BP PLC — Financial Supplement Data 2005

Apr 25, 2006

Making energy more Financial and Operating Information 2001-2005

Making energy more BP Financial and Operating Information 2001-2005

beyond petroleum®

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www.bp.com

• 2 BP history at a glance
• 4 Financial performance
• 30 Exploration and Production
• 64 Refining and Marketing
• 74 Gas, Power and Renewables
• 81 Other businesses and corporate

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• 83 Accounting policies
• 91 Definitions
• 92 Further information

INTERACTIVE RESOURCES Visit www.bp.com/investortools to chart our key financial and operating information for the past five years, on an annual or quarterly basis, for the BP group as a whole or by business segment.

BP p.l.c. is the parent company of the BP group of companies. Unless otherwise stated, the text does not distinguish between the activities and operations of the parent company and those of its subsidiaries.

BP is a leader in our industry and that position is reflected in our standards of social responsibility, corporate governance and financial and sustainability reporting, of which this document is part. For a complete view of BP's performance, it should be read in conjunction with BP Annual Report and Accounts 2005, BP Annual Report on Form 20-F 2005 and BP Sustainability Report 2005. Copies may be obtained free of charge (see page 92).

Cautionary statement

BP Financial and Operating Information 2001-2005 contains certain forward-looking statements, particularly those regarding capital expenditure; first tanker lifting from Ceyhan; start-up of the Shah Deniz field; completion of the associated South Caucasus pipeline; the progress and timing of projects including Greater Plutonio and In Amenas; the start of production from Thunder Horse and Atlantis; the potential of the Sakhalin region; the effect of the extension of two concessions in the Gulf of Suez; growth in gas demand in the Asia Pacific region; the commencement of exports from the North West Shelf venture; production from the Texas City refinery; the extension of the Castrol Edge range; the planned operation of an acetic acid plant at Nanjing; the start-up of and sales from Tangguh; planned investments in BP Alternative Energy; and the expected production from planned generation at Peterhead and Carson. By their nature, forward-looking statements involve risks and uncertainties 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 on stream; future levels of industry product supply; demand and pricing; operational problems; general

economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; exchange rate fluctuations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors; natural disasters and adverse weather conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this document and in BP Annual Report and Accounts 2005.

Cautionary note to US investors

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this report, such as 'reserves', that the SEC's guidelines strictly prohibit us from including in our filings with the SEC. US investors are urged to consider closely the disclosure in our Form 20-F, SEC File No. 1-6262, available from us at 1 St James's Square, London SW1Y 4PD. You can also obtain this form from the SEC by calling 1-800-SEC-0330.

Resourcefulness and options that help fuel the

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world's possibilities

BP is one of the world's largest oil and gas companies, serving about 13 million customers in more than 100 countries across six continents. Our business segments are Exploration and Production; Refining and Marketing; and Gas, Power and Renewables. Through these business segments, we provide fuel for transportation, retail brands and energy for heat and light.

Our performance and actions as a company are underpinned by the belief that we can make energy more – so that through the choices we make and the options those choices give us the future of energy can become more efficient, diverse and secure.

BP history at a glance

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The company is incorporated in England as the Anglo-Persian Oil Company Limited.The incorporation focuses on the commercialization of Masjid-i-Suleiman in Iran, the first commercial oil discovery in the Middle East.

1909 1920s-1930s 1922 1954

The Anglo-Persian Oil Company Limited becomes the pre-eminent oil producer in the Middle East. The company enters into international marketing in continental Europe, Africa and Australia.

After eight years of majority share ownership, the British government begins offering ordinary shares of BP stock for sale to the public.

carbon power.

The company name becomes The British Petroleum Company Limited. Marketing activities extend to New Zealand, parts of Africa and more countries in Europe. A consortium agreement for Iranian oil gives BP a 40% stake.

BP enters North America with its discovery and major share of the Prudhoe Bay oil field on Alaska's North Slope. This leads in the following year to BP's taking a sizeable interest in Standard Oil of Ohio. BP gains a majority interest in Standard Oil. The company acquires the chemicals and plastics interest in Europe of Union Carbide and, in 1979, of Monsanto. Privatization of BP shares is completed. Following periodic public offerings of a minority of its shareholdings over the previous 65 years, the British government disposes of nearly all its remaining shares. BP acquires the remaining 45% shareholding in Standard Oil, which becomes a wholly owned New frontier exploration strategy signals a shift in BP's focus to areas of major opportunity and future investment choices. 1969 1978 1987 1989

1997	1998	2000	2001
In response to mounting evidence and concern regarding greenhouse gas emissions and the rising temperature of the earth, BP becomes the first in its industry to state publicly the need for precautionary action on climate change.	BP merges with Amoco, becoming one of three leaders in the oil and gas industry. The merger gives the combined companies the opportunity to compete through a highly distinctive set of people, assets and market positions.	ARCO joins the BP group in a \$34-billion transaction that provides coast-to-coast coverage of the US fuels market. BP's acquisition of Burmah Castrol strengthens BP's market-facing business with one of the world's great brands.	Detailed engineering and planning activity begins on the longest pipeline BP has ever built. The 1,768-kilometre Baku-Tbilisi-Ceyhan pipeline will link the landlocked Caspian Sea in the east to the Mediterranean coast at Ceyhan, Turkey.

subsidiary of BP.

2002	2003	2004	2005
Acquisition of Veba's retail and refining assets in Germany and central Europe makes BP the market leader in Germany and Austria. BP markets under the Aral brand in Germany.	TNK-BP, the joint venture between BP and AAR (the Alfa Group and Access-Renova), operating in Russia, is finalized. The venture gives BP a 50% stake in one of the world's great hydrocarbon provinces.	BP announces plans to sell the Olefins and Derivatives business of its Petrochemicals segment while retaining the Aromatics and Acetyls businesses in Refining and Marketing.	BP sells Innovene, comprising the Olefins and Derivatives business and refineries in Grangemouth, UK, and Lavéra, France, to UK-based INEOS for \$8.3 billion cash. BP launches BP Alternative Energy, a new business dedicated to the development and wholesale marketing and trading of low

Basis of financial information

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To the greatest extent possible, the information in this book has been presented on the basis that BP will report its financial information in 2006.

ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

The group adopted International Financial Reporting Standards (IFRS) with effect from 1 January 2005. Financial information for 2004 and 2003 has been restated to reflect the adoption of IFRS, as has the balance sheet at 1 January 2003, BP's date of transition to IFRS. BP chose not to adopt International Accounting Standard No. 39 'Financial Instruments: Recognition and Measurement' (IAS 39) until 1 January 2005, so financial assets and liabilities including derivatives are reported on the basis of UK generally accepted accounting practice (UK GAAP) for 2004 and 2003. The balance sheet at 1 January 2005 is also presented to show the effect of adopting IAS 39.

The financial information for 2001 and 2002 has not been restated for IFRS and remains on the basis of UK GAAP.

UK GAAP information for 2002 has been restated to reflect the adoption by the group of Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17) with effect from 1 January 2004. Financial information for 2001 has not been restated for FRS 17.

CHANGE OF ACCOUNTING POLICY

The group's accounting policy has been to present oil, natural gas and power forward sales and purchases gross in the income statement. However, during 2005, a review was undertaken into the presentation of these commodity derivative transactions and related activity, which concluded that it was more appropriate to represent transactions in these areas net rather than gross. These sale and purchase transactions are now offset and reported net in sales and other operating revenues and data for all years has been restated to reflect this. Other derivative contracts where physical delivery is the norm continue to be reported gross.

RESEGMENTATION

The segmental financial and operating information in this book for 2003-2005 has been restated to reflect changes to the business

segment boundaries following the launch of BP Alternative Energy in November 2005 and the sale of Innovene to INEOS in December 2005. Note that financial information for 2001 and 2002 has not been restated for this resegmentation. These transfers are effective from 1 January 2006:

• ••• Following the sale of Innovene to INEOS, the transfer of three equity-accounted entities (Shanghai SECCO Petrochemical Company Limited in China and Polyethylene Malaysia Sdn Bhd (PEMSB) and Ethylene Malaysia Sdn Bhd (EMSB), both in Malaysia), previously reported in Other businesses and corporate, to Refining and Marketing.
• ••• The formation of BP Alternative Energy has resulted in the transfer of certain mid-stream assets and activities to Gas, Power and Renewables:
  • South Houston Green Power (SHGP) co-generation facility (in Texas City refinery) from Refining and Marketing.
  • Watson Cogeneration (in Carson City refinery) from Refining and Marketing.
  • Phu My Phase 3 CCGT plant in Vietnam from Exploration and Production.
• ••• The transfer of Hydrogen for Transport activities from Gas, Power and Renewables to Refining and Marketing.

SALE OF INNOVENE

The Innovene operations represented a separate major line of business for BP. As a result of the sale, these operations have been treated as discontinued operations for the years ended 31 December 2005, 2004 and 2003. A single amount is shown on the face of the income statement comprising the post-tax result of discontinued operations and the post-tax loss recognized on the remeasurement to fair value less costs to sell of the discontinued operation. That is, the income and expenses of Innovene are reported separately from the continuing operations of the BP group.

Data for the years ended 31 December 2002 and 2001 has not been restated; the results of Innovene operations are included within Other businesses and corporate.

Quarterly information
2004 IFRS	30,000 30,000	black type annual total in bold	The financial information for 2003 (annual) and 2004 (quarterly and annual) has been restated to reflect the adoption of IFRS.
2005 IFRS	30,000 30,000	black type in green tinted box annual total in bold	The financial information for 2001 and 2002 has not been
Annual information			restated for IFRS and remains on the basis of UK GAAP.
2001-2002 UK GAAP	30,000	green type
2003-2004 IFRS	30,000	black type	UK GAAP information for 2002 reflects the adoption by the
1Jan 2005 IFRS (including impact of IAS 39)	30,000	black type in grey tinted box	group of Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17) with effect from 1 January 2004. Financial
2005 IFRS	30,000	black type in green tinted box	information for 2001 has not been restated for FRS 17.

Financial contents

• 4 Financial performance
• 5 Group income statement
• 6 Summarized group income statement by quarter

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• 8 Replacement cost profit before interest and tax by business and geographical area
• 10 Non-operating items by business
• 12 Non-operating items by geographical area
• 14 Depreciation of fixed asset revaluation adjustment by business and geographical area
• 14 Amortization of goodwill by business and geographical area
• 16 Sales and other operating revenues
• 16 Taxation
• 17 Depreciation, depletion and amortization
• 18 Group balance sheet
• 19 Operating capital employed
• 20 Fixed assets property, plant and equipment
• 21 Working capital
• 22 Group cash flow statement
• 23 Movement in net debt
• 24 Capital expenditure, acquisitions and disposals
• 25 United States accounting principles
  • 27 Ratios
• 28 BP shareholding information
• 28 Employee numbers
• 29 BP share data

Financial performance

HIGHLIGHTS	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Replacement cost profit for the year (\$ million)	8,456	5,691	12,432	15,432	19,314
per ordinary share (cents)	37.68	25.40	56.06	70.71	91.41
per ADS (dollars)a	2.26	1.52	3.36	4.24	5.48

aOne American depositary share (ADS) is equivalent to six 25 cent ordinary shares.

EXTERNAL ENVIRONMENT	2001	2002	2003	2004	2005
BP average liquids realizations (\$/bbl)a	22.50	22.69	27.25	35.39	48.51
BP average natural gas realizations (\$/mcf)	3.30	2.46	3.39	3.86	4.90
Global Indicator Refining Margin (\$/bbl)b	4.36	2.27	4.08	6.31	8.60

aCrude oil and natural gas liquids.

bThe Global Indicator Refining Margin (GIM) is the average of six regional indicator margins weighted for BP's crude oil refining capacity in each region. Each regional indicator margin is based on a single representative crude oil with product yields characteristic of the typical level of upgrading complexity. 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. The GIM data shown above excludes the Grangemouth and Lavéra refineries.

Group income statement

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For the year ended 31 December

					\$ million
	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Sales and other operating revenues	148,502	149,674	169,441	199,876	249,465
Earnings from jointly controlled entities – after interest and tax	439	347	826	1,818	3,083
Earnings from associates – after interest and tax	756	617	388	462	460
Interest and other revenues	694	641	746	615	613
Total revenues	150,391	151,279	171,401	202,771	253,621
Gain on sale of businesses and fixed assets	1,130	2,933	1,895	1,685	1,538
Total revenues and other income	151,521	154,212	173,296	204,456	255,159
Purchases	(104,027)	(101,208)	(115,978)	(135,907)	(172,699)
Production and manufacturing expenses	(11,607)	(15,001)	(14,130)	(17,330)	(21,092)
Production and similar taxes	(1,689)	(1,274)	(1,723)	(2,149)	(3,010)
Depreciation, depletion and amortizationa	(8,683)	(9,127)	(8,076)	(8,529)	(8,771)
Impairment and losses on sale of businesses and fixed assets	(770)	(3,039)	(1,801)	(1,390)	(468)
Exploration expense	(480)	(644)	(542)	(637)	(684)
Distribution and administration expensesb	(9,603)	(11,590)	(12,270)	(12,768)	(13,706)
Fair value gain (loss) on embedded derivatives	–	–	–	–	(2,047)
Profit before interest and taxation from continuing operations	14,662	12,329	18,776	25,746	32,682
Finance costs	(1,670)	(1,140)	(513)	(440)	(616)
Other finance expense	–	–	(532)	(340)	(145)
Profit before taxation from continuing operations	12,992	11,189	17,731	24,966	31,921
Taxation	(6,375)	(4,317)	(5,050)	(7,082)	(9,473)
Profit for the year from continuing operations	6,617	6,872	12,681	17,884	22,448
Profit (loss) from Innovene operationsc	–	–	(63)	(622)	184
Profit for the year	6,617	6,872	12,618	17,262	22,632
Attributable to
BP shareholders	6,556	6,795	12,448	17,075	22,341
Minority interest (MI)	61	77	170	187	291
	6,617	6,872	12,618	17,262	22,632
Earnings per ordinary share – cents
Profit attributable to BP shareholders
Basic	29.21	30.33	56.14	78.24	105.74
Diluted	29.04	30.19	55.61	76.87	104.52
REPLACEMENT COST RESULTSd
Profit for the year	6,556	6,795	12,448	17,075	22,341
Inventory holding (gains) losses net of MI	1,900	(1,104)	(16)	(1,643)	(3,027)
Replacement cost profit for the year	8,456	5,691	12,432	15,432	19,314
aDepreciation of the fixed asset revaluation adjustment consequent upon the ARCO
acquisition amounted to	1,339	895	746	539	447
bResearch and development expenditure amounted to	385	373	234	300	374

cInnovene results for the years ended 31 December 2001 and 2002 are included within the results of Other businesses and corporate. dReplacement cost profit excludes inventory holding gains and losses. The effect of this is to set against income for the period the average cost of supplies incurred in the same period rather than applying costs obtained by using the first-in first-out method. Profit on the replacement cost basis therefore reflects more immediately changes in purchase costs and provides an indication of the underlying trend in trading performance in a continuing business. This basis is used to assist in the interpretation of profit. Replacement cost profit is not a recognized GAAP measure.

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REPLACEMENT COST RESULTS	2001	2002	IFRS 2003
Replacement cost profit before interest and taxa b
By business
Exploration and Production	12,472	8,277	15,081
Refining and Marketing	4,454	1,936	3,162
Gas, Power and Renewables	564	1,961	609
Other businesses and corporate	(928)	(974)	(260)
Consolidation adjustments
Unrealized profit in inventory	–	–	(61)
Net profit on transactions between continuing and Innovene operations	–	–	193
Replacement cost profit before interest and tax from continuing operations	16,562	11,200	18,724
Finance costs	(1,432)	(1,067)	(513)
Other finance expense	(238)	(73)	(532)
Replacement cost profit before taxation from continuing operations	14,892	10,060	17,679
Taxation	(6,375)	(4,317)	(5,050)
Replacement cost profit from continuing operations	8,517	5,743	12,629
Replacement cost profit from Innovene operationsc	–	–	(27)
Replacement cost profit for the period	8,517	5,743	12,602
Attributable to
BP shareholders	8,456	5,691	12,432
Minority interest	61	52	170
Replacement cost profit for the period	8,517	5,743	12,602
Earnings on replacement cost profit
per ordinary share – cents	37.68	25.40	56.06
per ADS – dollars	2.26	1.52	3.36
Replacement cost profit for the period	8,517	5,743	12,602
Inventory holding gains (losses)	(1,900)	1,104	16
Profit for the period	6,617	6,847	12,618
Earnings on profit
per ordinary share – cents
Basic	29.21	30.33	56.14
Diluted	29.04	30.19	55.61
per ADS – dollars
Basic	1.76	1.82	3.37
Diluted	1.74	1.81	3.34
Earnings on profit from continuing operations
per ordinary share – cents
Basic	29.21	30.33	56.42
Diluted	29.04	30.19	55.89
per ADS – dollars
Basic	1.76	1.82	3.39
Diluted	1.74	1.81	3.35
a Replacement cost profit before interest and tax includes equity-accounted interest and tax
Exploration and Production	–	–	273
Refining and Marketing	–	–	49
Gas, Power and Renewables	–	–	2
	–	–	324

bReplacement cost profit is before inventory holding gains and losses.

cInnovene results for the years ended 31 December 2001 and 2002 are included within the results of Other businesses and corporate.

									\$ million
IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2004	IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2005
4,242	4,262	4,822	4,749	18,075	6,484	5,901	6,534	6,566	25,485
928	1,664	1,301	1,301	5,194	1,411	1,273	1,875	(165)	4,394
200	206	53	505	964	412	189	347	129	1,077
1,108	(288)	(447)	(218)	155	(171)	(156)	(501)	(409)	(1,237)
(66)	(87)	(95)	57	(191)	(153)	(4)	(285)	234	(208)
26	42	89	31	188	96	159	144	128	527
6,438	5,799	5,723	6,425	24,385	8,079	7,362	8,114	6,483	30,038
(98)	(95)	(104)	(143)	(440)	(172)	(128)	(144)	(172)	(616)
(72)	(72)	(75)	(121)	(340)	(30)	(35)	(37)	(43)	(145)
6,268	5,632	5,544	6,161	23,605	7,877	7,199	7,933	6,268	29,277
(1,899)	(1,708)	(1,657)	(1,818)	(7,082)	(2,479)	(2,291)	(2,674)	(2,029)	(9,473)
4,369	3,924	3,887	4,343	16,523	5,398	4,908	5,259	4,239	19,804
(71)	(9)	(44)	(780)	(904)	154	142	(781)	286	(199)
4,298	3,915	3,843	3,563	15,619	5,552	5,050	4,478	4,525	19,605
4,264	3,873	3,791	3,504	15,432	5,491	4,981	4,410	4,432	19,314
34	42	52	59	187	61	69	68	93	291
4,298	3,915	3,843	3,563	15,619	5,552	5,050	4,478	4,525	19,605
19.30	17.69	17.49	16.23	70.71	25.61	23.42	21.04	21.34	91.41
1.16	1.06	1.05	0.97	4.24	1.54	1.40	1.26	1.28	5.48
4,298	3,915	3,843	3,563	15,619	5,552	5,050	4,478	4,525	19,605
648	462	1,027	(494)	1,643	1,111	610	2,053	(747)	3,027
4,946	4,377	4,870	3,069	17,262	6,663	5,660	6,531	3,778	22,632
22.24	19.79	22.21	14.00	78.24	30.79	26.30	30.75	17.90	105.74
21.77	19.39	21.96	13.75	76.87	30.36	25.94	30.54	17.68	104.52
1.33	1.19	1.33	0.84	4.69	1.85	1.58	1.84	1.07	6.34
1.31	1.16	1.32	0.82	4.61	1.82	1.56	1.83	1.06	6.27
22.12	19.55	21.85	17.57	81.09	29.37	25.81	33.87	15.82	104.87
21.65	19.16	21.59	17.26	79.66	28.97	25.45	33.62	15.62	103.66
1.33	1.17	1.31	1.06	4.87	1.76	1.55	2.03	0.95	6.29
1.30	1.15	1.29	1.04	4.78	1.74	1.53	2.01	0.94	6.22
208	268	318	424	1,218	279	345	484	369	1,477
24	22	27	25	98	26	19	46	45	136
2	1	3	3	9	4	4	5	2	15
234	291	348	452	1,325	309	368	535	416	1,628

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Replacement cost profit before interest and tax by business and geographical area

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BY BUSINESS	2001	2002	IFRS 2003
Exploration and Production
UK	3,395	2,294	3,468
Rest of Europe	756	724	587
USA	4,461	2,358	5,673
Rest of World	3,860	2,901	5,353
	12,472	8,277	15,081
Refining and Marketing
UKa	(644)	(710)	(119)
Rest of Europe	875	1,025	1,472
USA	3,007	926	1,009
Rest of World	1,216	695	800
	4,454	1,936	3,162
Gas, Power and Renewables
UK	69	(47)	79
Rest of Europe	189	1,685	(39)
USA	288	5	296
Rest of World	18	318	273
	564	1,961	609
Other businesses and corporate
UK	(472)	(506)	(167)
Rest of Europe	27	295	27
USA	(573)	(525)	(433)
Rest of World	90	(238)	313
	(928)	(974)	(260)
	16,562	11,200	18,592
Unrealized profit in inventory	–	–	(61)
Net profit on transactions between continuing and Innovene operations	–	–	193
Total for continuing operations	16,562	11,200	18,724
Innovene operationsb
UK	–	–	(155)
Rest of Europe	–	–	294
USA	–	–	37
Rest of World	–	–	5
	–	–	181
Net profit on transactions between continuing and Innovene operations	–	–	(193)
Total for Innovene operations	–	–	(12)
Total for period	16,562	11,200	18,712
BY GEOGRAPHICAL AREA
UKa	2,348	1,031	3,263
Rest of Europe	1,847	3,729	2,130
USA	7,183	2,764	6,592
Rest of World	5,184	3,676	6,739
Total for continuing operations	16,562	11,200	18,724

aUK area includes the UK-based international activities of Refining and Marketing.

bInnovene results for the years ended 31 December 2001 and 2002 are included within the results of Other businesses and corporate.

									\$ million
IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2004	IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2005
840	852	763	998	3,453	911	574	939	(295)	2,129
163	206	246	222	837	1,328	294	301	398	2,321
1,684	1,714	1,799	1,600	6,797	2,003	2,438	2,070	2,964	9,475
1,555	1,490	2,014	1,929	6,988	2,242	2,595	3,224	3,499	11,560
4,242	4,262	4,822	4,749	18,075	6,484	5,901	6,534	6,566	25,485
(118)	(129)	(70)	(378)	(695)	(272)	(60)	267	(516)	(581)
319	549	534	584	1,986	423	658	656	(170)	1,567
444	959	589	843	2,835	999	361	533	354	2,247
283	285	248	252	1,068	261	314	419	167	1,161
928	1,664	1,301	1,301	5,194	1,411	1,273	1,875	(165)	4,394
23	(6)	(89)	161	89	118	125	(16)	(157)	70
(13)	(3)	(12)	(2)	(30)	6	(1)	(3)	(18)	(16)
78	127	160	94	459	167	55	408	147	777
112	88	(6)	252	446	121	10	(42)	157	246
200	206	53	505	964	412	189	347	129	1,077
(171)	(83)	(170)	207	(217)	(179)	(209)	(144)	(141)	(673)
20	(26)	4	(132)	(134)	4	30	11	(124)	(79)
(152)	(168)	(265)	(197)	(782)	(9)	(13)	(361)	(22)	(405)
1,411	(11)	(16)	(96)	1,288	13	36	(7)	(122)	(80)
1,108	(288)	(447)	(218)	155	(171)	(156)	(501)	(409)	(1,237)
6,478	5,844	5,729	6,337	24,388	8,136	7,207	8,255	6,121	29,719
(66)	(87)	(95)	57	(191)	(153)	(4)	(285)	234	(208)
26	42	89	31	188	96	159	144	128	527
6,438	5,799	5,723	6,425	24,385	8,079	7,362	8,114	6,483	30,038
(110)	(14)	(49)	(71)	(244)	(13)	152	(276)	428	291
101	94	174	(423)	(54)	305	120	(169)	(4)	252
(8)	(14)	(14)	(362)	(398)	90	42	(258)	(127)	(253)
(4)	10	(3)	(115)	(112)	–	17	(37)	15	(5)
(21)	76	108	(971)	(808)	382	331	(740)	312	285
(26)	(42)	(89)	(31)	(188)	(96)	(159)	(144)	(128)	(527)
(47)	34	19	(1,002)	(996)	286	172	(884)	184	(242)
6,391	5,833	5,742	5,423	23,389	8,365	7,534	7,230	6,667	29,796
584	664	462	1,102	2,812	585	477	1,089	(965)	1,186
505	738	833	732	2,808	1,834	1,089	1,049	128	4,100
1,988	2,545	2,188	2,254	8,975	3,028	2,841	2,376	3,643	11,888
3,361	1,852	2,240	2,337	9,790	2,632	2,955	3,600	3,677	12,864
6,438	5,799	5,723	6,425	24,385	8,079	7,362	8,114	6,483	30,038

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Non-operating items by business

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	2001	2002	IFRS 2003
Exploration and Production
Impairment and gain (loss) on sale of businesses and fixed assets	20	(1,911)	175
Restructuring, integration and rationalization costs	(87)	(184)	(117)
Fair value gain (loss) on embedded derivatives	–	–	–
Other	(60)	(55)	–
	(127)	(2,150)	58
Refining and Marketing
Impairment and gain (loss) on sale of businesses and fixed assets	426	579	(214)
Environmental charges and other provisions	–	–	(369)
Restructuring, integration and rationalization costs	(446)	(499)	(287)
Other	–	100	10
	(20)	180	(860)
Gas, Power and Renewables
Impairment and gain (loss) on sale of businesses and fixed assets	–	1,521	(6)
Environmental charges and other provisions	–	–	–
Fair value gain (loss) on embedded derivatives	–	–	–
Other	–	–	–
	–	1,521	(6)
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(86)	(411)	139
Environmental charges and other provisions	–	(46)	(213)
Restructuring, integration and rationalization costs	(228)	(91)	5
Fair value gain (loss) on embedded derivatives	–	–	–
Othera	–	(140)	549
	(314)	(688)	480
Subtotal	(461)	(1,137)	(328)
Bond/lease redemption charges	(62)	(15)	–
Total before taxation for continuing operations	(523)	(1,152)	(328)
Taxation credit (charge)	224	494	94
Total after taxation for continuing operations	(299)	(658)	(234)
Innovene operations
Impairment and gain (loss) on sale of businesses and fixed assets	–	–	–
Restructuring, integration and rationalization costs	–	–	–
Other	–	–	–
Total before taxation for Innovene operationsb	–	–	–
Taxation credit (charge)	–	–	–
Total after taxation for Innovene operations	–	–	–
Subtotal	(299)	(658)	(234)
Minority interest	–	16	–
Total after taxation for period	(299)	(642)	(234)

a2003 includes a credit of \$648 million before tax, relating to a US medical plan.

bIncludes the loss on remeasurement to fair value of \$591 million recognized as \$724 million loss in the third quarter and \$133 million gain in the fourth quarter of 2005, impairment charges of \$24 million and \$35 million in the first and third quarters of 2005 respectively and a gain on disposal of \$3 million in the fourth quarter of 2005.

