Final Results

RNS Number : 1915Z

BP PLC

04 February 2014

BP p.l.c.

Group results

Fourth quarter and full year 2013

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FOR IMMEDIATE RELEASE London 4 February 2014

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
1,488	3,504	1,042	Profit for the period(a)	23,451	11,017
521	(326)	465	Inventory holding (gains) losses, net of tax	230	411
2,009	3,178	1,507	Replacement cost profit(b)	23,681	11,428
			Net (favourable) unfavourable impact of non-operating
1,843	514	1,302	items and fair value accounting effects, net of tax(c)	(10,253)	5,643
3,852	3,692	2,809	Underlying replacement cost profit(b)	13,428	17,071
			Replacement cost profit
10.53	16.84	8.06	per ordinary share (cents)	125.08	60.05
0.63	1.01	0.48	per ADS (dollars)	7.50	3.60
			Underlying replacement cost profit
20.19	19.57	15.02	per ordinary share (cents)	70.92	89.70
1.21	1.17	0.90	per ADS (dollars)	4.26	5.38

· BP's fourth-quarter replacement cost (RC) profit was $1,507 million, compared with $2,009 million for the same period in 2012. After adjusting for a net charge for non-operating items of $1,003 million and net unfavourable fair value accounting effects of $299 million (both on a post-tax basis), underlying RC profit for the fourth quarter was $2,809 million, compared with $3,852 million for the same period in 2012 with the reduction mainly arising due to lower profits in Upstream and Downstream which were partially offset by higher earnings from Rosneft compared with the earnings we reported for TNK-BP in the equivalent quarter of 2012(d). For the full year, RC profit was $23,681 million, compared with $11,428 million in 2012. After adjusting for a net gain for non-operating items of $10,533 million and net unfavourable fair value accounting effects of $280 million (both on a post-tax basis), underlying RC profit for the full year was $13,428 million, compared with $17,071 million for 2012. 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, 19 and 21.

· All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net adverse impact on a pre-tax basis of $189 million for the quarter and $469 million for the full year. For further information on the Gulf of Mexico oil spill and its consequences, including information on utilization of the Deepwater Horizon Oil Spill Trust fund, see page 12 and Note 2 on pages 25 - 31. Information on the Gulf of Mexico oil spill is also included in Legal proceedings on pages 35 - 37.

· Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and full year was $5.4 billion and $21.1 billion respectively, compared with $6.4 billion and $20.5 billion in the same periods of 2012. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the fourth quarter and full year was $5.3 billion and $21.2 billion respectively, compared with $5.8 billion and $22.9 billion in the same periods of 2012. We expect to see net cash provided by operating activities of between $30 billion and $31 billion in 2014(e), consistent with the cash flow objectives we set in 2011 as part of our 10-point plan.

· Net debt at the end of the quarter was $25.2 billion, compared with $27.5 billion at the end of 2012. The ratio of net debt to net debt plus equity at the end of the quarter was 16.2% compared with 18.7% at the end of 2012. We will continue to target a net debt ratio in the 10-20% range, while uncertainties remain. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 4 for more information.

· The reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities, was 129%(f) for the year, excluding the impact of acquisitions and disposals. Including the net growth in our Russian portfolio as a result of the change in our holdings, the reserves replacement ratio on a combined basis was 199%.

· BP today announced a quarterly dividend of 9.5 cents per ordinary share ($0.57 per ADS), which is expected to be paid on 28 March 2014. The corresponding amount in sterling will be announced on 17 March 2014. See page 4 for further information.

(a)	Profit attributable to BP shareholders.
(b)	See page 3 for definitions of RC profit and underlying RC profit.
(c)	See pages 20 and 21 respectively for further information on non-operating items and fair value accounting effects.
(d)	Fourth quarter 2012 included 21 days of earnings for TNK-BP, for the period 1 October to 21 October, at which point equity accounting for TNK-BP ceased as it was classified as held for sale.
(e)	Assumes $100/bbl oil and $5/mmBtu Henry Hub gas. The projection includes BP's estimate of the Rosneft dividend and the impact of payments in respect of federal criminal and securities claims with the US government and Securities and Exchange Commission where settlements have already been reached, but does not reflect any cash flows relating to other liabilities, contingent liabilities, settlements or contingent assets arising from the Gulf of Mexico oil spill, which may or may not arise at that time.
(f)	Includes BP's share of TNK-BP's production and reserves additions from 1 January 2013 to 20 March 2013, and BP's share of Rosneft production and reserves additions from 21 March 2013 to 31 December 2013.

The commentaries above and following are based on RC profit and should be read in conjunction with the cautionary statement on page 38.

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Group headlines (continued)

· Total capital expenditure for the fourth quarter was $7.2 billion, of which organic capital expenditure(a) was $7.1 billion. For the full year, total capital expenditure was $36.6 billion (including the Rosneft transaction), of which organic capital expenditure was $24.6 billion. In 2014, we expect organic capital expenditure to be around $24 billion to $25 billion. Disposal proceeds received in cash were $0.4 billion for the quarter and $22.0 billion for the full year. In October 2013, BP announced plans to divest a further $10 billion of assets before the end of 2015. BP has agreed around $1.7 billion of such further divestments to date.

· The effective tax rate (ETR) on RC profit for the fourth quarter was 15% compared with 49% for the same period in 2012. For the full year the ETR on RC profit was 21% compared with 38% in 2012. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the fourth quarter was 24% compared with 16% for the same period in 2012. The underlying ETR was higher in the fourth quarter of 2013 mainly due to the absence of a number of one-off items which reduced the ETR in the fourth quarter of 2012. For the full year the underlying ETR was 35% compared with 30% in 2012, the underlying ETR was higher in 2013 mainly due to foreign exchange effects on deferred tax. For 2014 the underlying ETR is expected to be around 35%.

· Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $378 million for the fourth quarter, compared with $467 million for the same period in 2012. For the full year, the respective amounts were $1,548 million and $1,638 million.

· As at 31 December 2013, BP had bought back 753 million shares for a total amount of $5.5 billion, including fees and stamp duty, since the announcement on 22 March 2013 of a share repurchase programme with a total value of up to $8 billion expected to be fulfilled over 12 - 18 months from the date of the announcement.

· Total production for the fourth quarter, including Rosneft, was 3.2 million barrels of oil equivalent per day. BP's share of Rosneft production in the fourth quarter was 985 thousand barrels of oil equivalent per day.

· The charge for depreciation, depletion and amortization was $13.5 billion in 2013 and we expect this to be around $1 billion higher in 2014. The expected increase reflects the expected ramp-up of production from new upstream projects, as well as the full-year impact of the Whiting refinery modernization project.

(a)	Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. See page 18 for further information.

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Analysis of RC profit before interest and tax

and reconciliation to profit for the period

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			RC profit before interest and tax
7,688	4,158	2,537	Upstream	16,657	22,491
1,329	616	(360)	Downstream	2,919	2,864
575	-	-	TNK-BP(a)	12,500	3,373
-	792	1,058	Rosneft(b)	2,153	-
(505)	(674)	(605)	Other businesses and corporate	(2,319)	(2,794)
(4,126)	(30)	(179)	Gulf of Mexico oil spill response(c)	(430)	(4,995)
(428)	263	(240)	Consolidation adjustment - UPII(d)	579	(576)
4,533	5,125	2,211	RC profit before interest and tax	32,059	20,363
			Finance costs and net finance expense relating to
(467)	(397)	(378)	pensions and other post-retirement benefits	(1,548)	(1,638)
(1,995)	(1,462)	(270)	Taxation on a RC basis	(6,523)	(7,063)
(62)	(88)	(56)	Non-controlling interests	(307)	(234)
2,009	3,178	1,507	RC profit attributable to BP shareholders	23,681	11,428
(766)	444	(634)	Inventory holding gains (losses)	(290)	(594)
			Taxation (charge) credit on inventory holding
245	(118)	169	gains and losses	60	183
1,488	3,504	1,042	Profit for the period attributable to BP shareholders	23,451	11,017

(a)	BP ceased equity accounting for its share of TNK-BP's earnings from 22 October 2012. See Note 3 on page 31 for further information.
(b)	BP's investment in Rosneft is accounted under the equity method from 21 March 2013. See page 10 for further information.
(c)	See Note 2 on pages 25 - 31 for further information on the accounting for the Gulf of Mexico oil spill response.
(d)	Unrealized profit in inventory arising on inter-segment transactions.

Replacement cost (RC) profit or loss reflects the replacement cost of supplies and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. See page 19 for further information on RC profit or loss.

Analysis of underlying RC profit before interest and tax

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Underlying RC profit before interest and tax
4,375	4,423	3,852	Upstream	18,265	19,436
1,394	720	70	Downstream	3,632	6,463
224	-	-	TNK-BP	-	3,127
-	808	1,087	Rosneft	2,198	-
(448)	(385)	(614)	Other businesses and corporate	(1,898)	(1,996)
(428)	263	(240)	Consolidation adjustment - UPII	579	(576)
5,117	5,829	4,155	Underlying RC profit before interest and tax	22,776	26,454
			Finance costs and net finance expense relating to
(461)	(388)	(368)	pensions and other post-retirement benefits	(1,509)	(1,619)
(742)	(1,661)	(922)	Taxation on an underlying RC basis	(7,532)	(7,530)
(62)	(88)	(56)	Non-controlling interests	(307)	(234)
3,852	3,692	2,809	Underlying RC profit attributable to BP shareholders	13,428	17,071

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. On pages 20 and 21 respectively, we provide 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.

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6 - 11 for the segments.

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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Per share amounts

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
			Per ordinary share (cents)
7.80	18.57	5.57	Profit for the period	123.87	57.89
10.53	16.84	8.06	RC profit for the period	125.08	60.05
20.19	19.57	15.02	Underlying RC profit for the period	70.92	89.70
			Per ADS (dollars)
0.47	1.11	0.33	Profit for the period	7.43	3.47
0.63	1.01	0.48	RC profit for the period	7.50	3.60
1.21	1.17	0.90	Underlying RC profit for the period	4.26	5.38

The amounts shown above are calculated based on the basic weighted average number of shares outstanding. See Note 6 on page 33 for details of the calculation of earnings per share.

Net debt ratio - net debt: net debt + equity

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
48,800	50,284	48,192	Gross debt	48,192	48,800
1,700	734	477	Less: fair value asset of hedges related to finance debt	477	1,700
47,100	49,550	47,715		47,715	47,100
19,635	29,499	22,520	Less: cash and cash equivalents	22,520	19,635
27,465	20,051	25,195	Net debt	25,195	27,465
119,752	131,251	130,407	Equity	130,407	119,752
18.7%	13.3%	16.2%	Net debt ratio	16.2%	18.7%

See Note 7 on page 34 for further details on finance debt.

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.

Dividends

Dividends payable

BP today announced a dividend of 9.5 cents per ordinary share expected to be paid in March. The corresponding amount in sterling will be announced on 17 March 2014, calculated based on the average of the market exchange rates for the four dealing days commencing on 11 March 2014. Holders of American Depositary Shares (ADSs) will receive $0.57 per ADS. The dividend is due to be paid on 28 March 2014 to shareholders and ADS holders on the register on 14 February 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 fourth-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

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
			Dividends paid per ordinary share
9.000	9.000	9.500	cents	36.500	33.000
5.589	5.763	5.801	pence	23.399	20.852
54.00	54.00	57.00	Dividends paid per ADS (cents)	219.00	198.00
			Scrip dividends
72.7	65.7	78.1	Number of shares issued (millions)	202.1	138.4
498	452	602	Value of shares issued ($ million)	1,470	982

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Upstream

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
7,692	4,165	2,540	Profit before interest and tax	16,661	22,387
(4)	(7)	(3)	Inventory holding (gains) losses	(4)	104
7,688	4,158	2,537	RC profit before interest and tax	16,657	22,491
			Net (favourable) unfavourable impact of non-operating
(3,313)	265	1,315	items and fair value accounting effects	1,608	(3,055)
4,375	4,423	3,852	Underlying RC profit before interest and tax(a)	18,265	19,436

(a)	See page 3 for information on underlying RC profit and see page 7 for a reconciliation to segment RC profit before interest and tax by region.

