BP p.l.c. 20F 2005 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F


(Mark One)
[ ]		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
		OR
[ü]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2005
		OR
[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		OR
[ ]		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-6262

BP p.l.c.

(Exact name of Registrant as specified in its charter)

ENGLAND and WALES

(Jurisdiction of incorporation or organization)

1 St James’s Square

London

SW1Y 4PD

United Kingdom

(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act.


Title of each class		Name of each exchange on which registered
Ordinary Shares of 25c each		New York Stock Exchange* Chicago Stock Exchange* NYSE Arca*

		*Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.


Ordinary Shares of 25c each		20,657,044,719
Cumulative First Preference Shares of £1 each		7,232,838
Cumulative Second Preference Shares of £1 each		5,473,414

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Yes [ü]	No [ ]

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934.


Yes [ ]	No [ü]

Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Yes [ü]	No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer [ü] Accelerated filer [ ] Non-accelerated filer [ ]

Indicate by check mark which financial statement item the Registrant has elected to follow.


Item 17 [ ]	Item 18 [ü]

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Yes [ ]	No [ü]

TABLE OF CONTENTS


			Page
		Certain Definitions		4
Part I	Item 1	Identity of Directors, Senior Management and Advisors		6
	Item 2	Offer Statistics and Expected Timetable		6
	Item 3	Key Information		6
		Selected Financial Information		6
		Risk Factors		10
		Forward Looking Statements		12
		Statements Regarding Competitive Position		12
	Item 4	Information on the Company		13
		General		13
		Segmental Information		19
		Exploration and Production		22
		Refining and Marketing		44
		Gas, Power and Renewables		59
		Other Businesses and Corporate		66
		Regulation of the Group’s Business		67
		Environmental Protection		68
		Property, Plants and Equipment		76
		Organizational Structure		77
	Item 4A	Unresolved Staff Comments		78
	Item 5	Operating and Financial Review		79
		Group Operating Results		79
		Liquidity and Capital Resources		93
		Outlook		99
		Critical Accounting Policies and New Accounting Standards		100
	Item 6	Directors, Senior Management and Employees		112
		Directors and Senior Management		112
		Compensation		115
		Board Practices		132
		Employees		144
		Share Ownership		145
	Item 7	Major Shareholders and Related Party Transactions		148
		Major Shareholders		148
		Related Party Transactions		148
	Item 8	Financial Information		148
		Consolidated Statements and Other Financial Information		148
		Significant Changes		150
	Item 9	The Offer and Listing		151


			Page
	Item 10	Additional Information		154
		Memorandum and Articles of Association		154
		Material Contracts		157
		Exchange Controls and Other Limitations Affecting Security Holders		157
		Taxation		158
		Documents on Display		161
	Item 11	Quantitative and Qualitative Disclosures about Market Risk		162
	Item 12	Description of Securities Other Than Equity Securities		172
Part II	Item 13	Defaults, Dividend Arrearages and Delinquencies		173
	Item 14	Material Modifications to the Rights of Security Holders and Use of Proceeds		173
	Item 15	Controls and Procedures		173
	Item 16A	Audit Committee Financial Expert		174
	Item 16B	Code of Ethics		174
	Item 16C	Principal Accountant Fees and Services		174
	Item 16D	Exemptions from the Listing Standards for Audit Committees		176
	Item 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		176
Part III	Item 17	Financial Statements		178
	Item 18	Financial Statements		178
	Item 19	Exhibits		178
Exhibit 4.3
Exhibit 4.4
Exhibit 7
Exhibit 8
Exhibit 12
Exhibit 13

CERTAIN DEFINITIONS

Unless the context indicates otherwise, the following terms have the meanings shown below:

Oil and natural gas reserves

‘Proved oil and gas reserves’ — Proved reserves are defined by the Securities and Exchange Commission (SEC) in Rule 4-10(a) of Regulation S-X, paragraphs (2), (2i), (2ii) and (2iii). Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.


	(i)	Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

	(ii)	Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved’ classification when successful testing by a pilot project, or the operation of an installed programme in the reservoir, provides support for the engineering analysis on which the project or programme was based.

	(iii)	Estimates of proved reserves do not include the following:


	(a)	oil that may become available from known reservoirs but is classified separately as ‘indicated additional reserves’;


	(b)	crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;


	(c)	crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and


	(d)	crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

‘Proved developed reserves’ — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as ‘proved developed reserves’ only after testing by a pilot project or after the operation of an installed programme has confirmed through production response that increased recovery will be achieved.

‘Proved undeveloped reserves’ — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates of proved undeveloped reserves attributable to acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Miscellaneous terms

‘ADR’ — American Depositary Receipt.

‘ADS’ — American Depositary Share.

‘Amoco’ — The former Amoco Corporation and its subsidiaries.

‘Atlantic Richfield’ — Atlantic Richfield Company and its subsidiaries.

‘Associate’ — An undertaking in which the BP Group has a participating interest and over whose operating and financial policy the BP Group exercises a significant influence (presumed to be the case where 20% or more of the voting rights are held) and which is not a subsidiary.

‘Barrel’ — 42 US gallons.

‘BP’, ‘BP Group’ or the ‘Group’ — BP p.l.c. and its subsidiaries.

‘Burmah Castrol’ — Burmah Castrol plc and its subsidiaries.

‘Cent’ or ‘c’ — One hundredth of the US dollar.

The ‘Company’ — BP p.l.c.

‘Dollar’ or ‘$’ — The US dollar.

‘EU’ — European Union

‘Gas’ — Natural Gas.

‘Hydrocarbons’ — Crude oil and natural gas.

‘IFRS’ — International Financial Reporting Standards as adopted by the EU.

‘Joint venture’ or ‘JV’ — an entity in which the Group has a long-term interest and shares control with one or more co-venturers.

‘Liquids’ — Crude oil, condensate and natural gas liquids.

‘LNG’ — Liquefied Natural Gas.

‘London Stock Exchange’ or ‘LSE’ — London Stock Exchange Limited.

‘LPG’ — Liquefied Petroleum Gas.

‘mmbtu’ — million British thermal units.

‘MTBE’ — Methyl Tertiary Butyl Ether.

‘NGL’ — Natural Gas Liquid.

‘OECD’ — Organization for Economic Cooperation and Development.

‘OPEC’ — The Organization of Petroleum Exporting Countries.

‘Ordinary shares’ — Ordinary fully paid shares in BP p.l.c. of 25c each.

‘Pence’ or ‘p’ — One hundredth of a pound sterling.

‘Pound’, ‘sterling’ or ‘£’ — The pound sterling.

‘Preference Shares’ — Cumulative First Preference Shares and Cumulative Second Preference Shares in BP p.l.c. of £1 each.

‘Subsidiary’ — An undertaking in which the BP Group holds a majority of the voting rights.

‘Tonne’ — 2,204.6 pounds.

‘UK’ — United Kingdom of Great Britain and Northern Ireland.

‘Undertaking’ — A body corporate, partnership or an unincorporated association, carrying on a trade or business.

‘US’ or ‘USA’ — United States of America.

‘US GAAP’ — Generally Accepted Accounting Principles in the USA.

PART I

ITEM 1 — IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Not applicable.

ITEM 2 — OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3 — KEY INFORMATION

SELECTED FINANCIAL INFORMATION

Summary

This information has been extracted or derived from the audited financial statements of the BP Group presented elsewhere herein or otherwise included with BP p.l.c.’s Annual Reports on Form 20-F for the relevant years which have been filed with the Securities and Exchange Commission, as reclassified to conform with the accounting presentation adopted in this annual report.

For all periods up to and including the year ended December 31, 2004, BP prepared its financial statements in accordance with UK generally accepted accounting practice (UK GAAP). BP, together with all other European Union (EU) companies listed on an EU stock exchange, was required to prepare consolidated financial statements in accordance with International Financial Reporting Standards as adopted by the EU with effect from January 1, 2005. The Annual Report and Accounts for the year ended December 31, 2005 are BP’s first consolidated financial statements prepared under IFRS. In preparing these financial statements, the Group has complied with all International Financial Reporting Standards applicable for periods beginning on or after January 1, 2005. In addition, BP has also decided to adopt early IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’, the amendment to IAS 19 ‘Amendment to International Accounting Standard IAS 19 Employee Benefits: Actuarial Gains and Losses, Group Plans and Disclosures’, the amendment to IAS 39 ‘Amendment to International Accounting Standard IAS 39 Financial Instruments: Recognition and Measurement: Cash Flow Hedge Accounting of Forecast Intragroup Transactions’ and IFRIC 4 ‘Determining whether an Arrangement contains a Lease’. The EU has adopted all standards and interpretations adopted by BP for its 2005 reporting.

The financial information for 2004 and 2003 has been restated to reflect the following, all with effect from January 1, 2005: (a) the adoption by the Group of IFRS (see Item 18 — Financial Statements — Note 3 on page F-30 and Note 52 on page F-145); (b) the transfer of the Mardi Gras pipeline system from Exploration and Production to Refining and Marketing; (c) the transfer of the aromatics and acetyls operations and the petrochemicals assets that are integrated with our Gelsenkirchen refinery in Germany from the former Petrochemicals segment to Refining and Marketing; (d) the transfer of the olefins and derivatives operations from the former Petrochemicals segment to the Olefins and Derivatives business (the legacy historical results of other petrochemicals assets that had been divested during 2004 and 2003 are included within Other businesses and corporate); (e) the transfer of the Grangemouth and Lavera refineries from Refining and Marketing to the Olefins and Derivatives business; and (f) the transfer of the Hobbs fractionator from Gas, Power and Renewables to the Olefins and Derivatives business. The Olefins and Derivatives business is reported within Other businesses and corporate. This reorganization was a precursor to seeking to divest the Olefins and Derivatives business. As indicated in Item 18 — Financial Statements — Note 5 on page F-35, we divested Innovene on December 16, 2005. Innovene represented the majority of the Olefins and Derivatives business. Innovene operations have been treated as discontinued operations in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. Item 18 — Financial Statements — Note 5 on page F-35 provides further detail. Under US GAAP, Innovene operations would

not be classified as discontinued operations due to BP’s continuing customer/ supplier arrangements with Innovene.