									\$ million
IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS
Q1	Q2	Q3	Q4	2004	Q1	Q2	Q3	Q4	2005
25	(274)	16	(236)	(469)	940	(3)	(106)	62	893
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	(160)	(674)	(53)	(801)	(1,688)
–	–	(35)	8	(27)	–	25	12	(240)	(203)
25	(274)	(19)	(228)	(496)	780	(652)	(147)	(979)	(998)
(160)	55	(18)	(333)	(456)	(27)	75	(14)	50	84
–	–	(206)	–	(206)	–	–	(140)	–	(140)
–	–	–	(32)	(32)	–	–	–	–	–
–	–	–	–	–	–	(733)	–	–	(733)
(160)	55	(224)	(365)	(694)	(27)	(658)	(154)	50	(789)
– –	– –	16 –	40 –	56 –	63 –	20 –	(2) 6	(26) –	55 6
–	–	–	–	–	42	67	91	(546)	(346)
–	–	–	–	–	–	–	–	265	265
–	–	16	40	56	105	87	95	(307)	(20)
1,261	(68)	(37)	8	1,164	–	34	4	–	38
–	–	(283)	–	(283)	–	22	(296)	(4)	(278)
1	–	(18)	(85)	(102)	(43)	(28)	(6)	(57)	(134)
–	–	–	–	–	(4)	(14)	8	(3)	(13)
–	–	–	66	66	–	3	–	–	3
1,262	(68)	(338)	(11)	845	(47)	17	(290)	(64)	(384)
1,127	(287)	(565)	(564)	(289)	811	(1,206)	(496)	(1,300)	(2,191)
–	–	–	–	–	–	–	–	–	–
1,127	(287)	(565)	(564)	(289)	811	(1,206)	(496)	(1,300)	(2,191)
(341)	87	171	166	83	(255)	384	167	421	717
786	(200)	(394)	(398)	(206)	556	(822)	(329)	(879)	(1,474)
(4)	–	1	(1,109)	(1,112)	(24)	–	(35)	3	(56)
(1)	–	(1)	(5)	(7)	–	–	–	–	–
–	–	–	–	–	–	–	(724)	133	(591)
(5)	–	–	(1,114)	(1,119)	(24)	–	(759)	136	(647)
2	–	–	251	253	10	–	167	190	367
(3)	–	–	(863)	(866)	(14)	–	(592)	326	(280)
783	(200)	(394)	(1,261)	(1,072)	542	(822)	(921)	(553)	(1,754)
–	–	–	–	–	–	–	–	–	–
783	(200)	(394)	(1,261)	(1,072)	542	(822)	(921)	(553)	(1,754)

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Non-operating items by geographical area

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	2001	2002	IFRS 2003
Exploration and Production
UK	(82)	(600)	526
Rest of Europe	8	13	(30)
USA	(122)	(758)	(658)
Rest of World	69	(805)	220
	(127)	(2,150)	58
Refining and Marketing
UK	(349)	(46)	(44)
Rest of Europe	(141)	(192)	(386)
USA	191	462	(431)
Rest of World	279	(44)	1
	(20)	180	(860)
Gas, Power and Renewables
UK	–	5	–
Rest of Europe	–	1,585	–
USA	–	(69)	(6)
Rest of World	–	–	–
	–	1,521	(6)
Other businesses and corporate
UK	(179)	(188)	(84)
Rest of Europe	(42)	20	(11)
USAa	4	(276)	402
Rest of World	(97)	(244)	173
	(314)	(688)	480
Subtotal	(461)	(1,137)	(328)
Bond/lease redemption charges	(62)	(15)	–
Total before taxation for continuing operations	(523)	(1,152)	(328)
Taxation credit (charge)	224	494	94
Total after taxation for continuing operations	(299)	(658)	(234)
Innovene operations
UK	–	–	–
Rest of Europe	–	–	–
USA	–	–	–
Rest of World	–	–	–
Total before taxation for Innovene operationsb	–	–	–
Taxation credit (charge)	–	–	–
Total after taxation for Innovene operations	–	–	–
Subtotal	(299)	(658)	(234)
Minority interest	–	16	–
Total after taxation for period	(299)	(642)	(234)

a2003 includes a credit of \$648 million before tax, relating to a US medical plan.

bIncludes the loss on remeasurement to fair value of \$591 million recognized as \$724 million loss in the third quarter and \$133 million gain in the fourth quarter of 2005, impairment charges of \$24 million and \$35 million in the first and third quarters of 2005 respectively and a gain on disposal of \$3 million in the fourth quarter of 2005.

									\$ million
IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2004	IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2005
(1)	(2)	(3)	(15)	(21)	(290)	(678)	(53)	(975)	(1,996)
– (19)	– (117)	(1) 31	– (268)	(1) (373)	1,027 (1)	3 (3)	– (106)	6 (121)	1,036 (231)
45	(155)	(46)	55	(101)	44	26	12	111	193
25	(274)	(19)	(228)	(496)	780	(652)	(147)	(979)	(998)
(36)	(58)	(25)	(411)	(530)	8	(23)	(3)	(8)	(26)
(37)	73	(46)	(25)	(35)	1	(12)	(53)	(33)	(97)
(5)	7	(143)	89	(52)	5	(634)	(96)	118	(607)
(82)	33	(10)	(18)	(77)	(41)	11	(2)	(27)	(59)
(160)	55	(224)	(365)	(694)	(27)	(658)	(154)	50	(789)
–	–	–	–	–	105	66	90	(306)	(45)
–	–	–	(1)	(1)	–	–	–	–	–
–	–	–	1	1	–	21	5	–	26
–	–	16	40	56	–	–	–	(1)	(1)
–	–	16	40	56	105	87	95	(307)	(20)
(3)	4	(44)	(87)	(130)	(42)	(6)	(6)	(57)	(111)
1	(1)	(54)	(12)	(66)	(1)	12	–	–	11
(126)	(70)	(251)	100	(347)	(4)	11	(284)	(7)	(284)
1,390	(1)	11	(12)	1,388	–	–	–	–	–
1,262	(68)	(338)	(11)	845	(47)	17	(290)	(64)	(384)
1,127 –	(287) –	(565) –	(564) –	(289) –	811 –	(1,206) –	(496) –	(1,300) –	(2,191) –
1,127	(287)	(565)	(564)	(289)	811	(1,206)	(496)	(1,300)	(2,191)
(341)	87	171	166	83	(255)	384	167	421	717
786	(200)	(394)	(398)	(206)	556	(822)	(329)	(879)	(1,474)
(5)	–	–	(218)	(223)	(24)	–	(301)	242	(83)
–	–	–	(427)	(427)	–	–	(224)	(49)	(273)
–	–	–	(355)	(355)	–	–	(208)	(51)	(259)
–	–	–	(114)	(114)	–	–	(26)	(6)	(32)
(5)	–	–	(1,114)	(1,119)	(24)	–	(759)	136	(647)
2	–	–	251	253	10	–	167	190	367
(3)	–	–	(863)	(866)	(14)	–	(592)	326	(280)
783	(200)	(394)	(1,261)	(1,072)	542	(822)	(921)	(553)	(1,754)
–	–	–	–	–	–	–	–	–	–
783	(200)	(394)	(1,261)	(1,072)	542	(822)	(921)	(553)	(1,754)

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Depreciation of fixed asset revaluation adjustment by business and geographical areaa b

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2001	2002	IFRS 2003
Exploration and Production
UK	55	66 38
USA 1,058	596	528
Rest of World	102 103	56
1,215	765	622
Refining and Marketing
USA	124 130	102
	124 130	102
Gas, Power and Renewables
USA	–	– 22
	–	– 22
1,339	895	746

aRelates to the revaluation adjustment consequent upon the ARCO acquisition.

bExcludes impairment of the revaluation adjustment, which is included in non-operating items.

Amortization of goodwill by business and geographical areaa

	2001	2002	IFRS 2003
Exploration and Production
UK	96	96	–
USA	472	482	–
Rest of World	32	32	–
	600	610	–
Refining and Marketing
UK	394	410	–
USA	252	254	–
	646	664	–
	1,246	1,274	–

aAmortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions.

									\$ million
IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS	IFRS
Q1	Q2	Q3	Q4	2004	Q1	Q2	Q3	Q4	2005
11	8	6	9	34	8	12	6	7	33
93	90	98	81	362	76	70	64	62	272
6	6	4	3	19	5	3	5	5	18
110	104	108	93	415	89	85	75	74	323
25	26	25	26	102	25	26	25	26	102
25	26	25	26	102	25	26	25	26	102
6	5	6	5	22	6	5	6	5	22
6	5	6	5	22	6	5	6	5	22
141	135	139	124	539	120	116	106	105	447

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:37 am Page 15

									\$ million
IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2004	IFRS Q1	IFRS Q2	IFRS Q3	IFRS Q4	IFRS 2005
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–
–	–	–	–	–	–	–	–	–	–

Sales and other operating revenues

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:37 am Page 16

					\$ million
BY BUSINESS	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Exploration and Production	27,540	25,083	30,621	34,700	47,210
Refining and Marketing	114,135	121,908	147,813	176,240	219,995
Gas, Power and Renewables	22,906	16,490	22,984	26,220	28,700
Other businesses and corporate	12,005	12,548	515	546	668
Sales by continuing operations	176,586	176,029	201,933	237,706	296,573
Less
Sales between businesses	28,084	26,355	26,214	29,604	35,318
Sales to Innovene operations	–	–	6,278	8,226	11,790
Third party sales of continuing operations	148,502	149,674	169,441	199,876	249,465
Innovene sales	–	–	13,463	17,448	20,627
Less sales to continuing operations	–	–	4,501	6,169	8,251
Third party sales of Innovene operations	–	–	8,962	11,279	12,376
Total third party sales	148,502	149,674	178,403	211,155	261,841
BY GEOGRAPHICAL AREA
UKa	41,245	38,958	35,546	60,151	96,134
Rest of Europe	36,701	46,518	42,033	44,858	64,305
USA	71,927	67,206	79,443	87,200	103,185
Rest of World	27,337	28,319	37,782	47,862	59,628
	177,210	181,001	194,804	240,071	323,252
Less
Sales between areas	28,708	31,327	19,085	31,969	61,997
Sales to Innovene operations	–	–	6,278	8,226	11,790
	148,502	149,674	169,441	199,876	249,465

aUK area includes the UK-based international activities of Refining and Marketing.

Taxation

					\$ million
			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Production and similar taxes provided for
UK	600	309	300	335	495
Overseas	1,089	965	1,423	1,814	2,515
	1,689	1,274	1,723	2,149	3,010
Production and similar taxes paid
UK	410	231	424	498	640
Overseas	1,114	930	1,386	1,709	2,327
	1,524	1,161	1,810	2,207	2,967
Tax on profit from continuing operations
Current tax chargea
UK	988	1,003	1,142	1,839	880
Overseas	3,846	1,883	3,581	5,022	7,744
Group	4,834	2,886	4,723	6,861	8,624
Jointly controlled entitiesb	94	75	–	–	–
Associatesb	203	187	–	–	–
	5,131	3,148	4,723	6,861	8,624
Deferred tax chargec
UK	(48)	390	289	(218)	(489)
Overseas	1,292	779	38	439	1,338
	1,244	1,169	327	221	849
Total tax on profit from continuing operationsc	6,375	4,317	5,050	7,082	9,473
Effective tax ratesd on
Replacement cost profit for the year	43%	43%	29%	30%	32%
Profit for the year	49%	39%	28%	28%	30%
Income taxes paid	4,660	3,094	4,804	6,388	9,028

aThe data for 2001 and 2002 relates to current tax on profit for total operations. The data for 2003, 2004 and 2005 relates to current tax on profit on continuing operations. bThe data for 2001 and 2002 includes the group's share of current tax relating to jointly controlled entities and associates. Under IFRS, the results of jointly controlled entities and associates for 2003, 2004 and 2005 are included in the income statement net of tax.

cThe data for 2001 and 2002 relates to deferred tax for total operations. The data for 2003, 2004 and 2005 relates to deferred tax for continuing operations. dThe data for 2001 and 2002 relates to total operations. The data for 2003, 2004 and 2005 relates to continuing operations.

Depreciation, depletion and amortization

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:38 am Page 17

					\$ million
			IFRS	IFRS	IFRS
BY BUSINESS	2001	2002	2003	2004	2005
Exploration and Productiona
UK	1,397	1,506	1,612	1,642	1,663
Rest of Europe	115	154	168	184	228
USA	3,147	2,952	2,627	2,407	2,426
Rest of World	946	989	1,132	1,350	1,716
	5,605	5,601	5,539	5,583	6,033
Refining and Marketinga
UKb	589	641	252	318	316
Rest of Europe	303	554	606	645	687
USA	1,394	1,396	1,063	1,238	1,082
Rest of World	214	224	277	331	297
	2,500	2,815	2,198	2,532	2,382
Gas, Power and Renewablesa
UK	6	4	34	37	47
Rest of Europe	3	4	22	24	20
USA	60	62	69	88	109
Rest of World	22	29	35	69	59
	91	99	160	218	235
Other businesses and corporate
UK	165	225	294	251	203
Rest of Europe	92	155	166	204	130
USA	173	161	205	199	187
Rest of World	57	71	43	25	13
	487	612	708	679	533
BY GEOGRAPHICAL AREA
UKb	2,157	2,376	2,192	2,248	2,229
Rest of Europe	513	867	962	1,057	1,065
USA	4,774	4,571	3,964	3,932	3,804
Rest of World	1,239	1,313	1,487	1,775	2,085
Totalc	8,683	9,127	8,605	9,012	9,183
Innovene operations	–	–	(529)	(483)	(412)
Continuing operations	8,683	9,127	8,076	8,529	8,771
aDepreciation of the fixed asset revaluation adjustment consequent
upon the ARCO acquisition
Exploration and Production	1,215	765	622	415	323
Refining and Marketing	124	130	102	102	102
Gas, Power and Renewables	–	–	22	22	22

bUK area includes the UK-based international activities of Refining and Marketing.

cExcludes impairments, which are included in non-operating items.

Group balance sheet

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:38 am Page 18

							\$ million
						IFRS post
			IFRS	IFRS	IFRS	IAS 39	IFRS
	2001	2002	2003	1 January 31 December 31 December 2003	2004	1 January 2005	31 December 2005
Non-current assets
Property, plant and equipmenta	77,410	87,682	84,943	88,607	93,092	93,092	85,947
Goodwilla	9,971	10,438	10,440	10,592	10,857	10,857	10,371
Intangible assetsa	6,518	5,128	5,127	4,471	4,205	4,205	4,772
Investments in jointly controlled entitiesa	3,861	4,031	5,596	12,909	14,556	14,556	13,556
Investments in associates	5,433	4,626	4,514	4,868	5,486	5,486	6,217
Other investments	2,403	1,995	1,995	1,452	394	811	967
Fixed assets	105,596	113,900	112,615	122,899	128,590	129,007	121,830
Loans and other receivables	4,681	2,346	2,548	2,838	2,492	3,146	6,512
Defined benefit pension plan surplus	–	388	554	1,680	2,105	2,105	3,282
	110,277	116,634	115,717	127,417	133,187	134,258	131,624
Current assets
Inventories	7,631	10,181	10,155	11,597	15,645	15,645	19,760
Trade and other receivables	21,653	26,811	26,793	31,329	44,280	44,956	52,358
Current tax receivable	335	94	94	92	159	159	212
Cash and cash equivalents	1,808	1,735	1,716	2,056	1,359	1,359	2,960
	31,427	38,821	38,758	45,074	61,443	62,119	75,290
Total assets	141,704	155,455	154,475	172,491	194,630	196,377	206,914
Current liabilities
Trade and other payables	25,068	32,795	31,154	36,151	48,096	48,738	57,189
Finance debt	9,090	10,086	10,086	9,456	10,184	10,184	8,932
Current tax payable	3,456	3,420	3,420	3,441	4,131	4,131	4,274
Provisions	847	716	716	735	715	715	1,102
	38,461	47,017	45,376	49,783	63,126	63,768	71,497
Non-current liabilities
Other payables	3,054	3,412	3,361	5,838	4,438	5,751	8,795
Finance debt	12,327	11,922	11,922	12,869	12,907	13,054	10,230
Deferred tax liabilities	11,702	13,514	15,045	16,051	16,701	16,589	16,443
Provisions	10,419	7,120	7,120	7,864	8,884	8,884	9,954
Defined benefit pension plan and other
post-retirement benefit plan deficits	–	7,998	10,784	9,822	10,339	10,339	9,230
	37,502	43,966	48,232	52,444	53,269	54,617	54,652
Total liabilities	75,963	90,983	93,608	102,227	116,395	118,385	126,149
Net assets	65,741	64,472	60,867	70,264	78,235	77,992	80,765
Equity
Share capital	5,629	5,616	5,616	5,552	5,403	5,403	5,185
Share premium account	3,590	3,794	3,794	3,957	5,636	5,636	7,371
Capital redemption reserve	424	449	449	523	730	730	749
Merger reserve	26,983	27,033	27,033	27,077	27,162	27,162	27,190
Other reserves	223	173	173	129	44	44	16
Shares held by ESOPb trusts	(266)	(159)	(159)	(96)	(82)	(82)	(140)
Treasury shares	–	–	–	–	–	–	(10,598)
Available-for-sale investments	–	–	–	–	–	230	385
Cash flow hedges	–	–	–	–	–	(118)	(234)
Foreign currency translation reserve	–	–	–	3,619	5,616	5,616	2,943
Retained earnings	28,560	26,928	23,323	28,378	32,383	32,028	47,109
BP shareholders' equity	65,143	63,834	60,229	69,139	76,892	76,649	79,976
Minority interest	598	638	638	1,125	1,343	1,343	789
Total equity	65,741	64,472	60,867	70,264	78,235	77,992	80,765
a
Revaluation adjustment and goodwill consequent
upon the ARCO and Burmah Castrol acquisitions
Property, plant and equipment	6,787	5,804	5,804	3,983	3,520	3,520	3,072
Goodwill	10,467	9,527	9,527	9,890	10,180	10,180	9,778
Intangible assets	1,196	912	912	589	241	241	241
Investments in jointly controlled entities	432	429	429	254	232	232	210
	18,882	16,672	16,672	14,716	14,173	14,173	13,301

bEmployee Share Ownership Plan.

C12386_BP_F&OI 2005_p04-29.qxp 5/4/06 5:57 pm Page 19

							\$ million
						IFRS post
			IFRS	IFRS 1 January 31 December 31 December	IFRS	IAS 39 1 January	IFRS 31 December
BY BUSINESS	2001	2002	2003	2003	2004	2005	2005
Exploration and Productionb
UK	9,608	8,819	8,819	8,729	8,803	7,766	5,924
Rest of Europe	1,049	1,452	1,452	1,476	1,558	1,558	1,451
USA	24,598	24,426	24,240	23,308	24,345	24,465	25,443
Rest of World	19,488	22,164	22,029	25,816	30,485	30,485	35,871
	54,743	56,861	56,540	59,329	65,191	64,274	68,689
Refining and Marketingb
UKc	3,037	3,024	2,878	3,471	3,485	3,491	3,696
Rest of Europe	3,195	10,010	10,005	10,701	12,543	12,590	11,588
USA	12,362	13,797	13,006	13,481	15,047	15,047	16,973
Rest of World	4,805	5,335	5,531	6,431	7,212	7,353	7,522
	23,399	32,166	31,420	34,084	38,287	38,481	39,779
Gas, Power and Renewablesb
UK	469	438	420	786	880	1,219	241
Rest of Europe	933	386	386	418	463	568	542
USA	1,060	1,044	1,510	2,130	2,122	2,143	2,990
Rest of World	880	1,054	1,077	1,427	1,868	1,865	1,769
	3,342	2,922	3,393	4,761	5,333	5,795	5,542
Other businesses and corporate
UK	2,477	2,357	3,806	3,700	6,560	6,637	5,187
Rest of Europe	2,058	(1,441)	(1,441)	(2,067)	(1,661)	(1,661)	(4,268)
USA	632	(2,028)	(1,822)	256	(2,306)	(2,331)	(3,953)
Rest of World	4,454	(584)	(799)	1,695	290	290	(137)
	9,621	(1,696)	(256)	3,584	2,883	2,935	(3,171)
Consolidation adjustment	–	–	(300)	(361)	(552)	(552)	(778)
	91,105	90,253	90,797	101,397	111,142	110,933	110,061
BY GEOGRAPHICAL AREA
UKc	15,591	14,638	15,923	16,686	19,728	19,113	15,023
Rest of Europe USA	7,235	10,407	10,402	10,528	12,903	13,055	9,313
Rest of World	38,652 29,627	37,239 27,969	36,634 27,838	38,814 35,369	38,656 39,855	38,772 39,993	40,722 45,003
Total operating capital employed Liabilities for current and deferred taxation	91,105 (14,815)	90,253 (14,211)	90,797 (18,362)	101,397 (19,400)	111,142 (20,673)	110,933 (20,560)	110,061 (20,505)
Goodwill	10,868	10,438	10,440	10,592	10,857	10,857	10,371
Capital employed
	87,158	86,480	82,875	92,589	101,326	101,230	99,927
Financed by
Finance debt	21,417	22,008	22,008	22,325	23,091	23,238	19,162
Minority interest BP shareholders' interest	598	638	638	1,125	1,343	1,343	789
	65,143	63,834	60,229	69,139	76,892	76,649	79,976
Capital employed	87,158	86,480	82,875	92,589	101,326	101,230	99,927

bOperating capital employed revaluation adjustment consequent
upon the ARCO and Burmah Castrol acquisitions
Exploration and Production	6,525	5,366	5,366	3,222	2,514	2,514	2,180
Refining and Marketing	1,890	1,779	1,502	1,349	1,247	1,247	1,134
Gas, Power and Renewables	–	–	277	255	232	232	209
	8,415	7,145	7,145	4,826	3,993	3,993	3,523

c UK area includes the UK-based international activities of Refining and Marketing. C12386_BP_F&OI 2005_p04-29.qxp 5/4/06 6:03 pm Page 20

							\$ million
						IFRS post
			IFRS	IFRS	IFRS	IAS 39	IFRS
				1 January 31 December 31 December		1 January	31 December
NET BOOK AMOUNT BY BUSINESS	2001	2002	2003	2003	2004	2005	2005
Exploration and Productiona
UK	11,573	11,827	11,827	11,418	11,783	11,783	10,972
Rest of Europe	1,030	1,438	1,438	1,594	1,985	1,985	1,727
USA	24,489	25,789	25,342	25,170	25,797	25,797	27,173
Rest of World	10,800	12,846	12,437	14,426	17,018	17,018	19,852
	47,892	51,900	51,044	52,608	56,583	56,583	59,724
Refining and Marketinga
UK	2,529	2,719	2,561	2,874	2,586	2,586	2,199
Rest of Europe	3,040	8,472	7,004	7,626	8,177	8,177	6,914
USA	11,491	11,402	10,967	10,993	10,763	10,763	10,323
Rest of World	2,831	3,216	3,127	3,599	3,402	3,402	3,251
	19,891	25,809	23,659	25,092	24,928	24,928	22,687
Gas, Power and Renewables
UK	473	377	377	460	610	610	108
Rest of Europe	104	132	132	148	155	155	125
USA	697	770	880	1,006	1,009	1,009	1,011
Rest of World	646	598	599	720	697	697	700
	1,920	1,877	1,988	2,334	2,471	2,471	1,944
Other businesses and corporate
UK	2,661	2,954	2,954	3,152	3,222	3,222	856
Rest of Europe	1,412	1,584	1,584	1,873	2,575	2,575	1
USA	3,177	3,089	3,089	3,004	3,049	3,049	723
Rest of World	457	469	625	544	264	264	12
	7,707	8,096	8,252	8,573	9,110	9,110	1,592
NET BOOK AMOUNT BY GEOGRAPHICAL AREA
UK	17,236	17,877	17,719	17,904	18,201	18,201	14,135
Rest of Europe	5,586	11,626	10,158	11,241	12,892	12,892	8,767
USA	39,854	41,050	40,278	40,173	40,618	40,618	39,230
Rest of World	14,734	17,129	16,788	19,289	21,381	21,381	23,815
	77,410	87,682	84,943	88,607	93,092	93,092	85,947
COST AND ACCUMULATED DEPRECIATION
Exploration and Production
Cost							122,142
Accumulated depreciation							(62,418)
							59,724
Refining and Marketing
Cost							45,398
Accumulated depreciation							(22,711)
							22,687
Gas, Power and Renewables
Cost							3,423
Accumulated depreciation							(1,479)
							1,944
Other businesses and corporate
Cost							2,350
Accumulated depreciation							(758)
							1,592
							85,947
a Fixed asset revaluation adjustment consequent upon
the ARCO and Burmah Castrol acquisitions
Exploration and Production	5,177	4,302	4,302	2,634	2,273	2,273	1,939
Refining and Marketing	1,610	1,502	1,502	1,349	1,247	1,247	1,134
	6,787	5,804	5,804	3,983	3,520	3,520	3,073

Working capital

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:38 am Page 21

						\$ million
			IFRS	IFRS
				1 January 31 December	IFRS	IFRS
INVENTORIES, RECEIVABLES AND PAYABLES	2001	2002	2003	2003	2004	2005
Inventories	6,697	7,779	7,753	8,729	11,837	16,321
Supplies	934	893	893	938	911	919
	7,631	8,672	8,646	9,667	12,748	17,240
Trading inventoriesa	–	1,509	1,509	1,930	2,897	2,520
	7,631	10,181	10,155	11,597	15,645	19,760
Current receivables
Trade and other receivables	15,436	18,798	18,780	23,449	30,657	33,565
Jointly controlled entities	32	70	70	122	886	1,345
Associates	236	282	282	337	210	186
Prepayments and accrued income	2,143	2,716	2,716	3,448	7,181	11,456
Current tax receivable	335	94	94	92	159	212
Other	3,806	4,945	4,945	3,973	5,346	5,806
	21,988	26,905	26,887	31,421	44,439	52,570
Non-current receivables
Associates	49	96	96	53	23	–
Prepayments and accrued income	789	1,771	1,970	957	354	1,269
Tax receivable	8	9	9	–	–	–
Pension prepayment	3,417	–	–	–	–	–
Other	418	470	473	1,828	2,115	5,243
	4,681	2,346	2,548	2,838	2,492	6,512
Current payables
Trade	13,129	17,454	17,210	20,830	27,471	28,614
Jointly controlled entities	21	22	22	126	637	251
Associates	268	287	287	322	865	627
Production and similar taxes	254	421	421	421	517	763
Current tax payable	3,456	3,420	3,420	3,441	4,131	4,274
Social security	63	81	81	96	122	78
Accruals and deferred income	4,843	5,763	5,763	6,411	9,556	15,053
Dividends	1,289	1,398	1	1	1	1
Other	5,201	7,369	7,369	7,944	8,927	11,802
	28,524	36,215	34,574	39,592	52,227	61,463
Non-current payables
Associates	4	12	12	4	5	–
Production and similar taxes	1,346	1,455	1,455	1,544	1,520	1,281
Accruals and deferred income	1,029	1,002	950	1,208	857	6,860
Other	675	943	944	3,082	2,056	654
	3,054	3,412	3,361	5,838	4,438	8,795

aTrading inventories are included in inventories for 2001.

