash and cash equivalents	30,729	22,520
	101,133	96,840
Assets classified as held for sale (Note 3)	1,384	–
	102,517	96,840
Total assets	309,692	305,690
Current liabilities
Trade and other payables	49,394	47,159
Derivative financial instruments	2,140	2,322
Accruals	7,223	8,960
Finance debt	6,453	7,381
Current tax payable	2,413	1,945
Provisions	4,122	5,045
	71,745	72,812
Liabilities directly associated with assets classified as held for sale (Note 3)	431	–
	72,176	72,812
Non-current liabilities
Other payables	3,668	4,756
Derivative financial instruments	2,480	2,225
Accruals	871	547
Finance debt	47,157	40,811
Deferred tax liabilities	18,366	17,439
Provisions	28,415	26,915
Defined benefit pension plan and other post-retirement benefit plan deficits	9,665	9,778
	110,622	102,471
Total liabilities	182,798	175,283
Net assets	126,894	130,407
Equity
BP shareholders’ equity	125,818	129,302
Non-controlling interests	1,076	1,105
	126,894	130,407

Top of page 15

Financial statements (continued)

Condensed group cash flow statement

Third	Second	Third			Nine	Nine
quarter	quarter	quarter			months	months
2013	2014	2014	$ million		2014	2013
			Operating activities
5,172	5,147	2,611	Profit before taxation		13,028	29,022
			Adjustments to reconcile profit before taxation to net
			cash provided by operating activities
			Depreciation, depletion and amortization and
3,765	3,953	4,602	exploration expenditure written off		12,977	10,587
			Impairment and (gain) loss on sale of businesses and
472	444	642	fixed assets		1,463	(11,585)
			Earnings from equity-accounted entities, less
(489)	(1,080)	527	dividends received		(1,237)	(943)
			Net charge for interest and other finance expense,
170	(3)	114	less net interest paid		281	363
153	178	153	Share-based payments		437	374
			Net operating charge for pensions and other post-
			retirement benefits, less contributions and benefit
(67)	(105)	(92)	payments for unfunded plans		(299)	(437)
(360)	56	705	Net charge for provisions, less payments		568	1,145
			Movements in inventories and other current and
(812)	654	1,744	non-current assets and liabilities(a)		2,083	(7,953)
(1,672)	(1,367)	(1,607)	Income taxes paid		(3,794)	(4,887)
6,332	7,877	9,399	Net cash provided by operating activities		25,507	15,686
			Investing activities
(5,882)	(5,499)	(5,256)	Capital expenditure		(16,646)	(17,722)
–	–	(3)	Acquisitions, net of cash acquired		(13)	–
(54)	(3)	(78)	Investment in joint ventures		(114)	(152)
(64)	(47)	(73)	Investment in associates		(208)	(4,955)
307	227	391	Proceeds from disposal of fixed assets		1,596	17,743
			Proceeds from disposal of businesses, net of
94	571	194	cash disposed		791	3,879
36	53	9	Proceeds from loan repayments		79	126
(5,563)	(4,698)	(4,816)	Net cash provided by (used in) investing activities		(14,515)	(1,081)
			Financing activities
(1,258)	(447)	(1,623)	Net issue (repurchase) of shares		(3,796)	(3,093)
3,245	856	2,780	Proceeds from long-term financing		9,615	6,347
(568)	(1,720)	(388)	Repayments of long-term financing		(3,345)	(1,747)
122	(57)	(527)	Net increase (decrease) in short-term debt		(507)	(1,751)
29	–	–	Net increase (decrease) in non-controlling interests		–	29
(1,247)	(1,572)	(1,122)	Dividends paid	– BP shareholders	(4,121)	(4,267)
(140)	(140)	(62)		– non-controlling interests	(215)	(256)
183	(3,080)	(942)	Net cash provided by (used in) financing activities		(2,369)	(4,738)
			Currency translation differences relating to cash and
234	49	(418)	cash equivalents		(414)	(3)
1,186	148	3,223	Increase (decrease) in cash and cash equivalents		8,209	9,864
28,313	27,358	27,506	Cash and cash equivalents at beginning of period		22,520	19,635
29,499	27,506	30,729	Cash and cash equivalents at end of period		30,729	29,499

(a)

Includes

(394)	(233)	1,560	Inventory holding (gains) losses	1,253	(292)
(238)	(32)	(113)	Fair value gain on embedded derivatives	(243)	(404)
192	(33)	(846)	Movements related to the Gulf of Mexico oil spill response	(1,457)	(2,066)

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.

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Financial statements (continued)

Notes

1. Basis of preparation

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

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

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

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

In BP Annual Report and Form 20-F 2013 we disclosed a significant estimate or judgement in relation to the provision for penalties under the US Clean Water Act arising from the Gulf of Mexico oil spill, which had been estimated based on the assumption that BP did not act with gross negligence or engage in wilful misconduct. However, in September 2014 the district court ruled that the discharge of oil was the result of BP’s gross negligence and wilful misconduct. No adjustment has been made to the provision and a contingent liability has been disclosed in relation to the potential for a higher penalty due to the recent ruling. See Note 2 for further information.

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

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

2. Gulf of Mexico oil spill

(a) Overview

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

The group income statement includes a pre-tax charge of $43 million for the third quarter and $342 million for the nine months of 2014 in relation to the Gulf of Mexico oil spill. The third-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization and adjustments to provisions. This includes $25 million for costs eligible to be paid from the Trust that have been charged to the income statement because the $20-billion fund has now been exceeded. See Trust fund below for further details. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $43,018 million.

The cumulative income statement charge does not include amounts for obligations that BP currently considers are not possible 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.