In the circumstances of discontinued operations, IFRS require that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations, and attributed to the continuing operations and vice versa. This adjustment has two offsetting elements: the net margin on crude refined by Innovene as substantially all crude for their refineries is supplied by BP and most of the refined products manufactured are taken by BP; and the margin on sales of feedstock from BP’s US refineries to Innovene manufacturing plants. The profits attributable to individual segments are not affected by this adjustment. Neither does this representation indicate the profits earned by continuing or Innovene operations, as if they were stand-alone entities, for past periods or likely to be earned in future periods.


		Year ended December 31,

		2005			2004			2003

		($ million except per share amounts)
IFRS
Income statement data
Sales and other operating revenues from continuing operations (a)			239,792			192,024			164,653
Profit before interest and taxation for continuing operations (a)			32,182			25,746			18,776
Profit from continuing operations (a)			22,133			17,884			12,681
Profit for the year			22,317			17,262			12,618
Profit for the year attributable to BP shareholders			22,026			17,075			12,448
Per ordinary share: (cents)
	Profit for the year attributable to BP shareholders:
	Basic		104.25			78.24			56.14
	Diluted		103.05			76.87			55.61
	Profit from continuing operations attributable to BP shareholders:
	Basic		103.38			81.09			56.42
	Diluted		102.19			79.66			55.89
	Dividends per share (cents)		34.85			27.70			25.50
	Dividends per share (pence)		19.152			15.251			15.658
Ordinary Share data(b)
Average number outstanding of 25 cents ordinary shares (shares million undiluted)			21,126			21,821			22,171
Average number outstanding of 25 cents ordinary shares (shares million diluted)			21,411			22,293			22,424
Balance sheet data
Total assets			206,914			194,630			172,491
Net assets			80,450			78,235			70,264
Share capital			5,185			5,403			5,552
BP shareholders’ equity			79,661			76,892			69,139
Finance debt due after more than one year			10,230			12,907			12,869
Debt to borrowed and invested capital (c)			11	%		14	%		15	%

Selected historical financial data is based on financial statements prepared in accordance with IFRS and accordingly is shown for the three years subsequent to the date of transition to IFRS.


		Year ended December 31,

		2005		2004		2003		2002		2001

		($ million except per share amounts)
US GAAP
Income statement data
Revenues			252,168		203,303		173,615		145,991		145,902
Profit for the year attributable to BP shareholders (d)			19,642		17,090		12,941		8,109		4,467
Comprehensive income			17,053		17,371		19,689		10,256		2,952
Profit per ordinary share: (cents)
	Basic		92.96		78.31		58.36		36.20		19.90
	Diluted		91.91		76.88		57.79		36.02		19.78
Profit per American Depositary Share: (cents)
	Basic		557.76		469.86		350.16		217.20		119.40
	Diluted		551.46		461.28		346.74		216.12		118.68
Balance sheet data
Total assets			213,722		206,139		186,576		164,103		145,990
Net assets			85,936		86,435		80,292		67,274		62,786
BP shareholders’ equity			85,147		85,092		79,167		66,636		62,188


(a)		Excludes Innovene which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. See Item 18 — Financial Statements — Note 5 on page F-35. Under US GAAP, Innovene is not treated as a discontinued operation.

(b)		The number of ordinary shares shown have been used to calculate per share amounts for both IFRS and US GAAP.

(c)		Finance debt due after more than one year, as a percentage of such debt plus BP and minority shareholders’ equity.

(d)		Under US GAAP, Innovene is not treated as a discontinued operation. See Item 18 — Financial Statements — Note 55 on page F-191. As such, the results of Innovene are included within the profit for the year, as adjusted to accord with US GAAP.

Dividends

BP has paid dividends on its ordinary shares in each year since 1917. In 2000 and thereafter, dividends were, and are expected to continue to be, paid quarterly in March, June, September and December. Until their shares have been exchanged for BP ADSs, Amoco and Atlantic Richfield shareholders do not have the right to receive dividends.

BP currently announces dividends for ordinary shares in US dollars and states an equivalent pounds sterling dividend. Dividends on BP ordinary shares will be paid in pounds sterling and on BP ADSs in US dollars. The rate of exchange used to determine the sterling amount equivalent is the average of the forward exchange rate in London over the five business days prior to the announcement date. The directors may choose to declare dividends in any currency provided that a sterling equivalent is announced, but it is not the Company’s intention to change its current policy of announcing dividends on ordinary shares in US dollars.

The following table shows dividends announced and paid by the Company per ADS for each of the past five years before the ‘refund’ and deduction of withholding taxes as described in Item 10 — Additional Information — Taxation on page 158. Refund means an amount equal to the tax credit available to individual shareholders resident in the UK in respect of such dividend, less a withholding tax equal to 15% (but limited to the amount of the tax credit) of the aggregate of such tax credit and such dividend.

For dividends paid after April 30, 2004, there is no refund available to shareholders resident in the US. Refer to Item 10 — Additional Information — Taxation for more information.


		March		June		September		December		Total

Dividends per American Depositary Share
2001	UK pence		21.7		22.0		23.5		22.8		90.0
	US cents		31.5		31.5		33.0		33.0		129.0
	Can. cents		47.9		48.3		50.4		52.6		199.2
2002	UK pence		24.3		24.3		23.3		23.4		95.3
	US cents		34.5		34.5		36.0		36.0		141.0
	Can. cents		54.9		54.1		56.7		56.1		221.8
2003	UK pence		22.9		23.7		24.2		23.1		93.9
	US cents		37.5		37.5		39.0		39.0		153.0
	Can. cents		57.4		54.3		54.0		51.1		216.8
2004	UK pence		22.0		22.8		23.2		23.5		91.5
	US cents		40.5		40.5		42.6		42.6		166.2
	Can. cents		53.7		54.8		56.7		52.2		217.4
2005	UK pence		27.1		26.7		30.7		30.4		114.9
	US cents		51.0		51.0		53.55		53.55		209.1
	Can. cents		64.0		63.2		65.3		63.7		256.2

A dividend reinvestment plan is in place whereby holders of BP ordinary shares can elect to reinvest the net cash dividend in shares purchased on the London Stock Exchange. This plan is not available to any person resident in the USA or Canada, or in any jurisdiction outside the UK where such an offer requires compliance by the Company with any governmental or regulatory procedures or any similar formalities. A dividend reinvestment plan is, however, available for holders of ADSs through JPMorgan Chase Bank.

Future dividends will be dependent upon future earnings, the financial condition of the Group, the Risk Factors set out below, and other matters which may affect the business of the Group set out in Item 5 — Operating and Financial Review on page 79.

RISK FACTORS

We urge you to carefully consider the risks described below. If any of these risks actually occur, our business, financial condition and results of operations could suffer, and the trading price and liquidity of our securities could decline, in which case you may lose all or part of your investment.

Delivery Risks

Delivery risks are those specific to implementing activities contained in our Group plan. Successful execution of this plan depends critically on implementing the set of activities described. Hence, our delivery risks are those factors that would result in our failure to deliver these activities economically. The most significant risks include:

Upstream renewal:Inability to renew the portfolio and sustain long-term reserves replacement. The challenge is growing due to increasing competition for access to opportunities globally.

Major project delivery: Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value.

Portfolio repositioning: Inability to complete planned disposals and/or lack of material positions in new markets (and hence the inability to capture above-average market growth).

Inherent Risks

There are a number of risks that arise as a result of the business climate, which are not directly controllable.

Competition Risk: The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency.

Price Risk: Oil, gas and product prices are subject to international supply and demand. Political developments (especially in the Middle East) and the outcome of meetings of OPEC can particularly affect world supply and oil prices. In addition to the adverse effect on revenues, margins and profitability from any future fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to a review for impairment of the Group’s oil and natural gas properties. This review would reflect management’s view of long-term oil and natural gas prices. Such a review could result in a charge for impairment that could have a significant effect on the Group’s results of operations in the period in which it occurs.

Regulatory Risk: The oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, causing our production to decrease, or we could incur additional costs.

Developing Country Risk: We have operations in developing countries where political, economic and social transition is taking place. Some countries have experienced political instability, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development

activities to be curtailed or terminated in these areas or our production to decline and could cause us to incur additional costs.

Currency Risk: Crude oil prices are generally set in US dollars while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs.

Economic Risk — Refining and Petrochemicals Market: Refining profitability can be volatile, with both periodic oversupply and supply tightness in various regional markets. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the petrochemicals market, with consequent effect on prices and profitability.

Enduring Risks

We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. This may create risks to our reputation if it is perceived that our actions are not aligned to these standards and aspirations.

Social Responsibility Risk: Risk could arise if it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate.

Environmental Risk: We seek to conduct our activities in such a manner that there is no or minimal damage to the environment. Risk could arise if we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment.

Compliance Risk: Incidents of non-compliance with applicable laws and regulation or ethical misconduct could be damaging to our reputation and shareholder value.

Inherent in our operations are hazards that require continual oversight and control. If operational risks materialized, loss of life, damage to the environment or loss of production could result.

Drilling and Production Risk: Exploration and production require high levels of investment and have particular economic risks and opportunities and may often involve innovative technologies. They are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements.

Technical Integrity Risk: There is a risk of loss of containment of hydrocarbons and other hazardous material at operating sites, pipelines or during transportation by road, rail or sea.

Security Risk: Acts of terrorism that threaten our plants and offices, pipelines, transportation or computer systems would severely disrupt business and operations.