Group cash flow statement

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:38 am Page 22

					\$ million
			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Operating activities
Profit before taxation from continuing operations	12,992	11,189	17,731	24,966	31,921
Adjustments to reconcile profits before taxation to net cash provided
by operating activities
Exploration expenditure written off	238	385	297	274	305
Depreciation, depletion and amortization	8,683	9,127	8,076	8,529	8,771
Impairment and (gain) loss on sale of businesses and fixed assets	(362)	108	(94)	(295)	(1,070)
Earnings from jointly controlled entities and associates	(1,194)	(966)	(1,214)	(2,280)	(3,543)
Dividends received from jointly controlled entities and associates	632	566	548	2,199	2,833
Interest receivable	(346)	(256)	(212)	(284)	(479)
Interest received	256	231	186	331	401
Finance costs	1,432	1,067	513	440	616
Interest paid	(1,282)	(1,204)	(1,007)	(698)	(1,127)
Other finance expense	238	73	532	340	145
Share-based payments	–	–	208	224	278
Net operating charge for pensions and other post-retirement benefits,
less contributions	–	(39)	(2,913)	(84)	(435)
Net charge for provisions, less payments	(191)	(253)	171	(110)	600
(Increase) decrease in inventories	1,490	(1,521)	(657)	(3,182)	(6,638)
(Increase) decrease in other current and non-current assets	1,989	(2,367)	(2,981)	(10,225)	(16,427)
Increase (decrease) in other current and non-current liabilities	(2,428)	2,897	1,575	10,290	18,628
Income taxes paid	(4,660)	(3,094)	(4,804)	(6,388)	(9,028)
Net cash provided by operating activities of continuing operations	17,487	15,943	15,955	24,047	25,751
Net cash provided by (used in) operating activities of Innovene operationsa	–	–	348	(669)	970
Net cash provided by operating activities	17,487	15,943	16,303	23,378	26,721
Investing activities
Capital expenditures	(12,181)	(12,098)	(11,885)	(12,286)	(12,281)
Acquisitions, net of cash acquired	(1,210)	(4,324)	(211)	(1,503)	(60)
Investment in jointly controlled entities	(497)	(354)	(2,630)	(1,648)	(185)
Investment in associates	(586)	(971)	(987)	(942)	(619)
Proceeds from disposal of property, plant and equipment	2,185	2,415	6,177	4,236	2,803
Proceeds from disposal of businesses	538	4,312	179	725	8,397
Proceeds from loan repayments	180	55	76	87	123
Other	–	–	–	–	93
Net cash used in investing activities	(11,571)	(10,965)	(9,281)	(11,331)	(1,729)
Financing activities
Net repurchase of shares	(1,133)	(573)	(1,889)	(7,208)	(11,315)
Proceeds from long-term financing	1,296	3,707	4,322	2,675	2,475
Repayments of long-term financing	(2,602)	(2,369)	(3,560)	(2,204)	(4,820)
Net increase (decrease) in short-term debt	1,434	(602)	(2)	(24)	(1,457)
Dividends paid
BP shareholders	(4,827)	(5,264)	(5,654)	(6,041)	(7,359)
Minority interest	(54)	(40)	(20)	(33)	(827)
Net cash used in financing activities	(5,886)	(5,141)	(6,803)	(12,835)	(23,303)
Currency translation differences relating to cash and cash equivalents	(53)	90	121	91	(88)
Increase (decrease) in cash and cash equivalents	(23)	(73)	340	(697)	1,601
Cash and cash equivalents at beginning of year	1,831	1,808	1,716	2,056	1,359
Cash and cash equivalents at end of year	1,808	1,735	2,056	1,359	2,960

aThe cash flows of the operating activities of Innovene for the years ended 31 December 2001 and 2002 are included within the operating activities of continuing operations.

Movement in net debt

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:39 am Page 23

					\$ million
			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Opening balance
Finance debt	21,190	21,417	22,008	22,325	23,091
Cash and cash equivalents	1,831	1,808	1,716	2,056	1,359
Opening net debt	19,359	19,609	20,292	20,269	21,732
Closing balance
Finance debt	21,417	22,008	22,325	23,091	19,162
Cash and cash equivalents	1,808	1,735	2,056	1,359	2,960
Closing net debt	19,609	20,273	20,269	21,732	16,202
Decrease (increase) in net debt	(250)	(664)	23	(1,463)	5,530
Movement in cash and cash equivalents	30	(163)	219	(788)	1,689
Net cash (inflow) outflow from financing (excluding share capital)	(128)	(736)	(760)	(431)	3,803
Adoption of IAS 39	–	–	–	–	(147)
Fair value hedge adjustment	–	–	–	–	171
Partnership interests exchanged for BP loan notes	–	1,135	–	–	–
Debt transferred to TNK-BP	–	–	93	–	–
Exchange of exchangeable bonds for Lukoil American depositary shares	–	–	420	–	–
Other movements	(36)	76	144	68	146
Debt acquired	(55)	(1,002)	(15)	–	–
Movement in net debt before exchange effects	(189)	(690)	101	(1,151)	5,662
Exchange adjustments	(61)	26	(78)	(312)	(132)
Decrease (increase) in net debt	(250)	(664)	23	(1,463)	5,530

Capital expenditure, acquisitions and disposals

C12386_BP_F&OI 2005_p04-29.qxp 3/4/06 10:39 am Page 24

					\$ million
BY BUSINESS	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Exploration and Production
UK	1,095	952	786	762	821
Rest of Europe	329	262	279	255	197
USA	4,047	4,116	3,906	3,913	3,870
Rest of World	3,282	4,153	10,214	6,072	5,349
	8,753	9,483	15,185	11,002	10,237
Refining and Marketing
UKa	398	382	430	411	408
Rest of Europeb	393	5,776	728	599	568
USA	1,651	1,527	1,401	1,314	1,226
Rest of World	501	468	522	665	658
	2,943	8,153	3,081	2,989	2,860
Gas, Power and Renewables
UK	102	31	69	166	30
Rest of Europe	156	161	76	19	26
USA	162	170	237	80	96
Rest of World	79	85	143	265	83
	499	447	525	530	235
Other businesses and corporate
UK	500	254	244	403	339
Rest of Europe	909	357	163	1,024	189
USA	300	282	423	698	277
Rest of World	187	117	2	5	12
	1,896	1,010	832	2,130	817
BY GEOGRAPHICAL AREA UKa
Rest of Europeb	2,095	1,619	1,529	1,742	1,598
	1,787	6,556	1,246	1,897	980
USA Rest of World	6,160 4,049	6,095 4,823	5,967 10,881	6,005 7,007	5,469 6,102
	14,091	19,093	19,623	16,651	14,149
Included above
Acquisitions and asset exchangesb c	924	5,790	6,026	2,841	211
Innovene operations	–	–	462	1,915	497
Disposals	2,903	6,782	6,356	4,961	11,200

a UK area includes the UK-based international activities of Refining and Marketing.

bSignificant acquisitions in 2002 include Veba Oil (\$5,038 million).

c 2003 includes \$5,794 million for the acquisition of our interest in TNK-BP.

United States accounting principles

C12386_BP_F&OI 2005_p04-29.qxp 5/4/06 6:04 pm Page 25

The following is a summary of adjustments to profit for the year and to BP shareholders' equity that would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of International Financial Reporting Standards.

					\$ million
PROFIT FOR THE YEAR UNDER US GAAP	2001	2002	2003	2004	2005
Profit for the year as reporteda	6,556	6,795	12,448	17,075	22,341
Adjustments
Deferred taxation/business combinations	(1,423)	(603)	(588)	(517)	(496)
Provisions	(182)	8	49	(80)	9
Oil and natural gas reserve differences	–	–	–	30	11
Goodwill and intangible assets	60	1,302	–	(61)	–
Derivative financial instruments	(313)	540	(27)	(337)	87
Inventory valuation	–	–	39	162	(232)
Gain arising on asset exchange	157	(18)	(19)	(107)	(12)
Pensions and other post-retirement benefits	–	50	(215)	(47)	(486)
Impairments	–	–	–	677	(378)
Equity-accounted investments Major maintenance expenditure	– –	– –	(47) 120	147 217	(255) –
Share-based payments	–	–	39	24	6
Other	(26)	35	90	(93)	156
Profit for the year before cumulative effect of accounting changes as adjusted
to accord with US GAAP	4,829	8,109	11,889	17,090	20,751
Cumulative effect of accounting changes
Major maintenance expenditure	–	–	–	–	(794)
Provisions	–	–	1,002	–	–
Derivative financial instruments	(362)	–	50	–	–
Profit for the year as adjusted to accord with US GAAP	4,467	8,109	12,941	17,090	19,957
Dividend requirements on preference shares	(2)	(2)	(2)	(2)	(2)
Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP	4,465	8,107	12,939	17,088	19,955
Per ordinary share – cents
Basic – before cumulative effect of accounting changes	21.51	36.20	53.62	78.31	98.22
Cumulative effect of accounting changes	(1.61)	–	4.74	–	(3.76)
	19.90	36.20	58.36	78.31	94.46
Diluted – before cumulative effect of accounting changes	21.38	36.02	53.10	76.88	97.09
Cumulative effect of accounting changes	(1.60)	–	4.69	–	(3.71)
	19.78	36.02	57.79	76.88	93.38
Per American depositary shareb – cents
Basic – before cumulative effect of accounting changes	129.06	217.20	321.72	469.86	589.32
Cumulative effect of accounting changes	(9.66)	–	28.44	–	(22.56)
	119.40	217.20	350.16	469.86	566.76
Diluted – before cumulative effect of accounting changes	128.28	216.12	318.60	461.28	582.54
Cumulative effect of accounting changes	(9.60)	–	28.14	–	(22.26)
	118.68	216.12	346.74	461.28	560.28
BP SHAREHOLDERS' EQUITY UNDER US GAAP
BP shareholders' equity as reporteda	65,143	63,834	69,139	76,892	79,976
Adjustments
Deferred taxation/business combinations	(139)	(748)	3,009	2,563	2,025
Provisions	(1,054)	(1,088)	(128)	(77)	(112)
Oil and natural gas reserve differences	–	–	–	30	41
Goodwill and intangible assets	(1,414)	(84)	248	224	171
Derivative financial instruments	(675)	(135)	26	(315)	225
Inventory valuation	–	–	(98)	65	(167)
Gain arising on asset exchange	157	142	269	251	239
Pensions and other post-retirement benefits	(942)	3,437	5,246	4,089	3,146
Impairments	–	–	–	677	327
Equity-accounted investments	–	–	65	212	(43)
Dividends	1,288	1,398	–	–	–
Investments	(2)	34	1,251	227	–
Major maintenance expenditure	–	–	545	794	–
Share-based payments	–	–	(235)	(353)	(334)
Other	(174)	(154)	(170)	(187)	(32)
BP shareholders' equity as adjusted to accord with US GAAP	62,188	66,636	79,167	85,092	85,462

a Profit for the year and BP shareholders' equity, as reported for 2003, 2004 and 2005, are on the basis of IFRS. For 2001 and 2002, profit for the year and BP

shareholders' equity, as reported, are on the basis of UK GAAP. bOne American depositary share (ADS) is equivalent to six 25 cent ordinary shares.

United States accounting principles continued

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The principal differences between IFRS and US GAAP relate to the following.

Deferred taxation/business combinations Under both IFRS and US GAAP, deferred tax assets and liabilities are recognized for the difference between the assigned values and the tax bases of the assets and liabilities recognized in a purchase business combination, with the offset in goodwill. However, business combinations prior to 1 January 2003, BP's date of transition to IFRS, were not restated and the offset was taken as an adjustment to shareholders' equity at the transition date, creating a difference relating to business combinations accounted for under the purchase method that occurred prior to the group's IFRS transition date.

Provisions For both IFRS and US GAAP, upon initial recognition of a decommissioning provision, a corresponding amount is also recognized as an asset and is subsequently depreciated as part of the capital cost of the facilities. Under IFRS, provisions for decommissioning and environmental liabilities are measured on a discounted basis if the effect of the time value of money is material. For US GAAP, the liability is measured based on the risk-adjusted future cash outflows discounted using a credit-adjusted risk-free rate. Unlike IFRS, subsequent changes to the discount rate do not impact the carrying value of the asset or liability. Subsequent changes to the estimates of the timing or amount of future cash flows, resulting in an increase to the asset and liability, are remeasured using updated assumptions related to the credit-adjusted risk-free rate. Under US GAAP, environmental liabilities are discounted only where the timing and amounts of payments are fixed and reliably determinable. In addition, the use of different oil and natural gas reserve volumes between US GAAP and IFRS (see below) results in different field lives and hence differences result in the manner in which the subsequent unwinding of the discount and the depreciation of the corresponding assets associated with decommissioning provisions are recognized.

Oil and natural gas reserve differences The US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves are different in certain respects from the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities' (SORP); in particular, the SEC requires the use of year-end prices, whereas under SORP the group uses long-term planning prices. Any consequent difference in reserve volumes results in different charges for depreciation, depletion and amortization between IFRS and US GAAP.

Goodwill and intangible assets Under the IFRS transition rules, the group did not restate its past business combinations in accordance with IFRS, but assumed its UK GAAP carrying amount for goodwill as its IFRS carrying amount at 1 January 2003 and ceased amortization from that date. Under US GAAP, goodwill amortization ceased on 31 December 2001.

Derivative financial instruments US GAAP accounting for derivative financial instruments is similar to IFRS. A difference arises between IFRS and US GAAP for cash flow hedges where the hedged item is the cost of a non-financial asset or liability. US GAAP does not allow the amounts taken to equity to be transferred to the initial carrying amount of the non-financial asset or liability. The amounts remain in equity and are recognized in earnings as the non-financial asset is depreciated. Prior to 1 January 2005, the group did not designate any of its derivative financial instruments as part of hedged transactions under US GAAP. As a result, all changes in fair value were recognized through earnings. A difference therefore exists between the treatment applied under SFAS 133 and that upon initial adoption of IFRS. This difference will remain until the individual derivative transactions mature.

Inventory valuation Under IFRS, inventory held for trading purposes is measured at fair value with the changes in fair value recognized in the profit for the period. For US GAAP, all balances recorded in inventory are measured at the lower of cost and net realizable value.

Gain arising on asset exchange Under IFRS, exchanges of non-monetary assets are generally accounted for at fair value, with any gain or loss recognized in income. Under US GAAP prior to 1 January 2005, exchanges of non-monetary assets were accounted for at book value. From 1 January 2005, exchanges of non-monetary assets are generally accounted for at fair value under both IFRS and US GAAP.

Pensions and other post-retirement benefits Under IFRS, surpluses and deficits of funded schemes for pensions and other post-retirement benefits are included in the group balance sheet at their fair values and all movements in these balances are reflected in the income statement, except for those relating to actuarial gains and losses, which are reflected in equity. Under US GAAP, actuarial gains and losses are recognized in income only when they exceed certain thresholds. This gives rise to differences in periodic pension costs as measured under IFRS and US GAAP. In addition, when a pension plan has an accumulated benefit obligation that exceeds the fair value of the plan assets, US GAAP requires the unfunded amount to be recognized as a minimum liability in the balance sheet. The offset to this liability is recorded as an intangible asset up to the amount of any unrecognized prior service cost or transitional liability, and thereafter directly in equity. IFRS does not have a similar concept. As a result, this creates a difference in shareholders' equity as measured under IFRS and US GAAP.

Impairments Under IFRS, in determining the amount of any impairment loss, the carrying value of property, plant and equipment and goodwill is compared with the discounted value of the future cash flows. US GAAP requires that the carrying value is compared with the undiscounted future cash flows to determine if an impairment is present, and only if the carrying value is less than the undiscounted cash flows is an impairment loss recognized. The impairment is measured using the discounted value of the future cash flows. Hence certain of the impairment charges recognized under IFRS have not been recognized for US GAAP.

Equity-accounted investments The major difference between IFRS and US GAAP in relation to equity-accounted entities is in respect of deferred tax. Investments Under IFRS for periods prior to 2005, certain equity investments are carried on the balance sheet at cost, subject to review for impairment. For US GAAP, these investments are classified as available-for-sale securities and are reported at fair value with unrealized holding gains and losses reported in equity.

Consolidation of variable interest entities Under US GAAP, a variable interest entity (VIE) is consolidated if a company is subject to a majority of the risk of loss from its activities or entitled to receive a majority of its residual returns. The group currently has several ships under construction, which are accounted for under IFRS as operating leases. Certain of the arrangements represent VIEs that are consolidated for US GAAP reporting. Major maintenance expenditure As of 1 January 2005, the group changed its US GAAP accounting policy to expense all overhaul costs and similar major maintenance expenditure as incurred. This new accounting policy is the same as IFRS and, as a result, a GAAP difference exists only in periods prior to 1 January 2005.

Share-based payments For periods prior to 1 January 2005, the group has recognized share-based payments under IFRS using a fair value method that is substantially different from the intrinsic value method used under US GAAP for the same period. From 1 January 2005, the group has used the same fair value methodology to measure compensation expense under both IFRS and US GAAP. A difference in compensation expense exists, however, because the group uses a different valuation model under US GAAP for those previously issued options outstanding and unvested as of 31 December 2004. In addition, a further difference arises relating to recognition of deferred taxes on share-based compensation.

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					\$ million
RETURN ON AVERAGE CAPITAL EMPLOYED	2001	2002	IFRS 2003	IFRS 2004	IRFS 2005
Replacement cost profit	8,456	5,691	12,432	15,432	19,314
Finance costsb	798	602	333	286	400
Minority interest	61	52	170	187	291
Adjusted replacement cost profit	9,315	6,345	12,935	15,905	20,005
Non-operating items (post-tax)	299	642	234	1,072	1,754
Adjusted replacement cost profit excluding non-operating items	9,614	6,987	13,169	16,977	21,759
Average capital employed (including goodwill)	87,179	86,819	87,732	96,958	100,627
Return on average capital employed (including goodwill and non-operating items)	10.7%	7.3%	14.7%	16.4%	19.9%
Average capital employed (excluding goodwill)	75,646	76,166	77,216	86,233	90,013
Return on average capital employed (excluding goodwill and non-operating items)	12.7%	9.2%	17.1%	19.7%	24.2%
PRE-TAX CASH RETURNS
Replacement cost profit before interest and tax	16,562	11,200	18,712	23,389	29,796
Equity-accounted interest and tax	–	–	324	1,328	1,628
Non-operating items	523	1,152	328	1,408	2,838
Depreciation, depletion and amortization	8,683	9,127	8,605	9,012	9,183
Pre-tax cash returns numerator	25,768	21,479	27,969	35,137	43,445
Capital employed	87,158	86,480	92,589	101,326	99,927
Liabilities for current and deferred taxation	14,815	14,211	19,400	20,673	20,505
Goodwill	(10,868)	(10,438)	(10,592)	(10,857)	(10,371)
Operating capital employed	91,105	90,253	101,397	111,142	110,061
Average operating capital employed	90,192	90,679	96,097	106,270	110,602
Pre-tax cash return	29%	24%	29%	33%	39%
DEBT RATIOS
Gross debt	21,417	22,008	22,325	23,091	19,162
Cash and cash equivalents	1,808	1,735	2,056	1,359	2,960
Net debt	19,609	20,273	20,269	21,732	16,202
Equity	65,741	64,472	70,264	78,235	80,765
Debt to debt-plus-equity ratio	25%	25%	24%	23%	19%
Debt to equity ratio	33%	34%	32%	30%	24%
Net debt to net debt-plus-equity ratio	23%	24%	22%	22%	17%
Net debt to equity ratio	30%	31%	29%	28%	20%

aThe ratios are defined on page 91.

bCalculated on a post-tax basis using a deemed tax rate equal to the US statutory tax rate.

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REGISTER OF MEMBERS HOLDING BP ORDINARY SHARES AS AT 31 DECEMBER 2005	Number of shareholders	Percentage of total shareholders	Percentage of total share capital
Range of holdings
1 – 200	60,420	18.25	0.02
201 – 1,000	127,158	38.40	0.30
1,001 – 10,000	128,949	38.94	1.81
10,001 – 100,000	12,622	3.81	1.19
100,001 – 1,000,000	1,164	0.35	1.92
Over 1,000,000a	818	0.25	94.76
	331,131	100.00	100.00

a Includes JPMorgan Chase Bank, holding 31.07% of the total share capital as the approved depositary for ADSs, a breakdown of which is shown in the table below.

REGISTER OF HOLDERS OF AMERICAN DEPOSITARY SHARES AS AT 31 DECEMBER 2005a	Number of ADS holders	Percentage of total ADS holders	Percentage of total ADSs
Range of holdings
1 – 200	81,911	52.25	0.44
201 – 1,000	45,386	28.95	1.95
1,001 – 10,000	27,478	17.53	6.73
10,001 – 100,000	1,955	1.24	3.07
100,001 – 1,000,000	29	0.02	0.57
Over 1,000,000b	1	0.01	87.24
	156,760	100.00	100.00

At 31 December 2005, there were also 1,588 preference shareholders.

a One American depositary share (ADS) represents six 25 cent ordinary shares.

bOne of the holders of ADSs represents some 839,800 preference shareholders.

		Percentage of shares in issue
BENEFICIAL OWNERS AS AT 31 DECEMBER 2005a b	Institutions	Individuals	Total
By principal area
UK	38	6	44
USA	26	13	39
Rest of Europe	9	–	9
Rest of World	4	–	4
Miscellaneousc	–	–	4
			100

a Reflects the beneficial (underlying) ownership of the shares.

bThis represents BP's best efforts to determine the domicile of the beneficial (underlying) owners of the group's shares, based on analysis of the year-end share register. ^c Miscellaneous represents shareholders below the 100,000-share threshold at which the 31 December 2005 share register was analysed (3%) and unidentified shares (1%). Unidentified shares represent holdings that are awaiting confirmation of the identity of the beneficial holder and the nature of their interest in the shares following enquiries made under Section 212 of the Companies Act 1985.

Employee numbers

					Year end
BY BUSINESS	2001	2002	2003	2004	2005
Exploration and Production	16,300	16,600	15,100	15,600	17,000
Refining and Marketing (excluding service station staff)	38,100	44,900	42,000	41,900	43,000
Gas, Power and Renewables	4,400	4,600	3,800	4,000	4,100
Other businesses and corporate	22,800	18,900	15,800	13,500	4,300
Sub-total	81,600	85,000	76,700	75,000	68,400
Service station staff	28,500	30,200	27,000	27,900	27,800
	110,100	115,200	103,700	102,900	96,200
BY GEOGRAPHICAL AREA
UK	19,600	17,700	17,100	17,500	16,500
Rest of Europe	22,800	29,800	25,300	25,900	21,300
USA	42,800	43,200	39,100	36,900	34,400
Rest of World	24,900	24,500	22,200	22,600	24,000
	110,100	115,200	103,700	102,900	96,200

BP share data

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SHARE PRICE AND DIVIDENDS	2001	2002	2003	2004	2005
Share price (pence per ordinary share)
High	647	625	455	557	684
Low	492	393	357	414	504
End year	534	427	453	508	619
Number of ordinary shares at end year (million)	22,432	22,379	22,123	21,526	20,657
Average number of shares (million)	22,436	22,397	22,171	21,821	21,126
Dividends paid (pence per ordinary share)
First quarter	3.617	4.055	3.815	3.674	4.522
Second quarter	3.665	4.051	3.947	3.807	4.450
Third quarter	3.911	3.875	4.039	3.860	5.119
Fourth quarter	3.805	3.897	3.857	3.910	5.061
	14.998	15.878	15.658	15.251	19.152
Dividends paid (cents per ordinary share)
First quarter	5.25	5.75	6.25	6.75	8.50
Second quarter	5.25	5.75	6.25	6.75	8.50
Third quarter	5.50	6.00	6.50	7.10	8.925
Fourth quarter	5.50	6.00	6.50	7.10	8.925
	21.50	23.50	25.50	27.70	34.850
ADS price (US dollars per ADS)
High	54.86	53.88	49.35	61.66	72.27
Low	43.23	36.78	35.37	47.27	56.61
End year	46.51	40.65	49.35	58.40	64.22
Dividends paid (US dollars per ADS)
First quarter	0.315	0.345	0.375	0.405	0.510
Second quarter	0.315	0.345	0.375	0.405	0.510
Third quarter	0.330	0.360	0.390	0.426	0.535
Fourth quarter	0.330	0.360	0.390	0.426	0.536
	1.290	1.410	1.530	1.662	2.091
Dividend payout ratio
Based on replacement cost profit for the year	58%	94%	45%	39%	38%
Based on profit for the year	75%	79%	45%	35%	33%
Dividend cover
Dividend cover out of incomea	1.71	1.06	2.20	2.56	2.62
Dividend cover out of cash flowb	3.62	3.03	2.88	3.87	3.63

a Based on replacement cost profit for the year.

bNet cash provided by operating activities, divided by gross dividends paid. The calculation is based on the assumption that all dividends are paid in cash.

					shares thousand
NUMBER OF SHARES	2001	2002	2003	2004	2005
Ordinary shares outstanding at period end	22,432,077	22,378,651	22,122,610	21,525,978	20,657,045
ADS equivalent	3,738,680	3,729,775	3,687,102	3,587,663	3,442,841
Average ordinary shares	22,435,737	22,397,126	22,170,741	21,820,535	21,125,902
ADS equivalent	3,739,290	3,732,854	3,695,124	3,636,756	3,520,984

1Exploration and Production

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• 32 2005 performance
• 33 Key indicators
• 34 Exploration and Production operations
• 42 Financial statistics
• 43 TNK-BP operational and financial information
• 44 Oil and natural gas exploration and production activities
• 49 Movements in estimated net proved reserves crude oil
• 54 Movements in estimated net proved reserves natural gas
• 54 Year-end estimated net proved reserves crude oil and natural gas
• 59 Group production interests oil
• 60 Group production interests natural gas
• 61 Group production interests oil and natural gas
• 62 Exploration interests at 31 December
• 63 Exploration and development wells

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Segment strategy

Build production with improving returns by:

• ••• Focusing on finding the largest fields, concentrating our involvement in a limited number of the world's most prolific hydrocarbon basins.
• ••• Building leadership positions in these areas.
• ••• Managing the decline of existing producing assets and divesting assets when they no longer compete in our portfolio.

Segment focus

BP employs a focused exploration strategy in areas with the potential for large oil and natural gas fields as new profit centres. Within our portfolio of assets, we continue to develop our new profit centres in which we have a distinctive position: Asia Pacific gas, Azerbaijan, Algeria, Angola, Trinidad, deepwater Gulf of Mexico and Russia. We also manage the decline of our existing profit centres in Alaska, Egypt, Latin America, Middle East, North American gas and the North Sea. We exercise rigorous quality through choice across our portfolio, investing in only the best opportunities.

2005 PERFORMANCE

The segment's replacement cost profit before interest and tax of \$25,485 million for the year was a record, representing an increase of 41% over 2004. The increase reflected higher realizations, partially offset by costs associated with the severe hurricanes and the Thunder Horse stability incident, and higher operating and revenue investment costs. The result included a net charge for non-operating items of \$998 million, primarily related to fair value losses on embedded derivatives, net gains on sales of assets, mainly from the sale of the Ormen Lange field in Norway, and net impairment charges.

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Capital expenditure was \$10.1 billion in 2005 and is expected to be around \$11 billion in 2006.

Production was 4,014 thousand barrels of oil equivalent a day (boe/d) in 2005. Increases in production in our new profit centres and TNK-BP were offset by the effects of severe weather disruptions, higher planned maintenance shutdowns, anticipated decline and operational issues in our existing profit centres.

NEW AND EXISTING PROFIT CENTRES

We continued to make significant progress in our new profit centres in 2005. In the past three years, we have brought on stream 20 major projects.