The replacement cost profit before interest and tax for the fourth quarter and full year was $2,537 million and $16,657 million respectively, compared with $7,688 million and $22,491 million for the same periods in 2012. The fourth quarter and full year included net non-operating charges of $1,201 million and $1,364 million respectively. These primarily related to an $845-million write-off attributable to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas, and impairment charges. For the full year, these charges were partly offset by fair value gains on embedded derivatives and disposal gains. In 2012, there were net non-operating gains of $3,346 million in the fourth quarter and $3,189 million for the full year. Fair value accounting effects in the fourth quarter and full year 2013 had unfavourable impacts of $114 million and $244 million respectively, compared with unfavourable impacts of $33 million and $134 million in the same periods of 2012.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $3,852 million and $18,265 million respectively, compared with $4,375 million and $19,436 million for the same periods in 2012. The result for the fourth quarter reflected higher costs, including exploration write-offs and higher depreciation, depletion and amortization, lower production due to divestments and lower liquids realizations partly offset by an increase in underlying volumes, a one-off benefit to production taxes as a result of fiscal relief allowing immediate deduction of past costs, stronger gas marketing and trading results and higher gas realizations. In addition to these factors, the full year reflected a one-off benefit in the third quarter resulting from the US Federal Energy Regulatory Commission's approval of cost pooling settlements between the owners of the Trans Alaska Pipeline System.

Production for the quarter was 2,246mboe/d, 1.9% lower than the fourth quarter of 2012. After adjusting for the effects of divestments and entitlement impacts in our production-sharing agreements (PSAs), underlying production increased by 3.7%. This primarily reflects new major project volumes in the North Sea, Angola and the Gulf of Mexico. For the full year, production was 2,256mboe/d, 2.7% lower than in 2012. After adjusting for the effects of divestments and entitlement impacts in our PSAs, underlying production for the full year was 3.2% higher than in 2012.

Reported production for the full year 2014 is expected to be lower than 2013 mainly due to the expiry of the Abu Dhabi onshore concession, with an impact of around 140mboe/d, and the effect of divestments. The actual reported outcome will depend on the exact timing of project start-ups, divestments, OPEC quotas and entitlement impacts in our PSAs. After adjusting for the effects of the concession expiry, divestments and entitlement impacts in our PSAs, we expect full-year underlying production in 2014 to increase compared with 2013. We expect first-quarter 2014 reported production to be lower than the fourth quarter of 2013, primarily reflecting the Abu Dhabi concession expiry in January and the impact of divestments.

In December, the government of the Sultanate of Oman and BP signed a gas sales agreement and an amended PSA for the development of the Khazzan field, with BP as operator. The Khazzan project represents the first phase in the development of one of the Middle East region's largest unconventional tight gas accumulations.

In Azerbaijan, the Shah Deniz consortium announced the final investment decision (FID) for the Stage 2 development of the Shah Deniz gas field in the Caspian Sea. SOCAR and the Shah Deniz partners also agreed terms for extending the Shah Deniz PSA up to 2048 and, coincident with the FID, BP agreed to purchase 3.3% equity in Shah Deniz and the South Caucasus Pipeline from Statoil, subject to conditions that are expected to be satisfied in 2014.

Also in December, we announced an oil discovery at the Gila prospect, our third significant Paleogene discovery in the deepwater Gulf of Mexico. We now have 10 drilling rigs in the deepwater Gulf of Mexico, a company record, as we continue to develop our strong portfolio of assets in this key US offshore basin.

In Brazil, the Pitu oil discovery on Block BM-POT-17 in the frontier deepwater of the Potiguar basin was announced by Petrobras. BP's farm-in to a 40% interest in this block is subject to final regulatory approval. In Angola, the Lontra oil and gas discovery announced by Cobalt International Energy, Inc. in October, was followed by a successful drill-stem test in December.

In the North Sea, BP was awarded 14 licences in the 27th UK Offshore Oil and Gas Licensing Round, subject to final government approval. Furthermore, the government of Greenland granted a consortium comprising ENI, BP, DONG and NUNAOIL a licence in the Amaroq block in the Greenland Sea.

After the end of the quarter, the Azerbaijan International Operating Company, operated by BP, announced the start-up of oil production from the West Chirag platform in the Azerbaijan sector of the Caspian Sea. This completes the Chirag oil project sanctioned in 2010.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.

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Upstream

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Underlying RC profit before interest and tax
827	1,301	1,091	US	4,001	3,854
3,548	3,122	2,761	Non-US	14,264	15,582
4,375	4,423	3,852		18,265	19,436
			Non-operating items
3,992	5	(3)	US	58	3,131
(646)	(231)	(1,198)	Non-US	(1,422)	58
3,346	(226)	(1,201)		(1,364)	3,189
			Fair value accounting effects(a)
(29)	(84)	(112)	US	(269)	(67)
(4)	45	(2)	Non-US	25	(67)
(33)	(39)	(114)		(244)	(134)
			RC profit before interest and tax
4,790	1,222	976	US	3,790	6,918
2,898	2,936	1,561	Non-US	12,867	15,573
7,688	4,158	2,537		16,657	22,491
			Exploration expense
139	147	126	US(b)	438	649
170	364	2,048	Non-US(c)	3,003	826
309	511	2,174		3,441	1,475
			Production (net of royalties)(d)
			Liquids (mb/d)(e)
402	356	392	US	363	390
100	75	97	Europe	96	109
670	716	712	Rest of World	718	680
1,172	1,147	1,201		1,176	1,179
			Natural gas (mmcf/d)
1,593	1,546	1,507	US	1,539	1,651
371	146	190	Europe	237	422
4,521	4,458	4,360	Rest of World	4,483	4,536
6,484	6,150	6,057		6,259	6,609
			Total hydrocarbons (mboe/d)(f)
676	622	652	US	628	675
164	100	130	Europe	137	182
1,449	1,485	1,464	Rest of World	1,491	1,462
2,290	2,207	2,246		2,256	2,319
			Average realizations(g)
100.00	100.66	98.26	Total liquids ($/bbl)	99.24	102.10
5.03	5.01	5.49	Natural gas ($/mcf)	5.35	4.75
62.38	62.80	65.04	Total hydrocarbons ($/boe)	63.58	61.86

(a)	These effects represent the favourable (unfavourable) impact relative to management's measure of performance. Further information on fair value accounting effects is provided on page 21.
(b)	Full year 2012 includes $308 million classified within the 'other' category of non-operating items (see page 20).
(c)	Fourth quarter and full year 2013 include an $845-million write-off relating to the value ascribed to block BM-CAL-13 offshore Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011 and $216 million of costs relating to the Pitanga exploration well, which was drilled in this block and did not encounter commercial quantities of oil or gas. The $845-million write-off has been classified in the 'other' category of non-operating items (see page 20). Exploration expense also includes the write-off of costs relating to the Risha concession in Jordan as our exploration activities did not establish the technical basis for a development project in the concession.
(d)	Includes BP's share of production of equity-accounted entities in the Upstream segment.
(e)	Crude oil and natural gas liquids.
(f)	Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
(g)	Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
Because of rounding, some totals may not agree exactly with the sum of their component parts.

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Downstream

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
564	1,009	(840)	Profit (loss) before interest and tax	2,725	2,377
765	(393)	480	Inventory holding (gains) losses	194	487
1,329	616	(360)	RC profit (loss) before interest and tax	2,919	2,864
			Net (favourable) unfavourable impact of non-operating
65	104	430	items and fair value accounting effects	713	3,599
1,394	720	70	Underlying RC profit before interest and tax(a)	3,632	6,463

(a)	See page 3 for information on underlying RC profit and see page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.

The replacement cost result before interest and tax was a loss of $360 million for the fourth quarter and a profit of $2,919 million for the full year. This compares with a replacement cost profit before interest and tax of $1,329 million and $2,864 million for the same periods in 2012.

The 2013 results included net non-operating charges of $74 million for the fourth quarter and $535 million for the full year, compared with $73 million and $3,172 million for the same periods in 2012 (see pages 9 and 20 for further information on non-operating items). The charge for the quarter principally reflects disposal activity, and for the full year, impairment charges, both relating to our fuels business. Fair value accounting effects had unfavourable impacts of $356 million for the fourth quarter and $178 million for the full year, compared with a favourable impact of $8 million for the fourth quarter and an unfavourable impact of $427 million for the full year in 2012. The main driver of the impact in the fourth quarter is the increase in the fair value of pipeline and storage capacity contracts which are reflected in management's internal measure of performance but are not recognized under IFRS. See page 21 for further information.

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

The fuels business experienced a challenging fourth quarter, reporting an underlying replacement cost loss before interest and tax of $204 million compared with a profit of $1,019 million for the same period in 2012. The benefit from strong Solomon availability in the quarter of 95.6%, the highest since 2004, and lower turnaround activity, was more than offset by the impacts of significantly weaker refining margins as well as a weak result from supply and trading. Also impacting the results were increased depreciation and start-up charges at our Whiting refinery related to the modernization project that was progressively commissioned during 2013 with the final major unit being brought onstream in December. In addition, the result was impacted by the absence of earnings from the divested Texas City and Carson refineries and associated marketing assets.

For the full year, the fuels business reported an underlying replacement cost profit of $2,230 million compared with $5,012 million for the same period in 2012. The principal factors driving this result were significantly weaker refining margins and the impacts of reduced throughput due to the planned crude unit outage at our Whiting refinery and commissioning of the new units. The result was also negatively impacted by the absence of earnings from the divested Texas City and Carson refineries. These impacts were partially offset by a significantly improved supply and trading contribution with especially strong performance in the first half of 2013, and lower overall turnaround activity during the year.

The lubricants business delivered an underlying replacement cost profit before interest and tax of $230 million in the fourth quarter and $1,272 million in the full year, compared with $329 million and $1,285 million in the same periods last year. The fourth-quarter result includes a restructuring charge associated with a transformation programme to improve competitiveness across our mature European business. In 2013, a significant share of the result is from our premium brands and positions in emerging markets where we are developing a strong base to capture further growth. In January 2014, BP announced that it has agreed to sell its specialist global aviation turbine oils business. The transaction, which is subject to regulatory and other approvals, is expected to be completed in the second quarter of 2014.

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $44 million in the fourth quarter and $130 million in the full year, compared with $46 million and $166 million in the same periods of 2012. Margins and volumes continued to be under pressure in 2013 with oversupply in certain markets, partially offset by lower turnaround activity in the US and Europe.

Going forward, in 2014 we expect refining margins to improve somewhat from the particularly low levels seen in the fourth quarter of 2013, but that in general the fuels and petrochemicals environments will remain challenging. Additionally, we expect to see increased exposure to heavy crude differentials in the US as we ramp up heavy crude processing at the Whiting refinery.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.

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Downstream

Fourth	Third	Fourth	$ million
quarter	quarter	quarter	Underlying RC profit (loss) before interest and tax -	Year	Year
2012	2013	2013	by region	2013	2012
583	(22)	(162)	US	1,123	3,045
811	742	232	Non-US	2,509	3,418
1,394	720	70		3,632	6,463
			Non-operating items
(96)	(145)	(20)	US	(154)	(2,846)
23	(12)	(54)	Non-US	(381)	(326)
(73)	(157)	(74)		(535)	(3,172)
			Fair value accounting effects(a)
(9)	81	(446)	US	(211)	(441)
17	(28)	90	Non-US	33	14
8	53	(356)		(178)	(427)
			RC profit (loss) before interest and tax
478	(86)	(628)	US	758	(242)
851	702	268	Non-US	2,161	3,106
1,329	616	(360)		2,919	2,864
			Underlying RC profit (loss) before interest and
			tax - by business(b)(c)
1,019	344	(204)	Fuels	2,230	5,012
329	325	230	Lubricants	1,272	1,285
46	51	44	Petrochemicals	130	166
1,394	720	70		3,632	6,463
			Non-operating items and fair value accounting
			effects(a)
(86)	(105)	(430)	Fuels	(712)	(3,609)
1	4	-	Lubricants	2	(9)
20	(3)	-	Petrochemicals	(3)	19
(65)	(104)	(430)		(713)	(3,599)
			RC profit (loss) before interest and tax(b)(c)
933	239	(634)	Fuels	1,518	1,403
330	329	230	Lubricants	1,274	1,276
66	48	44	Petrochemicals	127	185
1,329	616	(360)		2,919	2,864

16.9	13.6	11.0	BP average refining marker margin (RMM) ($/bbl)(d)	15.4	18.2
			Refinery throughputs (mb/d)
1,325	618	641	US	726	1,310
732	772	742	Europe	766	751
293	312	312	Rest of World	299	293
2,350	1,702	1,695		1,791	2,354
95.0	95.3	95.6	Refining availability (%)(e)	95.3	94.8
			Marketing sales of refined products (mb/d)
1,393	1,211	1,179	US	1,282	1,396
1,236	1,284	1,189	Europe	1,237	1,230
599	551	603	Rest of World	565	587
3,228	3,046	2,971		3,084	3,213
2,434	2,596	2,504	Trading/supply sales of refined products	2,485	2,444
5,662	5,642	5,475	Total sales volumes of refined products	5,569	5,657
			Petrochemicals production (kte)
959	1,114	993	US	4,264	4,047
925	999	952	Europe(c)	3,779	3,927
1,500	1,538	1,426	Rest of World	5,900	6,753
3,384	3,651	3,371		13,943	14,727

(a)	Fair value accounting effects represent the favourable (unfavourable) impact relative to management's measure of performance. For Downstream, these arise solely in the fuels business. Further information is provided on page 21.
(b)	Segment-level overhead expenses are included in the fuels business result.
(c)	BP's share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.
(d)	The 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. In 2013 BP updated the RMM methodology; prior periods have been restated.
(e)	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.