FORWARD LOOKING STATEMENTS

In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘should’, ‘may’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Item 4 — Information on the Company and Item 5 — Operating and Financial Review with regard to management aims and objectives, future capital expenditure, future hydrocarbon production volume, date or period(s) in which production is scheduled or expected to come on stream or a project or action is scheduled or expected to be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Item 4 — Information on the Company with regard to planned expansion, investment or other projects and future regulatory actions; and (iii) the statements in Item 5 — Operating and Financial Review with regard to the plans of the Group, cash flows, opportunities for material acquisitions, the cost of future remediation programmes, liquidity and costs for providing pension and other postretirement benefits; and including under ‘Liquidity and Capital Resources’ with regard to future cash flows, future levels of capital expenditure and divestments, working capital, future production volumes, the renewal of borrowing facilities, shareholder distributions and share buybacks and expected payments under contractual and commercial commitments; under ‘Outlook’ with regard to global and certain regional economies, oil and gas prices and realizations, expectations for supply and demand, refining and marketing margins; are all forward-looking in nature.

By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; 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; the success or otherwise of partnering; the actions of competitors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk Factors’ above. In addition to factors set forth elsewhere in this report, the factors set forth above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

STATEMENTS REGARDING COMPETITIVE POSITION

Statements made in Item 4 — Information on the Company, referring to BP’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

ITEM 4 — INFORMATION ON THE COMPANY

GENERAL

Unless otherwise indicated, information in this Item reflects 100% of the assets and operations of the Company and its subsidiaries which were consolidated at the date or for the periods indicated, including minority interests. Also, unless otherwise indicated, figures for business sales and other operating revenues include sales between BP businesses.

BP was created on December 31, 1998 by the merger of Amoco Corporation, incorporated in Indiana, USA, in 1889, and The British Petroleum Company p.l.c., registered in 1909 in England and Wales. The resulting company, BP p.l.c., is a public limited company, registered in England and Wales.

BP is one of the world’s leading oil companies on the basis of market capitalization and proved reserves. Our worldwide headquarters is located in London, UK. Our registered address is:

BP p.l.c.

1 St James’s Square

London SW1Y 4PD

United Kingdom

Tel: +44(0)20 7496 4000

Internet address: www.bp.com

Our agent in the USA is:

BP America Inc.

4101 Winfield Road

Warrenville, Illinois 60555

Tel: +1 630 821 2222

Overview of the Group

Our three operating business segments are Exploration and Production; Refining and Marketing; and Gas, Power and Renewables. Exploration and Production’s activities include oil and natural gas exploration, development and production (upstream activities), together with related pipeline transportation and processing activities (midstream activities). The activities of Refining and Marketing include oil supply and trading and the manufacture and marketing of petroleum products, including aromatics and acetyls as well as refining and marketing. Gas, Power and Renewables activities include the marketing and trading of natural gas, natural gas liquids (NGLs), liquefied natural gas (LNG), LNG shipping and regasification activities, and low-carbon power development, including solar and wholesale marketing and trading (BP Alternative Energy). The Group provides high quality technological support for all its businesses through its research and engineering activities.

The Group’s operating business segments are managed on a global basis and not on a regional basis. Geographical information for the Group and segments is given to provide additional information for investors, but does not reflect the way BP manages its activities. Information by geographical area is provided for production and reserves in response to the requirements of Appendix A to Item 4D of Form 20-F.

We have well established operations in Europe, the USA, Canada, Russia, South America, Australasia, Asia and parts of Africa. Currently, around 70% of the Group’s capital is invested in Organization for Economic Cooperation and Development (OECD) countries with just under 40% of our fixed assets located in the USA, and around 25% located in the UK and the Rest of Europe.

We believe that BP has a strong portfolio of assets in each of its main segments:


	—	In Exploration and Production, we have upstream interests in 26 countries. In addition to our drive to maximize the value of our existing portfolio we are continuing to develop new profit centres. Exploration and Production activities are managed through operating units which are accountable for theday-to-day management of the segment’s activities. An operating unit is accountable for one or more fields. Profit centres comprise one or more operating units. Profit centres are, or are expected to become, areas that provide significant production and income for the segment. Our new profit centres are in Asia Pacific (Australia, Vietnam, Indonesia and China), Azerbaijan, North Africa (Algeria), Angola, Trinidad and the Deepwater Gulf of Mexico; and Russia, where we believe we have competitive advantage and which we believe provide the foundation for volume growth and improved margins in the future. We also have significant midstream activities to support our upstream interests.

	—	In Refining and Marketing, we have a strong presence in the USA. We market under the Amoco and BP brands in the Midwest, East, and Southeast, and under the ARCO brand on the West Coast. In Europe, BP has both a retail and refining presence, strengthened by the acquisition of Veba Oil (Veba) in 2002, which markets gasoline under the Aral brand. Our Aromatics and Acetyls business maintains a manufacturing position globally with emphasis on growth in Asia. We also have, or are growing, businesses elsewhere in the world under the BP brand.

	—	In Gas, Power and Renewables, we have growing marketing and trading businesses in North America (USA and Canada), the UK and the rest of Europe. Our marketing and trading activities include natural gas, LNG, NGL and power. Our international natural gas monetization activities, which are our efforts to identify and capture worldwide opportunities to sell our upstream natural gas resources, are focused on growing natural gas markets including the USA, Canada, Spain and many of the emerging markets of the Asia Pacific region, notably China. We are involved in power projects in the USA, UK, Spain and South Korea. We are investing to offer real alternatives for generation of power with low-carbon emissions. We have plans to invest in a new business called BP Alternative Energy, which aims to extend significantly our capability in solar, wind power, hydrogen power and gas-fired generation.

Acquisitions and Disposals

In August 2003, BP and Alfa Group and Access-Renova (AAR) completed a transaction first announced in February 2003 to create the third largest oil company operating in Russia based on production volume. The company, TNK-BP, is a 50:50 joint venture between BP and AAR, and operates in Russia and the Ukraine. BP’s share of the result of the TNK-BP joint venture has been included within the Exploration and Production segment from August 29, 2003. AAR contributed its holdings in TNK and Sidanco, its share of Rusia Petroleum, its stake in the Rospan gasfield in West Siberia and its interest in the Sakhalin IV and V exploration licence to the joint venture. BP contributed its holding in Sidanco, its stake in Rusia Petroleum and its holding in the BP Moscow retail network. Neither AAR’s association with Slavneft, nor BP’s interest in LukArco or the Russian elements of BP’s international businesses such as lubricants, marine and aviation were included in this transaction. In addition, BP paid AAR $2.6 billion in cash upon completion of the transaction, which was subsequently reduced by receipt of pre-acquisition dividends net of transaction costs of $0.3 billion, and subject to the terms of its agreement with AAR, will pay three annual tranches of $1.25 billion in BP shares, valued at market prices prior to each annual payment. In September 2004, the first of the three annual tranches was paid to AAR in BP ordinary shares. In January 2004, BP and AAR completed a subsequent transaction to include AAR’s 50% stake in Slavneft within TNK-BP, at which time BP paid $1.35 billion to AAR. Slavneft was previously held equally by AAR and Sibneft. The shareholder agreement between BP and AAR establishes TNK-BP in the British Virgin Islands with English law principles governing the legal system. The shareholder agreement establishes joint control between AAR and BP. BP holds 50% of the voting rights in TNK-BP. BP and AAR have equal representation on the TNK-BP Board, with AAR nominating the Chairman and Chairman of the Remuneration Committee, and with BP nominating the

Vice Chairman and Chairman of the Audit Committee. BP appoints the Chief Executive Officer of TNK-BP and holds half of the senior management positions. In December 2005, TNK-BP disposed of non-core producing assets in the Saratov region, along with the Orsk refinery and certain TNK-BP operated petrol stations. The disposals allow TNK-BP to streamline its operations and concentrate on strategic investments in projects with high-growth potential.

Disposal proceeds in 2003 amounted to $6,356 million, and resulted primarily from the sale of various upstream interests and completion of divestments required as a condition of approval of the Veba acquisition in 2002.

On November 2, 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. On completion, the two entities, which manufacture and market high density polyethylene, became wholly owned subsidiaries of BP. The total consideration for the acquisition was $1,391 million. These two entities were subsequently included as part of the sale of Innovene to INEOS (see below).

During 2004, BP China and Sinopec announced the establishment of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd., a retail joint venture between BP and Sinopec. Based on the existing service station network of Sinopec, the new30-year dual branded joint venture has plans to build, operate and manage a network of 500 service stations in Hangzhou, Ningbo and Shaoxing. Also during the year, BP China and PetroChina announced the establishment of BP-PetroChina Petroleum Company Limited. Located in Guangdong, one of the most developed provinces in China, the 30 year dual branded joint venture is intended to acquire, build, operate and manage 500 service stations in the province within three years of establishment. The initial investment in both joint ventures amounted to $106 million.

Disposal proceeds in 2004 were $4,961 million which included $2.3 billion from the sale of the Group’s investments in PetroChina and Sinopec. Additionally, it includes proceeds from: the sale of various oil and gas properties, the sale of our interest in Singapore Refining Company Private Limited, the sale of our specialty intermediate chemicals and Fabrics and Fibres businesses and the sale of two natural gas liquids plants.

In 2005, there were no significant acquisitions. Disposal proceeds were $11,200 million, which includes net cash proceeds from the sale of Innovene to INEOS of $8,304 million after selling costs, closing adjustments and liabilities. Innovene represented the majority of the Olefins and Derivatives business. Additionally, it includes proceeds from the sale of the Group’s interest in the Ormen Lange field in Norway.

Resegmentation in 2006

With effect from January 1, 2006 the following changes to the business segments have been implemented:


	—	Following the sale of Innovene to INEOS in December 2005, the transfer of three equity-accounted entities (Shanghai SECCO Petrochemical Company Limited in China and Polyethylene Malaysia Sdn Bhd and Ethylene Malaysia Sdn Bhd, both in Malaysia), previously reported in Other businesses and corporate, to Refining and Marketing.