BP is operating four major projects in Azerbaijan on behalf of its consortium partners: the Azeri-Chirag-Gunashli oil fields, the Baku-Tbilisi-Ceyhan (BTC) pipeline, the Shah Deniz gas field and the South Caucasus pipeline. The Central Azeri project achieved its first production in February 2005 and the West Azeri project achieved its first production in December 2005, four months ahead of schedule. Construction of the BTC pipeline progressed and line-fill of the pipeline started in 2005, with the official inauguration ceremony held on 25 May at the Sangachal terminal near Baku. The Georgian section was inaugurated in early October and the first tanker lifting from Ceyhan is expected in the second quarter of 2006. In-country assembly of the drilling rig and platform for the Shah Deniz field is on schedule for start-up in 2006 and the associated South Caucasus pipeline is also on course to be completed during 2006.

The Kizomba B development offshore Angola achieved its first oil production four months ahead of schedule in July 2005 and the Greater Plutonio project remains on track to deliver first oil in 2007.

In Trinidad & Tobago, the Atlantic LNG Train 4 commenced liquefaction at the end of the year. The Cannonball gas development, Trinidad & Tobago's first major offshore construction project executed locally, started production in March 2006.

In Algeria, the carbon dioxide (CO2) capture system in our In Salah gas project started operations. This is one of the world's largest CO2 capture projects, providing emissions savings estimated to be equivalent to taking a quarter of a million cars off the road. The In Amenas project is expected to start production in the first half of 2006. BP was awarded three blocks in Algeria's sixth international licensing round.

In Indonesia, we received the final governmental approvals for the Tangguh LNG project, which is proceeding on schedule.

In the Gulf of Mexico, the Mad Dog project achieved first production in January 2005. Following stability problems in July 2005, repairs to the Thunder Horse platform are proceeding offshore. Production, originally scheduled for the end of 2005, is now expected to start in the second half of 2006. This is due to be followed by Atlantis, with first production expected around the end of 2006.

In Russia, oil production from TNK-BP grew by just under 10% compared with 2004. Total production, including gas, exceeded

2 million boe/d for the first time, in the third quarter of 2005. Total dividends received by BP amounted to \$1.95 billion. Towards the end of the year, TNK-BP disposed of non-core producing assets in the Saratov region, along with the Orsk refinery. Future investment in TNK-BP's upstream business includes further extension drilling in the Ust Vakh area of the Samotlor field and in the Kammenoye field, as well as the greenfield Demiansky project in the Uvat area. BP's exploration successes in Sakhalin through Elvaryneftegaz, a joint venture with Rosneft, continued in 2005 with a second discovery. The region is now beginning to show significant potential.

In Egypt, we sanctioned investment in the Saqqara field. We also extended two concessions in the Gulf of Suez, the Merged Concession Agreement and South Garib, which will extend the life of the existing oil fields, increase the recovery of remaining reserves and provide a foundation for future growth through exploration.

Progress also continued in our other existing profit centres. The North Sea completed its biggest maintenance campaign in several years in a demanding operational environment. Three new projects – Clair, Rhum and Farragon – started production in 2005. All three came on line successfully, underpinning our long-term commitment to this mature basin. In North America, a major project was sanctioned for the further development of the Wamsutter gas field in Wyoming for \$2.2 billion. In Alaska, we continue to improve our knowledge of the extraction of viscous oil resources, while striving for greater operational efficiencies on our existing facilities.

We continually seek to enhance our portfolio through planned divestments. In 2005, these yielded proceeds of \$1,416 million, mainly from the sale of our interests in the Ormen Lange field in Norway and also the Teak, Samaan and Poui fields in Trinidad & Tobago.

A total of 12 new oil and gas discoveries were made from a focused exploration programme. Major successes included a number of discoveries in the deepwater Gulf of Mexico and Angola and a second discovery in offshore Sakhalin Island in Russia.

RESERVES

On the basis of UK generally accepted accounting practice (SORP), our proved reserves replacement ratio (RRR) was 100% (including equityaccounted entities), compared with 110% in 2004. On the same basis, excluding equity-accounted entities, the RRR was 71%. This was the 13th consecutive year in which our RRR was 100% or greater. We also prepare estimates of our proved reserves on the basis of the rules and interpretation required by the US Securities and Exchange Commission (SEC). On this basis, the RRR, excluding equity-accounted entities, was 68% (compared with 78% in 2004); including equity-accounted entities, the ratio was 95% (compared with 89% in 2004). The differences from our SORP-based estimates arise mainly from the SEC's requirement that year-end prices should be used. All our proved RRRs are based on discoveries, extensions, revisions and improved recovery and exclude the effects of acquisitions and disposals. BP has a robust internal process to control the quality of its reserve bookings, which forms part of an integrated system of internal control. Details of that process and the applicable rules are described on pages 131-132 of BP Annual Report and Accounts 2005.

BP's total hydrocarbon proved reserves, on an oil-equivalent basis under SORP and including equity-accounted entities, stood at 18,271 million barrels of oil equivalent at 31 December 2005. Of this total, 43% was gas.

The management of our reserves is described under Other financial issues on pages 22-23 of BP Annual Report and Accounts 2005.

Key indicatorsa

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					\$ million
	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Result and oil price
Replacement cost profit before interest and tax (\$ billion)	12.47	8.28	15.08	18.08	25.49
BP average liquids realizations (\$/bbl)b	22.50	22.69	27.25	35.39	48.51
Finding and development costs (\$/boe, five-year rolling average)	3.72	3.72	3.98	4.65	5.79
Finding costs (\$/boe, five-year rolling average)	1.07	0.91	0.79	0.81	0.92
Lifting costs (\$/boe)	2.73	2.71	2.84	3.41	4.28
Cost of supply (\$/boe)c	8.32	9.21	8.68	9.54	10.44
Net income per barrel of oil equivalent
BP (\$/boe)	5.67	3.33	7.95	8.40	12.51
Range of other oil majors
Maximum (\$/boe)	6.82	6.26	8.24	10.81	15.32
Minimum (\$/boe)	5.31	5.07	6.32	7.31	9.74
Reserves replacement
BP subsidiaries (%)	191	175	122	106	71
BP subsidiaries and equity-accounted entities (%)	191	168	109	110	100
Range of other oil majors
Maximum (%)	126	119	118	125	129
Minimum (%)	74	49	66	35	13

a Except where indicated, all the data in this table relates to BP subsidiaries only.

bCrude oil and natural gas liquids.

c Cost of supply comprises exploration expense, lifting costs and depreciation, depletion and amortization.

Exploration and Production operations

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Deepwater Gulf of Mexico

BP began deepwater Gulf of Mexico operations in the mid-1980s. Execution of our exploration strategy has delivered excellent results, yielding a strong portfolio of large, high-quality development projects. We plan to continue focused exploration across our portfolio of more than 600 leases.

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Despite the impacts of major weather events – notably Hurricanes Katrina and Rita in the second half of 2005 – BP continues to produce in excess of 300,000boe/d from 18 fields. BP operates a number of subsea developments and has interests in a number of partner-operated developments.

In 2003, the Na Kika field started production and the Mardi Gras transportation system commenced operation. At the Holstein field, oil production commenced in late 2004 and Mad Dog followed with first oil production in January 2005. Production is expected to begin from the Thunder Horse development during 2006 and from the Atlantis development around the end of 2006.

• 1 Nile 2 Ram Powell 3 Marlin
• 4 Horn Mountain
• 5 Pompano
• 6 King (MC 85)
• 7 Mica
• 8 Na Kika
• 9 Princess 10 Tubular Bells
• 15 Deimos 16 Europa 17 Crosby 18 Diana

19 Hoover 20 Entrada

13 Ursa 14 Mars

• 11 Thunder Horse 12 King (MC 764) 21 Holstein 22 Puma
  • 23 Cascade
  • 24 Mad Dog
  • 25 Shenzi
  • 26 Atlantis 27 Great White

Angola

BP has been involved in Angola since the 1970s and has built a strong foundation for long-term growth in the country through both exploration and development. Technical skills developed in similar deepwater basins around the world have been applied extensively in BP's operations in Angola.

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BP is present in four major deepwater licences offshore Angola (Blocks 15, 17, 18 and 31). BP is operator in Block 18 and Block 31. Our first production in Angola began in December 2001 with the start-up of the Girassol field in Block 17.

In 2003, the Jasmim field (in Block 17) and Xikomba field (in Block 15) began producing. These were followed into production by the Kizomba A development (a single development of multiple fields in Block 15) in 2004. Kizomba B achieved first oil production four months ahead of schedule in July 2005. During 2005, BP also sanctioned the Kizomba C project and the next phase of the Kizomba A development. In addition, there were further exploration successes in Block 31. Greater Plutonio, the first major BP-operated project in Angola, continues on schedule for first oil in 2007.

BLOCK 15		BLOCK 17		BLOCK 18
1	Xikomba	16 Lirio		31 Platina
2	Bavuca	17 Violeta		32 Galio
3	Mondo	18 Anturio		33 Cromio
4	Vicango	19 Cravo		34 Paladio
5	Reco Reco	20 Orquidea		35 Chumbo
6	Kizomba A	21 Tulipa		36 Plutonio
7	Batuque	22 Rosa		37 Cobalto
8	Kizomba B	23 Hortensia		38 Cesio
				BLOCK 31
9	Saxi	24 Zinia
	10 Marimba	25 Perpetua		39 Marte
	11 Mbulumbumba	26 Jasmim		40 Venus
	12 Kakocha	27 Girassol		41 Saturno
	13 Mavicola	28 Dalia		42 Plutão
	14 Clochas	29 Acacia		43 Ceres
	15 Tchihumba	30 Camelia		44 Hebe
				45 Juno

47 Astraea

Trinidad & Tobago

BP has been operating in Trinidad & Tobago since 1961. We are the largest energy company in Trinidad & Tobago and the largest single foreign investor in the country. Trinidad & Tobago enjoys prime access to LNG markets, an advantaged infrastructure position and a proven record of exploration and delivery. BP aims to continue building on its integrated position through development of our gas reserves and a continued supply to the LNG markets.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:29 am Page 38

BP holds an average working interest of 41% in Atlantic LNG, which operates four LNG trains. Atlantic Train 1 started up in April 1999, followed by Trains 2 and 3 in August 2002 and April 2003 respectively, each of which is designed to produce 3.3 million tonnes per annum (mtpa). Train 4, which commenced liquefaction in late 2005, is designed to produce 5.2mtpa. The LNG produced is sold to world markets, primarily in the US and Spain. Further gas growth was added to BP's portfolio in Trinidad in 2004 with the start-up of Atlas Methanol, the largest methanol plant in the world, in which BP holds a 36.9% interest.

Much of the gas to LNG Train 4 is supplied from BPTT's Cannonball gas development. Cannonball was the industry's first major construction project executed in Trinidad & Tobago and started production in March 2006.

BLOCK SAMAAN

1	EMZ

2 El Diablo

• BLOCK SEG
• 3 Red Mango
• 4 Iron Horse
• 5 Cassia 6 Kapok
  -
• 7 Amherstia 8 Cannonball
• 9 Immortelle
  -
• 19 SEQB BLOCK 5B
• 20 Manakin

BLOCK EM 10 Coconut 11 Flamboyant 12 Cashima 13 NEQB 14 Mahogany 15 Lantana 16 Coralita 17 Chachalaca 18 EQB

PLANTS

• 21 Atlantic LNG
• 22 Atlas Methanol

Azerbaijan, Georgia and Turkey

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:29 am Page 39

BP has been in Azerbaijan since 1992 and is the largest foreign investor in the country. BP operates two production-sharing agreements (PSAs), which are under development – Azeri-Chirag-Gunashli (ACG) and Shah Deniz – and holds other exploration leases in the area. The contract areas of these PSAs cover about 1,300 square kilometres in total. In addition, BP leads the Baku-Tbilisi-Ceyhan (BTC) oil pipeline project.

BP is operator of the Azerbaijan International Operating Company and has a 34.1% interest in the ACG oil fields in the Caspian Sea, offshore Azerbaijan. The Central and West Azeri projects started up successfully in 2005.

BP holds a 30.1% interest in the BTC oil pipeline project. The BTC pipeline follows a 1,768-kilometre route from the onshore terminal at Sangachal, near Baku, through Georgia to a new marine export terminal at Ceyhan on the Turkish Mediterranean coast. Construction of the pipeline progressed and line-fill of the pipeline started in 2005, with the official inauguration ceremony held on 25 May at the Sangachal terminal near Baku. The Georgian section was inaugurated in early October and the first tanker lifting from Ceyhan is expected in the second quarter of 2006. The BTC pipeline will export crude oil from the Caspian to world markets, without the creation of additional maritime shipping in the Bosporus Straits. It is also planned to complete the South Caucasus gas pipeline during 2006. Good progress continued on the Shah Deniz gas field during 2005 and the project remains on track to start production during the second half of 2006.

Asia Pacific

During the next 10 years, the Asia Pacific region is expected to show significant growth in gas demand. BP is well positioned to capture a major portion of this growth, being one of the largest suppliers in the Asia Pacific LNG market. BP participates in this market through interests in Indonesia and Australia.

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 12:22 pm Page 40

In the mid-1990s, a world-class resource of natural gas was discovered in the Berau-Bintuni Bay, Papua, Indonesia, approximately 3,200km from Indonesia's capital, Jakarta. These discoveries gave rise to the Tangguh LNG project, key to BP's LNG growth aspirations in the region. This project was approved by the Indonesian government in early 2005 and is now in the development phase.

In Australia, we are one of six equal partners in the North West Shelf venture. This joint-venture operation covers offshore production platforms, a floating storage vessel, trunk lines and onshore gas processing plants. During 2005, the venture sanctioned the construction of a fifth LNG train. It is planned to commence export of gas to markets in the Far East in 2008.

In Vietnam, BP participates in the country's biggest foreign investment, the Nam Con Son gas project. This is an integrated resource and infrastructure project, including offshore gas production, a pipeline transportation system and a power plant.

LNG PLANTS

• 1 Bontang
• 2 Tangguh (BP-operated)

Russia

In August 2003, BP and AAR (the Alfa Group and Access-Renova) completed the creation of the TNK-BP joint venture, establishing one of the largest integrated oil companies operating in Russia, in which BP owns a 50% interest.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:30 am Page 41

TNK-BP encompasses the full spectrum of vertical integration, from wellhead to leading positions in the marketing of petroleum products. TNK-BP's portfolio contains eight fields of greater than 250 million barrels, including Samotlor, the third-largest oil field ever discovered.

Performance to date has been very good. During 2005, TNK-BP grew oil production by just under 10% and exceeded 2 million boe/d in total production for the first time, in the third quarter of 2005.

In addition, BP has a 49% holding in Elvaryneftegaz, a joint venture with Rosneft, encompassing acreage in Sakhalin, where a second hydrocarbon discovery was made in 2005.

BP also has an interest in the Russian-Kazakh Caspian Pipeline Consortium (CPC) and the Kazakh Tengiz super-giant oil field, held through another joint venture (Lukarco) with the Russian oil company Lukoil. BP holds a 46% interest and Lukoil a 54% interest in Lukarco. Lukarco holds a 5% interest in Tengiz and a 12.5% interest in the CPC pipeline.

Financial statistics

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 10:14 am Page 42

					\$ million
	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Replacement cost profit before interest and tax by geographical areaa
UK	3,395	2,294	3,468	3,453	2,129
Rest of Europe	756	724	587	837	2,321
USA	4,461	2,358	5,673	6,797	9,475
Rest of World	3,860	2,901	5,353	6,988	11,560
	12,472	8,277	15,081	18,075	25,485
a Includes equity-accounted interest and tax	–	–	273	1,218	1,477
Under IFRS, the results of jointly controlled entities and associates for 2003, 2004
and 2005 are included in the income statement net of interest and tax.
Operating capital employed by geographical area
UK	9,608	8,819	8,729	8,803	5,924
Rest of Europe	1,049	1,452	1,476	1,558	1,451
USA	24,598	24,426	23,308	24,345	25,443
Rest of World	19,488	22,164	25,816	30,485	35,871
	54,743	56,861	59,329	65,191	68,689
Sales and other operating revenues	27,540	25,083	30,621	34,700	47,210
Capital expenditure and acquisitions by geographical area
UK	1,095	952	786	762	821
Rest of Europe	329	262	279	255	197
USA	4,047	4,116	3,906	3,913	3,870
Rest of World	3,282	4,153	10,214	6,072	5,349
	8,753	9,483	15,185	11,002	10,237
EMPLOYEE NUMBERS AT YEAR END	16,300	16,600	15,100	15,600	17,000
BP AVERAGE REALIZATIONS
BP average liquids realizations (\$/bbl)b	22.50	22.69	27.25	35.39	48.51
BP average gas realizations (\$/mcf)	3.30	2.46	3.39	3.86	4.90
MARKER PRICES
Brent oil price (\$/bbl)	24.44	25.03	28.83	38.27	54.48
Alaska North Slope oil (\$/bbl)	23.18	24.77	29.59	38.96	53.55
WTI (\$/bbl)	25.89	26.14	31.06	41.49	56.58
Henry Hub gas price (\$/mmBtu)c	4.26	3.22	5.37	6.13	8.65

bCrude oil and natural gas liquids.

c Henry Hub First of the Month Index.

TNK-BP operational and financial information

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:30 am Page 43

PRODUCTION (BP SHARE, NET OF ROYALTIES)	2003a	2004	2005
Crude oil (mb/d)	665	830	911
Natural gas (mmcf/d)	281	463	482
Total hydrocarbons (mboe/d)b	713	910	994
INCOME STATEMENT (BP SHARE)			\$ million
Profit before interest and tax	521	2,421	3,817
Finance costs and other finance expense*	(37)	(101)	(128)
Taxation	(43)	(675)	(976)
Minority interest	–	(43)	(104)
Profit for the yearc	441	1,602	2,609
*Excludes unwinding of discount on deferred consideration	34	91	57
BALANCE SHEET
Investment in jointly controlled entities	7,098	8,294	8,089
Deferred consideration
Due within one year	1,227	1,227	1,227
Due after more than one year	2,352	1,194	–
	3,579	2,421	1,227
CASH FLOW
Acquisition of investment in TNK-BP joint venture	(2,351)	(1,250)	–
Dividends received	–	1,760	1,950
Dividends receivable	–	–	771
			\$ per barrel
AVERAGE OIL MARKER PRICES	2003	2004	2005
Urals (NWE – cif)	27.20	34.08	50.29
Urals (Med – cif)	27.28	34.45	50.84
Domestic oil	16.65	20.61	28.77

Various TNK-BP companies have received tax notifications. Upon entering into the joint venture arrangement, each party received indemnities from its co-venturers in respect of historical tax liabilities related to assets contributed to the joint venture. BP believes existing provisions are adequate for its share of any liabilities arising from tax claims not covered by these indemnities.

a Year 2003 covers the period from 29 August to 31 December.

bNatural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

c 2005 includes a net gain of \$270 million on the disposal of non-core producing assets in the Saratov region, along with the Orsk refinery.

Oil and natural gas exploration and production activitiesa

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:30 am Page 44

									\$ million
RESULTS OF OPERATIONS FOR YEAR ENDED 31 DECEMBER	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	2001 Total
Sales and other operating revenuesb
Third parties	2,979	564	1,601	848	689	546	–	498	7,725
Sales between businesses	3,003	462	9,540	2,141	420	526	–	1,805	17,897
	5,982	1,026	11,141	2,989	1,109	1,072	–	2,303	25,622
Exploration expenditure	(14)	(22)	(256)	(75)	(41)	(43)	(6)	(23)	(480)
Production costs	(878)	(91)	(1,325)	(371)	(148)	(228)	–	(168)	(3,209)
Production taxes	(559)	(17)	(384)	(69)	(36)	(2)	–	(581)	(1,648)
Other income (costs)c	(25)	(33)	(1,741)	(538)	(148)	(224)	(58)	(566)	(3,333)
Depreciation, depletion and amortization	(1,353)	(115)	(3,067)	(360)	(228)	(130)	–	(222)	(5,475)
Impairments and gains and losses on
sale of businesses and fixed assets	(12)	8	(45)	(175)	–	–	–	244	20
Profit before taxation	3,141	756	4,323	1,401	508	445	(64)	987	11,497
Allocable taxes	(1,026)	(331)	(1,444)	(682)	(167)	(105)	(1)	(411)	(4,167)
Results of operations	2,115	425	2,879	719	341	340	(65)	576	7,330
CAPITALIZED COSTS AT 31 DECEMBER
Gross capitalized costs
Proved properties	23,627	2,912	42,436	8,070	5,100	6,578	1	1,739	90,463
Unproved properties	313	120	1,426	970	1,969	456	113	169	5,536
	23,940	3,032	43,862	9,040	7,069	7,034	114	1,908	95,999
Accumulated depreciation	(13,320)	(1,883)	(19,322)	(4,047)	(1,910)	(4,134)	(14)	(875)	(45,505)
Net capitalized costs	10,620	1,149	24,540	4,993	5,159	2,900	100	1,033	50,494
COSTS INCURRED FOR YEAR ENDED 31 DECEMBER
Acquisition of properties
Proved	–	–	–	–	–	–	–	47	47
Unproved	4	–	20	4	155	34	–	–	217
	4	–	20	4	155	34	–	47	264
Exploration and appraisal costsd	109	80	295	253	68	248	7	42	1,102
Development costs	930	271	3,714	825	240	664	–	205	6,849
Total costs	1,043	351	4,029	1,082	463	946	7	294	8,215

a This note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group's share of jointly controlled entities' and associates' activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above.

bSales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash.

c

									\$ million
EXPLORATION AND PRODUCTION		Rest of		Rest of	Asia				2001
REPLACEMENT COST PROFIT	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Exploration and production activities
Group (as above)	3,141	756	4,323	1,401	508	445	(64)	987	11,497
Equity-accounted entities after
interest and tax	–	–	–	241	68	–	56	19	384
Mid-stream activities	254	–	138	92	54	–	–	53	591
Total replacement cost profit before
interest and tax	3,395	756	4,461	1,734	630	445	(8)	1,059	12,472

Oil and natural gas exploration and production activitiesa continued

								\$ million
								2002
UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
2,249	465	1,290	884	457	512	–	644	6,501
3,169	594	7,776	1,754	905	1,015	–	1,278	16,491
5,418	1,059	9,066	2,638	1,362	1,527	–	1,922	22,992
(27)	(47)	(258)	(167)	(67)	(50)	(17)	(11)	(644)
(820)	(104)	(1,318)	(403)	(190)	(237)	–	(122)	(3,194)
(279)	(7)	(288)	(115)	(36)	–	–	(519)	(1,244)
(315)	(36)	(1,556)	(341)	(110)	(331)	(42)	(670)	(3,401)
(1,875)	(154)	(3,118)	(413)	(296)	(134)	–	(140)	(6,130)
(32)	13	(479)	(234)	(311)	(230)	–	(14)	(1,287)
2,070	724	2,049	965	352	545	(59)	446	7,092
(1,327)	(412)	(925)	(480)	(291)	86	18	(220)	(3,551)
743	312	1,124	485	61	631	(41)	226	3,541
		Rest of		Rest of	Asia

CAPITALIZED COSTS AT 31 DECEMBER

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:30 am Page 45

Gross capitalized costs
Proved properties	26,804	4,029	46,555	9,406	5,275	7,803	–	2,120	101,992
Unproved properties	294	179	1,045	806	2,148	479	–	236	5,187
	27,098	4,208	47,600	10,212	7,423	8,282	–	2,356	107,179
Accumulated depreciation	(16,394)	(2,591)	(22,416)	(4,729)	(2,360)	(4,489)	–	(1,075)	(54,054)
Net capitalized costs	10,704	1,617	25,184	5,483	5,063	3,793	–	1,281	53,125

COSTS INCURRED FOR

YEAR ENDED 31 DECEMBER

Acquisition of properties
Proved	–	4	–	–	–	–	–	59	63
Unproved	–	–	29	7	–	1	–	–	37
	–	4	29	7	–	1	–	59	100
Exploration and appraisal costsd	28	68	441	179	161	160	17	54	1,108
Development costs	895	219	3,607	684	129	1,164	–	526	7,224
Total costs	923	291	4,077	870	290	1,325	17	639	8,432

a This note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group's share of jointly controlled entities' and associates' activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above.

bSales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash.

c

									\$ million
EXPLORATION AND PRODUCTION									2002
REPLACEMENT COST PROFIT	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Exploration and production activities
Group (as above)	2,070	724	2,049	965	352	545	(59)	446	7,092
Equity-accounted entities after
interest and tax	–	–	16	163	70	1	115	117	482
Mid-stream activities	224	–	293	138	56	(8)	–	–	703
Total replacement cost profit before
interest and tax	2,294	724	2,358	1,266	478	538	56	563	8,277

Oil and natural gas exploration and production activitiesa continued

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 46

									\$ million
									IFRS 2003
RESULTS OF OPERATIONS FOR		Rest of		Rest of	Asia
YEAR ENDED 31 DECEMBER	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Sales and other operating revenuesb
Third parties	2,257	441	1,491	1,233	421	444	–	777	7,064
Sales between businesses	2,901	568	10,991	2,589	925	974	–	1,707	20,655
	5,158	1,009	12,482	3,822	1,346	1,418	–	2,484	27,719
Exploration expenditure	(17)	(37)	(204)	(164)	(15)	(32)	(21)	(52)	(542)
Production costs	(825)	(113)	(1,262)	(463)	(166)	(241)	–	(135)	(3,205)
Production taxes	(233)	(14)	(439)	(189)	(40)	–	–	(742)	(1,657)
Other income (costs)c	151	(57)	(2,019)	(438)	(160)	(38)	(30)	(946)	(3,537)
Depreciation, depletion and amortization	(1,530)	(167)	(2,492)	(531)	(197)	(219)	–	(134)	(5,270)
Impairments and gains and losses on
sale of businesses and fixed assets	553	(30)	(573)	387	(347)	122	65	(2)	175
Profit before taxation	3,257	591	5,493	2,424	421	1,010	14	473	13,683
Allocable taxes	(1,306)	(305)	(1,574)	(847)	52	(438)	(56)	(47)	(4,521)
Results of operations	1,951	286	3,919	1,577	473	572	(42)	426	9,162
CAPITALIZED COSTS AT 31 DECEMBER
Gross capitalized costs
Proved properties	21,398	4,421	42,960	10,379	3,659	9,856	1	3,295	95,969
Unproved properties	299	230	1,278	713	1,779	563	51	64	4,977
	21,697	4,651	44,238	11,092	5,438	10,419	52	3,359	100,946
Accumulated depreciation	(13,013)	(2,886)	(19,658)	(5,080)	(2,413)	(5,642)	(33)	(1,246)	(49,971)
Net capitalized costs	8,684	1,765	24,580	6,012	3,025	4,777	19	2,113	50,975
COSTS INCURRED FOR YEAR ENDED 31 DECEMBER
Acquisition of properties
Proved	–	–	–	–	–	–	–	–	–
Unproved	–	–	–	–	–	–	–	–	–
	–	–	–	–	–	–	–	–	–
Exploration and appraisal costsd	20	69	288	119	57	205	26	40	824
Development costs	740	236	3,476	512	42	1,614	–	917	7,537
Total costs	760	305	3,764	631	99	1,819	26	957	8,361

a This note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group's share of jointly controlled entities' and associates' activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above.

bSales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash.