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Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

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

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Income statement
30	251	33	Production and manufacturing expenses	313	251
(30)	(251)	(33)	Profit (loss) before interest and taxation	(313)	(251)
9	9	10	Finance costs	29	29
(39)	(260)	(43)	Profit (loss) before taxation	(342)	(280)
(44)	44	45	Taxation	99	(7)
(83)	(216)	2	Profit (loss) for the period	(243)	(287)

$ million	30 September 2014	31 December 2013
Balance sheet
Current assets
Trade and other receivables	1,566	2,457
Current liabilities
Trade and other payables	(653)	(1,030)
Provisions	(1,942)	(2,951)
Net current assets (liabilities)	(1,029)	(1,524)
Non-current assets
Other receivables	3,289	2,442
Non-current liabilities
Other payables	(2,406)	(2,986)
Accruals	(166)	–
Provisions	(7,328)	(6,395)
Deferred tax	1,995	2,748
Net non-current assets (liabilities)	(4,616)	(4,191)
Net assets (liabilities)	(5,645)	(5,715)

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Cash flow statement - Operating activities
(39)	(260)	(43)	Profit (loss) before taxation	(342)	(280)
			Adjustments to reconcile profit (loss) before
			taxation to net cash provided by
			operating activities
			Net charge for interest and other finance
9	9	10	expense, less net interest paid	29	29
(576)	116	586	Net charge for provisions, less payments	605	1,118
			Movements in inventories and other current
192	(33)	(846)	and non-current assets and liabilities	(1,457)	(2,066)
(414)	(168)	(293)	Pre-tax cash flows	(1,165)	(1,199)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an inflow of $42 million and outflow of $313 million in the third quarter and nine months of 2014 respectively. For the same periods in 2013, the amounts were an outflow of $4 million and an outflow of $193 million respectively.

Top of page 18

Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

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.

The table below shows movements in the reimbursement asset during the period to 30 September 2014. At 30 September 2014, $4,855 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements.

		Third	Nine
		quarter	months
$ million		2014	2014
Opening balance		4,513	4,899
Net increase in provision for items covered by the trust fund		656	662
Amounts paid directly by the trust fund		(314)	(706)
At 30 September 2014		4,855	4,855
Of which	– current	1,566	1,566
	– non-current	3,289	3,289

During the third quarter, cumulative charges to be paid by the Trust exceeded the remaining headroom within the Trust by $25 million. Subsequent additional costs, over and above those provided within the $20 billion, will be expensed to the income statement.

As at 30 September 2014, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $6.0 billion, including $1.1 billion remaining in the seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. Should the cash balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.

(b) Provisions and contingent liabilities

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

Provisions

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

			Litigation	Clean
			and	Water Act
$ million		Environmental	claims	penalties	Total
At 1 July 2014		1,593	3,895	3,510	8,998
Net increase in provision		190	472	–	662
Utilization	– paid by BP	(18)	(58)	–	(76)
	– paid by the trust fund	(25)	(289)	–	(314)
At 30 September 2014		1,740	4,020	3,510	9,270
Of which	– current	780	1,162	–	1,942
	– non-current	960	2,858	3,510	7,328

Top of page 19

Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

			Litigation	Clean
			and	Water Act
		Environmental	claims	penalties	Total
$ million
At 1 January 2014		1,679	4,157	3,510	9,346
Net increase in provision		190	702	–	892
Utilization	– paid by BP	(62)	(225)	–	(287)
	– paid by the trust fund	(67)	(614)	–	(681)
At 30 September 2014		1,740	4,020	3,510	9,270

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. In October 2014, phase three of the natural resource damage early restoration projects was formally approved (comprising $627 million of approved project spend) under the framework agreement. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably the amounts or timing of any further natural resource damages claims, therefore no additional amounts have been provided for these items and they are disclosed as a contingent liability.

Litigation and claims

The litigation and claims provision includes amounts that can be estimated reliably for the future cost of settling claims by individuals and businesses for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources (Individual and Business Claims), and claims by state and local government entities for removal costs, damage to real or personal property, loss of government revenue and increased public services costs (State and Local Claims) under the Oil Pollution Act of 1990 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, except where an eligibility notice has been issued and is not subject to further appeal by BP within the claims facility. As disclosed in BP Annual Report and Form 20-F 2013, as part of its monitoring of payments made by the DHCSSP, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 33 of this report for further details on the settlements with the PSC and related matters.

Until the uncertainties described below are resolved, management is unable to estimate reliably the value and volume of future business economic loss claims and whether, and to what extent, received or processed but unpaid business economic loss claims will be paid, except where an eligibility notice has been issued and is not subject to further appeal by BP within the claims facility. Firstly, the inherent uncertainty as to the interpretation of the EPD Settlement Agreement in respect of causation issues will continue until the issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal, if an appeal to the Supreme Court is allowed, and until the impact of any new policies and procedures implemented in response to these issues and of the revised policy for the matching of revenue and expenses for business economic loss claims on the value and volume of business economic loss claims becomes clear. Secondly, uncertainty arises from the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends – the number of business economic loss claims received and the average amounts paid in respect of such claims prior to the district court’s injunction were higher than previously assumed by BP. This inability to extrapolate any reliable trends will continue until a sufficient number of relevant claims have been assessed against the revised policy for the matching of revenue and expenses for business economic loss claims (implemented in May 2014) and uncertainties concerning interpretation of the EPD Settlement Agreement described above have been resolved. Assessment of existing claims by the DHCSSP under the revised policy is ongoing. The PSC has filed a motion seeking to amend the revised policy. 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 or paid by the DHCSSP, except where an eligibility notice has been issued and is not subject to further appeal by BP within the claims facility. A provision for such business economic loss claims will be established when a reliable estimate can be made of the liability.

Top of page 20

Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated is $9.7 billion. The DHCSSP has issued eligibility notices, most of which are disputed by BP, in respect of business economic loss claims of $906 million which have not been provided for. The majority of these claims are being re-assessed using the new matching policy. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received. The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.7 billion because the current estimate does not reflect business economic loss claims not yet received, processed or paid, except where an eligibility notice has been issued and is not subject to further appeal by BP within the claims facility.