	—	The formation of BP Alternative Energy in November 2005 has resulted in the transfer of certain mid-stream assets and activities to Gas, Power and Renewables:


	—	South Houston Green Power 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 combined cycle gas turbine (CCGT) plant in Vietnam from Exploration and Production.


	—	The transfer of Hydrogen for Transport activities from Gas, Power and Renewables to Refining and Marketing.

Financial and Operating Information

The following table summarizes the Group’s sales and other operating revenues of continuing operations, profit and capital expenditure for the last three years and total assets at the end of each of those years. The financial information for 2004 and 2003 has been restated to reflect: (a) the adoption by the Group of IFRS; (b) various reorganizations as a precursor to seeking to divest the Olefins and Derivatives business; and (c) the presentation of Innovene as a discontinued operation as a result of its divestment. See Item 3 — Selected Financial Information — page 6 for further details related to these restatements.


	Year ended December 31,

	2005		2004		2003

Sales and other operating revenues of continuing operations		239,792		192,024		164,653
Profit for the year		22,317		17,262		12,618
Profit for the year attributable to BP shareholders		22,026		17,075		12,448
Capital expenditure and acquisitions (a)		14,149		16,651		19,623
Total assets		206,914		194,630		172,491


(a)	There were no significant acquisitions in 2005. Capital expenditure and acquisitions for 2004 includes $1,354 million for including TNK’s interest in Slavneft within TNK-BP and $1,355 million for the acquisition of Solvay’s interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America; and for 2003 includes $5,794 million for the acquisition of our interest in TNK-BP.

With the exception of the Atlantic Richfield acquisition, which was a share transaction, and the shares issued to AAR in connection with TNK-BP (see Acquisitions and Disposals in this Item on page 14) all capital expenditure and acquisitions during the last five years have been financed from cash flow from operations, disposal proceeds and external financing.

Information for 2005, 2004 and 2003 concerning the profits and assets attributable to the businesses and to the geographical areas in which the Group operates is set forth in Item 18 — Financial Statements — Note 7 on page F-39.

The following table shows our production for the last five years and the estimated net proved oil and natural gas reserves at the end of each of those years.


	Year ended December 31,

	2005		2004		2003		2002		2001

Crude oil production for subsidiaries (thousand barrels per day)		1,423		1,480		1,615		1,766		1,723
Crude oil production for equity-accounted entities (thousand barrels per day)		1,139		1,051		506		252		208
Natural gas production for subsidiaries (million cubic feet per day)		7,512		7,624		8,092		8,324		8,287
Natural gas production for equity-accounted entities (million cubic feet per day)		912		879		521		383		345
Estimated net proved crude oil reserves for subsidiaries (million barrels) (a)(b)		6,360		6,755		7,214		7,762		7,217
Estimated net proved crude oil reserves for equity- accounted entities (million barrels) (a)(c)		3,205		3,179		2,867		1,403		1,159
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet) (a)(d)		44,448		45,650		45,155		45,844		42,959
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet) (a)(e)		3,856		2,857		2,869		2,945		3,216


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

(b)		Includes 29 million barrels (40 million barrels at December 31, 2004 and 55 million barrels at December 31, 2003) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(c)		Includes 95 million barrels in respect of the 4.47% minority interest in TNK-BP at December 31, 2005 and includes 127 million barrels and 97 million barrels in respect of the 5.9% minority interest inTNK-BP at December 31, 2004 and December 31, 2003, respectively.

(d)		Includes 3,812 billion cubic feet of natural gas (4,064 billion cubic feet at December 31, 2004 and 4,505 billion cubic feet at December 31, 2003) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(e)		Includes 57 billion cubic feet in respect of the 4.47% minority interest in TNK-BP at December 31, 2005 and includes 13 billion cubic feet (December 31, 2003 nil) in respect of the 5.9% minority interest in TNK-BP at December 31,2004.

During 2005, 681 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP’s proved reserves for subsidiaries (excluding purchases and sales). After allowing for production, which amounted to 996 mmboe, BP’s proved reserves for subsidiaries, were 14,023 mmboe at December 31, 2005. These proved reserves are mainly located in the USA (43%), Rest of Americas (21%), Asia Pacific (10%) and the UK (9%).

For equity-accounted entities, 721 mmboe were added to proved reserves, (excluding purchases and sales), production was 478 mmboe and proved reserves were 3,870 mmboe at December 31, 2005.

* Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf) = 1 million barrels.

SEGMENTAL INFORMATION

The following tables show sales and other operating revenues and profit before finance costs, other finance expense and tax by business and by geographical area, for the years ended December 31, 2005, 2004 and 2003.

																					��
		Year ended December 31, 2005

								Gas,			Other			Consolidation
		Exploration			Refining			Power			businesses			adjustment								Consolidation			Total
		and			and			and			and			and			Total		Innovene			adjustment and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group		operations			eliminations (a)			operations

		($ million)
Sales and other operating revenues
Segment revenues			47,210			213,465			25,557			21,295			(55,359	)		252,168		(20,627	)		8,251			239,792
Less: sales between businesses			(32,606	)		(11,407	)		(3,095	)		(8,251	)		55,359			—		8,251			(8,251	)		—

Third party sales			14,604			202,058			22,462			13,044			—			252,168		(12,376	)		—			239,792

Results
Profit (loss) before interest and tax			25,508			6,442			1,104			(523	)		(208	)		32,323		(668	)		527			32,182

Includes
	Equity-accounted income		3,238			238			19			34			—			3,529		14			—			3,543


		Year ended December 31, 2004

											Other			Consolidation
		Exploration			Refining			Gas, Power			businesses			adjustment								Consolidation			Total
		and			and			and			and			and			Total		Innovene			adjustment and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group		operations			eliminations (a)			operations

		($ million)
Sales and other operating revenues
Segment revenues			34,700			170,749			23,859			17,994			(43,999	)		203,303		(17,448	)		6,169			192,024
Less: sales between businesses			(24,756	)		(10,632	)		(2,442	)		(6,169	)		43,999			—		6,169			(6,169	)		—

Third party sales			9,944			160,117			21,417			11,825			—			203,303		(11,279	)		—			192,024

Results
Profit (loss) before interest and tax			18,087			6,544			954			(362	)		(191	)		25,032		526			188			25,746

Includes
	Equity-accounted income		1,985			259			6			18			—			2,268		12			—			2,280


		Year ended December 31, 2003

								Gas,			Other			Consolidation
		Exploration			Refining			Power			businesses			adjustment								Consolidation			Total
		and			and			and			and			and			Total		Innovene			adjustment and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group		operations			eliminations (a)			operations

		($ million)
Sales and other operating revenues
Segment revenues			30,621			143,441			22,568			13,978			(36,993	)		173,615		(13,463	)		4,501			164,653
Less: sales between businesses			(22,885	)		(7,644	)		(1,963	)		(4,501	)		36,993			—		4,501			(4,501	)		—

Third party sales			7,736			135,797			20,605			9,477			—			173,615		(8,962	)		—			164,653

Results
Profit (loss) before interest and tax			15,084			3,235			578			(108	)		(61	)		18,728		(145	)		193			18,776

Includes
	Equity-accounted income		949			241			(5	)		14			—			1,199		15			—			1,214


(a)		In the circumstances of discontinued operations, International Accounting Standards require that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This adjustment has two offsetting elements: the net margin on crude refined by Innovene as substantially all crude for its refineries is supplied by BP and most of the refined products manufactured are taken by BP; and the margin on sales of feedstock from BP’s US refineries to Innovene’s manufacturing plants. The profits attributable to individual segments are not affected by this adjustment. Neither does this representation indicate the profits earned by continuing or Innovene operations, as if they were standalone entities, for past periods or likely to be earned in future periods.


		Year ended December 31, 2005

					Rest of						Rest of
By geographical area		UK			Europe			USA			World			Total

		($ million)
Sales and other operating revenues
Segment revenues			95,375			72,972			101,190			60,314			329,851
Less: sales attributable to Innovene operations			(2,610	)		(8,667	)		(4,309	)		(686	)		(16,272	)

Segment revenues from continuing operations			92,765			64,305			96,881			59,628			313,579
Less: sales between areas			(38,081	)		(5,013	)		(2,362	)		(16,541	)		(61,997	)
Less: sales by continuing operations to Innovene			(5,599	)		(4,640	)		(1,508	)		(43	)		(11,790	)

Third party sales of continuing operations			49,085			54,652			93,011			43,044			239,792

Results
Profit (loss) before interest and tax from continuing operations			1,167			5,206			12,639			13,170			32,182

Includes
	Equity-accounted income		(8	)		18			86			3,447			3,543


		Year ended December 31, 2004

					Rest of						Rest of
By geographical area		UK			Europe			USA			World			Total

		($ million)
Sales and other operating revenues
Segment revenues			59,615			52,540			86,358			48,534			247,047
Less: sales attributable to Innovene operations			(2,365	)		(7,682	)		(4,109	)		(672	)		(14,828	)

Segment revenues from continuing operations			57,250			44,858			82,249			47,862			232,219
Less: sales between areas			(18,846	)		(1,396	)		(1,539	)		(10,188	)		(31,969	)
Less: sales by continuing operations to Innovene			(5,263	)		(896	)		(2,064	)		(3	)		(8,226	)

Third party sales of continuing operations			33,141			42,566			78,646			37,671			192,024

Results
Profit (loss) before interest and tax from continuing operations			2,875			3,121			9,725			10,025			25,746

Includes
	Equity-accounted income		9			17			92			2,162			2,280


		Year ended December 31, 2003

					Rest of						Rest of
By geographical area		UK			Europe			USA			World			Total

		($ million)
Sales and other operating revenues
Segment revenues			36,253			48,138			79,092			38,316			201,799
Less: sales attributable to Innovene operations			(1,879	)		(6,105	)		(3,265	)		(534	)		(11,783	)

Segment revenues from continuing operations			34,374			42,033			75,827			37,782			190,016
Less: sales between areas			(6,953	)		(3,160	)		(714	)		(8,258	)		(19,085	)
Less: sales by continuing operations to Innovene			(3,947	)		(876	)		(1,455	)		—			(6,278	)

Third party sales of continuing operations			23,474			37,997			73,658			29,524			164,653

Results
Profit (loss) before interest and tax from continuing operations			3,348			1,819			7,008			6,601			18,776

Includes
	Equity-accounted income		11			39			99			1,065			1,214

EXPLORATION AND PRODUCTION

Our Exploration and Production business includes upstream and midstream activities in 26 countries, including the USA, UK, Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad, and locations within Asia Pacific, South America and the Middle East. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around the Deepwater Gulf of Mexico, Angola, Trinidad, Egypt, Algeria and Russia. Major development areas include the Deepwater Gulf of Mexico, Azerbaijan, Algeria, Angola, Egypt and Asia Pacific. During 2005, production came from 22 countries.