c

									\$ million
									IFRS 2003
EXPLORATION AND PRODUCTION REPLACEMENT COST PROFIT	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Exploration and production activities
Group (as above)	3,257	591	5,493	2,424	421	1,010	14	473	13,683
Equity-accounted entities after
interest and tax	–	–	1	171	20	–	573	25	790
Mid-stream activities	211	(4)	179	228	(2)	(2)	–	(2)	608
Total replacement cost profit before
interest and tax	3,468	587	5,673	2,823	439	1,008	587	496	15,081

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 47

								\$ million
								IFRS 2004
UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
3,458	626	1,735	1,776	977	492	5	403	9,472
2,424	609	11,794	2,556	530	1,439	–	2,912	22,264
								31,736
								(637)
								(3,577)
								(2,087)
								(3,764)
								(5,157)
								(469)
								16,045
								(5,327)
								10,718
27,540 300 27,840 (17,681) 10,159	4,691 170 4,861 (2,794) 2,067	43,011 1,395 44,406 (19,713) 24,693	10,450 456 10,906 (5,546) 5,360	2,892 1,240 4,132 (1,350) 2,782	10,401 526 10,927 (5,573) 5,354	– 119 119 – 119	3,834 105 3,939 (1,014) 2,925	102,819 4,311 107,130 (53,671) 53,459
–	–	–	–	–	–	–	–	–
2	–	58	5	–	13	–	–	78
								78
								1,039
679	262	3,247	527	88	1,460	–	1,007	7,270
732	279	3,728	731	173	1,615	113	1,016	8,387
	5,882 (26) (901) (273) 211 (1,524) (21) 3,348 (1,242) 2,106 2 51	1,235 (25) (117) (30) (38) (172) (1) 852 (534) 318 – 17	13,529 (361) (1,428) (477) (1,884) (2,268) (344) 6,767 (2,103) 4,664 58 423	4,332 (141) (535) (239) (458) (611) 55 2,403 (859) 1,544 5 199	1,507 (14) (142) (45) (96) (174) (113) 923 4 927 – 85	1,931 (45) (323) – (122) (287) (48) 1,106 (441) 665 13 142	5 (17) – – 3 – – (9) (2) (11) – 113	3,315 (8) (131) (1,023) (1,380) (121) 3 655 (150) 505 – 9

c

									\$ million
									IFRS 2004
EXPLORATION AND PRODUCTION REPLACEMENT COST PROFIT	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Exploration and production activities
Group (as above)	3,348	852	6,767	2,403	923	1,106	(9)	655	16,045
Equity-accounted entities after
interest and tax	–	–	–	113	36	–	1,665	–	1,814
Mid-stream activities	105	(15)	30	123	(50)	(19)	–	42	216
Total replacement cost profit before
interest and tax	3,453	837	6,797	2,639	909	1,087	1,656	697	18,075

Oil and natural gas exploration and production activitiesa continued

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 48

									\$ million
RESULTS OF OPERATIONS FOR									IFRS 2005
YEAR ENDED 31 DECEMBER	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Sales and other operating revenuesb
Third parties	4,667	635	2,048	2,260	1,045	1,350	–	690	12,695
Sales between businesses	2,458	976	14,842	2,863	782	2,402	–	4,796	29,119
	7,125	1,611	16,890	5,123	1,827	3,752	–	5,486	41,814
Exploration expenditure	(32)	(1)	(426)	(84)	(6)	(81)	(37)	(17)	(684)
Production costs	(1,082)	(118)	(1,814)	(578)	(159)	(460)	–	(180)	(4,391)
Production taxes	(485)	(33)	(610)	(281)	(54)	–	–	(1,536)	(2,999)
Other income (costs)c	(1,857)	55	(2,200)	(537)	(170)	(98)	(8)	(2,042)	(6,857)
Depreciation, depletion and
amortization	(1,548)	(220)	(2,288)	(675)	(162)	(542)	–	(193)	(5,628)
Impairments and gains and losses on
sale of businesses and fixed assets	(44)	1,038	(232)	133	–	–	(2)	–	893
Profit before taxation	2,077	2,332	9,320	3,101	1,276	2,571	(47)	1,518	22,148
Allocable taxes	(405)	(880)	(3,377)	(1,390)	(447)	(1,043)	1	(409)	(7,950)
Results of operations	1,672	1,452	5,943	1,711	829	1,528	(46)	1,109	14,198
CAPITALIZED COSTS AT 31 DECEMBER
Gross capitalized costs
Proved properties	28,453	4,608	46,288	9,585	2,922	12,183	–	5,184	109,223
Unproved properties	276	135	1,547	583	1,124	656	185	155	4,661
	28,729	4,743	47,835	10,168	4,046	12,839	185	5,339	113,884
Accumulated depreciation	(19,203)	(2,949)	(22,016)	(4,919)	(1,508)	(6,112)	–	(1,200)	(57,907)
Net capitalized costs	9,526	1,794	25,819	5,249	2,538	6,727	185	4,139	55,977
COSTS INCURRED FOR YEAR ENDED 31 DECEMBER
Acquisition of properties
Proved	–	–	–	–	–	–	–	–	–
Unproved	–	–	29	34	–	–	–	–	63
	–	–	29	34	–	–	–	–	63
Exploration and appraisal costsd	51	7	606	133	11	264	126	68	1,266
Development costs	790	188	2,965	681	186	1,691	–	1,177	7,678
Total costs	841	195	3,600	848	197	1,955	126	1,245	9,007

a This note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group's share of jointly controlled entities' and associates' activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above.

bSales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash. c

									\$ million
EXPLORATION AND PRODUCTION		Rest of		Rest of	Asia				IFRS 2005
REPLACEMENT COST PROFIT	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Exploration and production activities
Group (as above)	2,077	2,332	9,320	3,101	1,276	2,571	(47)	1,518	22,148
Equity-accounted entities after
interest and tax	–	–	–	309	35	–	2,685	–	3,029
Mid-stream activities	52	(11)	155	148	(20)	(39)	(1)	24	308
Total replacement cost profit before
interest and tax	2,129	2,321	9,475	3,558	1,291	2,532	2,637	1,542	25,485

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 49

									million barrels
									2001
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	1,138	213	2,150	365	109	208	–	135	4,318
Undeveloped	254	160	1,043	309	71	287	–	66	2,190
	1,392	373	3,193	674	180	495	–	201	6,508
Changes attributable to
Revisions of previous estimates	(16)	16	(39)	(86)	6	16	–	6	(97)
Purchases of reserves-in-place	9	–	–	10	1	–	–	–	20
Extensions, discoveries and
other additions	94	–	641	52	2	182	–	316	1,287
Improved recovery	24	29	48	8	–	4	–	–	113
Production	(177)	(37)	(243)	(61)	(24)	(39)	–	(20)	(601)
Sales of reserves-in-place	(1)	–	(11)	(1)	–	–	–	–	(13)
	(67)	8	396	(78)	(15)	163	–	302	709
At 31 Decemberb
Developed	1,008	269	2,195	401	113	200	–	122	4,308
Undeveloped	317	112	1,394	195	52	458	–	381	2,909
	1,325	381	3,589	596	165	658	–	503	7,217
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	116	3	–	19	848	986
Undeveloped	5	–	–	111	7	–	–	26	149
	5	–	–	227	10	–	19	874	1,135
Changes attributable to
Revisions of previous estimates	–	–	–	22	1	–	33	(1)	55
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	–	–	–	24	–	–	–	–	24
Improved recovery	–	–	–	21	–	–	–	–	21
Production	–	–	–	(19)	(2)	–	(7)	(48)	(76)
Sales of reserves-in-place	–	–	–	–	–	–	–	–	–
	–	–	–	48	(1)	–	26	(49)	24
At 31 Decemberc
Developed	5	–	–	129	3	–	45	800	982
Undeveloped	–	–	–	146	6	–	–	25	177
	5	–	–	275	9	–	45	825	1,159
Total group and BP share
of equity-accounted entities	1,330	381	3,589	871	174	658	45	1,328	8,376

a Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bMinority interest in BP Trinidad and Tobago LLC included 29, 39, 55, 17 and 20 million barrels at 31 December 2005, 2004, 2003, 2002 and 2001 respectively within Rest of Americas.

c Basis of reserves reporting in Abu Dhabi (where interests are held through associated undertakings in onshore and offshore concessions expiring in 2014 and 2018 respectively) is that reserves are restricted to those volumes expected to be produced by the end of the life of the concessions.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 50

									million barrels
		Rest of		Rest of	Asia				2002
SUBSIDIARIES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
At 1 January
Developed	1,008	269	2,195	401	113	200	–	122	4,308
Undeveloped	317	112	1,394	195	52	458	–	381	2,909
	1,325	381	3,589	596	165	658	–	503	7,217
Changes attributable to
Revisions of previous estimates	(58)	–	(33)	(28)	36	27	–	27	(29)
Purchases of reserves-in-place	8	2	–	210	–	–	–	7	227
Extensions, discoveries and
other additions	9	–	199	39	–	263	–	347	857
Improved recovery	19	4	60	20	5	–	–	24	132
Production	(168)	(38)	(254)	(65)	(27)	(46)	–	(21)	(619)
Sales of reserves-in-place	(8)	–	–	(1)	–	–	–	(14)	(23)
	(198)	(32)	(28)	175	14	244	–	370	545
At 31 Decemberb
Developed	858	250	2,225	573	125	179	–	125	4,335
Undeveloped	269	99	1,336	198	54	723	–	748	3,427
	1,127	349	3,561	771	179	902	–	873	7,762
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	5	–	–	129	3	–	45	800	982
Undeveloped	–	–	–	146	6	–	–	25	177
	5	–	–	275	9	–	45	825	1,159
Changes attributable to
Revisions of previous estimates	–	–	–	(4)	(1)	–	80	1	76
Purchases of reserves-in-place	–	–	–	–	–	–	203	–	203
Extensions, discoveries and
other additions	–	–	–	7	–	–	–	–	7
Improved recovery	–	–	–	55	–	–	–	–	55
Production	–	–	–	(21)	(1)	–	(27)	(43)	(92)
Sales of reserves-in-place	(5)	–	–	–	–	–	–	–	(5)
	(5)	–	–	37	(2)	–	256	(42)	244
At 31 Decemberc
Developed	–	–	–	173	1	–	252	752	1,178
Undeveloped	–	–	–	139	6	–	49	31	225
	–	–	–	312	7	–	301	783	1,403
Total group and BP share
of equity-accounted entities	1,127	349	3,561	1,083	186	902	301	1,656	9,165

a Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bMinority interest in BP Trinidad and Tobago LLC included 29, 39, 55, 17 and 20 million barrels at 31 December 2005, 2004, 2003, 2002 and 2001 respectively within Rest of Americas.

c Basis of reserves reporting in Abu Dhabi (where interests are held through associated undertakings in onshore and offshore concessions expiring in 2014 and 2018 respectively) is that reserves are restricted to those volumes expected to be produced by the end of the life of the concessions.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:31 am Page 51

									million barrels
									2003
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	858	250	2,225	573	125	179	–	125	4,335
Undeveloped	269	99	1,336	198	54	723	–	748	3,427
	1,127	349	3,561	771	179	902	–	873	7,762
Changes attributable to
Revisions of previous estimates	5	(3)	(246)	(28)	33	57	–	25	(157)
Purchases of reserves-in-place	–	–	–	42	–	–	–	–	42
Extensions, discoveries and
other additions	6	16	240	1	–	402	–	36	701
Improved recovery	38	5	84	42	–	–	–	3	172
Production	(138)	(30)	(237)	(71)	(22)	(43)	–	(21)	(562)
Sales of reserves-in-place	(144)	(19)	(164)	(13)	(24)	(145)	–	–	(509)
	(233)	(31)	(323)	(27)	(13)	271	–	43	(313)
At 31 Decemberb
Developed	678	231	1,885	378	83	206	–	115	3,576
Undeveloped	216	87	1,353	366	83	967	–	801	3,873
	894	318	3,238	744	166	1,173	–	916	7,449
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	173	1	–	252	752	1,178
Undeveloped	–	–	–	139	6	–	49	31	225
	–	–	–	312	7	–	301	783	1,403
Changes attributable to
Revisions of previous estimates	–	–	–	3	–	–	–	2	5
Purchases of reserves-in-place	–	–	–	–	–	–	1,600	–	1,600
Extensions, discoveries and
other additions	–	–	–	6	–	–	–	–	6
Improved recovery	–	–	–	42	–	–	–	–	42
Production	–	–	–	(23)	(1)	–	(107)	(53)	(184)
Sales of reserves-in-place	–	–	–	–	(5)	–	–	–	(5)
	–	–	–	28	(6)	–	1,493	(51)	1,464
At 31 Decemberc d
Developed	–	–	–	206	1	–	1,384	705	2,296
Undeveloped	–	–	–	134	–	–	410	27	571
	–	–	–	340	1	–	1,794	732	2,867
Total group and BP share

a Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bMinority interest in BP Trinidad and Tobago LLC included 29, 39, 55, 17 and 20 million barrels at 31 December 2005, 2004, 2003, 2002 and 2001 respectively within Rest of Americas.

c Basis of reserves reporting in Abu Dhabi (where interests are held through associated undertakings in onshore and offshore concessions expiring in 2014 and 2018 respectively) is that reserves are restricted to those volumes expected to be produced by the end of the life of the concessions. dIncludes 127 and 97 million barrels in respect of the 5.4% minority interest in TNK-BP at 31 December 2004 and 2003 respectively, and 97 million barrels of crude oil

in respect of the 4.47% minority interest in TNK-BP in 2005, within Russia.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:32 am Page 52

									million barrels
		Rest of		Rest of	Asia				2004
SUBSIDIARIES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
At 1 January
Developed	678	231	1,885	378	83	206	–	115	3,576
Undeveloped	216	87	1,353	366	83	967	–	801	3,873
	894	318	3,238	744	166	1,173	–	916	7,449
Changes attributable to
Revisions of previous estimates	(97)	32	63	(111)	5	38	–	194	124
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	22	–	74	5	8	48	–	212	369
Improved recovery	57	4	55	31	–	6	–	3	156
Production	(121)	(28)	(217)	(63)	(17)	(48)	–	(21)	(515)
Sales of reserves-in-place	–	–	(17)	(10)	(6)	–	–	–	(33)
	(139)	8	(42)	(148)	(10)	44	–	388	101
At 31 Decemberb
Developed	548	217	1,938	296	70	275	–	79	3,423
Undeveloped	207	109	1,258	300	86	942	–	1,225	4,127
	755	326	3,196	596	156	1,217	–	1,304	7,550
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	206	1	–	1,384	705	2,296
Undeveloped	–	–	–	134	–	–	410	27	571
	–	–	–	340	1	–	1,794	732	2,867
Changes attributable to
Revisions of previous estimates	–	–	–	(4)	–	–	382	15	393
Purchases of reserves-in-place	–	–	–	–	–	–	252	–	252
Extensions, discoveries and
other additions	–	–	–	2	–	–	–	–	2
Improved recovery	–	–	–	17	–	–	37	–	54
Production	–	–	–	(25)	–	–	(304)	(55)	(384)
Sales of reserves-in-place	–	–	–	–	–	–	(4)	–	(4)
	–	–	–	(10)	–	–	363	(40)	313
At 31 Decemberc d
Developed	–	–	–	204	1	–	1,863	593	2,661
Undeveloped	–	–	–	126	–	–	294	99	519
	–	–	–	330	1	–	2,157	692	3,180
Total group and BP share
of equity-accounted entities	755	326	3,196	926	157	1,217	2,157	1,996	10,730

a Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bMinority interest in BP Trinidad and Tobago LLC included 29, 39, 55, 17 and 20 million barrels at 31 December 2005, 2004, 2003, 2002 and 2001 respectively within Rest of Americas.

c Basis of reserves reporting in Abu Dhabi (where interests are held through associated undertakings in onshore and offshore concessions expiring in 2014 and 2018 respectively) is that reserves are restricted to those volumes expected to be produced by the end of the life of the concessions. dIncludes 127 and 97 million barrels in respect of the 5.4% minority interest in TNK-BP at 31 December 2004 and 2003 respectively, and 97 million barrels of crude oil

in respect of the 4.47% minority interest in TNK-BP in 2005, within Russia.

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:32 am Page 53

									million barrels
									2005
		Rest of		Rest of	Asia
SUBSIDIARIES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
At 1 January
Developed	548	217	1,938	296	70	275	–	79	3,423
Undeveloped	207	109	1,258	300	86	942	–	1,225	4,127
	755	326	3,196	596	156	1,217	–	1,304	7,550
Changes attributable to
Revisions of previous estimates	(39)	(10)	15	(20)	19	(193)	–	(144)	(372)
Purchases of reserves-in-place	–	–	2	–	–	–	–	–	2
Extensions, discoveries and
other additions	11	–	62	3	11	131	–	–	218
Improved recovery	33	21	240	1	–	2	–	13	310
Production	(101)	(28)	(200)	(52)	(17)	(64)	–	(34)	(496)
Sales of reserves-in-place	–	(15)	(1)	(35)	–	–	–	–	(51)
	(96)	(32)	118	(103)	13	(124)	–	(165)	(389)
At 31 Decemberb
Developed	475	209	1,801	206	73	202	–	94	3,060
Undeveloped	184	85	1,513	287	96	891	–	1,045	4,101
	659	294	3,314	493	169	1,093	–	1,139	7,161
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	204	1	–	1,863	593	2,661
Undeveloped	–	–	–	126	–	–	294	99	519
	–	–	–	330	1	–	2,157	692	3,180
Changes attributable to
Revisions of previous estimates	–	–	–	–	–	–	368	111	479
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	–	–	–	2	–	–	–	–	2
Improved recovery	–	–	–	25	–	–	–	–	25
Production	–	–	–	(26)	–	–	(333)	(57)	(416)
Sales of reserves-in-place	–	–	–	–	–	–	(24)	–	(24)
	–	–	–	1	–	–	11	54	66
At 31 Decemberc d
Developed	–	–	–	207	1	–	1,682	582	2,472
Undeveloped	–	–	–	124	–	–	486	164	774
	–	–	–	331	1	–	2,168	746	3,246
Total group and BP share
of equity-accounted entities	659	294	3,314	824	170	1,093	2,168	1,885	10,407

a Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bMinority interest in BP Trinidad and Tobago LLC included 29, 39, 55, 17 and 20 million barrels at 31 December 2005, 2004, 2003, 2002 and 2001 respectively within Rest of Americas.

c Basis of reserves reporting in Abu Dhabi (where interests are held through associated undertakings in onshore and offshore concessions expiring in 2014 and 2018

respectively) is that reserves are restricted to those volumes expected to be produced by the end of the life of the concessions. dIncludes 127 and 97 million barrels in respect of the 5.4% minority interest in TNK-BP at 31 December 2004 and 2003 respectively, and 97 million barrels of crude oil in respect of the 4.47% minority interest in TNK-BP in 2005, within Russia.

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 12:25 pm Page 54

									billion cubic feet
									2001
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	3,898	275	12,111	4,755	2,291	518	–	421	24,269
Undeveloped	1,058	71	2,400	8,868	2,085	2,237	–	112	16,831
	4,956	346	14,511	13,623	4,376	2,755	–	533	41,100
Changes attributable to
Revisions of previous estimates	(25)	(10)	16	(840)	103	12	–	18	(726)
Purchases of reserves-in-place	14	–	2	–	102	–	–	–	118
Extensions, discoveries and
other additions	70	15	620	2,157	255	1,334	–	2	4,453
Improved recovery	136	11	988	121	–	3	–	8	1,267
Productionb	(625)	(54)	(1,358)	(586)	(309)	(69)	–	(86)	(3,087)
Sales of reserves-in-place	(154)	–	(12)	–	–	–	–	–	(166)
	(584)	(38)	256	852	151	1,280	–	(58)	1,859
At 31 Decemberc
Developed	3,212	265	12,232	4,549	2,307	826	–	358	23,749
Undeveloped	1,160	43	2,535	9,926	2,220	3,209	–	117	19,210
	4,372	308	14,767	14,475	4,527	4,035	–	475	42,959
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	1,049	168	–	–	51	1,268
Undeveloped	25	–	–	991	501	–	–	33	1,550
	25	–	–	2,040	669	–	–	84	2,818
Changes attributable to
Revisions of previous estimates	(1)	–	–	74	1	–	–	18	92
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	–	–	–	360	–	–	–	–	360
Improved recovery	–	–	–	71	–	–	–	–	71
Production	–	–	–	(99)	(26)	–	–	–	(125)
Sales of reserves-in-place	–	–	–	–	–	–	–	–	–
	(1)	–	–	406	(25)	–	–	18	398
At 31 December
Developed	24	–	–	1,288	153	–	–	67	1,532
Undeveloped	–	–	–	1,158	491	–	–	35	1,684
	24	–	–	2,446	644	–	–	102	3,216
Total group and BP share
of equity-accounted entities	4,396	308	14,767	16,921	5,171	4,035	–	577	46,175

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 64, 76, 69, 63 and 61 billion cubic feet for 2005, 2004, 2003, 2002 and 2001 respectively of natural gas consumed in Alaskan operations. ^c

Minority interest in BP Trinidad and Tobago LLC included 3,872, 4,117, 4,505, 1,185 and 1,258 billion cubic feet of natural gas at 31 December 2005, 2004, 2003, 2002 and 2001 respectively.

Year-end estimated net proved reserves – crude oil and natural gas

								million barrels oil equivalenta
									2001
TOTAL DEVELOPED AND UNDEVELOPED OIL AND NATURAL GAS RESERVES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Subsidiaries	2,079	434	6,135	3,091	946	1,354	–	585	14,624
Equity-accounted entities (BP share)	9	–	–	697	120	–	45	842	1,713
Total group and BP share
of equity-accounted entities	2,088	434	6,135	3,788	1,066	1,354	45	1,427	16,337

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:32 am Page 55

									billion cubic feet
									2002
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	3,212	265	12,232	4,549	2,307	826	–	358	23,749
Undeveloped	1,160	43	2,535	9,926	2,220	3,209	–	117	19,210
	4,372	308	14,767	14,475	4,527	4,035	–	475	42,959
Changes attributable to
Revisions of previous estimates	(137)	3	(149)	30	1,061	38	–	46	892
Purchases of reserves-in-place	77	3	1	4	–	–	–	52	137
Extensions, discoveries and
other additions	126	–	340	2,687	–	11	–	4	3,168
Improved recovery	64	–	738	1,263	–	–	–	–	2,065
Productionb	(566)	(54)	(1,334)	(655)	(313)	(93)	–	(86)	(3,101)
Sales of reserves-in-place	(70)	–	(2)	(39)	–	–	–	(165)	(276)
	(506)	(48)	(406)	3,290	748	(44)	–	(149)	2,885
At 31 Decemberc
Developed	3,215	216	12,102	4,637	2,528	815	–	260	23,773
Undeveloped	651	44	2,259	13,128	2,747	3,176	–	66	22,071
	3,866	260	14,361	17,765	5,275	3,991	–	326	45,844
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	24	–	–	1,288	153	–	–	67	1,532
Undeveloped	–	–	–	1,158	491	–	–	35	1,684
	24	–	–	2,446	644	–	–	102	3,216
Changes attributable to
Revisions of previous estimates	–	–	–	(251)	82	–	–	12	(157)
Purchases of reserves-in-place	–	–	–	18	–	–	2	–	20
Extensions, discoveries and
other additions	–	–	–	27	–	–	–	–	27
Improved recovery	–	–	–	1	–	–	–	–	1
Production	(2)	–	–	(104)	(28)	–	(2)	(4)	(140)
Sales of reserves-in-place	(22)	–	–	–	–	–	–	–	(22)
	(24)	–	–	(309)	54	–	–	8	(271)
At 31 December
Developed	–	–	–	1,282	160	–	–	64	1,506
Undeveloped	–	–	–	855	538	–	–	46	1,439
	–	–	–	2,137	698	–	–	110	2,945
Total group and BP share
of equity-accounted entities	3,866	260	14,361	19,902	5,973	3,991	–	436	48,789

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 64, 76, 69, 63 and 61 billion cubic feet for 2005, 2004, 2003, 2002 and 2001 respectively of natural gas consumed in Alaskan operations. ^c

Minority interest in BP Trinidad and Tobago LLC included 3,872, 4,117, 4,505, 1,185 and 1,258 billion cubic feet of natural gas at 31 December 2005, 2004, 2003, 2002 and 2001 respectively.

Year-end estimated net proved reserves – crude oil and natural gas continued

								million barrels oil equivalenta
TOTAL DEVELOPED AND UNDEVELOPED		Rest of		Rest of	Asia				2002
OIL AND NATURAL GAS RESERVES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiaries	1,794	394	6,037	3,834	1,088	1,590	–	930	15,667
Equity-accounted entities (BP share)	–	–	–	680	127	–	301	803	1,911
Total group and BP share
of equity-accounted entities	1,794	394	6,037	4,514	1,215	1,590	301	1,733	17,578

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:32 am Page 56

									billion cubic feet
									2003
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	3,215	216	12,102	4,637	2,528	815	–	260	23,773
Undeveloped	651	44	2,259	13,128	2,747	3,176	–	66	22,071
	3,866	260	14,361	17,765	5,275	3,991	–	326	45,844
Changes attributable to
Revisions of previous estimates	(64)	27	(777)	(801)	(81)	9	–	19	(1,668)
Purchases of reserves-in-place	–	–	1	85	–	–	–	–	86
Extensions, discoveries and
other additions	397	1,213	293	64	–	–	–	764	2,731
Improved recovery	72	1	2,083	262	–	–	–	28	2,446
Productionb	(528)	(43)	(1,224)	(792)	(283)	(92)	–	(74)	(3,036)
Sales of reserves-in-place	(253)	(33)	(900)	(12)	–	(1,229)	–	–	(2,427)
	(376)	1,165	(524)	(1,194)	(364)	(1,312)	–	737	(1,868)
At 31 Decemberc
Developed	2,673	214	11,290	4,087	1,923	651	–	235	21,073
Undeveloped	817	1,211	2,547	12,484	2,988	2,028	–	828	22,903
	3,490	1,425	13,837	16,571	4,911	2,679	–	1,063	43,976
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	1,282	160	–	–	64	1,506
Undeveloped	–	–	–	855	538	–	–	46	1,439
	–	–	–	2,137	698	–	–	110	2,945
Changes attributable to
Revisions of previous estimates	–	–	–	190	17	–	47	(21)	233
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	–	–	–	12	–	–	–	–	12
Improved recovery	–	–	–	35	–	–	–	–	35
Production	–	–	–	(114)	(26)	–	(47)	(3)	(190)
Sales of reserves-in-place	–	–	–	–	(482)	–	–	–	(482)
	–	–	–	123	(491)	–	–	(24)	(392)
At 31 December
Developed
Undeveloped	–	–	–	1,437	130	–	–	58	1,625
	–	–	–	823	77	–	–	28	928
Total group and BP share	–	–	–	2,260	207	–	–	86	2,553
of equity-accounted entities	3,490	1,425	13,837	18,831	5,118	2,679	–	1,149	46,529

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 64, 76, 69, 63 and 61 billion cubic feet for 2005, 2004, 2003, 2002 and 2001 respectively of natural gas consumed in Alaskan operations. ^c

Minority interest in BP Trinidad and Tobago LLC included 3,872, 4,117, 4,505, 1,185 and 1,258 billion cubic feet of natural gas at 31 December 2005, 2004, 2003, 2002 and 2001 respectively.