Top of page 10

Rosneft

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
-	836	901	Profit before interest and tax(a)(b)	2,053	-
-	(44)	157	Inventory holding (gains) losses	100	-
-	792	1,058	RC profit before interest and tax(b)	2,153	-
-	16	29	Net charge (credit) for non-operating items	45	-
-	808	1,087	Underlying RC profit before interest and tax(b)(c)	2,198	-

(a)	BP's share of Rosneft's earnings after finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation.
(b)	Third quarter and full year 2013 include $5 million of foreign exchange losses arising on the dividend received. This amount is not reflected in the table below.
(c)	See page 3 for information on underlying RC profit.

Following the completion of the sale and purchase agreements with Rosneft and Rosneftegaz on 21 March 2013, BP's investment in Rosneft is reported as a separate operating segment under IFRS. See Note 3 on page 31 for further information.

Replacement cost profit before interest and tax for the fourth quarter and full year was $1,058 million and $2,153 million respectively. The fourth-quarter and full-year results included non-operating charges of $29 million and $45 million respectively, mainly relating to impairment charges. After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $1,087 million and $2,198 million respectively. BP's reported share of the fourth quarter result was higher than the amount reported for the third quarter. The fourth quarter was favourably impacted by the finalization of BP's equity accounting for the year, and included certain adjustments to net income in respect of prior quarters. These effects were partially offset by adverse foreign exchange, duty lag effects and lower realizations.

The Rosneft segment result included equity-accounted earnings from Rosneft, representing BP's 19.75% shareholding in Rosneft. BP's share of the components of Rosneft's net income is shown in the table below. BP completed the exercise to determine the fair value of its share of Rosneft's assets and liabilities as at 21 March 2013, as required under IFRS, and the results of this exercise are reflected in the fourth quarter and full year 2013 reported amounts.

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Income statement (BP share)
-	1,197	1,062	Profit before interest and tax	2,786	-
-	(18)	(116)	Finance costs	(264)	-
-	(272)	(97)	Taxation	(422)	-
-	(66)	52	Non-controlling interests	(42)	-
-	841	901	Net income	2,058	-
-	(44)	157	Inventory holding (gains) losses, net of tax	100	-
-	797	1,058	Net income on a RC basis	2,158	-
-	16	29	Net charge (credit) for non-operating items, net of tax	45	-
-	813	1,087	Net income on an underlying RC basis	2,203	-
			Cash flow statement
-	456	-	Dividends received	456	-

	31 December	31 December
$ million	2013	2012
Balance sheet
Investments in associates	13,681	-

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
			Production (net of royalties) (BP share)(d)(e)
-	828	833	Liquids (mb/d)(f)	650	-
-	793	884	Natural gas (mmcf/d)	617	-
-	965	985	Total hydrocarbons (mboe/d)(g)	756	-

(d)	Information on BP's share of TNK-BP's production for comparative periods is provided on page 22.
(e)	Full year 2013 reflects production for the period 21 March to 31 December, averaged over the full year.
(f)	Liquids comprise crude oil, condensate and natural gas liquids.
(g)	Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Top of page 11

Other businesses and corporate

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
(505)	(674)	(605)	Profit (loss) before interest and tax	(2,319)	(2,794)
-	-	-	Inventory holding (gains) losses	-	-
(505)	(674)	(605)	RC profit (loss) before interest and tax	(2,319)	(2,794)
57	289	(9)	Net charge (credit) for non-operating items	421	798
(448)	(385)	(614)	Underlying RC profit (loss) before interest and tax(a)	(1,898)	(1,996)
			Underlying RC profit (loss) before
			interest and tax(a)
(291)	(309)	(228)	US	(800)	(859)
(157)	(76)	(386)	Non-US	(1,098)	(1,137)
(448)	(385)	(614)		(1,898)	(1,996)
			Non-operating items
(54)	(297)	(14)	US	(449)	(782)
(3)	8	23	Non-US	28	(16)
(57)	(289)	9		(421)	(798)
			RC profit (loss) before interest and tax
(345)	(606)	(242)	US	(1,249)	(1,641)
(160)	(68)	(363)	Non-US	(1,070)	(1,153)
(505)	(674)	(605)		(2,319)	(2,794)

(a)	See page 3 for information on underlying RC profit or loss.

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.

The replacement cost loss before interest and tax for the fourth quarter and full year was $605 million and $2,319 million respectively, compared with $505 million and $2,794 million for the same periods in 2012.

The fourth-quarter result included a net non-operating credit of $9 million, compared with a net charge of $57 million for the same period in 2012. For the full year, the net non-operating charge was $421 million, compared with $798 million for the same period in 2012.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $614 million and $1,898 million respectively, compared with $448 million and $1,996 million for the same periods last year. The fourth-quarter 2012 result included certain one-off benefits in corporate costs that were not present in the fourth quarter 2013.

In Alternative Energy, net wind generation capacity(b) at the end of both 2013 and 2012 was 1,590MW (2,619MW gross). BP's net share of wind generation for the fourth quarter was 1,203GWh (2,106GWh gross), compared with 1,015GWh (1,678GWh gross) in the same period of 2012. For the full year, BP's net share was 4,203GWh (7,363GWh gross), compared with 3,587GWh (5,739GWh gross) in 2012.

In our biofuels business, we have three operating mills in Brazil where ethanol-equivalent production(c) for the fourth quarter was 129 million litres compared with 100 million litres in the same period of 2012. For the full year, ethanol-equivalent production was 492 million litres compared with 404 million litres a year ago.

In 2014, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be in the range of $400 million to $500 million although this will fluctuate from quarter to quarter.

(b)		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. Capacity figures include 32MW in the Netherlands managed by our Downstream segment.
(c)	Ethanol-equivalent production includes ethanol and sugar.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.

Top of page 12

Gulf of Mexico oil spill

BP continues to support completion of the operational clean-up response, facilitation of economic restoration through claims processes, and facilitation of environmental restoration through natural resource damage assessment and early restoration projects relating to the Gulf of Mexico oil spill.

Financial update

The replacement cost loss before interest and tax for the fourth quarter was $179 million, compared with a $4,126 million loss for the same period in 2012. The fourth-quarter charge reflects an increase in the provision for legal costs, as well as the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $42.7 billion.

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities in Note 2 on page 27, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed, as further described under Principal risks and uncertainties on pages 35 - 42 of our second-quarter 2013 results announcement.

Trust update

During the fourth quarter, $281 million was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $234 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $47 million for natural resource damage assessment. In addition, $72 million was paid out to claimants from the seafood compensation fund, for which the related provision and reimbursement asset had been previously derecognized upon funding of the QSF. As at 31 December 2013, the aggregate cash balances in the Trust and the QSFs amounted to $6.7 billion, including $1.2 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration projects.

As at 31 December 2013, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, amounted to $19.3 billion. No amount is provided for business economic loss claims not yet received, processed, and paid by the DHCSSP. See Note 2 on pages 25 - 31 and Legal proceedings on pages 35 - 37 for further details.

Legal proceedings

Phase 2 of the Trial of Liability, Limitation, Exoneration and Fault Allocation in the multi-district litigation proceedings in federal District Court (the District Court) in New Orleans (MDL 2179) commenced on 30 September 2013 to consider the issues of source control efforts and the volume of oil spilled into the Gulf as a result of the incident. That phase completed on 18 October 2013 and post-trial briefing was completed on 24 January 2014. BP does not know when the District Court will rule on the issues presented in either this phase or the previous phase of that trial and the court could issue its decision at any time. The District Court has not yet scheduled a hearing on the subsequent phase regarding the application of statutory penalty factors.

On 4 November 2013, a panel of the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) heard oral arguments in relation to appeals involving challenges to the final order and judgment that approved the Economic and Property Damages settlement (the EPD Settlement) and certified the class. On 10 January 2014, that panel of the Fifth Circuit issued its ruling upholding the approval of the settlement but left to another panel of the Fifth Circuit (the business economic loss panel) the question of how to interpret the EPD Settlement agreement, including the meaning of the causation requirements of that agreement. BP and several of the original appellants have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold the approval of the EPD Settlement.

There have been various rulings from the District Court and the business economic loss panel of the Fifth Circuit on matters relating to the interpretation of the EPD Settlement, in particular on the issue of matching of revenue and expenses as well as causation requirements of the EPD Settlement agreement.

On 24 December 2013, the District Court ruled on the issues in relation to the matching of revenue and expenses and causation under the EPD Settlement, that were remanded to it by the business economic loss panel of the Fifth Circuit. Regarding matching, the District Court reversed its earlier decision and ruled that the claims administrator, in administering business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed matching requirements. Regarding causation, the District Court ruled that the EPD Settlement agreement contained no causation requirement for class membership. The District Court maintained an injunction on business economic loss claims payments and offers pending further action by the Fifth Circuit. BP has appealed the District Court's ruling on causation to the business economic loss panel of the Fifth Circuit and has moved for a permanent injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not traceable to the spill. The business economic loss panel has agreed to hear the appeal on an expedited basis.

For further details, see Legal proceedings on pages 35 - 37.

Top of page 13

Group income statement

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
93,910	96,601	93,717	Sales and other operating revenues (Note 4)	379,136	375,765
38	119	101	Earnings from joint ventures - after interest and tax	447	260
322	1,010	1,000	Earnings from associates - after interest and tax	2,742	3,675
1,129	178	235	Interest and other income	777	1,677
4,412	295	43	Gains on sale of businesses and fixed assets	13,115	6,697
99,811	98,203	95,096	Total revenues and other income	396,217	388,074
74,061	76,603	74,960	Purchases	298,351	292,774
12,240	6,276	7,257	Production and manufacturing expenses(a)	27,527	33,926
2,073	1,889	1,491	Production and similar taxes (Note 5)	7,047	8,158
3,248	3,415	3,736	Depreciation, depletion and amortization	13,510	12,687
			Impairment and losses on sale of businesses and
828	767	474	fixed assets	1,961	6,275
309	511	2,174	Exploration expense	3,441	1,475
3,389	3,411	3,482	Distribution and administration expenses	13,070	13,357
(104)	(238)	(55)	Fair value gain on embedded derivatives	(459)	(347)
3,767	5,569	1,577	Profit before interest and taxation	31,769	19,769
307	279	255	Finance costs(a)	1,068	1,072
			Net finance expense relating to pensions and other
160	118	123	post-retirement benefits	480	566
3,300	5,172	1,199	Profit before taxation	30,221	18,131
1,750	1,580	101	Taxation(a)	6,463	6,880
1,550	3,592	1,098	Profit for the period	23,758	11,251
			Attributable to
1,488	3,504	1,042	BP shareholders	23,451	11,017
62	88	56	Non-controlling interests	307	234
1,550	3,592	1,098		23,758	11,251

			Earnings per share - cents (Note 6)
			Profit for the period attributable to BP
			shareholders
7.80	18.57	5.57	Basic	123.87	57.89
7.75	18.47	5.54	Diluted	123.12	57.50

(a)	See Note 2 for further details of the impact of the Gulf of Mexico oil spill on the income statement line items.

Top of page 14

Group statement of comprehensive income

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012

1,550	3,592	1,098	Profit for the period	23,758	11,251
			Other comprehensive income
			Items that may be reclassified subsequently to profit
			or loss
246	662	(177)	Currency translation differences	(1,608)	538
			Exchange gains (losses) on translation of foreign
			operations reclassified to gain or loss on sale of
(15)	9	13	businesses and fixed assets	22	(15)
290	-	-	Available-for-sale investments marked to market	(172)	306
			Available-for-sale investments reclassified to the
(1)	-	-	income statement	(523)	(1)
1,439	104	62	Cash flow hedges marked to market(a)	(2,000)	1,466
			Cash flow hedges reclassified to the income
3	2	3	statement	4	62
7	10	(8)	Cash flow hedges reclassified to the balance sheet	17	19
			Share of items relating to equity-accounted entities,
13	31	-	net of tax	(24)	(39)
(245)	(25)	(23)	Income tax relating to items that may be reclassified	147	(170)
1,737	793	(130)		(4,137)	2,166
			Items that will not be reclassified to profit or loss
			Remeasurements of the net pension and other post-
(1,506)	310	2,298	retirement benefit liability or asset	4,764	(1,625)
			Share of items relating to equity-accounted entities,
-	-	2	net of tax	2	(6)
			Income tax relating to items that will not be
367	(114)	(676)	reclassified	(1,521)	440
(1,139)	196	1,624		3,245	(1,191)
598	989	1,494	Other comprehensive income	(892)	975
2,148	4,581	2,592	Total comprehensive income	22,866	12,226
			Attributable to
2,088	4,485	2,533	BP shareholders	22,574	11,988
60	96	59	Non-controlling interests	292	238
2,148	4,581	2,592		22,866	12,226

(a)	Full year 2013 includes $2,061 million loss (fourth quarter and full year 2012 $1,410 million gain) relating to the contracts to acquire Rosneft shares. See Note 3 for further information.