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

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable, including claims payable under the DHCSSP and State and Local Claims. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported as described above and in Legal proceedings on page 33 and the outcomes of any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise. There is also uncertainty as to the cost of administering the claims process under the DHCSSP.

Clean Water Act penalties

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

In September 2014, the district court issued its decision in the Phase 1 trial that the discharge of oil was the result of the gross negligence and wilful misconduct of BP Exploration & Production Inc. (BPXP) and that BPXP is therefore subject to enhanced civil penalties. The statutory maximum penalty is up to $4,300 per barrel of oil discharged where gross negligence or wilful misconduct is proven.

BP does not believe that the evidence at trial supports a finding of gross negligence and wilful misconduct and intends to appeal the Phase 1 ruling. In the meantime BP has filed a motion with the district court to amend the findings in the Phase 1 ruling, to alter or amend the judgment, or for a new trial.

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

If BP is unsuccessful in its appeal, and the ruling of gross negligence and wilful misconduct is upheld, the maximum penalty that could be imposed is up to $4,300 per barrel. Based upon this penalty rate and the US government’s current estimate of the number of barrels spilled, the maximum penalty could be up to $18 billion.

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

Top of page 21

Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

Any amount that may become payable by BP is subject to a very high level of uncertainty since it will depend on the outcome of BP’s appeal as well as what is determined by the court in the federal multi-district litigation proceedings in New Orleans (MDL 2179) with respect to the volume of oil spilled and the application of statutory penalty factors as noted above. Furthermore, in the second phase of the trial the court will also rule on whether BP’s conduct involved negligence or gross negligence with respect to source control and although this does not affect the maximum penalty following a finding of gross negligence in the first phase of the trial, it could bear on the court’s consideration of the statutory penalty factors. The district court could issue its decision on the second phase of the trial, relating to source control and the volume of oil spilled, at any time, and has scheduled a trial on the subsequent phase to determine the amount of the Clean Water Act penalty to start 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.

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

See BP Annual Report and Form 20-F 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

A net increase in provisions of $662 million for the third quarter ($892 million for the nine months) arises due to increases in the provisions for natural resource damage assessment, claims administration costs and business economic loss claims, offset by adjustments to other claims provisions. The increase in provisions for the nine months also includes an increase in estimated legal costs. Expenses incurred that are eligible to be paid from the Trust exceeded the Trust headroom by $25 million.

		Third	Nine	Cumulative
		quarter	months	since the
$ million		2014	2014	incident
Environmental costs		190	190	3,221
Spill response costs		–	–	14,304
Litigation and claims costs		472	702	26,345
Clean Water Act penalties – amount provided		–	–	3,510
Other costs charged directly to the income statement		27	83	1,226
Recoveries credited to the income statement		–	–	(5,681)
Charge (credit) related to the trust fund		(656)	(662)	(137)
Other costs of the trust fund		–	–	8
Loss before interest and taxation		33	313	42,796
Finance costs	– related to the trust funds	–	–	137
	– not related to the trust funds	10	29	85
Loss before taxation		43	342	43,018

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 currently possible to measure reliably other obligations arising from the incident, namely any obligation in relation to natural resource damages claims or associated legal costs (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 33 of this report, the cost of business economic loss claims under the PSC settlement not yet received, processed or paid by the claims facility (except where an eligibility notice has been issued and is not subject to further appeal by BP within the claims facility), 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 State and Local Claims, and Clean Water Act penalties provided for as a reliable estimate of the liability in the event of a final determination of negligence rather than gross negligence or wilful misconduct, as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment.

Top of page 22

Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

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

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

3. Non-current assets held for sale

On 22 April 2014, BP announced that it had reached agreement to sell its interests in the Northstar and Endicott oilfields and 50% of its interests in each of the Milne Point and Liberty oilfields on the North Slope of Alaska to Hilcorp Alaska LLC, a subsidiary of Hilcorp Energy for $1.25 billion, subject to closing adjustments, 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 $1,384 million, and associated liabilities of $431 million, have been classified as held for sale in the group balance sheet at 30 September 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

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
4,158	4,049	3,311	Upstream	12,019	14,120
616	933	1,231	Downstream	2,958	3,279
–	–	–	TNK-BP(a)	–	12,500
792	1,024	107	Rosneft(b)	1,649	1,095
(674)	(434)	(432)	Other businesses and corporate	(1,363)	(1,714)
4,892	5,572	4,217		15,263	29,280
(30)	(251)	(33)	Gulf of Mexico oil spill response	(313)	(251)
263	(76)	370	Consolidation adjustment – UPII*	384	819
5,125	5,245	4,554	RC profit before interest and tax	15,334	29,848
			Inventory holding gains (losses)*
7	(1)	1	Upstream	(6)	1
393	233	(1,566)	Downstream	(1,256)	286
44	26	(20)	Rosneft (net of tax)	37	57
5,569	5,503	2,969	Profit before interest and tax	14,109	30,192
279	277	285	Finance costs	849	813
			Net finance expense relating to pensions
118	79	73	and other post-retirement benefits	232	357
5,172	5,147	2,611	Profit before taxation	13,028	29,022

			RC profit before interest and tax*(c)
530	1,643	1,800	US	4,568	3,413
4,595	3,602	2,754	Non-US	10,766	26,435
5,125	5,245	4,554		15,334	29,848

(a)	BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. Nine months 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 8 for further information.
(c)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.