Year-end estimated net proved reserves – crude oil and natural gas continued

								million barrels oil equivalenta
									2003
TOTAL DEVELOPED AND UNDEVELOPED OIL AND NATURAL GAS RESERVES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
Subsidiaries	1,496	564	5,624	3,601	1,013	1,635	–	1,098	15,031
Equity-accounted entities (BP share)	–	–	–	730	37	–	1,794	746	3,307
Total group and BP share
of equity-accounted entities	1,496	564	5,624	4,331	1,050	1,635	1,794	1,844	18,338

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:33 am Page 57

									billion cubic feet
									2004
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	2,673	214	11,290	4,087	1,923	651	–	235	21,073
Undeveloped	817	1,211	2,547	12,484	2,988	2,028	–	828	22,903
	3,490	1,425	13,837	16,571	4,911	2,679	–	1,063	43,976
Changes attributable to
Revisions of previous estimates	(226)	16	(791)	(1,889)	(2)	(9)	–	338	(2,563)
Purchases of reserves-in-place	–	–	3	2	–	–	–	–	5
Extensions, discoveries and
other additions	31	–	140	991	2,478	233	–	3	3,876
Improved recovery	134	4	870	75	–	29	–	38	1,150
Productionb	(427)	(46)	(1,097)	(854)	(284)	(98)	–	(73)	(2,879)
Sales of reserves-in-place	–	–	(202)	(91)	(247)	(103)	–	–	(643)
	(488)	(26)	(1,077)	(1,766)	1,945	52	–	306	(1,054)
At 31 Decemberc
Developed	2,079	216	10,207	3,981	1,578	1,054	–	257	19,372
Undeveloped	923	1,183	2,553	10,824	5,278	1,677	–	1,112	23,550
	3,002	1,399	12,760	14,805	6,856	2,731	–	1,369	42,922
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	1,437	130	–	–	58	1,625
Undeveloped	–	–	–	823	77	–	–	28	928
	–	–	–	2,260	207	–	–	86	2,553
Changes attributable to
Revisions of previous estimates	–	–	–	68	(13)	–	319	–	374
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and
other additions	–	–	–	–	–	–	–	–	–
Improved recovery	–	–	–	23	–	–	–	–	23
Production	–	–	–	(129)	(22)	–	(168)	(3)	(322)
Sales of reserves-in-place	–	–	–	–	–	–	–	–	–
	–	–	–	(38)	(35)	–	151	(3)	75
At 31 December
Developed	–	–	–	1,318	103	–	151	60	1,632
Undeveloped	–	–	–	904	69	–	–	23	996
	–	–	–	2,222	172	–	151	83	2,628
Total group and BP share
of equity-accounted entitiesd	3,002	1,399	12,760	17,027	7,028	2,731	151	1,452	45,550

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 64, 76, 69, 63 and 61 billion cubic feet for 2005, 2004, 2003, 2002 and 2001 respectively of natural gas consumed in Alaskan operations. ^c

Minority interest in BP Trinidad and Tobago LLC included 3,872, 4,117, 4,505, 1,185 and 1,258 billion cubic feet of natural gas at 31 December 2005, 2004, 2003, 2002 and 2001 respectively.

dIncludes 54 billion cubic feet of natural gas in respect of the 4.47% minority interest in TNK-BP in 2005 and 9 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP in 2004.

Year-end estimated net proved reserves – crude oil and natural gas continued

								million barrels oil equivalenta
TOTAL DEVELOPED AND UNDEVELOPED		Rest of		Rest of	Asia				2004
OIL AND NATURAL GAS RESERVES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiaries	1,273	567	5,396	3,149	1,338	1,688	–	1,539	14,950
Equity-accounted entities (BP share)	–	–	–	713	31	–	2,183	706	3,633
Total group and BP share
of equity-accounted entities	1,273	567	5,396	3,862	1,369	1,688	2,183	2,245	18,583

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:33 am Page 58

									billiion cubic feet
									2005
SUBSIDIARIES	UK	Rest of Europe	USA	Rest of Americas	Asia Pacific	Africa	Russia	Other	Total
At 1 January
Developed	2,079	216	10,207	3,981	1,578	1,054	–	257	19,372
Undeveloped	923	1,183	2,553	10,824	5,278	1,677	–	1,112	23,550
	3,002	1,399	12,760	14,805	6,856	2,731	–	1,369	42,922
Changes attributable to
Revisions of previous estimates	(15)	(12)	(2)	122	140	301	–	125	659
Purchases of reserves-in-place	–	–	66	2	–	–	–	–	68
Extensions, discoveries and
other additions	17	17	62	225	201	18	–	–	540
Improved recovery	124	18	1,730	83	–	–	–	9	1,964
Productionb	(395)	(39)	(1,006)	(870)	(274)	(154)	–	(77)	(2,815)
Sales of reserves-in-place	–	(1,153)	(16)	(203)	–	–	–	–	(1,372)
	(269)	(1,169)	834	(641)	67	165	–	57	(956)
At 31 Decemberc
Developed	1,962	184	9,916	3,433	1,423	987	–	242	18,147
Undeveloped	771	46	3,678	10,731	5,500	1,909	–	1,184	23,819
	2,733	230	13,594	14,164	6,923	2,896	–	1,426	41,966
EQUITY-ACCOUNTED ENTITIES (BP SHARE)
At 1 January
Developed	–	–	–	1,318	103	–	151	60	1,632
Undeveloped	–	–	–	904	69	–	–	23	996
	–	–	–	2,222	172	–	151	83	2,628
Changes attributable to
Revisions of previous estimates	–	–	–	21	(77)	–	1,340	103	1,387
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries and									–
other additions	–	–	–	27	–	–	–	–	27
Improved recovery	–	–	–	53	–	–	–	–	53
Production	–	–	–	(137)	(17)	–	(176)	(3)	(333)
Sales of reserves-in-place	–	–	–	–	–	–	(119)	–	(119)
	–	–	–	(36)	(94)	–	1,045	100	1,015
At 31 Decemberd
Developed	–	–	–	1,403	50	–	1,019	131	2,603
Undeveloped	–	–	–	783	28	–	177	52	1,040
	–	–	–	2,186	78	–	1,196	183	3,643
Total group and BP share
of equity-accounted entities	2,733	230	13,594	16,350	7,001	2,896	1,196	1,609	45,609

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 64, 76, 69, 63 and 61 billion cubic feet for 2005, 2004, 2003, 2002 and 2001 respectively of natural gas consumed in Alaskan operations. ^c

Minority interest in BP Trinidad and Tobago LLC included 3,872, 4,117, 4,505, 1,185 and 1,258 billion cubic feet of natural gas at 31 December 2005, 2004, 2003, 2002 and 2001 respectively.

dIncludes 54 billion cubic feet of natural gas in respect of the 4.47% minority interest in TNK-BP in 2005 and 9 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP in 2004.

Year-end estimated net proved reserves – crude oil and natural gas continued

								million barrels oil equivalenta
TOTAL DEVELOPED AND UNDEVELOPED		Rest of		Rest of	Asia				2005
OIL AND NATURAL GAS RESERVES	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiaries	1,130	334	5,658	2,935	1,363	1,592	–	1,385	14,397
Equity-accounted entities (BP share)	–	–	–	708	14	–	2,374	778	3,874
Total group and BP share									–
of equity-accounted entities	1,130	334	5,658	3,643	1,377	1,592	2,374	2,163	18,271

Group production interests – oil (includes NGLs and condensate)

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 1:30 pm Page 59

						BP net share of production	thousand barrels a daya
	Field	Interest %	2001	2002	2003	2004	2005
UK – OFFSHORE	ETAPb	Various	80	61	56	55	49
	Foinavenc	Various	60	72	55	48	39
	Magnusc	85.0	37	31	39	34	30
	Schiehallion/Loyalc	Various	40	43	42	39	28
	Hardingc	70.0	42	42	34	27	22
	Andrewc	62.8	25	23	17	12	12
	Other	Various	165	157	105	89	75
UK – ONSHORE	Wytch Farmc	67.8	36	32	29	26	22
			485	461	377	330	277
REST OF EUROPE
Netherlands	Various	Various	1	1	1	1	1
Norway	Valhallc	28.1	22	21	21	25	25
	Draugen	18.4	40	37	25	27	20
	Ulac	80.0	18	18	16	16	17
	Other	Various	19	27	21	8	12
			100	104	84	77	75
USA
Alaska	Prudhoe Bayc	26.4	123	113	105	97	89
	Kuparuk	39.2	76	74	73	68	62
	Northstarc	98.6	3	36	46	49	46
	Milne Pointc	100.0	45	44	44	44	37
	Other	Various	41	42	43	37	34
Lower 48 onshore	Various	Various	213	192	160	142	130
Gulf of Mexico	Na Kikac	50.0	–	–	–	27	44
	Horn Mountainc	66.6	–	1	42	41	26
	Kingc
		100.0	–	12	31	26	24
	Mars	28.5	42	41	43	35	21
	Ursa	22.7	23	20	17	29	19
	Other	Various	178	190	122	71	80
			744	765	726	666	612
REST OF WORLD
Angola	Kizomba A	26.7	–	–	–	16	56
	Girassol	16.7	1	29	33	31	34
	Xikomba	26.7	–	–	2	18	10
	Other	Various	–	–	–	6	28
Australia	Various	15.8	40	43	40	36	36
Azerbaijan	ACG (Chirag)c	34.1	35	38	38	39	76
Canada	Various	Various	18	16	13	11	10
Colombia	Various	Various	48	46	53	48	41
Egypt	Various	Various	91	85	73	57	47
Trinidad & Tobago	Various	100.0	48	67	74	59	40
Venezuela	Various	Various	54	51	53	55	55
Other	Various	Various	59	61	49	31	26
			394	436	428	407	459
Total group			1,723	1,766	1,615	1,480	1,423
Equity-accounted entities (BP share)
Abu Dhabi	Various	Various	126	113	138	142	148
Argentina – Pan American Energy	Various	Various	50	53	60	64	67
Russia – TNK-BP	Various	Various	20	73	296	831	911
Other	Various	Various	12	13	12	14	13
Total equity-accounted entities			208	252	506	1,051	1,139
Total group and BP share of equity-accounted entitiesd			1,931	2,018	2,121	2,531	2,562

a Net of royalty, whether payable in cash or in kind.

bOut of nine fields, BP operates six and Shell three.

c BP operator.

dIncludes NGLs (natural gas liquids) from processing plants in which an interest is held of 58 thousand barrels a day in 2005 (67 thousand barrels a day in 2004 and 70 thousand barrels a day in 2003).

Group production interests – natural gas

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 12:26 pm Page 60

						BP net share of production	million cubic feet a daya
	Field	Interest %	2001	2002	2003	2004	2005
UK – OFFSHORE	Braesb	Various	100	116	174	147	165
	Brucec	37.0	256	221	222	163	161
	West Solec	100.0	81	72	73	67	55
	Marnockc	62.0	125	135	98	70	47
	Britannia	9.0	65	56	55	54	46
	Shearwater	27.5	–	66	70	76	37
	Armada	18.2	71	71	58	50	30
	Other	Various	1,015	813	696	547	549
			1,713	1,550	1,446	1,174	1,090
REST OF EUROPE
Netherlands	P/18-2c	48.7	47	41	30	34	25
	Other	Various	52	46	37	46	37
Norway	Various	Various	48	60	52	45	46
			147	147	119	125	108
USA	San Juanc
Lower 48 onshore		Various	832	797	802	772	753
	Arkoma Hugotonc	Various	219	206	201	183	198
		Various	180	169	182	158	151
	Tuscaloosa Wamsutterc	Various	187	138	136	96	111
	Jonahc	70.5	100	108	111	105	110
		65.0	109	113	119	114	97
	Other Na Kikac	Various	733	715	558	514	465
Gulf of Mexico	Marlinc	50.0	–	–	–	133	133
	Other	78.2 Various	79 1,104	106 1,079	93 843	43 553	52 395
Alaska	Various	Various	11	52	83	78	81
			3,554	3,483	3,128	2,749	2,546
REST OF WORLD
Australia	Various	15.8	237	295	285	308	367
Canada	Various	Various	584	514	422	349	307
China	Yachengc	34.3	108	102	74	99	98
Egypt	Ha'pyc	50.0	66	74	83	80	106
	Others	Various	124	182	170	115	83
Indonesia	Sanga Sanga (direct)c	26.3	164	174	165	137	110
	Otherc	46.0	337	283	218	144	128
Sharjah	Sajaac	40.0	125	110	101	103	113
	Other	40.0	35	24	19	14	10
Trinidad & Tobago	Kapokc	100.0	–	–	79	553	1,005
	Mahoganyc	100.0	529	521	503	453	303
	Amherstiac	100.0	244	492	624	408	289
	Parangc	100.0	–	–	152	137	154
	Immortellec	100.0	128	154	235	172	132
	Cassiac	100.0	–	–	30	85	83
	Otherc	100.0	110	71	71	111	21
Other	Various	Various	82	148	168	308	459
			2,873	3,144	3,399	3,576	3,768
Total group			8,287	8,324	8,092	7,624	7,512
Equity-accounted entities (BP share)
Argentina – Pan American Energy	Various	Various	236	251	281	317	343
Russia – TNK-BP	Various	Various	–	6	129	458	482
Other	Various	Various	109	126	111	104	87
Total equity-accounted entities			345	383	521	879	912
Total group and BP share of equity-accounted entities			8,632	8,707	8,613	8,503	8,424

a Net of royalty, whether payable in cash or in kind.

b2004 includes 11 million cubic feet a day of natural gas received as in-kind tariff payments.

c BP operator.

Group production interests – oil and natural gas

C12386_BP_F&OI 2005_p30-63.qxp 3/4/06 11:33 am Page 61

		thousand barrels oil equivalent a day
OIL AND NATURAL GAS PRODUCTION (NET OF ROYALTY)	2001	2002	2003	2004	2005
UK	780	729	626	532	465
Rest of Europe	125	129	105	99	94
USA	1,357	1,365	1,265	1,142	1,051
Rest of World	1,157	1,296	1,610	2,224	2,404
Total group including equity-accounted entities	3,419	3,519	3,606	3,997	4,014
BP AVERAGE LIQUIDS REALIZATIONSa b					\$/bbl
UK	23.55	24.44	27.80	35.87	50.45
Rest of Europe	23.86	24.61	28.33	37.89	52.48
USA	21.87	21.34	27.23	35.41	47.83
Rest of World	21.90	22.65	26.60	34.51	47.56
BP average	22.50	22.69	27.25	35.39	48.51
BP AVERAGE NATURAL GAS REALIZATIONS					\$/bbl
UK	3.07	2.78	3.19	4.32	5.53
Rest of Europe	3.60	2.87	3.59	3.89	4.86
USA	3.99	2.63	4.47	5.11	6.78
Rest of World	2.52	2.10	2.47	2.74	3.46
BP average	3.30	2.46	3.39	3.86	4.90

a Crude oil and natural gas liquids.

bBased on sales of consolidated subsidiaries only (this excludes equity-accounted entities).

Exploration interests at 31December

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 1:19 pm Page 62

Oil and natural gas acreage thousand acres

iu acres

				2003				2004				2005
		Undevelopeda	Developed			Undevelopeda		Developed		Undevelopeda		Developed
BY GEOGRAPHICAL AREA	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
UK	2,660	1,395.2	748	216.3	2,484	1,328.5	507	221.9	2,325	1,232.3	500	218.4
Rest of Europe	3,311	1,077.5	132	42.7	2,972	1,120.3	138	46.1	1,668	617.5	138	46.2
USA
Alaska	455	256.6	556	233.2	298	153.7	550	230.2	278	140.0	543	226.4
Lower 48 onshore	3,315	2,102.0	5,964	4,203.0	3,258	2,070.0	5,865	4,170.0	3,261	2,064.0	5,786	4,108.0
Gulf of Mexico	4,078	3,019.0	1,100	572.0	3,968	3,164.0	796	444.0	3,630	2,932.0	730	403.0
Rest of World
South America and Canada		25,082 14,123.8	2,617	1,313.1		23,506 12,803.6	2,410	1,271.8	13,893	6,913.2	2,728	1,303.4
Middle East, Africa and
Former Soviet Union		38,567 13,682.7	6,096	2,433.9		38,835 14,338.5	5,972	2,108.4		44,155 18,384.2	6,600	2,500.5
Australasia and Far East		24,108 10,108.8	685	222.9	9,615	3,794.2	671	208.0	7,977	3,019.5	1,072	262.4
		101,576 45,765.6	17,898	9,237.1		84,936 38,772.8	16,909	8,700.4		77,187 35,302.7	18,097	9,068.3

a Undeveloped acreage includes leases and concessions.

Exploration and development wells

C12386_BP_F&OI 2005_p30-63.qxp 6/4/06 12:35 pm Page 63

PRODUCTIVE WELLS DRILLED	Gross	2001 Net	Gross	2002 Net	Gross	2003 Net	Gross	2004 Net	Gross	2005 Net
Exploration
UK	6	3.2	1	0.8	2	0.3	–	–	1	0.5
Rest of Europe	3	0.9	2	0.4	2	1.1	–	–	1	0.8
USA	12	5.7	9	2.1	1	1.0	4	2.1	24	10.7
Rest of World	48	18.7	37	17.3	27	10.6	49	20.2	45	18.8
	69	28.5	49	20.6	32	13.0	53	22.3	71	30.8
Development
UK	36	13.5	48	17.3	35	11.0	32	10.0	39	10.6
Rest of Europe USA	10	4.2	6	1.5	10	2.8	1	0.3	9	3.5
Rest of World	1,084 714	705.3 325.2	955 497	384.2 212.9	812 483	466.2 225.8	979 790	513.3 342.5	836 977	473.9 417.2
	1,844	1,048.2	1,506	615.9	1,340	705.8	1,802	866.1	1,861	905.2
DRY WELLS DRILLED
Exploration
UK	2	1.2	–	–	–	–	–	–	1	0.3
Rest of Europe	1	0.7	2	0.5	1	0.2	–	–	–	–
USA	8	3.8	3	1.0	1	0.7	5	3.2	10	6.4
Rest of World	11	2.5	30	19.5	11	4.9	23	9.8	17	7.8
	22	8.2	35	21.0	13	5.8	28	13.0	28	14.5
Development
UK	4	1.6	6	2.8	2	0.4	1	0.1	–	–
Rest of Europe	–	–	–	–	1	0.3	–	–	1	0.3
USA	34	25.7	29	19.7	7	5.4	4	3.0	10	5.0
Rest of World	52	33.5	37	28.2	13	8.2	34	14.9	46	22.7
	90	60.8	72	50.7	23	14.3	39	18.0	57	28.0
							Rest of		Rest of
NUMBER OF PRODUCTIVE WELLS AT END OF 2005						UK	Europe	USA	World	Total
Oil wellsa
Gross						372	86	8,589	27,598	36,645
Net						144.3	28.5	2,629.1	12,287.1	15,089.0
Natural gas wellsb
Gross						298	44	17,442	2,939	20,723
Net						140.9	16.1	11,238.2	1,616.0	13,011.2

a

Includes approximately 1,072 gross (336.3 net) multiple completion wells (more than one formation producing into the same well bore). bIncludes approximately 2,473 gross (1,586.0 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.

DRILLING AND PRODUCTION ACTIVITIES IN PROGRESS AT END OF 2005a	UK	Rest of Europe	USA	Rest of World	Total
Exploratory
Gross	–	1	26	20	47
Net	–	0.1	11.5	7.7	19.3
Development
Gross	9	1	248	117	375
Net	2.8	0.3	125.7	49.0	177.8

a Includes suspended development and exploratory wells.

2 Refining and Marketing

C12386_BP_F&OI 2005_p64-73.qxp 3/4/06 11:39 am Page 64

• 66 2005 performance
• 67 Key indicators
• 68 Financial statistics
• 69 Crude oil sales
• 69 Major plant capacities by site
• 70 Refinery throughputs and utilization
• 71 Refineries
• 72 Petroleum product sales
• 73 Chemicals production
• 73 Service stations
• 73 Shop sales

C12386_BP_F&OI 2005_p64-73.qxp 3/4/06 11:40 am Page 65

Segment strategy

• ••• Continue to focus on advantaged refining locations, where we can earn distinctive returns.
• ••• Operate in retail markets where supply advantage and distinctive offer can capture market share and margin, underpinned by efficiency improvements.
• ••• Increase brand loyalty in lubricants.
• ••• Apply advantaged technology in A&A, building new capacity in Asia.
• ••• Build strong strategic relationships in business-to-business sector.

Segment focus

We aim to improve the quality and capability of our manufacturing portfolio. Our marketing businesses, underpinned by world-class manufacturing, generate customer value by providing quality products and offers. Our retail strategy provides differentiated fuel and convenience offers to some of the most attractive global markets. Our lubricants brands offer customers benefits through technology and relationships, and we focus on increasing brand and product loyalty in Castrol lubricants. We continue to build deep customer relationships and strategic partnerships in the business-tobusiness sector.

2005 PERFORMANCE

Replacement cost profit before interest and tax for the segment was \$4,394 million, compared with \$5,194 million in 2004. This was affected by the Texas City refinery outage, adverse impacts related to fair value accounting and costs associated with rationalization and efficiency programmes. The full year average Global Indicator Refining Margin (GIM) was higher than that for the full year 2004 and consistent with the increase in BP's actual realized refining margin. Retail marketing margins, despite the recovery in the fourth quarter, were significantly lower than those for the full year 2004, although partly offset by increases in our other marketing businesses. The result included a net charge for non-operating items of \$789 million. Of this, \$700 million was in respect of fatality and personal injury claims associated with the incident at the Texas City refinery on 23 March 2005.

C12386_BP_F&OI 2005_p64-73.qxp 3/4/06 11:40 am Page 66

REFINING

The average GIM was higher in 2005 than in 2004, owing to the strength of demand and concerns over supply disruptions, particularly in the US. BP's refining margin also reflected the benefits of locational advantages and supply optimization.

Refining volumes were lower in 2005, owing to the impact of disposal of the Mersin and Singapore refineries in 2004 and reduced availability at the Texas City refinery. The latter resulted from the explosion in the isomerization unit in March 2005 and the refinery's complete shutdown in late September, like other refineries in the area, owing to Hurricane Rita. Subsequent assessments revealed that this precautionary measure necessitated additional work to prepare the refinery for a safe and reliable start-up, prolonging the period of the shutdown. Following a comprehensive refurbishment, the steam system at the Texas City refinery was successfully recommissioned in December 2005. The refinery remained shut down in the first quarter of 2006, with a phased recommissioning starting at the end of March. Refinery throughputs for 2005 were 2,399 thousand barrels a day (mb/d), compared with 2,607mb/d in 2004.

We have continued to upgrade our refining portfolio. Following the sale of the Lavéra, France, and Grangemouth, UK, refineries that were part of Innovene, our refining portfolio is weighted more heavily to the US, where margins are structurally higher. Our capital investments continue to focus on further enhancing our position in the US and repositioning our European activities by continuing to invest in upgrading existing facilities.

MARKETING

Retail marketing margins were lower than in 2004, reflecting sustained pressure from rising crude oil and product prices. There was also unprecedented volatility in margins. This was partly due to the effects of Hurricanes Katrina and Rita on supply and pricing in the US.

Marketing sales were 3,942mb/d in 2005, compared with 4,002mb/d the previous year. The decrease was due mainly to the effects of the price increases as a result of the supply disruption and market uncertainty. Shop sales maintained a similar level to those of the previous year, despite the impact of the rise in fuel prices.

In 2005, the lubricants business was affected by significantly higher costs of base oil, additives, packaging and logistics. Marketing volumes were weaker than in 2004 in some developed markets. Volumes continued to grow in some emerging markets. In 2005, we launched Castrol Edge passenger car oils in Australia, South Africa, Sweden and the UK, seeking to bring a new generation of quality-conscious consumers to the Castrol brand. It is planned to extend the range to other countries during 2006. We formed a joint venture between Castrol and the Dong Feng group, a Chinese automobile manufacturer, to supply lubricants to the Chinese market. Our strength in fast-growth emerging markets depends on strong brands and focused technological innovation.

BP enjoys strong market shares and leading technologies in the high-growth aromatics and acetyls (A&A) business. In Asia, we continue to develop a strong position in PTA (the main component of polyester fibres and packaging) and acetic acid (commonly used for paints, adhesives and inks). Our investment is biased towards this high-growth region, especially China. Capital expenditure in our A&A business increased slightly in 2005 as we invested to maintain our leadership position.

BP and Sinopec Corporation of China signed a joint-venture contract to build a world-scale acetic acid plant in Nanjing, Jiangsu province. The 500,000-tonnes-a-year operation is planned to come on stream in the second half of 2007. The sale of BP's 70% shareholding in BP Malaysia Sdn Bhd to Lembaga Tabung Angkatan, announced in 2004, was successfully concluded during the third quarter of 2005. We also announced plans for a second purified terephthalic acid (PTA) plant at the BP Zhuhai Chemical Company's site in China's Guangdong province, subject to governmental approval. The new plant is designed to have an operating capacity of 900,000 tonnes a year and will be the first plant to use BP's new-generation proprietary PTA technology.

Key indicators

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	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Result and refining margin
Replacement cost profit before interest and tax (\$ billion)	4.45	1.94	3.16	5.19	4.39
Global Indicator Refining Margin (\$/bbl)	4.36	2.27	4.08	6.31	8.60
Refining availability (%)a	95.6	96.1	95.5	95.4	92.9
Shop sales (\$ million)	3,234	5,171	5,708	6,061	6,083

aRefining availability is the weighted average percentage of the period that refinery units are available for processing, after accounting for downtime such as turnarounds.

Financial statistics

C12386_BP_F&OI 2005_p64-73.qxp 6/4/06 5:44 pm Page 68

					\$ million
			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Replacement cost profit before interest and tax by geographical areaa
UKb	(644)	(710)	(119)	(695)	(581)
Rest of Europe	875	1,025	1,472	1,986	1,567
USA	3,007	926	1,009	2,835	2,247
Rest of World	1,216	695	800	1,068	1,161
	4,454	1,936	3,162	5,194	4,394
aIncludes equity-accounted interest and tax	–	–	49	98	136
Under IFRS, the results of jointly controlled entities and associates for 2003, 2004
and 2005 are included in the income statement net of interest and tax.
Operating capital employed by geographical area
UKb	3,037	3,024	3,471	3,485	3,696
Rest of Europe	3,195	10,010	10,701	12,543	11,588
USA	12,362	13,797	13,481	15,047	16,973
Rest of World	4,805	5,335	6,431	7,212	7,522
	23,399	32,166	34,084	38,287	39,779
Sales and other operating revenues	114,135	121,908	147,813	176,240	219,995
Property, plant and equipment (net book value) UKb
	2,529	2,719	2,874	2,586	2,199
Rest of Europe	3,040	8,472	7,626	8,177	6,914
USA	11,491	11,402	10,993	10,763	10,323
Rest of World	2,831	3,216	3,599	3,402	3,251
	19,891	25,809	25,092	24,928	22,687
Capital expenditure and acquisitions by geographical area
UKb	398	382	430	411	408
Rest of Europe	393	5,776	728	599	568
USA	1,651	1,527	1,401	1,314	1,226
Rest of World	501	468	522	665	658
	2,943	8,153	3,081	2,989	2,860
EMPLOYEE NUMBERS AT YEAR END
Excluding service station staff	38,100	44,900	42,000	41,900	43,000
Service station staff	28,500	30,200	27,000	27,900	27,800
	66,600	75,100	69,000	69,800	70,800
					\$ per barrel
GLOBAL INDICATOR REFINING MARGINc	2001	2002	2003	2004	2005
NWE	2.24	1.04	2.62	4.28	5.47
USGC	4.84	2.36	4.71	7.15	11.40
USMW	6.05	3.30	4.54	5.08	13.49

bUK area includes the UK-based international activities of Refining and Marketing.

cThe Global Indicator Refining Margin (GIM) is the average of six regional indicator margins weighted for BP's crude oil refining capacity in each region. Each regional indicator margin is based on a single representative crude oil with product yields characteristic of the typical level of upgrading complexity. 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. The GIM data shown above excludes the Grangemouth and Lavéra refineries.