Top of page 15

Group statement of changes in equity

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

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

Total comprehensive income	22,574	292	22,866
Dividends	(5,441)	(469)	(5,910)
Repurchases of ordinary share capital	(6,923)	-	(6,923)
Share-based payments, net of tax	473	-	473
Share of equity-accounted entities' changes in equity, net of tax	73	-	73
Transactions involving non-controlling interests	-	76	76
At 31 December 2013	129,302	1,105	130,407

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

At 1 January 2012	111,568	1,017	112,585

Total comprehensive income	11,988	238	12,226
Dividends	(5,294)	(82)	(5,376)
Share-based payments, net of tax	284	-	284
Transactions involving non-controlling interests	-	33	33
At 31 December 2012	118,546	1,206	119,752

Top of page 16

Group balance sheet

	31 December	31 December
$ million	2013	2012
Non-current assets
Property, plant and equipment	133,690	125,331
Goodwill	12,181	12,190
Intangible assets	22,039	24,632
Investments in joint ventures	9,199	8,614
Investments in associates	16,636	2,998
Other investments	1,565	2,704
Fixed assets	195,310	176,469
Loans	763	642
Trade and other receivables	5,985	5,961
Derivative financial instruments	3,509	4,294
Prepayments	922	830
Deferred tax assets	985	874
Defined benefit pension plan surpluses	1,376	12
	208,850	189,082
Current assets
Loans	216	247
Inventories	29,231	28,203
Trade and other receivables	39,831	37,611
Derivative financial instruments	2,675	4,507
Prepayments	1,388	1,091
Current tax receivable	512	456
Other investments	467	319
Cash and cash equivalents	22,520	19,635
	96,840	92,069
Assets classified as held for sale	-	19,315
	96,840	111,384
Total assets	305,690	300,466
Current liabilities
Trade and other payables	47,159	46,673
Derivative financial instruments	2,322	2,658
Accruals	8,960	6,875
Finance debt	7,381	10,033
Current tax payable	1,945	2,503
Provisions	5,045	7,587
	72,812	76,329
Liabilities directly associated with assets classified as held for sale	-	846
	72,812	77,175
Non-current liabilities
Other payables	4,756	2,292
Derivative financial instruments	2,225	2,723
Accruals	547	491
Finance debt	40,811	38,767
Deferred tax liabilities	17,439	15,243
Provisions	26,915	30,396
Defined benefit pension plan and other post-retirement benefit plan deficits	9,778	13,627
	102,471	103,539
Total liabilities	175,283	180,714
Net assets	130,407	119,752
Equity
BP shareholders' equity	129,302	118,546
Non-controlling interests	1,105	1,206
	130,407	119,752

Top of page 17

Condensed group cash flow statement

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Operating activities
3,300	5,172	1,199	Profit before taxation	30,221	18,131
			Adjustments to reconcile profit before taxation to net
			cash provided by operating activities
			Depreciation, depletion and amortization and
3,403	3,765	5,633	exploration expenditure written off	16,220	13,432
			Impairment and (gain) loss on sale of businesses and
(3,584)	472	431	fixed assets	(11,154)	(422)
			Earnings from equity-accounted entities, less dividends
(65)	(489)	(855)	received	(1,798)	(2,172)
			Net charge for interest and other finance expense,
9	170	(40)	less net interest paid	323	268
(109)	153	(77)	Share-based payments	297	156
			Net operating charge for pensions and other post-
			retirement benefits, less contributions and benefit
(434)	(67)	(483)	payments for unfunded plans	(920)	(858)
3,938	(360)	(84)	Net charge for provisions, less payments	1,061	5,338
			Movements in inventories and other current and
1,190	(812)	1,110	non-current assets and liabilities(a)	(6,843)	(6,912)
(1,269)	(1,672)	(1,420)	Income taxes paid	(6,307)	(6,482)
6,379	6,332	5,414	Net cash provided by operating activities	21,100	20,479
			Investing activities
(7,059)	(5,882)	(6,798)	Capital expenditure	(24,520)	(23,222)
-	-	(67)	Acquisitions, net of cash acquired	(67)	(116)
(457)	(54)	(299)	Investment in joint ventures	(451)	(1,526)
(17)	(64)	(39)	Investment in associates	(4,994)	(54)
6,804	307	372	Proceeds from disposals of fixed assets	18,115	9,992
			Proceeds from disposals of businesses, net of
67	94	5	cash disposed	3,884	1,606
70	36	52	Proceeds from loan repayments	178	245
(592)	(5,563)	(6,774)	Net cash used in investing activities	(7,855)	(13,075)
			Financing activities
61	(1,258)	(2,265)	Net issue (repurchase) of shares	(5,358)	122
3,031	3,245	2,467	Proceeds from long-term financing	8,814	11,087
(3,592)	(568)	(4,212)	Repayments of long-term financing	(5,959)	(7,177)
(668)	122	(268)	Net increase (decrease) in short-term debt	(2,019)	(666)
-	29	3	Net increase (decrease) in non-controlling interests	32	-
(1,217)	(1,247)	(1,174)	Dividends paid - BP shareholders	(5,441)	(5,294)
(10)	(140)	(213)	- non-controlling interests	(469)	(82)
(2,395)	183	(5,662)	Net cash provided by (used in) financing activities	(10,400)	(2,010)
			Currency translation differences relating to
69	234	43	cash and cash equivalents	40	64
3,461	1,186	(6,979)	Increase (decrease) in cash and cash equivalents	2,885	5,458
16,174	28,313	29,499	Cash and cash equivalents at beginning of period	19,635	14,177
19,635	29,499	22,520	Cash and cash equivalents at end of period	22,520	19,635

(a)

Includes

737	(394)	482	Inventory holding (gains) losses	190	534
(104)	(238)	(55)	Fair value gain on embedded derivatives	(459)	(347)
(771)	192	(33)	Movements related to Gulf of Mexico oil spill response	(2,099)	(6,088)

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 18

Capital expenditure and acquisitions

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			By segment
			Upstream
1,843	1,611	1,727	US(a)	6,439	6,385
3,345	3,124	3,751	Non-US(b)	12,676	12,135
5,188	4,735	5,478		19,115	18,520
			Downstream
902	559	360	US	2,535	3,475
799	438	921	Non-US	1,971	1,774
1,701	997	1,281		4,506	5,249
			Rosneft
-	-	-	Non-US(c)	11,941	-
-	-	-		11,941	-
			Other businesses and corporate
143	54	85	US	231	681
395	136	375	Non-US	819	754
538	190	460		1,050	1,435
7,427	5,922	7,219		36,612	25,204
			By geographical area
2,888	2,224	2,172	US(a)	9,205	10,541
4,539	3,698	5,047	Non-US(b)(c)	27,407	14,663
7,427	5,922	7,219		36,612	25,204
			Included above:
45	-	71	Acquisitions and asset exchanges	71	200
543	-	-	Other inorganic capital expenditure(a)(b)(c)	11,941	1,054

(a)	Fourth quarter and full year 2012 include $388 million and $899 million respectively associated with deepening our natural gas asset base.
(b)	Fourth quarter 2012 includes $155 million related to increasing our interest in North Sea assets.
(c)	Full year 2013 includes $11,941 million relating to our investment in Rosneft - see Note 3 for further information.

Exchange rates

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
1.61	1.55	1.62	US dollar/sterling average rate for the period	1.56	1.58
1.62	1.61	1.65	US dollar/sterling period-end rate	1.65	1.62
1.30	1.32	1.36	US dollar/euro average rate for the period	1.33	1.28
1.32	1.35	1.38	US dollar/euro period-end rate	1.38	1.32

Top of page 19

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
7,688	4,158	2,537	Upstream	16,657	22,491
1,329	616	(360)	Downstream	2,919	2,864
575	-	-	TNK-BP(a)	12,500	3,373
-	792	1,058	Rosneft(b)	2,153	-
(505)	(674)	(605)	Other businesses and corporate	(2,319)	(2,794)
9,087	4,892	2,630		31,910	25,934
(4,126)	(30)	(179)	Gulf of Mexico oil spill response	(430)	(4,995)
(428)	263	(240)	Consolidation adjustment - UPII	579	(576)
4,533	5,125	2,211	RC profit before interest and tax	32,059	20,363
			Inventory holding gains (losses)
4	7	3	Upstream	4	(104)
(765)	393	(480)	Downstream	(194)	(487)
(5)	-	-	TNK-BP (net of tax)	-	(3)
-	44	(157)	Rosneft (net of tax)	(100)	-
3,767	5,569	1,577	Profit before interest and tax	31,769	19,769
307	279	255	Finance costs	1,068	1,072
			Net finance expense relating to pensions and
160	118	123	other post-retirement benefits	480	566
3,300	5,172	1,199	Profit before taxation	30,221	18,131

			RC profit before interest and tax
1,069	560	(258)	US	3,279	180
3,464	4,565	2,469	Non-US	28,780	20,183
4,533	5,125	2,211		32,059	20,363

(a)	BP ceased equity accounting for its share of TNK-BP's earnings from 22 October 2012. See Note 3 on page 31 for further information.
(b)	BP's investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 10 for further information.

IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, both replacement cost (RC) profit or loss before interest and tax and underlying RC profit or loss before interest and tax (see page 3 for further information) are provided regularly to the chief operating decision maker. In such cases IFRS requires that the measure of profit disclosed for each operating segment is the measure that is closest to IFRS, which for BP is RC profit or loss before interest and tax. In addition, a reconciliation is required between the total of the operating segments' measures of profit or loss and the group profit or loss before taxation.

RC profit or loss reflects the replacement cost of supplies. The RC profit or loss for the period is arrived at by excluding from profit or loss inventory holding gains and losses and their associated tax effect. RC profit or loss for the group is not a recognized GAAP measure.

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

Management believes this information is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP's management believes it is helpful to disclose this information.

Top of page 20

Non-operating items(a)

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Upstream
			Impairment and gain (loss) on sale of businesses and
3,673	(374)	(391)	fixed assets	(802)	3,638
-	(21)	1	Environmental and other provisions	(20)	(48)
-	-	-	Restructuring, integration and rationalization costs	-	-
103	238	55	Fair value gain (loss) on embedded derivatives	459	347
(430)	(69)	(866)	Other(b)	(1,001)	(748)
3,346	(226)	(1,201)		(1,364)	3,189
			Downstream
			Impairment and gain (loss) on sale of businesses and
(81)	(11)	(61)	fixed assets	(348)	(2,934)
-	(132)	7	Environmental and other provisions	(134)	(171)
13	-	(11)	Restructuring, integration and rationalization costs	(15)	(32)
-	-	-	Fair value gain (loss) on embedded derivatives	-	-
(5)	(14)	(9)	Other	(38)	(35)
(73)	(157)	(74)		(535)	(3,172)
			TNK-BP
			Impairment and gain (loss) on sale of businesses and
-	-	-	fixed assets	12,500	(55)
(33)	-	-	Environmental and other provisions	-	(83)
-	-	-	Restructuring, integration and rationalization costs	-	-
-	-	-	Fair value gain (loss) on embedded derivatives	-	-
384	-	-	Other	-	384
351	-	-		12,500	246
			Rosneft
			Impairment and gain (loss) on sale of businesses and
-	(16)	(19)	fixed assets	(35)	-
-	-	(10)	Environmental and other provisions	(10)	-
-	-	-	Restructuring, integration and rationalization costs	-	-
-	-	-	Fair value gain (loss) on embedded derivatives	-	-
-	-	-	Other	-	-
-	(16)	(29)		(45)	-
			Other businesses and corporate
			Impairment and gain (loss) on sale of businesses and
(8)	(87)	21	fixed assets	(196)	(282)
-	(216)	(19)	Environmental and other provisions	(241)	(261)
(14)	(4)	3	Restructuring, integration and rationalization costs	(3)	(15)
1	-	-	Fair value gain (loss) on embedded derivatives	-	-
(36)	18	4	Other	19	(240)
(57)	(289)	9		(421)	(798)
(4,126)	(30)	(179)	Gulf of Mexico oil spill response	(430)	(4,995)
(559)	(718)	(1,474)	Total before interest and taxation	9,705	(5,530)
(6)	(9)	(10)	Finance costs(c)	(39)	(19)
(565)	(727)	(1,484)	Total before taxation	9,666	(5,549)
(1,258)	205	481	Taxation credit (charge)(d)	867	251
(1,823)	(522)	(1,003)	Total after taxation for period	10,533	(5,298)

(a)	Non-operating items are charges and credits arising in consolidated entities and in TNK-BP and Rosneft that are included in the financial statements and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. An analysis of non-operating items by region is shown on pages 7, 9 and 11.
(b)	Fourth quarter and full year 2013 include $845 million relating to the value ascribed to block BM-CAL-13 offshore Brazil, following the acquisition of upstream assets from Devon Energy in 2011, which was written off as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas. See also page 7.
(c)	Finance costs relate to the Gulf of Mexico oil spill. See Note 2 for further details.
(d)	For the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, tax 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 the deferred tax adjustment relating to a reduction in UK corporation tax rates ($99 million for the third quarter 2013)). Non-operating items reported within the equity-accounted earnings of TNK-BP and Rosneft are reported net of tax.