Midstream activities involve the management of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities. Our most significant midstream pipeline interests include: the Trans Alaska Pipeline System; the Forties Pipeline System and the Central Area Transmission System pipeline both in the UK sector of the North Sea; and the Baku-Tbilisi-Ceyhan pipeline running through Azerbaijan, Georgia and Turkey. Our significant LNG interests include: the Atlantic LNG plant in Trinidad; our interests in the Sanga-Sanga Production Sharing Agreement (PSA) which supplies natural gas to the Bontang LNG plant, and the Tangguh PSA, which is under construction, both in Indonesia; and through our share of LNG from the North West Shelf natural gas development in Australia.

With effect from January 1, 2005, we transferred the Mardi Gras pipeline system in the Gulf of Mexico to the Refining and Marketing segment. The 2004 and 2003 data below has been restated to reflect this transfer.


	Year ended December 31,

	2005		2004		2003

	($ million)
Sales and other operating revenues from continuing operations (a)		47,210		34,700		30,621
Profit before interest and tax from continuing operations		25,508		18,087		15,084
Total assets		93,479		85,808		79,446
Capital expenditure and acquisitions		10,237		11,008		15,192
	($ per barrel)

Average BP crude oil realizations (b)		50.27		36.45		28.23
Average BP NGL realizations (b)		33.23		26.75		19.26
Average BP liquids realizations (b)(c)		48.51		35.39		27.25
Average West Texas Intermediate oil price		56.58		41.49		31.06
Average Brent oil price		54.48		38.27		28.83
	($ per thousand cubic feet)

Average BP natural gas realizations (b)		4.90		3.86		3.39
Average BP US natural gas realizations (b)		6.78		5.11		4.47
	($ per mmbtu)

Average Henry Hub gas price (d)		8.65		6.13		5.37


(a)		Includes profit after interest and tax of equity-accounted entities.

(b)		The Exploration and Production business does not undertake any hedging activity. Consequently, realizations reflect the market price achieved. Realizations are based on sales of consolidated subsidiaries only — this excludes equity-accounted entities.

(c)		Crude oil and natural gas liquids.

(d)		Henry Hub First of Month Index.

Our upstream activities are divided between existing profit centres — that is our operations in Alaska, Egypt, Latin America (including Argentina, Bolivia, Brazil, Colombia and Venezuela), Middle East (including Abu Dhabi, Sharjah and Pakistan), North America Gas (Onshore USA and Canada) and the

North Sea (UK, Netherlands and Norway); and new profit centres — that is our operations in Asia Pacific (Australia, Vietnam, Indonesia and China), Azerbaijan, North Africa (Algeria), Angola, Trinidad, and the Deepwater Gulf of Mexico; and Russia.

Operations in Argentina, Bolivia, Abu Dhabi, Kazakhstan and the TNK-BP operations in Russia are conducted through equity-accounted entities.

The Exploration and Production strategy is to 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; and

	—	Managing the decline of existing producing assets and divesting assets when they no longer compete in our portfolio.

This strategy is underpinned by a focused exploration strategy in areas with the potential for large oil and natural gas fields as new profit centres. Through the application of advanced technology and significant investment, we have gained a strong position in many of these areas. Within our existing profit centres, we seek to manage the decline through the application of technology, reservoir management, maintaining operating efficiency and investing in new projects. We also continually review our existing assets and dispose of them when the opportunities for future investment are no longer competitive compared with other opportunities within our portfolio and offer greater value to another operator.

In support of growth, 2005 capital expenditure including acquisitions was $10.2 billion (2004 $11.0 billion and 2003 $15.2 billion). Acquisitions in 2004 and 2003 comprised essentially our progressive investment inTNK-BP of $1.4 billion and $5.8 billion, respectively. Excluding acquisitions, capital expenditure in 2005 amounted to $10.1 billion (2004, $9.6 billion and 2003 $9.4 billion) and is planned to be around $11 billion in 2006. The projected increase in capital expenditure in 2006 reflects our project programme, managed within the context of our disciplined approach to capital investment, and taking into account sector specific inflation.

Development expenditure incurred in 2005, excluding midstream activities, was $7,678 million compared with $7,270 million in 2004 and $7,537 million in 2003. This reflects the investment we have been making in our new profit centres and the development phase on many of our major projects.

Upstream Activities


	*Exploration*

The Group explores for oil and natural gas under a wide range of licensing, joint venture and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures.

Our exploration and appraisal costs in 2005 were $1,266 million compared to $1,039 million in 2004 and $824 million in 2003. These costs include exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. About 28% of 2005 exploration and appraisal costs were directed towards appraisal activity. In 2005, we participated in 98 gross (44 net) exploration and appraisal wells in 14 countries. The principal areas of activity were Angola, Egypt, Russia (outsideTNK-BP), Trinidad, Turkey and the USA.

Total exploration expense in 2005 of $684 million (2004 $637 million and 2003 $542 million) includes the write-off of unsuccessful drilling activity in the Deepwater Gulf of Mexico ($120 million), in Onshore North America ($18 million), in Egypt ($13 million) and others ($21 million).

In 2005, we obtained upstream rights in several new tracts, which include the following:


	—	In Algeria, we were awarded three new blocks (BP 100%), two in the Illizi Basin and one in the Benoud Basin.

	—	In Egypt, we were awarded two new blocks in the shallow water Nile Delta, Burullus (BP 100%) and North El Burg (BP 50%).

	—	In the Gulf of Mexico, we were awarded 41 blocks (BP 100%) in the Deepwater and 8 blocks (BP 100%) in the Shelf through the Outer Continental Shelf Lease Sales 194 and 196.

In 2005, we were involved in discoveries, the most significant of which were in Angola, Russia, Trinidad and the USA. In most cases, reserve bookings from these fields will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. Our 2005 discoveries included the following:


	—	In Angola, we made further discoveries in the ‘ultra deep water’ (greater than 1,500 metres) in Block 31 (BP 26.7% and operator) with Ceres, Juno, Astraea and Hebe wells. In 2006, the Urano discovery was announced in the same block.

	—	In Trinidad, BP Trinidad and Tobago LLC (BP 70%) made a discovery with the Coconut Deep well.

	—	In Russia, a second discovery was made in the Kaigansky-Vasukansky licence in the south of the Sakhalin V area with the Udachnaya well (BP 49%)

	—	In the Deepwater Gulf of Mexico, we continued our successful exploration efforts with a number of new discoveries.


	*Reserves and Production*

BP manages its hydrocarbon resources in three major categories: prospect inventory; non-proved resources and proved reserves. When a discovery is made, volumes transfer from the prospect inventory to the non-proved resource category. The resources move through various non-proved resource sub-categories as their technical and commercial maturity increases through appraisal activity.

Resources in a field will only be categorized as proved reserves when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction, or for sanction expected within six months and, for additional reserves in existing fields, the requirement that the reserves be included in the business plan and scheduled for development within three years. Internal approval and final investment decision are what we refer to as project sanction.

At the point of sanction, all booked reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s reserves depends on a later phase of activity, only that portion of reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking to the start of production. Changes to reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

BP has an internal process to control the quality of reserve bookings that forms part of a holistic and integrated system of internal control. BP’s process to manage reserve bookings has been centrally controlled for over 15 years and it currently has several key elements.

The first element is the accountabilities of certain officers of the Company to ensure that there are effective controls in the proved reserve verification and approval process of the Group’s reserve estimates and the timely reporting of the related financial impacts of proved reserve changes. These

officers of the Company are responsible for carrying out verification of proved reserve estimates and are independent of the operating business unit to ensure integrity and accuracy of reporting.

The second element is the capital allocation processes whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the Group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects.

The third element is Internal Audit, whose role includes systematically examining the effectiveness of the Group’s financial controls designed to assure the reliability of reporting and safeguarding of assets and examining the Group’s compliance with laws, regulations and internal standards.

The fourth element is a quarterly due diligence review, which is separate and independent from the operating business units, of proved reserves associated with properties where technical, operational or commercial issues have arisen.

The fifth element is the established criteria whereby proved reserve changes above certain thresholds require central authorization. Furthermore, the volumes booked under these authorization levels are reviewed on a periodic basis. The frequency of review is determined according to field size and ensures that more than 80% of the BP reserves base undergoes central review every two years and more than 90% is reviewed every four years.

For the executive directors and senior management, no specific portion of compensation bonuses is directly related to oil and gas reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Exploration and Production business segment is assessed by the Remuneration Committee for the purposes of determining compensation bonuses for the executive directors and senior management. Other indicators include a number of financial and operational measures.