USWC 8.60 4.34 7.06 11.27 8.19 Singapore 0.90 0.57 1.77 4.94 5.56 BP average 4.36 2.27 4.08 6.31 8.60

Crude oil sales

					thousand barrels a day
CRUDE OIL SALES	2001	2002	2003	2004	2005
UK	2,139	2,015	908	1,174	1,205
Rest of Europe	114	223	113	82	82
USA	1,220	1,144	957	539	673
Rest of World	437	553	859	897	750
	3,910	3,935	2,837	2,692	2,710

Major plant capacities by site

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Aromatics and Acetyls

Geographical			BP share of capacity at end 2005
area		Site Product		thousand tonnes a year
UK
		Hull acetic acid	677
		acetic anhydride	141
		vinyl acetate	208
		ethyl acetate	228
		acetone	38
		other	49
REST OF EUROPE
Belgium	Geel PTA		1,044
		paraxylene	520
USA
	Cooper River PTA		1,330
	Decatur PTA		1,100
		paraxylene	1,121
		NDC	27
		Texas City acetic acid	527a
		paraxylene	1,282
		metaxylene	122
REST OF WORLD
Brazil	São Paulo PTA			143 (49% of Rhodiaco)
China	Chongqing acetic acid			169 (51% of YARACO)b
		esters		52 (51% of YARACO)b
	Zhuhai PTA		583
Indonesia	Merak PTA			250 (50% of PT Ami)
Korea	Ulsan PTA			550 (47% of SPC)c
		VAM		56 (34% of ASACCO)d
		acetic acid		229 (51% of SS-BP)e
	Seosan PTA			339 (47% of SPC)e
Malaysia		Kertih acetic acid	544
	Kuantan PTA		703
Taiwan	Kaohsiung PTA			825 (61% of CAPCO)f
	Taichung PTA			458 (61% of CAPCO)f
		Mai Ling acetic acid		162 (50% FBPC)g
			13,477

Olefins and Derivatives

Geographical			BP share of capacity at end 2005
area		Site Product	thousand tonnes a year
REST OF EUROPE
Germany	Gelsenkirchen ethylene		599 (61% of ROG)h
		propylene	276 (57% of ROG)h
		benzene	101 (50% of ROG)h
		butadiene	218 (61% of ROG)h
		other	308 (50% of ROG)h
	Münchmünster ethylene		325 (50% of ROG)h
		propylene	230 (50% of ROG)h
		benzene	67 (50% of ROG)h
	Mülheim other		72 (50% of ROG)h
REST OF WORLD
China		Caojing acrylonitrile	143 (50% of SECCO)i
		ethylene	521 (50% of SECCO)i
		HDPE	354 (50% of SECCO)i
		polypropylene	134 (50% of SECCO)i
		polystyrene	165 (50% of SECCO)i
		styrene	274 (50% of SECCO)i
		other	251 (50% of SECCO)i
Malaysia		Kertih HDPE	185 (60% of PEMSB)j
		ethylene	66 (15% of EMSB)k
			4,289

aSterling Chemicals plant, the output of which is marketed by BP. bYangtze River Acetyls Company.

cSamsung-Petrochemicals Company Ltd. dAsian Acetyls Company Ltd.

eSamsung-BP Chemicals Ltd.

^f China American Petrochemical Company Ltd.

gFormosa BP Chemicals Corporation.

hRuhr Oel GmbH.

ⁱ Shanghai SECCO Petrochemical Company Limited.

^j Polyethylene Malaysia Sdn Bhd.

kEthylene Malaysia Sdn Bhd.

C12386_BP_F&OI 2005_p64-73.qxp 3/4/06 11:41 am Page 70

					thousand barrels a day
REFINERY THROUGHPUTSa	2001	2002	2003	2004	2005
UK	190	206	202	208	180
Rest of Europe	505	758	753	684	667
USA	1,526	1,439	1,386	1,373	1,255
Rest of World	376	357	382	342	297
	2,597	2,760	2,723	2,607	2,399
For BP by others	14	14	–	–	–
	2,611	2,774	2,723	2,607	2,399
Crude distillation capacity at 31 December	2,836	3,111	2,983	2,823	2,747
Crude distillation capacity utilizationb	92%	92%	91%	93%	87%

aIncludes actual crude oil and other feedstock input both for BP and third parties.

bCrude distillation capacity utilization is defined as the percentage utilization of capacity per calendar day over the year after making allowance for average annual shutdowns at BP refineries (i.e. net rated capacity).

					%
CRUDE OIL INPUT	2001	2002	2003	2004	2005
Low sulphur crude	54	55	55	47	52
High sulphur crude	46	45	45	53	48
					thousand barrels a day
REFINERY YIELDa	2001	2002	2003	2004	2005
Aviation fuels	256	262	264	241	241
Gasolines	1,055	1,141	1,059	1,025	940
Middle distillates	713	787	793	717	715
Fuel oil	168	150	170	144	133
Other products	442	548	528	534	474
	2,634	2,888	2,814	2,661	2,503

aRefinery yields exceed throughputs because of volumetric expansion.

Refineries

C12386_BP_F&OI 2005_p64-73.qxp 3/4/06 11:41 am Page 71

REFINERY CAPACITIES				Crude distillation capacitiesa											Major upgrading plant capacitiesb
Wholly and partly owned refineries at 31 December 2005		Group interest %c	Total	BP share	Vacuum	Fluid distill- catalytic ation cracking cracking		Catalytic Hydro- reform- ing	lation	Hydro- Alky- 232ºC & 232ºC &	Hydro treating treating	Vis- lighter heavier breaking	Coker	Isomer ization	Lubes	Otherd
EUROPE
UK	Coryton	100	172	172	99	62	–	38	21	66	53	–	–	35	–	–
France	Reichstett	17	84	14	34	14	–	13	–	21	21	17	–	–	–	–
Germanye	Bayernoil	23	269	62	24	15	–	11	–	20	24	10	–	3	–	1
	Gelsenkirchen	50	270	135	55	15	23	16	–	46	46	10	16	5	–	–
	Karlsruhe	12	308	37	17	11	–	7	2	13	24	3	4	2	–	1
	Lingen	100	91	91	42	–	27	30	7	32	39	–	23	9	–	–
	Schwedt	19	230	43	28	11	–	7	2	17	27	9	–	3	–	–
Netherlands	Nerefco	69	400	276	61	43	–	21	6	115	63	25	–	–	–	2
Spain	Castellón	100	110	110	47	30	–	17	4	56	33	–	–	19	–	–
			1,934	940	407	201	50	160	42	386	330	74	43	76	–	4
USA
California	Carson	100	260	260	140	103	45	52	16	83	129	–	71	23	–	–
Washington	Cherry Point	100	232	232	101	–	57	63	–	57	26	–	63	–	–	–
Indiana	Whiting	100	405	405	189	165	–	84	25	144	183	–	35	32	–	–
Ohio	Toledo	100	155	155	72	52	31	43	12	40	64	–	34	–	–	–
Texas	Texas City	100	475	475	237	210	130	138	55	253	243	–	43	29	–	–
				1,527 1,527	739	530	263	380	108	577	645	–	246	84	–	–
REST OF WORLD
Australia	Bulwer	100	97	97	39	23	21	16	3	13	42	–	–	–	–	–
	Kwinana	100	137	137	22	35	–	24	4	44	49	–	–	15	–	–
New Zealand	Whangerei	24	107	25	51	–	34	27	–	62	–	–	–	–	–	–
Kenya	Mombasa	17	90	15	–	–	–	9	–	36	–	–	–	–	–	–
South Africa	Durban	50	182	91	68	37	–	34	3	69	62	30	–	14	3	–
			613	365	180	95	55	110	10	224	153	30	–	29	3	–
				4,074 2,832 1,326		826	368	650		160 1,187 1,128		104	289	189	3	4

aGross-rated capacity is defined as the owner's maximum achievable utilization of capacity (24-hour assessment) based on standard feed. bThese are shown as BP share of capacities; BP has varying interests.

cBP share of equity, which is not necessarily the same as BP share of processing entitlements.

dOther consists of MTBE, except for Castellón, which includes Makfiner, 29 thousand barrels a day, and Scanfiner, 10 thousand barrels a day. eInterests in the Gelsenkirchen, Karlsruhe, Lingen and Schwedt refineries and an additional interest in Bayernoil were acquired as part of the Veba acquisition.

					thousand barrels a day
REGIONAL REFINING DISTILLATION CAPACITY	2001	2002	2003	2004	2005
Europe	787	1,118	1,002	934	939
USGC	470	470	470	470	475
USMW	575	575	575	560	560
USWC	492	492	492	492	492
Other USA	62	–	–	–	–
Total USA	1,599	1,537	1,537	1,522	1,527
Rest of World	450	456	444	367	366
Total	2,836	3,111	2,983	2,823	2,832

thousand barrels a day

Petroleum product sales

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			thousand barrels a day
REGIONAL MARKETING SALES VOLUMESa	2001	2002	2003	2004	2005
UK
Aviation fuels	54	62	65	57	77
Gasolines	88	85	92	118	109
Middle distillates	81	77	96	116	116
Fuel oil	20	16	6	9	15
Other products	23	13	16	22	38
	266	253	275	322	355
Rest of Europe
Aviation fuels	123	144	148	144	138
Gasolines	293	382	350	316	307
Middle distillates	428	551	600	649	635
Fuel oil	124	272	101	139	155
Other products	94	118	109	112	118
	1,062	1,467	1,308	1,360	1,353
USA
Aviation fuels	267	257	245	219	196
Gasolines	1,131	1,120	1,119	1,093	1,044
Middle distillates	387	415	346	333	307
Fuel oil	66	65	41	26	30
Other products	15	17	15	11	57
	1,866	1,874	1,766	1,682	1,634
Rest of World
Aviation fuels	71	66	72	74	88
Gasolines	147	157	153	148	142
Middle distillates	181	189	161	157	126
Fuel oil	141	98	148	169	179
Other products	63	76	86	90	63
	603	586	620	638	599
Product totals
Aviation fuels	515	529	530	494	499
Gasolines	1,659	1,744	1,714	1,675	1,603
Middle distillates	1,077	1,232	1,203	1,255	1,185
Fuel oil	351	451	296	343	379
Other products	195	224	226	235	276
Total marketing sales	3,797	4,180	3,969	4,002	3,942
Trading/supply salesb	2,409	2,383	2,719	2,396	1,946
Total oil product sales	6,206	6,563	6,688	6,398	5,888

aMarketing sales are sales to service stations, end consumers, bulk buyers, jobbers and small resellers.

bTrading/supply sales are sales to large unbranded resellers and other oil companies.

					\$ million
PETROLEUM PRODUCT SALES BY GEOGRAPHICAL AREAa	2001	2002	2003	2004	2005
UKb	8,474	8,335	10,612	16,596	22,477
Rest of Europe	22,494	28,120	30,824	34,072	47,479
USA	39,212	38,379	44,845	54,400	63,363
Rest of World	12,061	12,686	15,721	19,390	21,779
	82,241	87,520	102,002	124,458	155,098

aProceeds exclude sales to other BP businesses, customs duties and sales taxes.

bUK area includes the UK-based international activities of Refining and Marketing.

Chemicals productiona

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					thousand tonnes
PRODUCTION BY GEOGRAPHICAL AREA	2001	2002	2003	2004	2005
UK	1,121	1,193	1,157	1,302	1,199
Rest of Europe	1,217	2,864	3,074	3,189	3,123
USA	3,909	4,312	4,364	4,643	3,891
Rest of World	2,451	2,797	3,797	4,224	5,863
	8,698	11,166	12,392	13,358	14,076

aProduction of aromatics and acetyls and olefins and derivatives.

Service stations

					at 31 December
	2001	2002	2003	2004	2005
UK	1,400	1,300	1,300	1,300	1,300
Rest of Europe	6,100	9,200	8,200	8,000	7,900
USA (excluding jobbers)	4,900	4,400	4,100	3,900	3,100
USA jobbers	10,600	10,500	10,600	10,300	9,700
Rest of World	3,800	3,800	3,600	3,300	3,200
	26,800	29,200	27,800	26,800	25,200

Shop salesa

					\$ million
	2001	2002	2003	2004	2005
UK	458	527	567	655	628
Rest of Europe	904	2,638	3,000	3,090	3,069
USA	1,510	1,585	1,620	1,715	1,776
Rest of World	362	421	521	601	610
	3,234	5,171	5,708	6,061	6,083
Direct-managed	1,650	1,869	2,090	2,319	2,489
Franchise	1,504	3,216	3,508	3,623	3,533
Shop alliances	80	86	110	119	61
	3,234	5,171	5,708	6,061	6,083

aShop sales reported are sales through direct-managed stations, franchisees and the BP share of shop alliances. Sales figures exclude VAT and lottery sales but include quick-service restaurant sales.

3 Gas, Power and Renewables

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• 76 2005 performance
• 77 Key indicators
• 78 Gas, Power and Renewables operations
• 80 Financial statistics
• 80 LNG projects

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Segment strategy

• ••• Capture distinctive world-scale gas market positions by accessing key pieces of infrastructure.
• ••• Expand gross margin by providing distinctive products to selected customer segments and optimizing the gas and power value chains.
• ••• Develop the world's leading low-carbon power generation and wholesale marketing and trading businesses.

Segment focus

In line with growing demand for cleaner fuels, BP seeks to participate on a large scale in fast-growing markets for natural gas, gas liquids and low-carbon power. We have strong upstream gas assets near the major markets, significant interests in gas pipelines and a series of integrated LNG positions in the Pacific and Atlantic basins. We are expanding our LNG business by accessing import terminals in Asia Pacific, North America and Europe. We are extending our strength in US natural gas liquids (NGLs) processing and marketing on a global basis. Our emerging Alternative Energy business is being developed from a strong base in gas-fired and solar power assets and power marketing and trading, together with planned developments in hydrogen and wind power.

2005 PERFORMANCE

Replacement cost profit before interest and tax for the segment for the year was \$1,077 million, compared with \$964 million in 2004. The result includes a net charge for non-operating items of \$20 million (2004 \$56 million gain), which primarily comprises fair value losses on embedded derivatives of \$346 million and compensation of \$265 million received on cancellation of an intra-group gas supply contract. The operating business result has increased by 21% over 2004, with higher margins from gas marketing and trading and NGLs businesses. The volumes of gas supplied into liquefaction plants rose by 1%. Our solar and power businesses continued to grow profitably.

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GAS AND NGLs

Our intent is to grow the business in the medium term by 2-3% a year, in line with global gas demand. North America, where we continue to hold the largest market share, is our most important gas market. This position is anchored by our strong upstream positions around the Gulf of Mexico, the mid-continent, the Rockies, Canada and Trinidad & Tobago. We have strong positions in the North Sea, the Caspian and North Africa that, together with imports of LNG, give us the opportunity to support Europe's move towards cleaner gas-fired heat and power. We have significant gas sales via pipeline and LNG in Asia.

Our LNG plans remain on track. Our Atlantic basin LNG business is underpinned by our upstream positions in Trinidad & Tobago, Egypt and, in future, Angola. We are bringing this gas to market through investment in downstream regasification and logistics assets. In the US, we have long-term capacity agreements in place at Cove Point, Maryland, for 250 million standard cubic feet per day (mmscfd) and Elba Island, Georgia, for 150mmscfd. We are continuing to seek approval to develop a regasification facility at Crown Landing in New Jersey, where important progress was made in relation to associated shipping, environmental and legal matters. BP also has a long-term contract to supply LNG into the Dominican Republic.

In the UK, we began to supply LNG cargoes to the new Isle of Grain terminal where, with Sonatrach, we have rights to 450mmscfd of capacity. Despite tightness in world LNG supplies, we were able to source cargoes of LNG successfully from Trinidad & Tobago and Algeria in response to increases in UK market prices. In Spain, we are partners (BP 25%) in the 700mmscfd Bilbao regasification plant and 800MW gas-fired power station. BP supplies LNG cargoes into the Pacific Basin, including Japan and Taiwan. We have also started LNG supply into the Gwangyang regasification terminal in South Korea since its start-up in mid-2005. Sales into this terminal will be sourced from Tangguh after its start-up, expected in 2008. It is planned that Tangguh will supply gas into new terminals in Fujian, China, and Baja, Mexico. In 2005, we made good progress in the construction of China's first LNG import facility in Guangdong, where BP is a joint-venture partner. When the facility becomes operational, which is due to be in 2006, gas will be supplied from the NWS partnership (BP 16.7%) in Australia.

We continue to be the largest NGLs marketer in the US. Our capacity utilization was well above plan, despite disruptions to supply following the summer's Gulf of Mexico hurricanes. Full operations at our joint venture NGLs plant in Egypt started in the first quarter of 2005 and the plant reached full gas processing capacity of close to 1.1 billion cubic feet per day in the second half of the year.

BP ALTERNATIVE ENERGY

In 2005, we announced the launch of BP Alternative Energy, a business dedicated to the development and wholesale marketing and trading of low-carbon power. We believe we have sufficient new technologies and sound commercial opportunities within our reach to build a significant and sustainable business in alternative and renewable energy. BP Alternative Energy will manage a first phase of investment of around \$1.8 billion during the next three years, the first part of our aim to invest \$8 billion over 10 years. It is planned to spread this first phase investment in broadly equal proportions between solar, wind, hydrogen and high-efficiency gas-fired power generation. The business will initially employ around 2,500 people. It will bring together the group's existing activities in these technologies with our power marketing and trading capabilities to form a single business. In solar, our sales grew by 6% in 2005 and continued to generate profits. We are committed to doubling our manufacturing capacity of solar cells between 2004 and the end of 2006. In 2005, we successfully completed the Frederick solar plant expansion in Maryland, US. We also signed a joint venture agreement with Xinjiang SunOasis Company, a leading photovoltaic module manufacturer and system supplier in China.

We completed the construction and commissioning of our 9MW Amsterdam wind farm, and have begun feasibility studies at several US sites with a view to building new wind farms five to 10 times the size of our largest existing site. We are also looking for additional opportunities across Europe and Asia.

We finalized all the commercial agreements and commissioned the first unit of K-Power's 1,100MW gas-fired power plant in South Korea, where we have a 35% interest. We successfully started commercial operations at our wholly owned 50MW combined heat and power plant in Hythe, UK, which supplies steam and electricity to local industrial customers. We sold our 100% interest in the Great Yarmouth 400MW gas-fired power station to RWE in November 2005 for \$282 million. At the end of 2005, two new co-generation projects in North America, with capacity totalling over 700MW, were in the early stages of development.

In June 2005, together with our partners, we announced plans for the development of the world's first large project to generate electricity from hydrogen, while reducing carbon dioxide (CO2) emissions and enhancing oil recovery in the North Sea. The hydrogen is to be used at a power station in Peterhead, UK, to generate 350MW of 'clean' electricity and the CO2 reinjected into the offshore Miller field. Work has begun on the front-end engineering design stage, addressing significant technical challenges that we believe we and our partners are well placed to manage. At the same time, we are keeping under constant review the schedule of the project and its commercial viability, which is itself dependent on clarification of the regulatory regime.

A second hydrogen power plant, planned for Carson, California, in the US, is to use petroleum coke as feedstock, demonstrating how lowcarbon energy can be generated from coal, which is plentiful in the US. Once operational, the Carson project is expected to produce 500MW of low-carbon electricity, enough to power about 325,000 homes in southern California. The facility would also capture and permanently store about 4 million tonnes of CO2 a year. BP and our partner, Edison Mission Group, hope to complete detailed engineering and commercial studies for the Carson project in 2006, to finalize project investment decisions in 2008 and to bring the new power plant on line by 2011.

Key indicators

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			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Replacement cost profit before interest and tax (\$ million)	564	1,961	609	964	1,077

Gas, Power and Renewables operations

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Financial statistics

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					\$ million
			IFRS	IFRS	IFRS
	2001	2002	2003	2004	2005
Replacement cost profit before interest and tax by geographical areaa
UK	69	(47)	79	89	70
Rest of Europe	189	1,685	(39)	(30)	(16)
USA	288	5	296	459	777
Rest of World	18	318	273	446	246
	564	1,961	609	964	1,077
aIncludes equity-accounted interest and tax	–	–	2	9	15
Under IFRS, the results of jointly controlled entities and associates for 2003, 2004
and 2005 are included in the income statement net of interest and tax.
Operating capital employed by geographical area
UK	469	438	786	880	241
Rest of Europe	933	386	418	463	542
USA	1,060	1,044	2,130	2,122	2,990
Rest of World	880	1,054	1,427	1,868	1,769
	3,342	2,922	4,761	5,333	5,542
Sales and other operating revenues	22,906	16,490	22,984	26,220	28,700
Capital expenditure and acquisitions by geographical area
UK	102	31	69	166	30
Rest of Europe	156	161	76	19	26
USA	162	170	237	80	96
Rest of World	79	85	143	265	83
	499	447	525	530	235
EMPLOYEE NUMBERS AT YEAR END	4,400	4,600	3,800	4,000	4,100

LNG projects

		Upstream supply					LNG plant
LNG supply		Start-up year	BP % of capacitya	Total plant capacity mscfd	BP plant capacity mmscfd	BP equity gas into plant 2005 mmscfd	BP % equity in the plant	Plant total capacity mtpa	BP equity capacity mtpa	Markets served
Trinidad	Trains 1-4	1999-2006	72	2,659	1,922	1,167	39	15.2		5.9 US, Spain, UK
NWS	Trains 1-4	1989-2004	17	2,150	358	276	17	12.0		2.0 Japan, China
Bontang		1977	n/a	3,622	n/a	139	–	22.2		– Japan, Korea,
										Taiwan
ADGAS	Trains 1-3	1977	–	800	–	–	10	5.6	0.6	Japan, Spain
Total					1,916	1,581		55.0	8.5

aShare of equity ownership and input capacity varies between LNG trains – average percentages shown, weighted by train capacity.

Other businesses and corporate – financial statistics

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					\$ million
	2001	2002	IFRS 2003	IFRS 2004	IFRS 2005
Replacement cost profit before interest and tax by geographical areaa
UK	(472)	(506)	(167)	(217)	(673)
Rest of Europe	27	295	27	(134)	(79)
USA	(573)	(525)	(433)	(782)	(405)
Rest of World	90	(238)	313	1,288	(80)
	(928)	(974)	(260)	155	(1,237)
aIncludes equity-accounted interest and tax	–	–	–	–	–
Under IFRS, the results of jointly controlled entities and associates for 2003, 2004
and 2005 are included in the income statement net of interest and tax.
Operating capital employed by geographical area
UK	2,477	2,357	3,700	6,560	5,187
Rest of Europe	2,058	(1,441)	(2,067)	(1,661)	(4,268)
USA	632	(2,028)	256	(2,306)	(3,953)
Rest of World	4,454	(584)	1,695	290	(137)
	9,621	(1,696)	3,584	2,883	(3,171)
Sales and other operating revenues	12,005	12,548	515	546	668
Capital expenditure and acquisitions by geographical area
UK	500	254	244	403	339
Rest of Europe	909	357	163	1,024	189
USA	300	282	423	698	277
Rest of World	187	117	2	5	12
	1,896	1,010	832	2,130	817
EMPLOYEE NUMBERS AT YEAR END	22,800	18,900	15,800	13,500	4,300

Other businesses and corporate comprises Finance, the group's coal asset (divested in October 2003) and aluminium asset, its investments in PetroChina and Sinopec (both divested in early 2004), interest income and costs relating to corporate activities worldwide.

Other businesses and corporate – Innovene

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BP announced on 7 October 2005 its intention to sell Innovene, its olefins, derivatives and refining group, to INEOS. The transaction became unconditional on 9 December on receipt of European Commission clearance and was completed on 16 December 2005. The transaction included all Innovene's manufacturing sites, markets and technologies. The equity-accounted investments in China and Malaysia that were part of the Olefins and Derivatives business remain with BP and are now included in Refining and Marketing.

Gross proceeds received amounted to \$8,477 million. There were selling costs of \$120 million and initial closing adjustments of \$43 million. The proceeds are subject to final closing adjustments. The remeasurement to fair value less costs to sell resulted in a loss of \$591 million before tax. Financial information for the Innovene operations after group eliminations is presented below.

	2003	2004	2005
Total revenues and other income	8,986	11,327	12,441
Expenses	9,034	12,041	11,709
Profit (loss) before interest and taxation	(48)	(714)	732
Other finance income (expense)	(15)	(17)	3
Profit (loss) before taxation and loss recognized on remeasurement to fair value less costs to sell and on disposal	(63)	(731)	735
Loss recognized on the remeasurement to fair value less costs to sell and on disposal	–	–	(591)
Profit (loss) before taxation from Innovene operations	(63)	(731)	144
Tax (charge) credit
On profit (loss) before loss recognized on remeasurement to fair value less costs to sell and on disposal	–	109	(306)
On loss recognized on the remeasurement to fair value less costs to sell and on disposal	–	–	346
Profit (loss) from Innovene operations	(63)	(622)	184
Earnings (loss) per share from Innovene operations – cents
Basic	(0.28)	(2.85)	0.87
Diluted	(0.28)	(2.79)	0.86
The cash flows of Innovene operations are presented below
Net cash provided by (used in) operating activities	348	(669)	970
Net cash used in investing activities	(572)	(1,731)	(524)
Net cash provided by (used in) financing activities	224	2,400	(446)

Accounting policies

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BASIS OF PREPARATION

This is the first year in which the group has prepared its financial statements under IFRSs and the comparative financial information for 2004 and 2003 has been restated from UK generally accepted accounting practice (UK GAAP) to comply with IFRSs. Financial information for 2002 and 2001 has not been restated. The accounting policies that follow set out those policies that apply in preparing the consolidated financial statements for the year ended 31 December 2005.

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars (\$ million), except where otherwise indicated.

BASIS OF CONSOLIDATION

The group financial statements consolidate the financial statements of BP p.l.c. and the entities it controls (its subsidiaries) drawn up to 31 December each year. Control comprises the power to govern the financial and operating policies of the investee so as to obtain benefit from its activities and is achieved through direct and indirect ownership of voting rights; currently exercisable or convertible potential voting rights; or by way of contractual agreement. Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies.

All inter-company balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated in full. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred.

Minority interests represent the portion of profit or loss and net assets in subsidiaries that is not held by the group and is presented separately within equity in the consolidated balance sheet.

INTERESTS IN JOINT VENTURES

A joint venture is a contractual arrangement whereby two or more parties (venturers) undertake an economic activity that is subject to joint control. Joint control exists only when the strategic financial and operating decisions relating to the activity require the unanimous consent of the venturers. A jointly controlled entity is a joint venture that involves the establishment of a company, partnership or other entity to engage in economic activity that the group jointly controls with its fellow venturers.