Top of page 21

Non-GAAP information on fair value accounting effects

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Favourable (unfavourable) impact relative to
			management's measure of performance
(33)	(39)	(114)	Upstream	(244)	(134)
8	53	(356)	Downstream	(178)	(427)
(25)	14	(470)		(422)	(561)
5	(6)	171	Taxation credit (charge)(a)	142	216
(20)	8	(299)		(280)	(345)

(a)

Tax is calculated using the group's discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, equity-accounted earnings, certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives and the deferred tax adjustment relating to a reduction in UK corporation tax rates ($99 million for the third quarter 2013)).

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.

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Upstream
			Replacement cost profit before interest and tax
7,721	4,197	2,651	adjusted for fair value accounting effects	16,901	22,625
(33)	(39)	(114)	Impact of fair value accounting effects	(244)	(134)
7,688	4,158	2,537	Replacement cost profit before interest and tax	16,657	22,491
			Downstream
			Replacement cost profit (loss) before interest and
1,321	563	(4)	tax adjusted for fair value accounting effects	3,097	3,291
8	53	(356)	Impact of fair value accounting effects	(178)	(427)
1,329	616	(360)	Replacement cost profit (loss) before interest and tax	2,919	2,864
			Total group
			Profit before interest and tax
3,792	5,555	2,047	adjusted for fair value accounting effects	32,191	20,330
(25)	14	(470)	Impact of fair value accounting effects	(422)	(561)
3,767	5,569	1,577	Profit before interest and tax	31,769	19,769

Top of page 22

Realizations and marker prices

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
			Average realizations(a)
			Liquids ($/bbl)(b)
94.36	91.20	89.87	US	91.88	96.35
104.80	107.78	105.23	Europe	104.77	109.05
104.59	107.21	104.60	Rest of World	104.20	105.84
100.00	100.66	98.26	BP Average	99.24	102.10
			Natural gas ($/mcf)
2.62	2.91	3.08	US	3.07	2.32
9.33	9.72	9.95	Europe	9.68	8.63
5.58	5.67	6.21	Rest of World	5.97	5.33
5.03	5.01	5.49	BP Average	5.35	4.75
			Total hydrocarbons ($/boe)
62.40	59.24	62.11	US	60.78	61.57
84.38	95.00	93.29	Europe	90.46	85.24
59.04	61.74	63.36	Rest of World	61.72	58.13
62.38	62.80	65.04	BP Average	63.58	61.86
			Average oil marker prices ($/bbl)
110.08	110.29	109.24	Brent	108.66	111.67
88.15	105.79	97.59	West Texas Intermediate	97.99	94.13
107.08	110.52	104.80	Alaska North Slope	107.67	111.08
103.56	104.77	95.98	Mars	102.23	106.79
108.64	109.36	107.65	Urals (NWE - cif)	107.38	110.19
54.23	57.11	55.95	Russian domestic oil	54.97	53.98
			Average natural gas marker prices
3.41	3.58	3.60	Henry Hub gas price ($/mmBtu)(c)	3.65	2.79
65.26	65.21	67.48	UK Gas - National Balancing Point (p/therm)	67.99	59.74

(a)	Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b)	Crude oil and natural gas liquids.
(c)	Henry Hub First of Month Index.

BP share of TNK-BP production for comparative periods

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013		2013	2012
			Production (net of royalties) (BP share)(a)(b)
870	-	-	Crude oil (mb/d)	187	876
818	-	-	Natural gas (mmcf/d)	184	784
1,011	-	-	Total hydrocarbons (mboe/d)(c)	218	1,012

(a)	BP continued to report its share of TNK-BP's production and reserves following the agreement to sell its 50% share to Rosneft until the sale completed on 21 March 2013. Estimated hydrocarbon production for the full year 2013 represents BP's share of TNK-BP's estimated production from 1 January to 20 March, averaged over the full year.
(b)	On 21 March 2013, Rosneft acquired 100% of TNK-BP. BP's share of Rosneft production, which includes TNK-BP, is shown on page 10.
(c)	Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Top of page 23

Notes

1. Basis of preparation

(a) Basis of preparation

The results for the interim periods and for the year ended 31 December 2013 are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature. The directors draw attention to Note 2 on pages 25 - 31 which describes the uncertainties surrounding the amounts and timings of liabilities arising from the Gulf of Mexico oil spill. It is likely that the independent auditor's report in the BP Annual Report and Form 20-F 2013 will contain an emphasis of matter paragraph in relation to this matter.

The directors have a reasonable expectation that the company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual financial statements. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2012 included in the BP Annual Report and Form 20-F 2012.

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 2013. These accounting policies differ from those used in BP Annual Report and Form 20-F 2012 as noted below.

Segmental reporting

On 21 March 2013, BP completed sale and purchase agreements with Rosneft and Rosneftegaz - the Russian state-owned parent company of Rosneft - for the sale of BP's 50% interest in TNK-BP to Rosneft, and for BP's further investment in Rosneft. With effect from that date, BP's 19.75% shareholding in Rosneft is accounted for using the equity method and is reported as a separate operating segment.

Comparative group income statement and group balance sheet

As noted in BP's results announcement for the first quarter 2013, in addition to the changes made to the comparative data presented in this report as a result of the adoption of the amended IAS 19 and the new standard IFRS 11 (as detailed below), the comparative group balance sheet as at 31 December 2012 also reflects an adjustment, made subsequent to releasing our unaudited fourth quarter and full year 2012 results announcement dated 5 February 2013, which was included in the balance sheet approved by the board of directors on 6 March 2013 and published in BP Annual Report and Form 20-F 2012. The difference relates to an adjustment of $0.8 billion that was made to decrease provisions relating to the Gulf of Mexico oil spill as at 31 December 2012, with a corresponding decrease in the reimbursement asset. There was no impact on profit or loss for the year. A further adjustment was made to the group income statement to correct a $4.7-billion understatement of revenue and purchases for the year ended 31 December 2012. There was no impact on profit or loss for the year. For further information, see BP Annual Report and Form 20-F 2012.

New or amended International Financial Reporting Standards adopted

BP adopted several new or amended accounting standards issued by the IASB with effect from 1 January 2013.

IFRS 10 'Consolidated Financial Statements', IFRS 11 'Joint Arrangements' and IFRS 12 'Disclosure of Interests in Other Entities' were issued in May 2011. The main impact of this suite of new standards for BP is that certain of the group's jointly controlled entities, which were previously equity-accounted, now fall under the definition of a joint operation under IFRS 11 and so we now recognize the group's assets, liabilities, revenue and expenses relating to these arrangements. Whilst the effect on the group's reported income and net assets as a result of the new requirements is not material, the change impacts certain of the component lines of the income statement, balance sheet and cash flow statement. On the balance sheet, there was a reduction in investments in joint ventures of approximately $7 billion as at 31 December 2012, which has been replaced with the recognition (on the relevant line items, principally intangible assets and property, plant and equipment) of our share of the assets and liabilities relating to these arrangements.

An amended version of IAS 19 'Employee Benefits' was issued in June 2011. The main impact for BP is that the expense for defined benefit pension and other post-retirement benefit plans now includes a net interest income or expense, which is calculated by applying the discount rate used for measuring the obligation and applying that to the net defined benefit asset or liability. This means that the expected return on assets credited to profit or loss (previously calculated based on the expected long-term return on pension assets) is now based on a lower corporate bond rate, the same rate that is used to discount the pension liability. Under the amended IAS 19, profit before tax was $763 million and $1,001 million lower for full year 2012 and 2013 respectively, with corresponding pre-tax increases in other comprehensive income. There is no impact on cash flows or on the balance sheet at 31 December 2012 or 31 December 2013.

Top of page 24

Notes

1. Basis of preparation (continued)

The accounting policies which will be used in preparing BP Annual Report and Form 20-F 2013 which differ from those used in BP Annual Report and Form 20-F 2012 are shown in full in BP Financial and Operating Information 2008-2012 available on bp.com/investors.

There are no other new or amended standards or interpretations adopted with effect from 1 January 2013 that have a significant effect on the financial statements.

(b) Impact of the adoption of new or amended International Financial Reporting Standards

The following tables set out the adjustments made to certain selected line items of the previously reported comparative amounts as a result of the adoption of the amended IAS 19 'Employee Benefits' and the new standard IFRS 11 'Joint Arrangements'.

Annual restated information for 2012 is shown in BP Financial and Operating Information 2008-2012 available on bp.com/investors. Full restated quarterly information for 2012 was published in the quarterly supplement of BP Financial and Operating Information 2008-2012 on bp.com/investors in May 2013.

	First		Second		Third		Fourth		Full
	quarter		quarter		quarter		quarter		year
	2012		2012		2012		2012		2012
Selected lines only	As	As	As	As	As	As	As	As	As	As
	reported	restated	reported	restated	reported	restated	reported	restated	reported	restated
$ million
(except per share amounts)
Income statement
Earnings from joint
ventures - after interest
and tax	290	151	88	(36)	235	107	131	38	744	260
Net finance income
(expense) relating to
pensions and other
post-retirement benefits	53	(136)	55	(137)	58	(133)	35	(160)	201	(566)
Profit (loss) for the period	5,976	5,828	(1,340)	(1,474)	5,500	5,347	1,680	1,550	11,816	11,251

Earnings per share
Basic (cents)	31.17	30.39	(7.29)	(7.99)	28.54	27.74	8.48	7.80	60.86	57.89
Diluted (cents)	30.74	29.97	(7.29)	(7.99)	28.39	27.59	8.43	7.75	60.45	57.50

Replacement cost profit
(loss) before interest
and tax
Upstream
US	2,534	2,534	(1,584)	(1,584)	1,178	1,178	4,790	4,790	6,918	6,918
Non-US	4,445	4,449	4,497	4,497	3,732	3,729	2,882	2,898	15,556	15,573
	6,979	6,983	2,913	2,913	4,910	4,907	7,672	7,688	22,474	22,491
Downstream
US	158	158	(1,984)	(1,984)	1,106	1,106	478	478	(242)	(242)
Non-US	698	701	248	252	1,297	1,302	845	851	3,088	3,106
	856	859	(1,736)	(1,732)	2,403	2,408	1,323	1,329	2,846	2,864
Group
US	1,935	1,935	(4,246)	(4,246)	1,422	1,422	1,069	1,069	180	180
Non-US	5,781	5,789	4,967	4,971	5,956	5,959	3,443	3,464	20,147	20,183
	7,716	7,724	721	725	7,378	7,381	4,512	4,533	20,327	20,363

Balance sheet
Property, plant and
equipment	119,991	124,379	117,565	121,960	119,687	124,288	120,488	125,331	120,488	125,331
Intangible assets	22,000	22,570	22,345	22,919	23,184	23,766	24,041	24,632	24,041	24,632
Investments in joint
ventures	15,862	8,578	15,672	8,532	15,920	8,843	15,724	8,614	15,724	8,614
Net assets	119,220	119,315	113,323	113,415	118,773	118,883	119,620	119,752	119,620	119,752

Cash flow statement
Profit (loss) before
taxation	8,923	8,756	(1,815)	(1,989)	8,239	8,064	3,462	3,300	18,809	18,131
Net cash provided by
(used in) operating
activities	3,367	3,406	4,403	4,448	6,287	6,246	6,340	6,379	20,397	20,479
Net cash provided by
(used in) investing
activities	(4,329)	(4,308)	(3,462)	(3,473)	(4,672)	(4,702)	(499)	(592)	(12,962)	(13,075)
Increase (decrease) in
cash and cash
equivalents	25	90	789	808	1,160	1,099	3,507	3,461	5,481	5,458

Top of page 25

Notes

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 2012 - Financial statements - Note 2, Note 36 and Note 43 and Legal proceedings on pages 162 - 169 and on pages 35 - 37 of this report. In addition, further information will be included in BP Annual Report and Form 20-F 2013 which will be available from early March 2014.