Top of page 23

Financial statements (continued)

Notes

5. Sales and other operating revenues

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			By segment
16,810	16,739	15,879	Upstream	49,624	51,446
90,481	86,871	87,068	Downstream	258,237	265,613
454	412	530	Other businesses and corporate	1,373	1,288
107,745	104,022	103,477		309,234	318,347

			Less: sales and other operating revenues
			between segments
10,512	9,729	9,427	Upstream	28,373	31,489
440	152	(73)	Downstream	641	789
192	184	219	Other businesses and corporate	649	650
11,144	10,065	9,573		29,663	32,928

			Third party sales and other operating revenues
6,298	7,010	6,452	Upstream	21,251	19,957
90,041	86,719	87,141	Downstream	257,596	264,824
262	228	311	Other businesses and corporate	724	638
			Total third party sales and other operating
96,601	93,957	93,904	revenues	279,571	285,419

			By geographical area(a)
35,541	35,507	34,678	US	105,010	105,272
71,892	67,303	66,402	Non-US	200,010	210,178
107,433	102,810	101,080		305,020	315,450
			Less: sales and other operating revenues
10,832	8,853	7,176	between areas	25,449	30,031
96,601	93,957	93,904		279,571	285,419

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

6. Production and similar taxes

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
223	215	140	US	634	813
1,666	601	604	Non-US	1,912	4,743
1,889	816	744		2,546	5,556

Top of page 24

Financial statements (continued)

Notes

7. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 209 million ordinary shares at a cost of $1,637 million - 12 million ordinary shares at a cost of $100 million completed the share repurchase programme announced on 22 March 2013. The remaining repurchases continue the share buybacks as announced on 29 April 2014. 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.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Results for the period
			Profit for the period attributable to BP
3,504	3,369	1,290	shareholders	8,187	22,409
–	1	–	Less: preference dividend	1	1
			Profit attributable to BP ordinary
3,504	3,368	1,290	shareholders	8,186	22,408

			Number of shares (thousand)(a)
			Basic weighted average number of
18,867,320	18,440,909	18,390,006	shares outstanding	18,436,995	19,012,247
3,144,553	3,073,484	3,065,001	ADS equivalent	3,072,832	3,168,708

			Weighted average number of shares
			outstanding used to calculate diluted
18,967,190	18,556,789	18,499,505	earnings per share	18,544,448	19,120,033
3,161,198	3,092,798	3,083,250	ADS equivalent	3,090,741	3,186,672

18,821,216	18,435,266	18,311,461	Shares in issue at period-end	18,311,461	18,821,216
3,136,869	3,072,544	3,051,910	ADS equivalent	3,051,910	3,136,869

(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.

Top of page 25

Financial statements (continued)

Notes

8. Dividends

Dividends payable

BP today announced a dividend of 10.00 cents per ordinary share expected to be paid in December. The corresponding amount in sterling will be announced on 8 December 2014, calculated based on the average of the market exchange rates for the four dealing days commencing on 2 December 2014. Holders of American Depositary Shares (ADSs) will receive $0.600 per ADS. The dividend is due to be paid on 19 December 2014 to shareholders and ADS holders on the register on 7 November 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 third-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

Dividends paid

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014		2014	2013
			Dividends paid per ordinary share
9.000	9.750	9.750	cents	29.000	27.000
5.763	5.807	5.959	pence	17.473	17.598
54.00	58.50	58.50	Dividends paid per ADS (cents)	174.00	162.00
			Scrip dividends
65.7	26.5	85.2	Number of shares issued (millions)	151.9	124.0
452	225	672	Value of shares issued ($ million)	1,223	868

9. Net debt*

Net debt ratio*

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
50,284	52,906	53,610	Gross debt	53,610	50,284
			Fair value (asset) liability of hedges related
(734)	(1,001)	(434)	to finance debt	(434)	(734)
49,550	51,905	53,176		53,176	49,550
29,499	27,506	30,729	Less: cash and cash equivalents	30,729	29,499
20,051	24,399	22,447	Net debt	22,447	20,051
131,251	132,978	126,894	Equity	126,894	131,251
13.3%	15.5%	15.0%	Net debt ratio	15.0%	13.3%

Top of page 26

Financial statements (continued)

Notes

9. Net debt* (continued)

Analysis of changes in net debt

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Opening balance
46,990	53,249	52,906	Finance debt	48,192	48,800
			Fair value (asset) liability of hedges
(460)	(633)	(1,001)	related to finance debt	(477)	(1,700)
28,313	27,358	27,506	Less: cash and cash equivalents	22,520	19,635
18,217	25,258	24,399	Opening net debt	25,195	27,465
			Closing balance
50,284	52,906	53,610	Finance debt	53,610	50,284
			Fair value (asset) liability of hedges
(734)	(1,001)	(434)	related to finance debt	(434)	(734)
29,499	27,506	30,729	Less: cash and cash equivalents	30,729	29,499
20,051	24,399	22,447	Closing net debt	22,447	20,051
(1,834)	859	1,952	Decrease (increase) in net debt	2,748	7,414
			Movement in cash and cash equivalents
952	99	3,641	(excluding exchange adjustments)	8,623	9,867
			Net cash outflow (inflow) from financing
(2,799)	921	(1,865)	(excluding share capital and dividends)	(5,763)	(2,849)
			Movement in finance debt relating to
–	–	–	investing activities	–	632
(17)	(276)	(38)	Other movements	(432)	(123)
			Movement in net debt before
(1,864)	744	1,738	exchange effects	2,428	7,527
30	115	214	Exchange adjustments	320	(113)
(1,834)	859	1,952	Decrease (increase) in net debt	2,748	7,414

10. Inventory valuation

A provision of $1,006 million was held at 30 September 2014 ($468 million at 30 June 2014 and $322 million at 31 December 2013) to write inventories down to their net realizable value. The net movement charged to the income statement during the third quarter 2014 was $554 million (second quarter 2014 was a charge of $59 million and third quarter 2013 was a charge of $407 million).