BP’s variable pay programme for the other senior managers in the Exploration and Production business segment is based on Individual Performance Contracts. Individual Performance Contracts are based on agreed items from the business performance plan, one of which, if they choose, could relate to oil and gas reserves.

Details of our net proved reserves of crude oil, condensate, natural gas liquids and natural gas at December 31, 2005, 2004, and 2003 and reserves changes for each of the three years then ended are set out in the Supplementary Oil and Gas Information section in Item 18 — Supplementary Oil and Gas Information beginning on page S-1. We separately disclose our share of reserves held in equity-accounted companies (jointly controlled entities and associates) although we do not control these entities or the assets held by such entities.

All of the Group’s oil and gas reserves held in consolidated companies have been estimated by the Group’s petroleum engineers. Of the oil and gas reserves held in equity-accounted companies, approximately 21% have been estimated by the Group’s petroleum engineers. The majority of the rest consists of reserves in TNK-BP which have been estimated by independent engineering consultants. For significant properties where BP has adopted the proved reserve estimates of others, BP’s petroleum engineers reviewed such estimates before making their assessment of volumes to be booked by BP.

Our proved reserves are associated with both concessions (tax and royalty arrangements) and PSAs. In a concession, the consortium of which we are a part is entitled to the reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Fifteen per cent of our proved reserves are associated with PSAs. The main countries in which we operate under PSA arrangements are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.

The Company’s proved reserves estimates for the year ended December 31, 2005 reported in this Form 20-F reflect year-end prices and some adjustments which have been made vis-à-vis individual asset reserve estimates based on different applications of certain SEC interpretations of SEC regulations relating to the use of technology (mainly seismic) to estimate reserves in the reservoir away from wellbores and the reporting of fuel gas (i.e. gas used for fuel in operations on the lease) within proved reserves. The 2005 year-end marker prices used were Brent $58.21/bbl (2004 $40.24/bbl and 2003 $30.10/bbl) and Henry Hub $9.52/mmbtu (2004 $6.01/mmbtu and 2003 $5.76/mmbtu). The other 2005 movements in proved reserves are reflected in the tables showing movements in oil and gas reserves by region in Item 18 — Financial Statements — Supplementary Oil and Gas Information on pages S-1 to S-8.

Total hydrocarbon proved reserves, on an oil equivalent basis and excluding equity-accounted entities, comprised 14,023 mmboe at December 31, 2005, a decrease of 4.1% compared with December 31, 2004. Natural gas represents about 55% of these reserves. This reduction includes net sales of 287 mmboe largely comprising a number of assets in Norway and Trinidad. The proved reserve replacement ratio was 68% (2004 78% and 2003 119%). The proved reserve replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserve additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, extensions, discoveries and other additions, excluding the impact of sales and purchases ofreserves-in-place and excluding reserves related to equity-accounted entities. The proved reserve replacement ratio, including sales and purchases ofreserves-in-place but excluding equity-accounted entities, was 40% (2004 64% and 2003 39%). By their nature, there is always some risk involved in the ultimate development and production of reserves, including but not limited to final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices and the continued availability of additional development capital.

In 2005, total additions to the Group’s proved reserves (excluding sales and purchases ofreserves-in-place and equity-accounted entities) amounted to 681 mmboe, mostly through extensions to and improved recovery from existing fields and discoveries of new fields. Of these reserve additions, approximately 77% are associated with new projects and are proved undeveloped reserve additions and the remainder are in existing developments where they represent a mixture of proved developed and proved undeveloped. Major new development projects typically take one to four years from the time of initial booking to the start of production. The principal reserve additions were in Angola (Kizomba C), United States (Wamsutter, Ursa, Shenzi) and Trinidad (Coconut) and it is planned to bring these into production over the period 2006 — 2011.

Total hydrocarbon proved reserves, on an oil equivalent basis for equity-accounted entities alone, comprised 3,870 mmboe at December 31, 2005, an increase of 5.4% compared with December 31, 2004. Natural gas represents about 17% of these reserves. The proved reserve replacement ratio for equity-accounted entities alone was 151% (2004 114% and 2003 72%), and the proved reserve replacement ratio for equity-accounted entities alone but including sales and purchases ofreserves-in-place was 141% (2004 170% and 2003 796%).

Additions to proved developed reserves in 2005 for subsidiaries were 632 mmboe. This included some reserves which were previously classified as proved undeveloped. The proved developed reserve replacement ratio (including both sales and purchases ofreserves-in-place) was 63% (2004 70% and 2003 - -2%).

Additions to proved developed reserves in 2005 for equity-accounted entities were 474 mmboe. This included some reserves which were previously classified as proved undeveloped. The proved developed reserve replacement ratio (including both sales and purchases ofreserves-in-place) was 99% (2004 180% and 2003 642%).

Our total hydrocarbon production during 2005 averaged 2,718 thousand barrels of oil equivalent per day (mboe/d), for subsidiaries and 1,296 mboe/d, for equity-accounted entities, a decrease of 2.8% and an increase of 7.8%, respectively, compared with 2004. For subsidiaries, 39% of our production was in the USA, 17% in the UK. For equity-accounted entities, 77% of production is from TNK-BP.

Total production for 2006 is estimated at an average of between 2.8 and 2.85 mmboe/d for subsidiaries and between 1.3 and 1.35 mmboe/d for equity-accounted entities; these estimates are based on the Group’s asset portfolio at January 1, 2006, anticipated start-ups in 2006 and Brent at $40/bbl, before any 2006 disposal effects, and before any effects of prices above $40/bbl on volumes in Production Sharing Agreements. The daily production of the Gulf of Mexico Shelf assets, whose sale was announced in April 2006, is estimated at 27 mboe.

The anticipated decline in production volumes from subsidiaries in our existing profit centres is partly mitigated by the development of new projects and the investment in incremental reserves in and around existing fields. We expect that this overall decline in production from subsidiaries in our existing profit centres will be more than compensated for by strong increases in production from subsidiaries in our new profit centres over the next few years. Production growth in our equity-accounted joint venture, TNK-BP, is expected to moderate to between 2% and 3% over the period 2005 to 2010.

The most important determinants of cash flows in relation to our oil and natural gas production are the prices of these commodities. At constant prices, cash flows from currently developed proved reserves are expected to decline in a manner consistent with anticipated production decline rates. Development activities associated with recent discoveries, as well as continued investment in these producing fields, are expected to more than offset this decline, resulting in increased operating cash flows over the next few years. Cash flows from equity-accounted entities are expected to be in the form of dividend payments. See Item 5 — Liquidity and Capital Resources on page 93.

The following tables show BP’s estimated net proved reserves as at December 31, 2005.

Estimated net proved reserves of liquids at December 31, 2005 (a) (b)


	Developed		Undeveloped		Total

	(million barrels
UK		496		184		680
Rest of Europe		225		86		311
USA		1,984		1,429		3,413
Rest of Americas		215		286		501	(c)
Asia Pacific		70		95		165
Africa		142		536		678
Russia		—		—		—
Other		69		543		612

		3,201		3,159		6,360

Equity-accounted entities						3,205	(d)

Estimated net proved reserves of natural gas at December 31, 2005(a) (b)


	Developed		Undeveloped		Total

	(billion cubic feet)
UK		2,382		904		3,286
Rest of Europe		245		80		325
USA		11,184		4,198		15,382
Rest of Americas		3,560		10,504		14,064	(e)
Asia Pacific		1,459		5,375		6,834
Africa		934		2,000		2,934
Russia		—		—		—
Other		281		1,342		1,623

		20,045		24,403		44,448

Equity-accounted entities						3,856	(f)

Net proved reserves on an oil equivalent basis (mmboe)
— Group						14,023
— Equity-accounted entities						3,870


(a)		Net proved reserves of crude oil and natural gas, stated as of December 31, 2005, exclude production royalties due to others, whether payable in cash or in kind, and include minority interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities.

(b)		In certain deepwater fields, such as fields in the Gulf of Mexico, BP has claimed proved reserves before production flow tests are conducted in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. The general method of reserves assessment to determine reasonable certainty of commercial recovery which BP employs relies on the integration of three types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and fluids; (2) field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control; and (3) data from relevant analog fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be superior to a flow test in providing a better understanding of the overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of investigation associated with a short term flow test.

		Historically, proved reserves recorded using these methods have been validated by actual production levels. As at the end of 2005, BP had proved reserves in 21 fields in the Deepwater Gulf of Mexico that had been initially booked prior to production flow testing. Of these fields, 18 have been in production and two, Thunder Horse and Atlantis, are expected to begin production in the second half of the year and around the end of 2006, respectively. A further field is in the early stages of development.

(c)		Includes 29 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(d)		Includes 95 million barrels of crude oil in respect of the 4.47% minority interest in TNK-BP.

(e)		Includes 3,812 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(f)		Includes 57 billion cubic feet of natural gas in respect of the 4.47% minority interest in TNK-BP.

The following tables show BP’s production by major field for 2005, 2004 and 2003.

Liquids


				Year ended December 31,

				Net production

Production	Field or Area	Interest		2005		2004		2003

		(%)		(thousand barrels per day)
Alaska	Prudhoe Bay*		26.4		89		97		105
	Kuparuk		39.2		62		68		73
	Northstar*		98.6		46		49		46
	Milne Point*		100.0		37		44		44
	Other		Various		34		37		43

Total Alaska					268		295		311

Lower 48 onshore (a)	Various		Various		130		142		160

Gulf of Mexico Deepwater (a)	Na Kika*		50.0		44		27		—
	Horn Mountain*		66.6		26		41		42
	King*		100.0		24		26		31
	Mars		28.5		21		35		43
	Ursa		22.7		19		29		17
	Other		Various		64		47		73
Gulf of Mexico Shelf (a)	Other		Various		16		24		49

Total Gulf of Mexico					214		229		255

Total USA					612		666		726

UK offshore (a)	ETAP†		Various		49		55		56
	Foinaven*		Various		39		48		55
	Magnus*		85.0		30		34		39
	Schiehallion/Loyal*		Various		28		39		42
	Harding*		70.0		22		27		34
	Andrew*		62.8		12		12		17
	Other		Various		75		89		105

Total UK offshore					255		304		348

Onshore	Wytch Farm*		67.8		22		26		29

Total UK					277		330		377

Netherlands	Various		Various		1		1		1
Norway (a)	Valhall*		28.1		25		25		21
	Draugen		18.4		20		27		25
	Ula*		80.0		17		16		16
	Other		Various		12		8		21

Total Rest of Europe					75		77		84


*	BP operated.