The group income statement includes a pre-tax charge of $189 million for the fourth quarter in relation to the Gulf of Mexico oil spill and $469 million for the full year. The fourth-quarter charge reflects an increase in the provision for legal costs, as well as the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $42,676 million.

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

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further described under Principal risks and uncertainties on pages 35 - 42 of our second-quarter 2013 results announcement.

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.

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Income statement
4,126	30	179	Production and manufacturing expenses	430	4,995
(4,126)	(30)	(179)	Profit (loss) before interest and taxation	(430)	(4,995)
6	9	10	Finance costs	39	19
(4,132)	(39)	(189)	Profit (loss) before taxation	(469)	(5,014)
69	(44)	80	Taxation	73	94
(4,063)	(83)	(109)	Profit (loss) for the period	(396)	(4,920)

		31 December 2013	31 December 2012
		Of which:		Of which:
		amount related		amount related
$ million	Total	to the trust fund	Total	to the trust fund
Balance sheet
Current assets
Trade and other receivables	2,457	2,457	4,239	4,178
Current liabilities
Trade and other payables	(1,030)	(1)	(522)	(22)
Provisions	(2,951)	-	(5,449)	-
Net current assets (liabilities)	(1,524)	2,456	(1,732)	4,156
Non-current assets
Other receivables	2,442	2,442	2,264	2,264
Non-current liabilities
Other payables	(2,986)	-	(175)	-
Provisions	(6,395)	-	(9,751)	-
Deferred tax	2,748	-	4,002	-
Net non-current assets (liabilities)	(4,191)	2,442	(3,660)	2,264
Net assets (liabilities)	(5,715)	4,898	(5,392)	6,420

Top of page 26

Notes

2. Gulf of Mexico oil spill (continued)

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Cash flow statement - Operating activities
(4,132)	(39)	(189)	Profit (loss) before taxation	(469)	(5,014)
			Adjustments to reconcile profit (loss) before
			taxation to net cash provided by operating
			activities
			Net charge for interest and other finance
6	9	10	expense, less net interest paid	39	19
3,618	(576)	11	Net charge for provisions, less payments	1,129	4,834
			Movements in inventories and other current
(771)	192	(33)	and non-current assets and liabilities	(2,099)	(6,088)
(1,279)	(414)	(201)	Pre-tax cash flows	(1,400)	(6,249)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an inflow of $120 million and an outflow of $73 million in the fourth quarter and full year respectively. For the same periods in 2012, the amounts were an inflow of $629 million and an outflow of $2,382 million respectively.

Trust fund

BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. The Trust is available to fund the qualified settlement funds (QSFs) established under the terms of the settlement agreements (comprising the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) and the Medical Benefits Class Action Settlement) with the PSC administered through the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), and the separate BP claims programme - see below for further information. 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. We use the term 'reimbursement asset' to describe this asset. BP will not actually receive any reimbursements from the trust fund, instead payments will be made directly from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements. The table below shows movements in the reimbursement asset during the period to 31 December 2013. The net increase in the provision of $1,542 million for the full year relates principally to business economic loss claims processed by the DHCSSP subsequent to finalization of the BP Annual Report and Form 20-F 2012 that have been paid as well as increases in the provision for claims administration costs. For more information about the movement in provisions for items covered by the trust fund, see Provisions below. The amount of the reimbursement asset at 31 December 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund - see below.

	Fourth
	quarter	Year
$ million	2013	2013
Opening balance	5,147	6,442
Net increase (decrease) in provision for items covered by the trust fund	33	1,921
Derecognition of provision for items that can no longer be estimated reliably	-	(379)
Amounts paid directly by the trust fund	(281)	(3,085)
At 31 December 2013	4,899	4,899
Of which - current	2,457	2,457
- non-current	2,442	2,442

Top of page 27

Notes

2. Gulf of Mexico oil spill (continued)

Any increases in estimated future expenditure that will be covered by the trust fund (up to an aggregate of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 31 December 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,338 million. Thus, a further $662 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. Additional liabilities in excess of this amount regarding claims under the Oil Pollution Act of 1990 (OPA 90), claims that are currently administered by the DHCSSP, or otherwise, including the various claims described in Legal proceedings on pages 35 - 37 of this report and on pages 162 - 169 of BP Annual Report and Form 20-F 2012, would be expensed to the income statement. Information on those items that currently cannot be estimated reliably is provided under Provisions and contingent liabilities below.

Under the terms of the EPD Settlement Agreement with the PSC, several QSFs were established in 2012. These QSFs each relate to specific elements of the agreement, have been and will continue to be funded through payments from the Trust, and are available to make payments to claimants in accordance with those elements of the agreement.

As at 31 December 2013, the aggregate cash balances in the Trust and the QSFs amounted to $6.7 billion, including $1.2 billion remaining in the seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. Should the cash balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.

The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012. See Provisions below for further information on the current status of the EPD Settlement Agreement. In addition, a separate BP claims programme began processing claims from claimants not in the Economic and Property Damages class as determined by the EPD Settlement Agreement or who have requested to opt out of that settlement. Payments made to claimants through the BP claims programme are paid directly from the Trust.A separate claims administrator has been appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on pages 35 - 37 of this report and on pages 166 - 168 of BP Annual Report and Form 20-F 2012.

(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 2012 - Financial statements - Notes 2, 36 and 43.

Provisions

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

				Litigation	Clean
			Spill	and	Water Act
$ million		Environmental	response	claims	penalties	Total
At 1 October 2013		1,609	156	4,341	3,510	9,616
Increase in provision - items not
covered by the trust fund		-	-	150	-	150
Increase in provision - items
covered by the trust fund		-	-	33	-	33
Transfer of amounts between
categories of provision		47	(47)	-	-	-
Change in discount rate		(5)	-	-	-	(5)
Utilization	- paid by BP	(14)	(20)	(133)	-	(167)
	- paid by the trust fund	(47)	-	(234)	-	(281)
At 31 December 2013		1,590	89	4,157	3,510	9,346
Of which	- current	389	84	2,478	-	2,951
	- non-current	1,201	5	1,679	3,510	6,395
Of which	- payable from the
	trust fund	1,253	-	3,595	-	4,848

Top of page 28

Notes

2. Gulf of Mexico oil spill (continued)

				Litigation	Clean
			Spill	and	Water Act
$ million		Environmental	response	claims	penalties	Total
At 1 January 2013		1,862	345	9,483	3,510	15,200
Increase (decrease) in provision -
items not covered by the trust fund		(24)	(66)	408	-	318
Increase in provision - items
covered by the trust fund		24	-	1,897	-	1,921
Derecognition of provision for items
that can no longer be
estimated reliably		-	-	(379)	-	(379)
Transfer of amounts between
categories of provision		47	(47)	-	-	-
Change in discount rate		(5)	-	-	-	(5)
Unwinding of discount		1	-	-	-	1
Reclassified to other payables		-	-	(3,933)	-	(3,933)
Utilization	- paid by BP	(60)	(143)	(523)	-	(726)
	- paid by the trust fund	(255)	-	(2,796)	-	(3,051)
At 31 December 2013		1,590	89	4,157	3,510	9,346

Environmental

The environmental provision includes amounts for BP's commitment to fund the Gulf of Mexico Research Initiative, estimated natural resource damage (NRD) assessment costs and early NRD restoration projects under the $1-billion framework agreement.

Spill response

The spill response provision relates primarily to ongoing shoreline operational activity.

Litigation and claims

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

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic loss claims. As disclosed in BP Annual Report and Form 20-F 2012, 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 EPD Settlement Agreement by the claims administrator that BP believes was incorrect.

Between March and December 2013, there were various rulings from both the federal District Court in New Orleans (the District Court) and a panel of the US Court of Appeals for the Fifth Circuit (the business economic loss panel) on matters relating to the interpretation of the EPD Settlement Agreement, in particular on the issue of matching revenue and expenses as well as causation requirements of the EPD Settlement Agreement.

On 5 December 2013, the District Court amended its earlier preliminary injunction and temporarily suspended the issuance of final determination notices and payments of business economic loss claims, until the business economic loss issues have been resolved. On 24 December 2013, the District Court ruled on the issues in relation to the matching of revenue and expenses and causation that were remanded to it by the business economic loss panel. Regarding matching, the District Court reversed its earlier decision and ruled that the claims administrator, in administering business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed matching requirements. Regarding causation, the District Court ruled that the EPD Settlement Agreement contained no causation requirement for class membership. BP has appealed the District Court's ruling on causation to the business economic loss panel and has moved for a permanent injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not traceable to the spill.

Top of page 29

Notes

2. Gulf of Mexico oil spill (continued)

In addition to the proceedings in relation to the interpretation of the EPD Settlement Agreement, following the District Court's final order and judgment approving the EPD Settlement in January 2013, groups of purported members of the Economic and Property Damages Settlement Class (the Appellants) appealed from the District Court's approval of that settlement to a different panel of the Fifth Circuit. On 10 January 2014, that other panel of the Fifth Circuit affirmed the District Court's approval of the EPD Settlement but left to the business economic loss panel of the Fifth Circuit the question of how to interpret the EPD Settlement Agreement, including the meaning of the causation requirements of that agreement. BP and several Appellants have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold approval of the EPD Settlement.

See Legal proceedings on pages 35 - 37 of this report and 162-169 of BP Annual Report and Form 20-F 2012 for further details on the settlements with the PSC and related matters.

As at 30 June 2013, BP held a provision for business economic loss claims which had been processed and for which eligibility notices had been issued but had not yet been paid by the DHCSSP. Pending the implementation of the Fifth Circuit's directions to the District Court on remand, there was significant uncertainty as to the amount of claims which had been processed but not paid by the DHCSSP that would be determined to be payable in the future. During the third quarter, BP derecognized the remaining provision for business economic loss claims which were processed but not yet paid, as BP considered and continues to consider that no reliable estimate can be made for these claims.

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

As reported in BP Annual Report and Form 20-F 2012, the estimated cost of the PSC settlement for Individual and Business Claims was originally $7.8 billion. BP's estimate at the time of the second-quarter results announcement dated 30 July 2013 of the total cost of those elements of the PSC settlement that it considered could be reliably estimated, was $9.6 billion. Following the derecognition of the provision in respect of processed but unpaid business economic loss claims during the third quarter, the current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated is $9.2 billion.

The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.2 billion because the current estimate does not reflect business economic loss claims not yet received, processed and paid. The DHCSSP has issued eligibility notices, disputed by BP, in respect of business economic loss claims of $1,019 million which have not yet been paid. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received.

The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP's current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on page 166 of BP Annual Report and Form 20-F 2012 and Contingent liabilities below for further details.

Top of page 30

Notes

2. Gulf of Mexico oil spill (continued)

Clean Water Act penalties

A provision was recognized in 2010 for the estimated civil penalties for strict liability under the Clean Water Act, which are based on a specified range per barrel of oil released. No adjustments have been made subsequently to this estimate. The penalty rate per barrel used to calculate the provision is based upon the company's conclusion, amongst other things, that it did not act with gross negligence or engage in wilful misconduct. The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court in the federal multi-district litigation proceedings in New Orleans (MDL 2179) as to negligence or gross negligence, the volume of oil spilled and the application of statutory penalty factors, or upon any settlement, if one were to be reached. The trial court could issue its decision on the first two phases of the trial at any time and has not yet scheduled a hearing on the subsequent phase regarding the application of statutory penalty factors. The court has wide discretion in its determination as to whether a defendant's conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors. See BP Annual Report and Form 20-F 2012 - Financial statements - Note 36 for further details.

Provision movements and analysis of income statement charge

A net increase in the provision for the estimated cost of the settlement with the PSC and various other costs of $183 million for the fourth quarter and a net increase of $1,860 million for the full year was recognized. The full year amount is net of the derecognition of $379 million relating to business economic loss claims that can no longer be estimated reliably. The provisions relating to the agreement with the US government to resolve all criminal claims and relating to the Gulf Region Health Outreach Program, amounting to $3.9 billion, were reclassified to payables during the first quarter, upon court approval. Utilization of the provision of $3,777 million during the full year included $2,654 million paid out under the PSC settlement from the Trust.