11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 27 October 2014, is unaudited and does not constitute statutory financial statements. BP Annual Report and Form 20-F 2013 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and contained an emphasis of matter paragraph relating to significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill. The report of the auditor on those accounts did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

Top of page 27

Additional non-GAAP and other information

Capital expenditure and acquisitions

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			By segment
			Upstream(a)
1,599	1,435	1,510	US	4,643	4,684
3,136	3,351	2,973	Non-US(b)	10,023	8,953
4,735	4,786	4,483		14,666	13,637
			Downstream
559	232	239	US	677	2,175
438	378	458	Non-US	1,180	1,050
997	610	697		1,857	3,225
			Rosneft
–	–	–	Non-US(c)	–	11,941
–	–	–		–	11,941
			Other businesses and corporate
54	13	28	US	44	146
136	204	141	Non-US	480	444
190	217	169		524	590
5,922	5,613	5,349		17,047	29,393
			By geographical area(a)
2,212	1,680	1,777	US	5,364	7,005
3,710	3,933	3,572	Non-US(b)(c)	11,683	22,388
5,922	5,613	5,349		17,047	29,393
			Included above:
–	10	24	Acquisitions and asset exchanges	270	–
–	–	–	Other inorganic capital expenditure(b)(c)	442	11,941

(a)	A minor amendment has been made to the analysis by region for the comparative periods in 2013.
(b)	Nine months 2014 includes $442 million relating to the purchase of additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus Pipeline.
(c)	Nine months 2013 includes $11,941 million relating to our investment in Rosneft.

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

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Additional non-GAAP and other information (continued)

Non-operating items*

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Upstream
			Impairment and gain (loss) on sale of businesses and
(374)	(527)	(248)	fixed assets(a)	(891)	(411)
(21)	–	(59)	Environmental and other provisions	(59)	(21)
–	–	–	Restructuring, integration and rationalization costs	–	–
238	32	113	Fair value gain (loss) on embedded derivatives	243	404
(69)	(21)	(307)	Other(a)	(34)	(135)
(226)	(516)	(501)		(741)	(163)
			Downstream
			Impairment and gain (loss) on sale of businesses and
(11)	79	(400)	fixed assets	(576)	(287)
(132)	–	(128)	Environmental and other provisions	(128)	(141)
–	(1)	(5)	Restructuring, integration and rationalization costs	(7)	(4)
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
(14)	(28)	(19)	Other	(69)	(29)
(157)	50	(552)		(780)	(461)
			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
(16)	–	(3)	fixed assets	244	(16)
–	–	–	Environmental and other provisions	–	–
–	–	–	Restructuring, integration and rationalization costs	–	–
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
–	–	–	Other	–	–
(16)	–	(3)		244	(16)
			Other businesses and corporate
			Impairment and gain (loss) on sale of businesses and
(87)	4	6	fixed assets	4	(217)
(216)	–	(145)	Environmental and other provisions	(145)	(222)
(4)	–	–	Restructuring, integration and rationalization costs	(1)	(6)
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
18	–	–	Other	(1)	15
(289)	4	(139)		(143)	(430)
(30)	(251)	(33)	Gulf of Mexico oil spill response	(313)	(251)
(718)	(713)	(1,228)	Total before interest and taxation	(1,733)	11,179
(9)	(9)	(10)	Finance costs(b)	(29)	(29)
(727)	(722)	(1,238)	Total before taxation	(1,762)	11,150
205	241	440	Taxation credit (charge)(c)	707	386
(522)	(481)	(798)	Total after taxation for period	(1,055)	11,536

(a)	Third quarter and nine months 2014 include a $395-million impairment and $375-million write-off in the ‘other’ non-operating item category relating to Block KG D6 in India (see pages 4-5).
(b)	Finance costs relate to the Gulf of Mexico oil spill. See Note 2 for further details.
(c)	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, equity-accounted earnings and a deferred tax adjustment in the third quarter 2013 relating to a reduction in UK corporation tax rates). Non-operating items reported within the equity-accounted earnings of Rosneft are reported net of income tax.

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Additional non-GAAP and other information (continued)

Non-GAAP information on fair value accounting effects

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Favourable (unfavourable) impact relative to
			management’s measure of performance
(39)	(90)	(87)	Upstream	(195)	(130)
53	150	299	Downstream	510	178
14	60	212		315	48
(6)	(32)	(66)	Taxation credit (charge)(a)	(115)	(29)
8	28	146		200	19

(a)

From the first quarter 2014, tax is calculated using statutory rates. For earlier periods tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for certain non-operating items, equity-accounted earnings and a deferred tax adjustment in the third quarter 2013 relating to a reduction in UK coporation tax rates).

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

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

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

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

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

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014	$ million	2014	2013
			Upstream
			Replacement cost profit before interest and tax adjusted
4,197	4,139	3,398	for fair value accounting effects	12,214	14,250
(39)	(90)	(87)	Impact of fair value accounting effects	(195)	(130)
4,158	4,049	3,311	Replacement cost profit before interest and tax	12,019	14,120
			Downstream
			Replacement cost profit (loss) before interest and tax
563	783	932	adjusted for fair value accounting effects	2,448	3,101
53	150	299	Impact of fair value accounting effects	510	178
616	933	1,231	Replacement cost profit (loss) before interest and tax	2,958	3,279
			Total group
			Profit before interest and tax adjusted for fair value
5,555	5,443	2,757	accounting effects	13,794	30,144
14	60	212	Impact of fair value accounting effects	315	48
5,569	5,503	2,969	Profit before interest and tax	14,109	30,192

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Additional non-GAAP and other information (continued)