†	Out of nine fields, BP operates six and Shell three.


				Year ended December 31,

				Net production

Production	Field or Area	Interest		2005		2004		2003

		(%)		(thousand barrels per day)
Angola	Kizomba A		26.7		56		16		—
	Girassol		16.7		34		31		33
	Xikomba		26.7		10		18		2
	Other		Various		28		6		—
Australia	Various		15.8		36		36		40
Azerbaijan	Azeri-Chirag-Gunashli*		34.1		76		39		38
Canada	Various		Various		10		11		13
Colombia	Various		Various		41		48		53
Egypt	Various		Various		47		57		73
Trinidad & Tobago	Various		100.0		40		59		74
Venezuela	Various		Various		55		55		53
Other	Various		Various		26		31		49

Total Rest of World					459		407		428

Total Group (c)					1,423		1,480		1,615

Equity-accounted entities (BP Share)
Abu Dhabi (b)	Various		Various		148		142		138
Argentina - Pan American Energy	Various		Various		67		64		60
Russia - TNK-BP (a)	Various		Various		911		831		296
Other	Various		Various		13		14		12

Total equity-accounted entities					1,139		1,051		506


*	BP operated.

Natural gas


				Year ended December 31,

				Net production

Production	Field or Area	Interest		2005		2004		2003

		(%)		(million cubic feet per day)
Lower 48 onshore (a)	San Juan*		Various		753		772		802
	Arkoma		Various		198		183		201
	Hugoton*		Various		151		158		182
	Tuscaloosa		Various		111		96		136
	Wamsutter*		70.5		110		105		111
	Jonah*		65.0		97		114		119
	Other		Various		465		514		558

Total Lower 48 onshore					1,885		1,942		2,109

Gulf of Mexico Deepwater (a)	Na Kika*		50.0		133		133		—
	Marlin*		78.2		52		43		93
	Other		Various		235		313		470
Gulf of Mexico Shelf (a)	Other		Various		160		240		373

Total Gulf of Mexico					580		729		936

Alaska	Various		Various		81		78		83

Total USA					2,546		2,749		3,128

UK offshore (a)	Braes†		Various		165		147		174
	Bruce*		37.0		161		163		222
	West Sole*		100.0		55		67		73
	Marnock*		62.0		47		70		98
	Britannia		9.0		46		54		55
	Shearwater		27.5		37		76		70
	Armada		18.2		30		50		58
	Other		Various		549		547		696

Total UK					1,090		1,174		1,446

Netherlands	P/18-2*		48.7		25		34		30
	Other		Various		37		46		37
Norway (a)	Various		Various		46		45		52

Total Rest of Europe					108		125		119


*	BP operated.


†	Includes 4 million and 7 million cubic feet a day of natural gas received as in-kind tariff payments in 2005 and 2004, respectively.


		��		Year ended December 31,

				Net production

Production	Field or Area	Interest		2005		2004		2003

		(%)		(million cubic feet per day)
Australia	Various		15.8		367		308		285
Canada	Various		Various		307		349		422
China	Yacheng*		34.3		98		99		74
Egypt	Ha’py*		50.0		106		80		83
	Other		Various		83		115		170
Indonesia	Sanga-Sanga (direct)*		26.3		110		137		165
	Other*		46.0		128		144		218
Sharjah	Sajaa*		40.0		113		103		101
	Other		40.0		10		14		19
Trinidad & Tobago	Kapok*		100.0		1,005		553		79
	Mahogany*		100.0		303		453		503
	Amherstia*		100.0		289		408		624
	Parang*		100.0		154		137		152
	Immortelle*		100.0		132		172		235
	Cassia*		100.0		83		85		30
	Other*		100.0		21		111		71
Other (a)	Various		Various		459		308		168

Total Rest of World					3,768		3,576		3,399

Total Group (d)					7,512		7,624		8,092

Equity-accounted entities (BP Share)
Argentina - Pan American Energy	Various		Various		343		317		281
Russia - TNK-BP (a)	Various		Various		482		458		129
Other	Various		Various		87		104		111

Total equity-accounted entities (d)					912		879		521


*		BP operated

(a)		In 2005, BP divested the Teak, Samaan and Poui assets in Trinidad and sold interests in certain properties in the Gulf of Mexico. In addition, BP exchanged the Gulf of Mexico Deepwater Blind Faith prospect for Kerr McGee’s interest in the Arkoma Red Oak and Williburton fields. TNK-BP disposed of non-core producing assets in the Saratov region. In 2004, BP agreed with AAR to incorporate their 50% interest in Slavneft into TNK-BP, an equity-accounted entity. BP also acquired minor additional working interests in Canada and the United States. BP diluted its working interests in King’s Peak and divested the Swordfish assets in the deepwater Gulf of Mexico. Additionally, BP sold various properties including its interest in the South Pass 60 in the Gulf of Mexico Shelf, various assets in Alberta, Canada, and the Kangean PSA in Indonesia. In 2003, BP and AAR merged certain of their Russian and Ukranian oil and gas businesses to create TNK-BP. BP also acquired the interests of Amerada Hess in Colombia and disposed of its interests in Forties, Montrose/ Arbroath and Bacton Area assets in the UK North Sea, Gyda in Norway, LL652 in Venezuela, QHD and Liuhua in China, the Malaysia Thailand Joint Development Area, Aspen in the Gulf of Mexico, various shallow water fields in the Gulf of Mexico and various fields in the US Lower 48 states.

(b)		The BP Group holds proportionate interests, through associates, in onshore and offshore concessions in Abu Dhabi expiring in 2014 and 2018, respectively.


(c)		Includes NGLs from processing plants in which an interest is held of 58 thousand barrels per day (mb/d), 67 mb/d and 70 mb/d for 2005, 2004 and 2003, respectively. The related reserves are excluded from the Group’s reserves.

(d)		Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the Group’s reserves.


	*United States*

2005 liquids production at 612 thousand barrels per day (mb/d) decreased 8% from 2004, while natural gas production at 2,546 million cubic feet per day (mmcf/d) decreased 7% compared with 2004.

Hurricanes Katrina and Rita passed through the Gulf of Mexico in August and September, 2005, respectively, requiring the shut-in of all deepwater and shelf facilities. BP’s production was significantly affected. The hurricanes resulted in heavy damage to operated and non-operated assets in both our upstream and midstream activities.

Crude oil production decreased 54 mb/d from 2004, with production from new projects being offset by the impact of hurricanes Dennis, Katrina and Rita and natural reservoir decline. The decline in the NGLs component of liquids production (17 mb/d) was primarily caused by the impact of hurricanes. Gas production was lower (203 mmcf/d) because of hurricanes Katrina and Rita, divestments, and natural reservoir decline.

Development expenditure in the USA (excluding midstream) during 2005 was $2,965 million, compared with $3,247 million in 2004 and $3,476 million in 2003. The annual decrease is the result of various development projects being completed.

Our activities within the United States take place in four main areas. Significant events during 2005 within each of these are indicated below.


	Deepwater Gulf of Mexico

Deepwater Gulf of Mexico is one of our new profit centres and our largest area of growth in the United States. In 2005, our deepwater Gulf of Mexico crude oil production was 198 mb/d and gas production was 420 mmcf/d.

Significant events were:


	—	In July 2005, stability problems impacted the Thunder Horse platform (BP 75% and operator). We concluded that this was caused by an issue with the ballast system. Repairs have been completed offshore and remaining construction has progressed with the installation of the risers. During routine pre-start-up testing, we have experienced problems with the subsea equipment. Investigations are ongoing, and pending the results, production is planned for the second half of 2006.

	—	The Mars platform (BP 28.5%) suffered heavy damage from hurricane Katrina. Production, which resumed in May 2006, is expected to be restored to pre-Katrina rates by the middle of 2006.

	—	Production from the Holstein field (BP 50% and operator) commenced in December 2004 and increased during 2005. The facility is designed to produce more than 100 mb/d of oil and 150 mmscf/d of gas.

	—	Production from the Mad Dog facility (BP 60.5% and operator) commenced in January 2005. The facility is designed to process approximately 100 mb/d of oil and 60 mmscf/d of gas.

	—	During 2005, a number of new discoveries were made in the deepwater Gulf of Mexico.

Development of other major projects continued in the Gulf of Mexico during 2005 — Atlantis (BP 56% and operator) is scheduled to commence production around the end of 2006 followed by the King

Sub-sea Pump project (BP 100% and operator) in late 2007. These projects, including Thunder Horse, are expected to add over 200 mboe/d to our Gulf of Mexico production over the next two years.


	Gulf of Mexico Shelf

The Shelf is a mature basin, with decline rates that average greater than 30% per year. Our gas production from Gulf of Mexico Shelf operations was 160 mmcf/d in 2005, down 33% compared to 2004. Liquids production was 16 mb/d, down 33% compared to 2004. Theyear-on-year decline in production was the result of normal decline and the effects of hurricanes Katrina and Rita.

BP’s shelf operations suffered significant damage from hurricanes Katrina and Rita, including seven toppled platforms and an additional three platforms leaning, out of a total of 105, and flooding of onshore tanks and pumps. An impairment charge of $208 million was recognized in 2005 related to hurricane damage.