The total charge in the income statement is analysed in the table below.

	Fourth
	quarter	Year
$ million	2013	2013
Net increase (decrease) in provisions	183	2,239
Derecognition of provision for items that can no longer be estimated reliably	-	(379)
Recognition of reimbursement asset, net	(33)	(1,542)
Other net costs charged directly to the income statement	34	117
Change in discount rate	(5)	(5)
Loss before interest and taxation	179	430
Finance costs	10	39
Loss before taxation	189	469

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 in Litigation and claims above and Legal proceedings on pages 35 - 37 and the outcomes of any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise.

Furthermore, significant uncertainty exists in relation to the amount of fines that will ultimately be levied on BP (including any determination of BP's culpability based on any findings of negligence, gross negligence or wilful misconduct), the outcome of litigation proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. The amount and timing of any amounts payable could also be impacted by any further settlements which may or may not occur.

Further information on provisions is provided in BP Annual Report and Form 20-F 2012 - Financial statements - Note 36.

Contingent liabilities

BP considers that it is not possible, at this time, to measure reliably other obligations arising from the incident, namely any obligation in relation to natural resource damages claims or associated legal costs (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings on pages 35 - 37 of this report and pages 161 - 171 of BP Annual Report and Form 20-F 2012, the cost of business economic loss claims under the PSC settlement not yet received, processed and paid by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private or governmental litigation, fines or penalties (except for the Clean Water Act civil penalty claims and State and Local Claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment.

Top of page 31

Notes

2. Gulf of Mexico oil spill (continued)

Furthermore, since 6 March 2013, BP has been named as a defendant in more than 2,200 additional civil lawsuits brought by individuals, corporations and government entities related to the incident, and further actions are likely to be brought. Until further fact and expert disclosures occur, court rulings clarify the issues in dispute, liability and damage trial activity nears or progresses, or other actions such as possible settlements occur, it is not possible, given these uncertainties, to arrive at a range of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits. Therefore no amounts have been provided for these additional civil lawsuits as at 31 December 2013.

At 31 December 2013 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. Furthermore, for those items where a provision has been recorded, significant uncertainty also exists in relation to the ultimate exposure and cost to BP.

See also BP Annual Report and Form 20-F 2012 - Financial statements - Note 43.

3. Disposal of TNK-BP and investment in Rosneft

Disposal of TNK-BP

In BP Annual Report and Form 20-F 2012 the transaction to sell BP's investment in TNK-BP and acquire an investment in Rosneft was described as consisting of three tranches under which BP would receive $25.4 billion (including the $0.7 billion dividend received from TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft; BP would then use $4.8 billion of the cash to acquire a further 5.66% in Rosneft from Rosneftegaz and $8.3 billion to acquire a further 9.80% stake in Rosneft from a Rosneft subsidiary. On completion, the transactions between BP, Rosneft and the Rosneft subsidiary were instead settled on a net basis, so that BP received the 9.80% stake in Rosneft directly rather than receiving and immediately paying $8.3 billion in cash. The net result was the same.

The gain on disposal of BP's investment in TNK-BP, recognized in the TNK-BP segment in the first quarter, was $12.5 billion. Part of the gain arising on the disposal, amounting to $3.0 billion, was deferred due to BP selling its investment in TNK-BP to Rosneft, which in turn is now accounted for by BP as an associate. The deferred gain is released to BP's income statement over time as the TNK-BP assets are depreciated or amortized.

Disposal proceeds of $4.9 billion were used to purchase the 5.66% stake in Rosneft from Rosneftegaz ($4.8 billion described above plus $0.1 billion of interest). The net cash inflow relating to the transaction included in net cash flow from investing activities in the cash flow statement was $11.8 billion.

Investment in Rosneft

BP's investment in Rosneft is included in the balance sheet within investments in associates. The investment is measured at cost less the deferred gain described above (in roubles), plus post-acquisition changes in BP's share of Rosneft's net assets.

During the first quarter 2013 a charge of $2.1 billion (fourth quarter 2012 $1.4 billion credit) was recognized in other comprehensive income in relation to the agreements for BP to acquire shares in Rosneft which were accounted for as derivatives in a cash flow hedge. The resulting cumulative charge of $0.7 billion recognized in other comprehensive income would only be recognized in the income statement if the investment in Rosneft were either sold or impaired. The cash flow hedge derivatives were valued using the quoted Rosneft share price at the time the deal completed, of $7.60 per share.

BP completed the exercise to determine the fair value of its share of Rosneft's assets and liabilities as at 21 March 2013, as required under IFRS, and the results of this exercise are reflected in the fourth quarter and full year 2013 reported amounts.

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Notes

4. Sales and other operating revenues

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			By segment
19,429	16,810	18,928	Upstream	70,374	72,225
86,142	90,481	85,582	Downstream	351,195	346,391
570	454	517	Other businesses and corporate	1,805	1,985
106,141	107,745	105,027		423,374	420,601

			Less: sales and other operating revenues
			between segments
11,800	10,512	10,838	Upstream	42,327	42,572
187	440	256	Downstream	1,045	1,365
244	192	216	Other businesses and corporate	866	899
12,231	11,144	11,310		44,238	44,836

			Third party sales and other operating revenues
7,629	6,298	8,090	Upstream	28,047	29,653
85,955	90,041	85,326	Downstream	350,150	345,026
326	262	301	Other businesses and corporate	939	1,086
			Total third party sales and other operating
93,910	96,601	93,717	revenues	379,136	375,765

			By geographical area
33,648	35,619	32,351	US	137,875	138,304
69,069	71,843	70,082	Non-US	280,104	275,105
102,717	107,462	102,433		417,979	413,409
			Less: sales and other operating revenues
8,807	10,861	8,716	between areas	38,843	37,644
93,910	96,601	93,717		379,136	375,765

5. Production and similar taxes

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
438	223	299	US	1,112	1,472
1,635	1,666	1,192	Non-US	5,935	6,686
2,073	1,889	1,491		7,047	8,158

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Notes

6. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 287 million ordinary shares at a cost of $2,191 million as part of the share repurchase programme announced on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period, for which an amount of $1,430 million has been accrued at 31 December 2013. The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

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

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Results for the period
			Profit for the period attributable to BP
1,488	3,504	1,042	shareholders	23,451	11,017
1	-	1	Less: preference dividend	2	2
			Profit attributable to BP ordinary
1,487	3,504	1,041	shareholders	23,449	11,015
			Inventory holding (gains) losses, net
521	(326)	465	of tax	230	411
			RC profit attributable to BP ordinary
2,008	3,178	1,506	shareholders	23,679	11,426
			Net (favourable) unfavourable impact of
			non-operating items and fair value
1,843	514	1,302	accounting effects, net of tax	(10,253)	5,643
			Underlying RC profit attributable to BP
3,851	3,692	2,808	shareholders	13,426	17,069

			Number of shares (thousand)(a)
			Basic weighted average number of
19,071,754	18,867,320	18,689,386	shares outstanding	18,931,021	19,027,929
3,178,626	3,144,553	3,114,897	ADS equivalent	3,155,170	3,171,321

			Weighted average number of shares
			outstanding used to calculate diluted
19,177,841	18,967,190	18,802,026	earnings per share	19,046,173	19,157,888
3,196,307	3,161,198	3,133,671	ADS equivalent	3,174,362	3,192,981

19,119,757	18,821,216	18,611,489	Shares in issue at period-end	18,611,489	19,119,757
3,186,626	3,136,869	3,101,914	ADS equivalent	3,101,914	3,186,626

(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 34

Notes

7. Analysis of changes in net debt(a)

Fourth	Third	Fourth
quarter	quarter	quarter		Year	Year
2012	2013	2013	$ million	2013	2012
			Opening balance
49,071	46,990	50,284	Finance debt	48,800	44,208
16,174	28,313	29,499	Less: cash and cash equivalents(b)	19,635	14,177
			Less: FV asset of hedges related to
1,572	460	734	finance debt	1,700	1,133
31,325	18,217	20,051	Opening net debt	27,465	28,898
			Closing balance
48,800	50,284	48,192	Finance debt	48,192	48,800
19,635	29,499	22,520	Less: cash and cash equivalents	22,520	19,635
			Less: FV asset of hedges related to
1,700	734	477	finance debt	477	1,700
27,465	20,051	25,195	Closing net debt	25,195	27,465
3,860	(1,834)	(5,144)	Decrease (increase) in net debt	2,270	1,433
			Movement in cash and cash equivalents
3,392	952	(7,022)	(excluding exchange adjustments)	2,845	5,394
			Net cash outflow (inflow) from financing
1,229	(2,799)	2,013	(excluding share capital and dividends)	(836)	(3,244)
			Movement in finance debt relating to
(602)	-	-	investing activities(c)	632	(602)
(93)	(17)	(69)	Other movements	(192)	(104)
3,926	(1,864)	(5,078)	Movement in net debt before exchange effects	2,449	1,444
(66)	30	(66)	Exchange adjustments	(179)	(11)
3,860	(1,834)	(5,144)	Decrease (increase) in net debt	2,270	1,433

(a)	Net debt is a non-GAAP measure - see page 4 for further information.
(b)	The cash balance at 31 December 2012 includes $709 million relating to the dividend received from TNK-BP in the fourth quarter 2012 which met the criteria to be treated as restricted cash until completion of the sale of BP's interest in TNK-BP to Rosneft. This is no longer restricted because the transaction completed in March 2013.
(c)	At 31 December 2013, finance debt includes no deposits received in advance relating to disposal transactions (nil at 30 September 2013 and $632 million at 31 December 2012).

At 31 December 2013, $141 million of finance debt ($144 million at 30 September 2013 and $142 million at 31 December 2012) was secured by the pledging of assets. The remainder of finance debt was unsecured.

At 31 December 2013, the company had in place committed bank standby facilities totalling $7.4 billion ($7.4 billion at 30 September 2013) with $7 billion available to draw and repay until the first half of 2018 and $0.4 billion available to draw and repay until April 2016. No drawings have ever been made against any of the standby facilities.

8. Inventory valuation

A provision of $322 million was held at 31 December 2013 ($636 million at 30 September 2013 and $124 million at 31 December 2012) to write inventories down to their net realizable value. The net movement credited to the income statement during the fourth quarter 2013 was $313 million (third quarter 2013 was a charge of $407 million and fourth quarter 2012 was a credit of $16 million).

9. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 3 February 2014, is unaudited and does not constitute statutory financial statements. Audited financial information is expected to be published in BP Annual Report and Form 20-F 2013 in early March 2014 and delivered to the Registrar of Companies in due course. BP Annual Report and Form 20-F 2012 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 35

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 162 - 171 of BP Annual Report and Form 20-F 2012.

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.Post-trial briefing in the first phase (Phase 1) of a Trial of Liability, Limitation, Exoneration and Fault Allocation in the federal multi-district litigation proceeding in New Orleans (MDL 2179) completed on 12 July 2013 in the federal district court in New Orleans (the District Court). The presentation of evidence in Phase 1 addressed issues arising out of the conduct of various parties allegedly relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on the Deepwater Horizon on 20 April 2010, the sinking of the vessel on 22 April 2010 and the initiation of the release of oil from the Deepwater Horizon or the Macondo well during those time periods, including whether BP or any other party was grossly negligent.

The second trial phase (Phase 2), which commenced in the District Court on 30 September 2013, addressed the amount of oil that was spilled into the Gulf as a result of the Incident and source control efforts. The presentation of evidence in Phase 2 completed on 18 October 2013. The parties completed court-ordered post-trial briefing in respect of Phase 2 on 24 January 2014. BP is not currently aware of the timing of the court's rulings in respect of issues presented in Phase 1 or Phase 2 and the court could issue its decision on these phases at any time. The District Court has not yet scheduled a hearing on the subsequent phase regarding the application of statutory penalty factors.

The District Court has wide discretion in its determination as to whether a defendant's conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors. For further information, see page 164 of BP Annual Report and Form 20-F 2012.

Plaintiffs' Steering Committee (PSC) Settlements - Economic and Property Damages Settlement fairness appeal. The Economic and Property Damages Settlement was approved by the District Court in a final order and judgment on 21 December 2012. For further information, see pages 166 - 168 of BP Annual Report and Form 20-F 2012.