Realizations and marker prices

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014		2014	2013
			Average realizations(a)
			Liquids* ($/bbl)
91.20	89.61	87.26	US	88.89	92.68
107.78	101.43	96.33	Europe	100.81	104.61
107.21	103.37	94.14	Rest of World	99.80	104.07
100.66	96.90	91.42	BP Average	95.09	99.59
			Natural gas ($/mcf)
2.91	3.86	3.48	US	3.97	3.07
9.72	8.07	6.41	Europe	8.18	9.61
5.67	6.31	6.15	Rest of World	6.36	5.90
5.01	5.67	5.40	BP Average	5.75	5.31
			Total hydrocarbons* ($/boe)
59.24	63.83	60.69	US	63.37	60.29
95.00	88.22	82.16	Europe	87.95	89.58
61.74	62.89	59.91	Rest of World	61.81	61.17
62.80	64.90	61.61	BP Average	64.19	63.09
			Average oil marker prices ($/bbl)
110.29	109.67	101.93	Brent	106.52	108.46
105.79	103.05	97.56	West Texas Intermediate	99.77	98.13
82.01	82.66	77.67	Western Canadian Select	79.13	75.79
110.52	108.05	101.47	Alaska North Slope	105.06	108.62
104.77	100.70	97.34	Mars	99.60	104.33
109.36	107.30	100.73	Urals (NWE – cif)	104.69	107.29
57.11	57.51	51.42	Russian domestic oil	54.39	54.63
			Average natural gas marker prices
3.58	4.68	4.07	Henry Hub gas price ($/mmBtu)(b)	4.57	3.67
65.21	44.81	42.17	UK Gas – National Balancing Point (p/therm)	49.06	68.17

(a)	Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
(b)	Henry Hub First of Month Index.

Exchange rates

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2013	2014	2014		2014	2013
1.55	1.68	1.67	US dollar/sterling average rate for the period	1.67	1.54
1.61	1.70	1.62	US dollar/sterling period-end rate	1.62	1.61
1.32	1.37	1.33	US dollar/euro average rate for the period	1.35	1.32
1.35	1.36	1.27	US dollar/euro period-end rate	1.27	1.35
32.80	34.96	36.25	Rouble/US dollar average rate for the period	35.43	31.64
32.33	33.73	39.48	Rouble/US dollar period-end rate	39.48	32.33

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Glossary

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

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

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its 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 based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss 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 5, 7 and 9.

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

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

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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.

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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 and pages 42-44 of BP Second quarter and half year results 2014.

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

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

Trial Phases. On 4 September 2014, the federal district court in New Orleans (the District Court) issued its ruling on Findings of Fact and Conclusion of Law for Phase 1 (the Phase 1 Ruling) of the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179. The District Court found that BP Exploration & Production Inc. (BPXP), BP America Production Company (BPAPC), Transocean Holdings LLC, Transocean Deepwater Inc., Transocean Offshore Deepwater Drilling Inc. (Transocean, but excluding Transocean Ltd), and Halliburton Energy Services, Inc. (Halliburton) are each liable under general maritime law for the blowout, explosion, and oil spill from the Macondo well. The District Court found that the conduct of BPXP and BPAPC was reckless, and it apportioned to them 67% of the fault for the blowout, explosion, and oil spill. The District Court found that the conduct of Transocean was negligent and apportioned to them 30% of the fault for the blowout, explosion, and oil spill. The court found that Halliburton’s conduct was negligent and apportioned to it 3% of the fault for the blowout, explosion, and oil spill.

The District Court ruled that under US Court of Appeals for the Fifth Circuit (the Fifth Circuit) precedent BPXP and BPAPC cannot be liable for punitive damages under general maritime law, but to the extent the standards of the First Circuit or Ninth Circuit Courts of Appeals would apply to a particular claim, the court found that BP would be liable for punitive damages under those rules.

With respect to the United States’ claims against BPXP under the Clean Water Act, the District Court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP is therefore subject to enhanced civil penalties. The court further found that BPXP was an ‘operator’ and ‘person in charge’ of the Macondo well and the Deepwater Horizon vessel for the purposes of the Clean Water Act.

The District Court did not find BP p.l.c. to be at fault in connection with the blowout, explosion and oil spill, and it ruled that BP p.l.c., Transocean Ltd., and Triton Asset Leasing GmbH are not liable under general maritime law.

The District Court ruled that Transocean is not entitled to limit liability under the Limitation of Liability Act and that they are liable to the United States for removal costs under the Oil Pollution Act of 1990.

In addition, the District Court ruled that the indemnity and release clauses in BP’s contracts with Halliburton and Transocean are valid and enforceable against BP and granted BP’s motion to supplement the Phase 1 trial record with Halliburton agreement to plead guilty to destroying evidence relating to Halliburton’s internal examination of the Incident and the US government’s press release announcing the Halliburton plea agreement.

On 2 October 2014, BPXP and BPAPC filed a motion with the District Court to amend the findings in the Phase 1 Ruling, to alter or amend the judgment, or for a new trial on the grounds that the court’s allocation of fault and findings of gross negligence and wilful misconduct relied upon testimony which had been excluded from the evidence presented at the Phase 1 trial and as to which BPXP and BPAPC did not have adequate notice and opportunity to present evidence in rebuttal. BPXP and BPAPC also intend to appeal the Phase 1 Ruling to the United States Court of Appeals for the Fifth Circuit. The deadline for such an appeal is suspended until after the District Court rules on the 2 October motion.

Trial in the penalty phase in MDL 2179 (the Penalty Phase) is scheduled to commence on 20 January 2015 and is expected to last three weeks. Discovery in the Penalty Phase is scheduled to conclude in early November 2014. In the Penalty Phase, the District Court will determine the amount of civil penalties owed to the United States under the Clean Water Act based on the court’s rulings (or ultimate determinations on appeal) 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 District Court’s ruling in respect of issues presented in Phase 2 (source control and quantification of discharge) and the District Court could issue its decision on this phase at any time. The District Court has wide discretion in its determination as to whether a defendant’s conduct involved negligence, gross negligence or wilful misconduct 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 and Note 2 on page 16.

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

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Legal proceedings (continued)

On 1 August 2014, BP filed a petition for certiorari with the US Supreme Court (Supreme Court) for review of the Fifth Circuit’s decision upholding the District Court’s ruling that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in an exhibit to that agreement, as well as a related decision by a different panel of the Fifth Circuit similarly interpreting the Economic and Property Damages Settlement Agreement to permit payment to business economic loss claimants whose losses (if any) were not caused by the spill. The PSC filed to oppose BP’s petition on 8 October 2014. Several other parties have filed in support of the PSC or of BP.