The results, assets and liabilities of a jointly controlled entity are incorporated in these financial statements using the equity method of accounting. Under the equity method, the investment in a jointly controlled entity is carried in the balance sheet at cost plus post-acquisition changes in the group's share of net assets of the jointly controlled entity, less distributions received and less any impairment in value of the investment. The group income statement reflects the group's share of the results after tax of the jointly controlled entity. The group statement of recognized income and expense reflects the group's share of any income and expense recognized by the jointly controlled entity outside profit and loss.

Financial statements of jointly controlled entities are prepared for the same reporting year as the group. Where necessary, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group.

Unrealized gains on transactions between the group and its jointly controlled entities are eliminated to the extent of the group's interest in the jointly controlled entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.

The group ceases to use the equity method of accounting on the date from which it no longer has joint control over, or significant influence in, the joint venture, or when the interest becomes held for sale.

Certain of the group's activities, particularly in the Exploration and Production segment, are conducted through joint ventures where the venturers have a direct ownership interest in and jointly control the assets of the venture. The income, expenses, assets and liabilities of these jointly controlled assets are included in the consolidated financial statements in proportion to the group's interest.

INTERESTS IN ASSOCIATES

An associate is an entity over which the group is in a position to exercise significant influence through participation in the financial and operating policy decisions of the investee, but which is not a subsidiary or a jointly controlled entity.

The results, assets and liabilities of an associate are incorporated in these financial statements using the equity method of accounting. Under the equity method, the investment in an associate is carried in the balance sheet at cost plus post-acquisition changes in the group's share of net assets of the associate, less distributions received and less any impairment in value of the investment. The group income statement reflects the group's share of the results after tax of the associate. The group statement of recognized income and expense reflects the group's share of any income and expense recognized by the associate outside profit and loss.

The financial statements of associates are prepared for the same reporting year as the group. Where necessary, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group.

Unrealized gains on transactions between the group and its associates are eliminated to the extent of the group's interest in the associates. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.

The group ceases to use the equity method of accounting on the date from which it no longer has significant influence in the associate or when the interest becomes held for sale.

FOREIGN CURRENCY TRANSLATION

In individual companies, transactions in foreign currencies are initially recorded in the functional currency by applying the rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the rate of exchange ruling at the balance sheet date. Any resulting exchange differences are included in the income statement. Non-monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated into the functional currency using the rates of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated into the functional currency using the rate of exchange at the date the fair value was determined.

In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, jointly controlled entities and associates, including related goodwill, are translated into US dollars at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries, jointly

controlled entities and associates are translated into US dollars using average rates of exchange. Exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, jointly controlled entities and associates are translated into US dollars are taken to a separate component of equity and reported in the statement of recognized income and expense. Exchange gains and losses arising on long-term foreign currency borrowings used to finance the group's non-US dollar investments are also taken to equity. On disposal of a non-US dollar functional currency subsidiary, jointly controlled entity or associate, the deferred cumulative amount recognized in equity relating to that particular non-US dollar operation is recognized in the income statement.

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BUSINESS COMBINATIONS AND GOODWILL

Business combinations are accounted for using the acquisition method of accounting. The cost of an acquisition is measured as the cash paid and the fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to the acquisition. The acquired identifiable assets, liabilities and contingent liabilities are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the net fair value of the identifiable assets acquired is recognized as goodwill. Any deficiency of the cost of acquisition below the fair values of the identifiable net assets acquired (i.e. discount on acquisition) is credited to the income statement in the period of acquisition. Where the group does not acquire 100% ownership of the acquired company, the interest of minority shareholders is stated at the minority's proportion of the fair values of the assets and liabilities recognized. Subsequently, any losses applicable to the minority shareholders in excess of the minority interest are allocated against the interests of the parent.

Goodwill on acquisition is initially measured at cost being the excess of the cost of the business combination over the acquirer's interest in the net fair value of the identifiable assets, liabilities and contingent liabilities. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired.

As at the acquisition date, any goodwill acquired is allocated to each of the cash-generating units expected to benefit from the combination's synergies. For this purpose, cash-generating units are set at one level below a business segment. Impairment is determined by assessing the recoverable amount of the cash-generating unit to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognized.

Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous UK GAAP carrying amount.

Goodwill may also arise upon investments in jointly controlled entities and associates, being the surplus of the cost of investment over the group's share of the net fair value of the identifiable assets. Such goodwill is recorded within investments in jointly controlled entities and associates, and any impairment of the goodwill is included within the income from jointly controlled entities and associates.

NON-CURRENT ASSETS HELD FOR SALE

Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.

Non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

Property, plant and equipment and intangible assets once classified as held for sale are not depreciated.

INTANGIBLE ASSETS

Intangible assets are stated at cost, less accumulated amortization and accumulated impairment losses. Intangible assets include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences, trademarks and product development costs.

Intangible assets acquired separately from a business are carried initially at cost. The initial cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. An intangible asset acquired as part of a business combination is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights and its fair value can be measured reliably.

Product development costs are capitalized as intangible assets when a project has obtained internal sanction and the future recoverability of such costs can reasonably be regarded as assured.

Intangible assets with a finite life are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the lower of the duration of the legal agreement and economic useful life, which can range from three to 15 years. Computer software costs have a useful life of three to five years.

The expected useful lives of the assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

The carrying value of intangible assets is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. In addition, the carrying value of capitalized product development expenditure is reviewed for impairment annually before being brought into use.

OIL AND NATURAL GAS EXPLORATION AND DEVELOPMENT EXPENDITURE

Oil and natural gas exploration and development expenditure is accounted for using the successful efforts method of accounting.

Licence and property acquisition costs Exploration and property leasehold acquisition costs are capitalized within intangible fixed assets and amortized on a straight-line basis over the estimated period of exploration. Each property is reviewed on an annual basis to confirm that drilling activity is planned and it is not impaired. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Upon determination of economically recoverable reserves ('proved reserves' or 'commercial reserves'), amortization ceases and the remaining costs are aggregated with exploration expenditure and held on a field-by-field basis as proved properties awaiting approval within intangible assets. When development is approved internally, the relevant expenditure is transferred to property, plant and equipment.

Exploration expenditure Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons are not found, the exploration expenditure is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, which may include the drilling of further wells (exploration or exploratory-type stratigraphic test wells), are likely to be capable of commercial development, the costs continue to be carried as an asset. All such carried costs are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to property, plant and equipment.

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Development expenditure Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalized within property, plant and equipment.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of any decommissioning obligation, if any, and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment.

Exchanges of assets are measured at the fair value of the asset given up unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes are expensed as incurred. All other maintenance costs are expensed as incurred.

Oil and natural gas properties are depreciated using a unit-ofproduction method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, decommissioning and field development costs are amortized over total proved reserves. The unit-of-production rate for the amortization of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure.

Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.

The useful lives of the group's other property, plant and equipment are as follows:

Land improvements	15 to 25 years
Buildings	20 to 40 years
Refineries	20 to 30 years
Petrochemicals plants	20 years
Pipelines	Unit-of-throughput
	10 to 50 years
Service stations	15 years
Office equipment	3 to 7 years
Fixtures and fittings	5 to 15 years

The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

The carrying value of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.

An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period the item is derecognized.

IMPAIRMENT OF INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT

The group assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If any such indication of impairment exists or when annual impairment testing for an asset group is required, the group makes an estimate of its recoverable amount. An asset group's recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money.

An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in profit or loss. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

FINANCIAL ASSETS

Financial assets are classified as financial assets at fair value through profit or loss; loans and receivables; held-to-maturity investments; or as available-for-sale financial assets, as appropriate. Financial assets include cash and cash equivalents; trade receivables; other receivables; loans; other investments; and derivative financial instruments. The group determines the classification of its financial assets at initial recognition. When financial assets are recognized initially, they are measured at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through profit or loss, directly attributable transaction costs. The group has not restated comparative amounts, on first applying IAS 32 'Financial Instruments: Disclosure and Presentation' and IAS 39 'Financial Instruments: Recognition and Measurement', as permitted in IFRS 1 'First-time Adoption of International Financial Reporting Standards'.

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All regular way purchases and sales of financial assets are recognized on the trade date, being the date that the group commits to purchase or sell the asset. Regular way transactions require delivery of assets within the timeframe generally established by regulation or convention in the marketplace. The subsequent measurement of financial assets depends on their classification, as follows:

Financial assets at fair value through profit or loss Financial assets classified as held for trading and other assets designated as such on inception are included in this category. Financial assets are classified as held for trading if they are acquired for sale in the short term. Derivatives are also classified as held for trading unless they are designated as hedging instruments. Assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement.

Loans and receivables Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market, do not qualify as trading assets and have not been designated as either fair value through profit and loss or available-for-sale. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process.

Held-to-maturity investments Non-derivative financial assets with fixed or determinable payments and fixed maturity are classified as held-tomaturity when the group has the positive intention and ability to hold to maturity. Held-to-maturity investments are carried at amortized cost using the effective interest method. Gains and losses are recognized in income when the investments are derecognized or impaired, as well as through the amortization process. Investments intended to be held for an undefined period are not included in this classification.

Available-for-sale financial assets Available-for-sale financial assets are those non-derivative financial assets that are designated as such or are not classified in any of the three preceding categories. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses being recognized as a separate component of equity until the investment is derecognized or until the investment is determined to be impaired, at which time the cumulative gain or loss previously reported in equity is included in the income statement.

Fair values The fair value of quoted investments is determined by reference to bid prices at the close of business on the balance sheet date. Where there is no active market, fair value is determined using valuation techniques. These include using recent arm's-length market transactions; reference to the current market value of another instrument that is substantially the same; discounted cash flow analysis; and pricing models. Otherwise assets are carried at cost.

IMPAIRMENT OF FINANCIAL ASSETS

The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.

Assets carried at amortized cost If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows discounted at the financial asset's original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in administration costs.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed. Any subsequent reversal of an impairment loss is recognized in the income statement, to the extent that the carrying value of the asset does not exceed its amortized cost at the reversal date.

Assets carried at cost If there is objective evidence that an impairment loss on an unquoted equity instrument that is not carried at fair value because its fair value cannot be reliably measured, or on a derivative asset that is linked to and must be settled by delivery of such an unquoted equity instrument, has been incurred, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows discounted at the current market rate of return for a similar financial asset.

Available-for-sale financial assets If an available-for-sale asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization) and its fair value is transferred from equity to the income statement.

Reversals of impairment losses on debt instruments are taken through the income statement if the increase in fair value of the instrument can be objectively related to an event occurring after the impairment loss was recognized in profit or loss. Reversals in respect of equity instruments classified as available-for-sale are not recognized in the income statement.

INVENTORIES

Inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.

Inventories held for trading purposes are stated at fair value less costs to sell and any changes in net realizable value are recognized in the income statement.

Supplies are valued at cost to the group mainly using the average method or net realizable value, whichever is the lower.

TRADE AND OTHER RECEIVABLES

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Trade and other receivables are carried at the original invoice amount, less allowances made for doubtful receivables. Where the time value of money is material, receivables are carried at amortized cost. Provision is made when there is objective evidence that the group will be unable to recover balances in full. Balances are written off when the probability of recovery is assessed as being remote.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

For the purpose of the group cash flow statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts.

TRADE AND OTHER PAYABLES

Trade and other payables are carried at payment or settlement amounts. Where the time value of money is material, payables are carried at amortized cost.

INTEREST-BEARING LOANS AND BORROWINGS

All loans and borrowings are initially recognized at cost, being the fair value of the proceeds received net of issue costs associated with the borrowing.

After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement.

Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest and other revenues and other finance expense.

LEASES

Finance leases, which transfer to the group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between the finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly against income.

Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.

Operating lease payments are recognized as an expense in the income statement on a straight-line basis over the lease term.

DERECOGNITION OF FINANCIAL ASSETS AND LIABILITIES

Financial assets A financial asset (or, where applicable, a part of a financial asset or part of a group of similar financial assets) is derecognized where:

• ••• The rights to receive cash flows from the asset have expired;
• ••• The group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a 'pass-through' arrangement; or
• ••• The group has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and

rewards of the asset or (b) has neither transferred nor retained substantially all the risks and rewards of the asset but has transferred control of the asset.

Where the group has transferred its rights to receive cash flows from an asset and has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the asset is recognized to the extent of the group's continuing involvement in the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that the group could be required to repay.

Where continuing involvement takes the form of a written and/or purchased option (including a cash-settled option or similar provision) on the transferred asset, the extent of the group's continuing involvement is the amount of the transferred asset that the group may repurchase, except that in the case of a written put option (including a cash-settled option or similar provision) on an asset measured at fair value, the extent of the group's continuing involvement is limited to the lower of the fair value of the transferred asset and the option exercise price.

Financial liabilities A financial liability is derecognized when the obligation under the liability is discharged, cancelled or expires. Where an existing financial liability is replaced by another from the same lender on substantially different terms or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, such that the difference in the respective carrying amounts, together with any costs or fees incurred are recognized in profit or loss.

DERIVATIVE FINANCIAL INSTRUMENTS

The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices. From 1 January 2005, such derivative financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.

Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments, as if the contracts were financial instruments, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group's expected purchase, sale or usage requirements, are financial instruments.

For those derivatives designated as hedges and for which hedge accounting is desired, the hedging relationship is documented at its inception. This documentation identifies the hedging instrument, the hedged item or transaction, the nature of the risk being hedged and how effectiveness will be measured throughout its duration. Such hedges are expected at inception to be highly effective.

For the purpose of hedge accounting, hedges are classified as:

• ••• Fair value hedges when hedging the exposure to changes in the fair value of a recognized asset or liability;
• ••• Cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognized asset or liability or a highly probable forecast transaction, including intra-group transactions; or
• ••• Hedges of the net investment in a foreign entity.

Any gains or losses arising from changes in the fair value of all other derivatives, which are classified as held for trading, are taken to the income statement. These may arise from derivatives for which hedge accounting is not applied because they are either not designated or not effective as hedging instruments or from derivatives that are acquired for trading purposes.

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The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows:

Fair value hedges For fair value hedges, the carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged; the derivative is remeasured at fair value and gains and losses from both are taken to profit or loss. For hedged items carried at amortized cost, the adjustment is amortized through the income statement such that it is fully amortized by maturity. When an unrecognized firm commitment is designated as a hedged item, this gives rise to an asset or liability in the balance sheet, representing the cumulative change in the fair value of the firm commitment attributable to the hedged risk.

The group discontinues fair value hedge accounting if the hedging instrument expires or is sold, terminated or exercised, the hedge no longer meets the criteria for hedge accounting or the group revokes the designation.

Cash flow hedges For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognized directly in equity, while the ineffective portion is recognized in profit or loss. Amounts taken to equity are transferred to the income statement when the hedged transaction affects profit or loss, such as when a forecast sale or purchase occurs. Where the hedged item is the cost of a non-financial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-financial asset or liability.

If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, the hedged transaction ceases to be highly probable, or if its designation as a hedge is revoked, amounts previously recognized in equity remain in equity until the forecast transaction occurs and are transferred to the income statement or to the initial carrying amount of a non-financial asset or liability as above. If a forecast transaction is no longer expected to occur, amounts previously recognized in equity are transferred to profit or loss.

Hedges of the net investment in a foreign entity For hedges of the net investment in a foreign entity, the effective portion of the gain or loss on the hedging instrument is recognized directly in equity, while the ineffective portion is recognized in profit or loss.

Amounts taken to equity are transferred to the income statement when the foreign entity is sold.

Embedded derivatives Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of host contracts and the host contracts are not carried at fair value. Contracts are assessed for embedded derivatives when the group becomes a party to them, including at the date of a business combination. These embedded derivatives are measured at fair value at each period end. Any gains or losses arising from changes in fair value are taken directly to net profit or loss for the period.

PROVISIONS

Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the group expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a separate asset, but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as other finance expense. Any change in the amount recognized for environmental and litigation and other provisions arising through changes in discount rates is included within other finance expense.

A contingent liability is disclosed where the existence of an obligation will only be confirmed by future events or where the amount of the obligation cannot be measured with reasonable reliability. Contingent assets are not recognized, but are disclosed where an inflow of economic benefits is probable.

ENVIRONMENTAL LIABILITIES

Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future earnings are expensed.

Liabilities for environmental costs are recognized when environmental assessments or clean-ups are probable and the associated costs can be reasonably estimated. Generally, the timing of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure.

DECOMMISSIONING

Liabilities for decommissioning costs are recognized when the group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. Where an obligation exists for a new facility, such as oil and natural gas production or transportation facilities, this will be on construction or installation. An obligation for decommissioning may also crystallize during the period of operation of a facility through a change in legislation or through a decision to terminate operations. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements.

A corresponding item of property, plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the facility or item of plant.

Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment.

EMPLOYEE BENEFITS

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the period end are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policy for pensions and other post-retirement benefits is described below.

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SHARE-BASED PAYMENTS

Equity-settled transactions The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions).

No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are treated as vesting irrespective of whether or not the market condition is satisfied, provided that all other performance conditions are satisfied.

At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired and management's best estimate of the achievement or otherwise of non-market conditions and the number of equity instruments that will ultimately vest or, in the case of an instrument subject to a market condition, be treated as vesting as described above. The movement in cumulative expense since the previous balance sheet date is recognized in the income statement, with a corresponding entry in equity.

Where the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognized over the original vesting period. In addition, an expense is recognized over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation and any cost not yet recognized in the income statement for the award is expensed immediately. Any compensation paid up to the fair value of the award at the cancellation or settlement date is deducted from equity, with any excess over fair value being treated as an expense in the income statement.

Cash-settled transactions The cost of cash-settled transactions is measured at fair value using an appropriate option valuation model.

Fair value is established initially at the grant date and at each balance sheet date thereafter until the awards are settled. During the vesting period, a liability is recognized representing the product of the fair value of the award and the portion of the vesting period expired as at the balance sheet date. From the end of the vesting period until settlement, the liability represents the full fair value of the award as at the balance sheet date. Changes in the carrying amount for the liability are recognized in profit or loss for the period.

PENSIONS AND OTHER POST-RETIREMENT BENEFITS

The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit method, which attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present value of defined benefit obligation) and is based on actuarial advice. Past service costs are recognized in profit or loss on a straight-line basis over the vesting period or immediately if the benefits have vested. When a settlement (eliminating all obligations for benefits already accrued) or a curtailment (reducing future obligations as a result of a material reduction in the scheme membership or a reduction in future entitlement) occurs, the obligation and related plan assets are remeasured using current actuarial assumptions and the resultant gain or loss recognized in the income statement during the period in which the settlement or curtailment occurs.

The interest element of the defined benefit cost represents the change in present value of scheme obligations resulting from the passage of time, and is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation during the year. The expected return on plan assets is based on an assessment made at the beginning of the year of long-term market returns on scheme assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The difference between the expected return on plan assets and the interest cost is recognized in the income statement as other finance income or expense.

Actuarial gains and losses are recognized in full in the group statement of recognized income and expense in the period in which they occur.

The defined benefit pension asset or liability in the balance sheet comprises the total for each plan of the present value of the defined benefit obligation (using a discount rate based on high-quality corporate bonds), less any past service cost not yet recognized and less the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. The value of a net pension benefit asset is restricted to the sum of any unrecognized past service costs and the present value of any amount the group expects to recover by way of refunds from the plan or reductions in the future contributions.

Contributions to defined contribution schemes are recognized in the income statement in the period in which they become payable.

CORPORATE TAXES

Tax expense represents the sum of the tax currently payable and deferred tax.

The tax currently payable is based on the taxable profits for the period. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred tax liabilities are recognized for all taxable temporary differences:

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• ••• Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and
• ••• In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the timing of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax assets and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax assets and unused tax losses can be utilized:

• ••• Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and
• ••• In respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date.

Tax relating to items recognized directly in equity is recognized in equity and not in the income statement.

CUSTOMS DUTIES AND SALES TAXES

Revenues, expenses and assets are recognized net of the amount of customs duties or sales tax except:

• ••• Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the customs duty or sales tax is recognized as part of the cost of acquisition of the asset or as part of the expense item as applicable; and
• ••• Receivables and payables are stated with the amount of customs duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the balance sheet.

OWN EQUITY INSTRUMENTS

The group's holding in its own equity instruments, including shares held by Employee Share Ownership Plans, are classified as 'treasury shares', and shown as deductions from shareholders' equity at cost. Consideration received for the sale of such shares is also recognized in equity, with any difference between the proceeds from sale and the original cost being taken to revenue reserves. No gain or loss is recognized in the performance statements on the purchase, sale, issue or cancellation of equity shares.

REVENUE

Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer and it can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes.

Revenues associated with the sale of oil, natural gas liquids, liquefied natural gas, petroleum and chemicals products and all other items are recognized when the title passes to the customer. Supply buy/sell arrangements with common counterparties are reported net as are physical exchanges. Similarly, oil and natural gas forward sales/purchase contracts and sales/purchases of trading inventory are included on a net basis in sales and other operating revenues. Generally, revenues from the production of oil and natural gas properties in which the group has an interest with other producers are recognized on the basis of the group's working interest in those properties (the entitlement method). Differences between the production sold and the group's share of production are not significant.

Interest income is recognized as the interest accrues (using the effective interest rate method that is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument) to the net carrying amount of the financial asset.

Dividend income from investments is recognized when the shareholders' right to receive the payment is established.

RESEARCH

Research costs are expensed as incurred.

FINANCE COSTS

Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use.

All other finance costs are recognized in the income statement in the period in which they are incurred.

USE OF ESTIMATES

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from those estimates.

Definitions

DEBT TO DEBT-PLUS-EQUITY RATIO

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The ratio of finance debt (borrowings plus obligations under finance leases) to the total of finance debt plus shareholders' interest.

DEBT TO EQUITY RATIO

The ratio of finance debt (borrowings plus obligations under finance leases) to shareholders' interest.

DIVIDEND COVER

The dividend cover out of income is calculated as the replacement cost profit for the period, divided by the dividend paid in the period.

The dividend cover out of cash is calculated as the net cash provided by operating activities divided by the gross dividends paid. The calculation is based on the assumption that all dividends are paid in cash.

DIVIDEND PAYOUT RATIO

The ratio of dividend paid for the period to replacement cost profit, expressed as a percentage.

EARNINGS PER SHARE

The profit in cents attributable to each equity share, based on the appropriate consolidated profit of the period after tax and after deducting minority interests and preference dividends, divided by the weighted average number of equity shares in issue during the period.

EFFECTIVE TAX RATE

The ratio of the tax charge to the profit after interest expense but before tax.

NET DEBT

Net debt equals finance debt less cash and cash equivalents.

PRE-TAX CASH RETURNS

The ratio of replacement cost profit before interest and tax and excluding equity-accounted interest and tax, non-operating items and depreciation, depletion and amortization to the average operating capital employed (which excludes goodwill).

RETURN ON AVERAGE CAPITAL EMPLOYED (ROACE)

The ratio of replacement cost profit before interest expense and minority interest but after tax to the average of opening and closing capital employed.

Capital employed is BP shareholders' interest plus finance debt and minority interest.

A further ROACE measure is presented based on average capital employed after deducting goodwill from the denominator in the calculation and excluding non-operating items from the numerator.

US GAAP

Represents the net profit prepared under US generally accepted accounting principles (GAAP).

Further information

Although this publication of financial and operating information is unaudited, much of the information it contains is derived from the BP group's audited accounts.

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Enquiries about the contents of this document should be addressed to:

UK

Investor Relations BP p.l.c. 1 St James's Square, London SW1Y 4PD Telephone: +44 (0)20 7496 4632 Fax: +44 (0)20 7496 4570 ir@bp.com

US

Investor Relations BP p.l.c. 535 Madison Avenue – 22nd Floor New York, NY 10022 Telephone: +1 212 451 8136 Fax: +1 212 451 8089 ir@bp.com

Internet

Spreadsheets containing the data in this document can be downloaded from our website at www.bp.com/financialandoperating.

BP news via e-mail

To receive the latest news and information about BP via e-mail, register at www.bp.com/email.

These and other BP publications may be obtained, free of charge, from the following sources:

US and Canada

BP Shareholder Services Toll-free: +1 800 638 5672 Fax: +1 630 821 3456 shareholderus@bp.com

UK and Rest of World

BP Distribution Services Telephone: +44 (0)870 241 3269 Fax: +44 (0)870 240 5753 bpdistributionservices@bp.com

ACKNOWLEDGEMENTS

Design VSA Partners, Chicago Typesetting Pauffley, London Printing St Ives Financial, UK Photography Tom Nagy

© BP p.l.c. 2006

1 www.bp.com/annualreport

BP Annual Report and Accounts 2005 gives details of our financial and operating performance.

2 www.bp.com/annualreview

BP Annual Review 2005 summarizes our financial and operating performance.

3 www.bp.com/sustainabilityreport BP Sustainability Report 2005 explains our environmental and social commitments and performance.

4 www.bp.com/statisticalreview BP Statistical Review of World Energy, published in June each year, reports on key global energy trends.

Paper This document is printed on FSC-certified Mohawk Options 100% PC White, which is manufactured entirely with wind energy and contains 100% post-consumer recycled fibre. This paper is certified by SmartWood for FSC standards.

2 BP history at a glance 4 Financial performance 30 Exploration and Production 64 Refining and Marketing 74 Gas, Power and Renewables 81 Other businesses and corporate

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INTERACTIVE RESOURCES Visit www.bp.com/investortools to chart our key financial and operating information for the past five years, on an annual or quarterly basis, for the BP group

BP p.l.c. is the parent company of the BP group of companies.

BP is a leader in our industry and that position is reflected in our standards of social responsibility, corporate governance and financial and sustainability reporting, of which this document is part. For a complete view of BP's performance, it should be read in conjunction with BP Annual Report and Accounts 2005, BP Annual Report on Form 20-F 2005 and BP Sustainability Report 2005. Copies may be obtained free

economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; exchange rate fluctuations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors; natural disasters and adverse weather conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this report, such as 'reserves', that the SEC's guidelines strictly prohibit us from including in our filings with the SEC. US investors are urged to consider closely the disclosure in our Form 20-F, SEC File No. 1-6262, available from us at 1 St James's Square, London SW1Y 4PD.

document and in BP Annual Report and Accounts 2005.

You can also obtain this form from the SEC by calling 1-800-SEC-0330.

Cautionary note to US investors

Unless otherwise stated, the text does not distinguish between the activities and operations of the parent company

as a whole or by business segment.

and those of its subsidiaries.

of charge (see page 92).

83 Accounting policies

92 Further information

91 Definitions

Cautionary statement

BP Financial and Operating Information 2001-2005 contains certain forward-looking statements, particularly those regarding capital expenditure; first tanker lifting from Ceyhan; start-up of the Shah Deniz field; completion of the associated South Caucasus pipeline; the progress and timing of projects including Greater Plutonio and In Amenas; the start of production from Thunder Horse and Atlantis; the potential of the Sakhalin region; the effect of the extension of two concessions in the Gulf of Suez; growth in gas demand in the Asia Pacific region; the commencement of exports from the North West Shelf venture; production from the Texas City refinery; the extension of the Castrol Edge range; the planned operation of an acetic acid plant at Nanjing; the start-up of and sales from Tangguh; planned investments in BP Alternative Energy; and the expected production from planned generation at Peterhead and Carson. By their nature, forward-looking statements involve risks and uncertainties 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 on stream; future levels of industry product supply; demand and pricing; operational problems; general

beyond petroleum®

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Making energy more BP Financial and Operating Information 2001-2005

Making energy more

Financial and Operating Information 2001-2005