Subsequent to the District Court's final order and judgment approving the Economic and Property Damages Settlement, groups of purported members of the Economic and Property Damages Settlement Class (the Appellants) appealed from the District Court's approval of that settlement to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit). On 4 November 2013, the Fifth Circuit heard oral arguments regarding those appeals, which involved challenges to the order and judgment that approved the Economic and Property Damages Settlement and certified the class. Additionally, a coalition of fishing and community groups (the Coalition) appealed to the Fifth Circuit from an order of the District Court denying it permission to intervene in the civil action serving as the vehicle for the Economic and Property Damages Settlement and further denying it permission to take discovery regarding the fairness of that settlement. On 11 November 2013, the Fifth Circuit affirmed the District Court's rulings in respect of the Coalition. On 10 January 2014, a panel of the Fifth Circuit affirmed the District Court's approval of the Economic and Property Damages Settlement but left to another panel of the Fifth Circuit (the business economic loss panel) the question of how to interpret the Economic and Property Damages Settlement, including the meaning of the causation requirements of that agreement. BP and several Appellants have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold approval of the settlement.

PSC Settlements - Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages Settlement Agreement. As part of its monitoring of payments made by the court-supervised claims processes operated by the DHCSSP for the Economic and Property Damages Settlement, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement by that settlement's claims administrator that BP believes was incorrect. This interpretation produced a higher number and value of awards than the interpretation BP used in making its initial estimate of the total cost of the Economic and Property Damages Settlement. On 5 March 2013, the District Court affirmed the claims administrator's interpretation of the agreement and rejected BP's position as it relates to business economic loss claims (the March 2013 Ruling).

BP appealed the District Court's March 2013 Ruling and related rulings to the Fifth Circuit. On 2 October 2013, the business economic loss panel of the Fifth Circuit (by a 2-1 vote) reversed the District Court's denial of BP's motion for a preliminary injunction and the District Court's March 2013 Ruling, remanded the case for further proceedings and ordered the District Court to enter a "narrowly-tailored" injunction that suspends payment to claimants affected by the misinterpretation issue and who do not have "actual injury traceable to loss from the Deepwater Horizon accident." The business economic loss panel also retained jurisdiction to review the District Court's conclusions on remand.

On 18 October 2013, the District Court issued a preliminary injunction that, amongst other things, required the claims administrator to temporarily suspend payments of business economic loss claims other than those claims supported by sufficiently matched accrual-basis accounting or any other business economic loss claim for which the claims administrator determines that the matching of revenue and expenses is not an issue. On 25 October 2013, the claims administrator provided a declaration outlining the criteria that the claims administrator's office will use to determine the eligibility of claims for payment. In orders dated 18 October 2013, 15 November 2013, and 22 November 2013, the District Court held that causation (i.e., whether the claims administrator could properly pay business economic loss claimants whose injuries are not traceable to

Top of page 36

Legal proceedings (continued)

the spill) was not an issue for consideration on remand. On 21 November 2013, BP filed an emergency motion to enforce the business economic loss panel's 2 October 2013 judgment and to enjoin any further payments to the business economic loss claimants whose injuries are not traceable to the spill. On 2 December 2013, the business economic loss panel of the Fifth Circuit ordered that the issue of causation is again remanded for expeditious consideration and resolution in crafting "[a] stay tailored so that those who experienced actual injury traceable to loss from the Deepwater Horizon accident continue to receive recovery but those who did not do not receive their payments until this case is fully heard and decided through the judicial process." On 5 December 2013, the District Court amended its preliminary injunction related to business economic loss claims to temporarily suspend the issuance of final determination notices and payments of business economic loss claims, until the business economic loss issues that are the subject of the pending remand have been resolved.

On 24 December 2013, the District Court ruled on the issues remanded to it by the business economic loss panel of the Fifth Circuit, ordering that the claims administrator, in administering business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed matching requirements. As to the issue of causation, the District Court ruled that the Economic and Property Damages Settlement Agreement contained no causation requirement for class membership and that BP was judicially estopped from arguing otherwise. The District Court also held that the absence of a further causation requirement does not defeat class certification or invalidate the settlement under the federal class certification rule or Article III of the US Constitution. On 26 December 2013, BP filed with the business economic loss panel of the Fifth Circuit a protective notice of appeal from the District Court's 24 December 2013 order. BP subsequently filed a renewed motion for a permanent injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not traceable to the spill. On 2 January 2014, the business economic loss panel of the Fifth Circuit granted BP's separate motion to expedite consideration of that renewed motion and set an expedited briefing schedule that ran through 10 January 2014. The parties have also submitted to the business economic loss panel of the Fifth Circuit letter briefs addressing what implications the Fifth Circuit's 10 January 2014 decision affirming the District Court's approval of the Economic and Property Damages Settlement Agreement has on the business economic loss claims appeal.

For information about BP's current estimate of the total cost of the PSC settlements, see Note 2.

PSC Settlements - Seafood Compensation Fund. On 17 December 2013, BP filed a civil lawsuit in MDL 2179 against former PSC lawyer Mikal C. Watts, accusing him of having fraudulently claimed to represent more than 40,000 deckhands who allegedly suffered economic injuries as a result of the Incident. BP's action alleges that BP relied on Mr Watts's representations when it agreed to pay $2.3 billion to the Seafood Compensation Fund (the Fund), which was established under the Economic and Property Damages Settlement to compensate those who earn their livelihood from Gulf waters and were directly affected by the spill, and that the Economic and Property Damages Class stands to benefit unjustly from the full distribution of the money remaining in the Fund. In addition, BP filed two motions asking the District Court to suspend further distributions from the Fund and to grant discovery in order to determine the extent of the fraud and what portion, if any, of the Fund should be returned to BP as a result. On 17 January 2014, Mr Watts filed a motion to stay the litigation pending a parallel criminal investigation and the PSC also filed a brief opposing BP's motion seeking an injunction. On 24 January 2014, BP filed an opposition to Mr Watts's motion for a stay and on 27 January 2014, BP filed a reply in support of its motion for a preliminary injunction.

Department of Justice Action. The United States filed a civil complaint in MDL 2179 against BP Exploration & Production Inc. (BPXP) and others on 15 December 2010 (the DoJ Action). The complaint seeks a declaration of liability under OPA 90 and civil penalties under the Clean Water Act and sets forth a purported reservation of rights on behalf of the US to amend the complaint or file additional complaints seeking various remedies under various US federal laws and statutes. For further information, see page 164 of BP Annual Report and Form 20-F 2012.

On 8 December 2011, the United States brought a motion for partial summary judgment in the DoJ Action seeking, among other things, an order finding that BPXP, Transocean and Anadarko are strictly liable for a civil penalty under Section 311(b) (7)(A) of the Clean Water Act. On 22 February 2012, the judge ruled that BPXP and Anadarko are responsible parties under OPA 90 with regard to the subsurface discharge, and that BPXP and Anadarko have joint and several liability under OPA 90 for removal costs and damages for such discharge. While the judge held that Transocean is not a responsible party under OPA 90 for subsurface discharge, the judge left open the question of whether Transocean may be liable under OPA 90 for removal costs for such discharge as the owner/operator of the Deepwater Horizon. Regarding the Clean Water Act, the judge held that the subsurface discharge was from the Macondo well, rather than from the Deepwater Horizon, and that BPXP and Anadarko are liable for civil penalties under Section 311 of the Clean Water Act as owners of the well. For further information, see page 164 of BP Annual Report and Form 20-F 2012.

Anadarko, BPXP and the United States each appealed the 22 February 2012 ruling to the Fifth Circuit, and the appeals were consolidated. Briefing in this appeal is complete and oral argument was heard on 4 December 2013, but no ruling has been issued.

Top of page 37

Legal proceedings (continued)

US Environmental Protection Agency (EPA) matters

On 28 November 2012, the EPA notified BP that it had temporarily suspended BP p.l.c., BPXP and a number of other BP subsidiaries from participating in new federal contracts. In addition, as a result of BP's agreement with the Department of Justice to resolve all federal criminal charges against BP, on 1 February 2013 the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. For further information, see page 163 of BP Annual Report and Form 20-F 2012. BP maintains that the EPA's actions do not have an adequate legal basis and do not reflect BP's present status as a responsible government contractor. On 12 August 2013, BP filed a lawsuit in the US District Court for the Southern District of Texas (the Texas District Court) challenging the EPA's suspension and debarment decisions. On 25 November 2013, BP filed a motion for summary judgment on its claims in the Southern District of Texas. The UK government and a coalition of major trade and business groups led by the American Petroleum Institute later filed friend of the court (amicus) briefs supporting BP's position. On 28 January 2014, the EPA filed a motion for summary judgment in the Texas District Court together with a memorandum in support of such motion and in opposition to BP's motion for summary judgment.

On 26 November 2013, the EPA issued a Notice of Continued Suspensions and Proposed Debarments that continued the suspensions of the previously suspended BP entities, suspended two new BP entities (BP Alternative Energy and BP Pipelines (Alaska) Inc.), and proposed discretionary debarment of all suspended BP entities.

BP continues to work with the EPA in preparing an administrative agreement to resolve these suspension and debarment issues.

MDL 2185 and other securities-related litigation

Securities class actions. On 13 February 2012, the district court in the federal multi-district litigation proceeding in Houston (MDL 2185) issued two decisions on the defendants' motions to dismiss the two consolidated securities fraud complaints filed on behalf of purported classes of BP ordinary shareholders and ADS holders. The court dismissed all of the claims of the ordinary shareholders, dismissed the claims of the lead class of ADS holders against most of the individual defendants while holding that a subset of the claims against two individual defendants and the corporate defendants could proceed, and dismissed all of the claims of a smaller purported subclass with leave to re-plead in 20 days. Following an amended consolidated complaint from the plaintiffs, on 2 May 2012, the defendants moved to dismiss the claims based on the 13 statements in the amended complaint that the judge did not already rule are actionable. On 6 February 2013, the court granted in part this motion to dismiss, rejecting the plaintiffs' claims based on 10 of the 17 statements at issue in the motion and also dismissing all claims against former BP employee Andrew Inglis. On 6 December 2013, the court denied the plaintiffs' motion for class certification and gave the plaintiffs 30 days to renew that motion, and the plaintiffs renewed their motion on 6 January 2014. Briefing on the plaintiffs' renewed motion is scheduled to complete on 10 March 2014. On 20 December 2013, the court revised the schedule for the action and set a trial date for 14 October 2014.

For further information about MDL 2185 and other securities-related litigation, see pages 162 - 163 of BP Annual Report and Form 20-F 2012.

Other legal proceedings

Clean Air Act matters. As disclosed in BP Annual Report and Form 20-F 2012, BP has been in discussions with the

EPA regarding alleged historic violations of the Clean Air Act (CAA) at the Texas City refinery. On 1 February 2013, Marathon Petroleum Company LP (Marathon) purchased the Texas City refinery from BP Products North America, Inc. (BP Products) and directed BP Products to transfer the refinery to Blanchard Refining Company LLC (Blanchard). On 4 November 2013, BP Products, Blanchard and the EPA reached an agreement to settle certain alleged CAA violations at the Texas City refinery. Pursuant to the settlement BP Products paid a civil penalty of $950,000 and Blanchard agreed to undertake certain injunctive relief.

Top of page 38

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, BP's intentions in respect of its announced share repurchase programme, including the total value of shares expected to be purchased in connection therewith and programme timing; the expected range of net cash that will be provided by operating activities in 2014; BP's target net debt ratio; the expected organic capital expenditures for 2014; BP's plans to divest a further $10 billion of assets before the end of 2015; the expected underlying effective tax rate for 2014; the expected quarterly dividend payment and timing of the payment; the expected increase in the charge for depreciation, depletion and amortization in 2014; the expected ramp-up of production from new upstream projects; the expected level of reported production in the first quarter of 2014 and the impact of the expiry of the Abu Dhabi onshore concession and divestments on the expected level of reported production in the first quarter of 2014; the expected level of reported and underlying production for the full year 2014; the expected timing for satisfaction of conditions precedent to completion of BP's planned purchase of an additional 3.3% equity stake in Shah Deniz and the South Caucasus Pipeline from Statoil; the expected timing for completion of the sale of the specialist global aviation turbine oils business; BP's expectations regarding the improvement of refining margins and the challenging conditions in the fuels and petrochemicals environments in 2014; the expected increase in exposure to heavy crude differentials in the US due to the ramp-up of heavy crude processing at Whiting refinery; the expected range for Other businesses and corporate average quarterly charges in 2014; and certain statements regarding the legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties, and the risks associated with such proceedings; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of maintenance and/or turnaround activity; the nature, timing and volume of refinery additions and outages; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including court decisions, the types of enforcement action pursued and the nature of remedies sought or imposed; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; decisions by Rosneft's management and board of directors; 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 2013 and under "Risk factors" in BP Annual Report and Form 20-F 2012, 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

This information is provided by RNS

The company news service from the London Stock Exchange

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