On 27 June 2014, BP asked the District Court to order the return of excessive payments made by the DHCSSP under the matching policy in effect before the December 2013 Ruling. BP also requested that the District Court enter an injunction preventing the business economic loss claimants specified in its motion from spending excessive payments until the correct compensation amount is definitively determined under the revised matching policy. On 24 September 2014, the District Court denied BP’s motion, and on 7 October 2014 BP filed a notice of appeal to the Fifth Circuit. Even if the District Court or the Fifth Circuit enters such an order and injunction as requested by BP, there is significant uncertainty as to the amounts of any such excessive payments that may actually be recoverable by BP.

On 2 September 2014, BP filed a motion seeking an order removing Patrick A. Juneau from his roles as Claims Administrator and Settlement Trustee for the Economic and Property Damages Settlement.

For information about BP’s current estimate of the total cost of the PSC settlements, see Note 2 on page 16.

PSC settlements – Seafood Compensation Fund (Fund) – Pursuant to the Economic and Property Damages Settlement, BP paid $2.3 billion to the Fund to help resolve economic loss claims related to the Gulf seafood industry, a portion of which has not yet been distributed. On 19 September 2014, the District Court designated-neutrals appointed to preside over the settlement of the seafood program (the Neutrals) submitted to the District Court their report on Recommendations for Seafood Compensation Program Supplement Distribution (Recommendations). The Neutrals observed that there remain some claims against the Fund which have not been paid, and that BP has filed a motion which seeks a return of part of the Fund, on the basis that it is currently impossible to fully distribute the balance of the Fund. The Neutrals recommended that the Court target a $500 million partial distribution in the second round of payments using a proportionate distribution method. The District Court issued an Order filing the Recommendations into the court record and requiring that any objections to or comments on the Recommendations to be filed by 20 October 2014. BP filed a motion asserting that the District Court should not yet order second round distributions on the basis that, amongst other things, the first round distributions are not complete. The District Court will either adopt, modify or reject the Recommendations.

Medical Benefits Class Action Settlement (Medical Settlement) – The District Court approved the Medical Benefits Class Action Settlement Agreement (MSA) in a final order and judgment on 11 January 2013. The Medical Settlement’s effective date was 12 February 2014. As of 3 October 2014, the Medical Claims Administrator received 11,313 claim forms, including 10,113 for certain Specified Physical Conditions (SPCs), and has determined 493 claims to be eligible for monetary compensation totaling approximately $826,500. For those claimants seeking benefits under the Periodic Medical Consultation Program, approximately 7,763 claims have been determined to be eligible. The deadline for submitting claims under the MSA is 12 February 2015. The claims administrator under the MSA issued its policy statement, with which BP agrees, classifying physical conditions first diagnosed after 16 April 2012 as later-manifested physical conditions, which requires a class member seeking compensation to file a notice of intent to sue that allows BP the option to mediate the claim in lieu of litigation. The PSC disagrees with the policy statement and claims that class members should be able to seek monetary compensation to be calculated under the matrix for certain specified physical conditions pursuant to the MSA. On 23 July 2014, the District Court issued an Order affirming the claims administrator’s policy statement. On 20 August 2014, the PSC and other attorneys representing certain class members filed motions for reconsideration of the District Court’s Order. The parties are awaiting a ruling.

State and local civil claims – District Attorneys of 11 parishes in the State of Louisiana have filed suits under state wildlife statutes seeking penalties for damage to wildlife as a result of the Incident. In December 2011, the District Court granted BP’s motions to dismiss the District Attorneys’ complaints, holding that those claims are pre-empted by the Clean Water Act. All 11 of the parishes filed notices of appeal, and on 24 February 2014 the Fifth Circuit affirmed the District Court’s ruling. Several of the parishes sought Supreme Court review, which BP opposed. On 20 October 2014, the Supreme Court declined to hear the appeal.

Agreement for early natural resource restoration – On 21 April 2011, BP announced an agreement with natural resource trustees for the US and five Gulf Coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the Incident. Funding for these projects will come from the $20 billion Trust fund. BP and the trustees have reached agreement on a total of 54 early restoration projects that are expected to cost approximately $698 million. These include 10 projects that are already in place or under way, and 44 projects that were approved on 2 October 2014, following a regulatory review and public comment process. As part of the project agreements, BP will receive Natural Resource Damages (NRD) restoration credits that can be used to offset related NRD restoration obligations, either in whole or in part.

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Legal proceedings (continued)

MDL 2185 and other securities-related litigation

Individual securities litigation – BP entities and current and former officers and directors are defendants in 29 cases filed by a number of plaintiffs, including certain pension funds, investment funds and advisers. The plaintiffs in these cases seek damages for alleged losses suffered as a result of purchases of BP ordinary shares or American depository shares (ADSs). As previously disclosed, the judge has held that English law governs the plaintiffs’ ordinary share claims. On 30 September 2014, the court granted in part and denied in part the defendants’ motion to dismiss ten cases. The court dismissed the negligent misstatement claims in all but one of the ten cases and dismissed claims in these cases based on certain public and private misstatements. The court also dismissed BP’s arguments that the ordinary share claims of the non-US plaintiffs should be heard in England.

Securities class litigation – The trial of the consolidated securities fraud complaints filed on behalf of purported classes of BP ordinary shareholders and ADS holders has been scheduled to commence on 18 May 2015.

For further information about MDL 2185 and other securities-related litigation, see pages 257-265 of BP Annual Report and Form 20-F 2013 and pages 43-44 of BP Second quarter and half year results 2014.

