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

Top of page 1

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.

Top of page 2

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.

Top of page 3

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.

Top of page 4

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.

Top of page 5

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.

Top of page 6

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.

Top of page 7

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.

Top of page 8

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.

Top of page 9

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.

Top of page 10

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.

Top of page 11

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

Top of page 12

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.

Top of page 13

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

Top of page 14

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.

Top of page 16

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.

Top of page 17

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