Canadian class action

On 20 July 2012, a BP entity received an amended statement of claim for an action in Alberta, Canada, filed by three plaintiffs seeking to assert claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ordinary shares and ADSs. This case was dismissed on jurisdictional grounds on 14 November 2012. On 15 November 2012, one of the plaintiffs re-filed a statement of claim against BP in Ontario, Canada, seeking to assert the same claims against BP. BP moved to dismiss that action for lack of jurisdiction, and on 9 October 2013 the Ontario court denied BP’s motion. On 7 November 2013, BP filed a notice of appeal from that decision. On 14 August 2014, the Ontario Court of Appeal held that the case should be stayed and that the claims made on behalf of Canadian residents who purchased BP ordinary shares and ADSs on exchanges outside of Canada should be litigated in those countries, and granted leave for the plaintiff to amend the complaint to assert claims only on behalf of Canadian residents who purchased ADSs on the Toronto Stock Exchange. On 10 October 2014, the plaintiff filed an application for leave to appeal to the Supreme Court of Canada.

Louisiana Department of Natural Resources

On 21 August 2013, the Louisiana Department of Natural Resources (LDNR) issued a Cease and Desist Order (the Order) directing BP to apply for a Coastal Use Permit to remove certain ’orphan’ anchors that had been placed in coastal waters to secure the containment boom during oil spill response operations in 2010. On 18 September 2013, BP filed a complaint in the US District Court for the Middle District of Louisiana seeking to enjoin the State of Louisiana from enforcing the Order on grounds including that the Order is pre-empted by federal law. On 7 August 2014, the court entered a final judgment providing that the Order was pre-empted on the basis of impossibility and obstacle pre-emption. The LDNR did not file a notice of appeal and the time period to file such notice has expired.

Other legal proceedings

FERC and CTFC matters – The US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) have been investigating several BP entities regarding trading in the next-day natural gas market at Houston Ship Channel during September, October and November 2008. On 28 July 2011, FERC staff issued a Notice of Alleged Violations stating that it had preliminarily determined that several BP entities fraudulently traded physical natural gas in the Houston Ship Channel and Katy markets and trading points to increase the value of their financial swing spread positions. On 5 August 2013, the FERC issued an Order to Show Cause and Notice of Proposed Penalty directing BP to respond to a FERC Enforcement Staff report, which FERC issued on the same day, alleging that BP manipulated the next-day, fixed price gas market at Houston Ship Channel from mid-September 2008 to 30 November 2008. The FERC Enforcement Staff report proposes a civil penalty of $28 million and the surrender of $800,000 of alleged profits. BP filed its answer on 4 October 2013 denying the allegations and moving for dismissal. On 15 May 2014, FERC denied the motion to dismiss and the matter has been set for a hearing before an Administrative Law Judge in March 2015.

Abbott Atlantis related matters – In April 2009, Kenneth Abbott, as relator, filed a US False Claims Act lawsuit against BP, alleging that BP violated federal regulations, and made false statements in connection with its compliance with those regulations, by failing to have necessary documentation for the Atlantis subsea and other systems. BP is the operator and 56% interest owner of the Atlantis unit which is in production in the Gulf of Mexico. On 21 August 2014, the Court granted BP’s motions for summary judgment. On 28 August 2014, the court entered final judgment in favour of BP.

EC Investigation and related matters – On 14 May 2013, European Commission officials made a series of unannounced inspections at the offices of BP and other companies involved in the oil industry acting on concerns that anticompetitive practices may have occurred in connection with oil price reporting practices and the reference price assessment process. Related inquiries and requests for information have also been received from US and other regulators following the European Commission’s actions, including from the Japanese Fair Trade Commission, the Korean Fair Trade Commission, the Federal Trade Commission (FTC) and the CFTC. On 1 October 2014, BP was informed by the FTC that it was closing its investigation. The other investigations remain open and there is no deadline for the completion of the inquiries.

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Legal proceedings (continued)

Texas City flaring event – A flaring event occurred at the Texas City refinery in April and May 2010. This flaring event was the subject of civil lawsuit claims for personal injury and in some cases property damage by roughly 50,000 individuals. As previously disclosed, the first trial in the matter completed in October 2013 and of the six plaintiffs initially scheduled for trial, two filed nonsuits before trial, the claims of one plaintiff were dismissed by the court on directed verdict, and the jury awarded no damages to the remaining three plaintiffs. In the second trial, on 17 October 2014, the jury returned a verdict finding in favour of BP. The flares involved in this event remain the subject of a federal government enforcement action.

Other matters

During the third quarter the US and the EU have imposed further sanctions on certain Russian activities, individuals and entities, including Rosneft. To date, these sanctions have had no material adverse impact on BP or Ruhr Oel GmbH.

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Cautionary statement

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operation and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, plans regarding the divestment of $10 billion in assets by the end of 2015; the expected organic capital expenditure for full year 2014; the expected quarterly dividend payment and timing of the payment; the expected level of fourth-quarter reported production; the expected level of Downstream turnaround activity; the expected decrease in seasonal demand and its impact on margins in both the fuels and petrochemicals businesses; and certain statements regarding the legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties, and the risks associated with such proceedings; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of maintenance and/or turnaround activity; the nature, timing and volume of refinery additions and outages; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including court decisions, the types of enforcement action pursued and the nature of remedies sought or imposed; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism, cyber-attacks or sabotage; and other factors discussed under “Principal risks and uncertainties” in our Form 6-K for the period ended 30 June 2014 and under “Risk factors” in BP Annual Report and Form 20-F 2013, each as filed with the US Securities and Exchange Commission.

Contacts

	London	United States

Press Office	David Nicholas	Scott Dean
	+44 (0)20 7496 4708	+1 630 420 4990

Investor Relations	Jessica Mitchell	Craig Marshall
bp.com/investors	+44 (0)20 7496 4962	+1 281 366 3123

SIGNATURES

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

BP p.l.c.
(Registrant)

Dated: 28 October, 2014

/s/ J. BERTELSEN
...............................
J. BERTELSEN
Deputy Company Secretary