	Lower 48 States

In the Lower 48 States (Onshore), our 2005 natural gas production was 1,885 mmcf/d, which was down 3% compared to 2004. Liquids production was 130 mb/d, down 8% compared to 2004. Theyear-on-year decrease in production is attributed to normal decline. In 2005, we drilled approximately 400 wells as operator and continued to maintain a level programme of drilling activity throughout the year.

Production is derived primarily from two main areas:


	—	In the Western Basins (Colorado, New Mexico, and Wyoming) our assets produced 214 mboe/d in 2005.

	—	In the Gulf Coast and Mid-Continental basins (Kansas, Louisiana, Oklahoma and Texas) our assets produced 183 mboe/d in 2005.

Significant events were:


	—	On February 1, 2005 we completed the acquisition of Kerr McGee’s interests in the Arkoma Red Oak and Williburton fields in exchange for our Deepwater Gulf of Mexico Blind Faith prospect.

	—	In October 2005, we announced the investment of $2.2 billion in the expansion of the Wamsutter natural gas field. The multi-year drilling programme is expected to double production from 125 mmscf/d to 250 mmscf/d by the end of 2010. This project is part of a projected10-year, $15 billion investment program for North America onshore operations.

	—	The development of recovery technology continues to be a fundamental strategy in accessing our North America tight gas resources. Through the use of horizontal drilling and advanced hydraulic fracturing techniques, we are achieving well rates up to ten times higher than more conventional techniques and per-well recoveries some five times higher.


	Alaska

In Alaska, BP net crude oil production in 2005 was 268 mb/d, a decrease of 9% from 2004 due to mature field decline and operational issues partially offset by the development of satellite fields around Prudhoe Bay and Kuparuk and the restart of the Badami field.

Significant events were:


	—	Maximizing productivity through active reservoir management of the fields we operate remains an essential part of the Alaska business. In 2005, BP operated drilling activity across the North Slope totalling 8.3 rig-years. Prudhoe Bay, and the associated satellite fields (BP 26.4% and operator) maintained an active infill and new well drilling programme with 75 wells in 2005, which generated net production of 4.9 mboe/d. The Northstar Unit drilled 2 wells in 2005, increasing net production by 2.6 mboe/d.

	—	Developing viscous oil is an important part of the Alaska business. We are continually looking to develop viscous oil production in various fields through the application of advanced technology.

	—	The State of Alaska decided on January 12, 2005 to aggregate six of the satellite fields around Prudhoe Bay with the Prudhoe Bay field for the purposes of calculating production taxes. The State estimated that the impact for 2005 will be around $150 million in higher production taxes for the five owners (BP equity 26.4%). BP filed an appeal against this decision on March 11, 2005 which is still awaiting resolution.

	—	On December 19, 2005, the Alaska Gasline Port Authority filed a lawsuit against BP and ExxonMobil alleging violation of antitrust laws. BP denied the allegations. In an order dated June 19, 2006, the United States District Court for Alaska dismissed the Alaska Gasline Port Authority’s antitrust lawsuit against BP and Exxon Mobil.

	—	Negotiations on the Gas Pipeline fiscal contract with the State of Alaska continued during 2005. In February 2006, the gas portion of the fiscal contract was agreed in principle with the State Administration. BP and the other project sponsors are actively engaged with the Alaska Legislature toward the development of a new oil tax structure that will support a healthy oil and gas business in Alaska.

	—	On March 2, 2006, a transit pipeline in the Prudhoe Bay field was discovered to have spilled an estimated 4,200 to 4,800 bbls of crude oil over approximately two acres. The processing facility that feeds into the transit line was immediately shut down. An investigation team has determined that the leak was caused by internal corrosion. Spillclean-up is complete and business operations have resumed using a separate bypass line. See also Environmental Protection — Health, Safety and Environmental Regulation in this Item on page 68.


	*United Kingdom*

We are the largest producer of oil and second largest producer of gas in the UK. BP remains the largest overall producer in the UK of hydrocarbons. In 2005, total liquids production was 277 mb/d, a 16% decrease on 2004, and gas production was 1,090 mmscf/d, a 7% decrease on 2004. This decrease in production was driven by the natural decline of the mature North Sea basin combined with planned maintenance shutdowns partially offset by production from new projects. Our activities in the North Sea are focused on operations efficiency, in-field drilling and selected new field developments. Our development expenditure (excluding midstream) in the UK was $790 million in 2005 compared to $679 million in 2004 and $740 million in 2003.

Significant events were:


	—	The Clair Phase 1 development (BP 28.6% and operator) produced first oil in February 2005. Drilling continues as part of the development programme.

	—	The Rhum project (BP 50% and operator) produced first gas in December 2005. This was the UK’s largest undeveloped gas discovery with initial production of 130 mmscf/d.


	—	In November 2005, BP achieved first oil in the $130 million development of the Farragon oil discovery (BP 50% and and operator), less than one year after Department of Trade and Industry (DTI) approval. The project is expected to achieve peak production at 18 mb/d.

	—	Progress continued on the Magnus Expansion Project (BP 85% and operator) with first oil expected in the second half of 2006.

	—	Drilling commenced in the first quarter of 2006 on the Schiehallion North West Area development project (BP 33.4% and operator). Three new wells will be drilled in the programme with first production expected by the end of 2006.

	—	BP, on behalf of the owners of North West Hutton (BP 26% and operator), submitted the proposed decommissioning programme to the DTI in November 2004. The proposal is still under review with platform removal expected to begin between 2007 and 2009.

	—	In December 2005, the UK government announced a 10% supplemental tax increase on North Sea oil profits, taking the total corporate tax rate to 50%. If this proposal is confirmed by the legislative process it is expected to have retroactive effect from January 1, 2006.

	—	In March 2006, we reached agreement for the sale of our 4.84% interest in the Statfjord oil and gas field. Completion of this sale is expected in the middle of 2006.


	*Rest of Europe*

Development expenditure, excluding midstream, in the Rest of Europe was $188 million compared with $262 million in 2004 and $236 million in 2003.


	Norway

In 2005, total Norway production was 82 mboe/d, a 2% decrease on 2004. This decrease in production was driven by natural decline partly offset by high operational efficiency on the BP operated Ula and Valhall fields.

Significant activities were:


	—	On February 28, 2005 we completed the sale of our 10.3% interest in the Ormen Lange development and our 10.2% interest in the Langeled gas export pipeline to the Danish utility company, DONG.

	—	Progress on the Valhall (BP 28.1% and operator) redevelopment project continued during 2005. A new platform is scheduled to become operational in 2009 with expected oil production capacity of 250 mb/d and gas handling capacity of 175 mmscf/d.

	—	In March 2006, we reached agreement for the sale of our interest in the Luva gas discovery, in the North Sea. This sale was completed in the second quarter of 2006.


	Netherlands

In May 2006, we announced our intention to sell our exploration and production and gas infrastructure business in the Netherlands. This includes onshore and offshore production assets and the onshore gas supply facility, Piek Gas Installatie, at Alkmaar. The sale is expected to be completed by the end of 2006, subject to consultation with the Works Council.


	*Rest of World*

Development expenditure, excluding midstream, in Rest of World was $3,735 million in 2005 compared with $3,082 million in 2004 and $3,085 million in 2003. We discuss the significant events and developments under each section below.


	Rest of Americas

Canada


	—	In Canada, our natural gas and liquids production was 63 mboe/d in 2005, a decrease of 11% compared to 2004. Theyear-on-year decrease in production is mainly due to natural field decline.

	—	On March 16, 2005, BP and Chevron sold Central Alberta Midstream, their jointly owned midstream gas processing business, to SemCAMS Midstream Company, a wholly owned subsidiary of SemGroup, L.P.

Trinidad


	—	In Trinidad, natural gas production volumes increased by 3%, to 1,987 mmscf/d in 2005. The increase was principally driven by a full year of gas supply to the Atlas Methanol plant (initialstart-up was in the third quarter 2004). Liquids production declined by 19 mb/d (32%), to 40 mb/d in 2005 mainly due to the divestment of the Teak, Samaan and Poui (TSP) fields and natural decline.

	—	Cannonball, Trinidad’s first major offshore construction project executed locally, started production in March 2006. Cannonball is currently providing gas for Atlantic LNG Train 4 (BP 37.8%), which commenced liquefaction in December 2005.

	—	In November 2005, we completed the sale of the TSP oil fields to Repsol YPF and the government of Trinidad. At the time of the sale, the TSP fields produced approximately 20.5 mboe/d which represented five per cent of Trinidad’s production of oil and gas.

Venezuela


	—	In Venezuela, our 2005 liquids production remained unchanged at 55 mb/d compared to 2004. Three of BP’s four base assets are reactivation projects (projects that are expected to continue and improve exploitation in mature fields) consisting of two operated properties, Boqueron and Desarollo Zulia Occidental (DZO), and one non-operated property, Jusepin, under Operating Service Agreements to produce oil for the state oil company, Petroleos de Venezuela S.A. (PDVSA). A fourth asset, Cerro Negro, is a non-operated property that is a heavy oil project from which production is sold directly by BP.

	—	In March 2006, BP signed Memoranda of Understanding to cooporate with PDVSA in setting up incorporated joint ventures in which PDVSA would be the majority shareholder. The incorporated joint ventures would become the operators of the Boqueron and DZO properties. It is expected that these arrangements will be finalized in the second half of 2006. The operator of Jusepin is aiming to enter into a similar agreement on behalf of the partners, including BP.

	—	In 2005, changes were made by the Venezuelan government to increase corporate income taxes on Oil Service Companies from 34% to 50%. In 2006, proposals have also been made by the government to increase corporate income taxes on Oil Extraction Companies from 34% to 50%, and to introduce a new Extraction Tax at a maximum rate of 33.33% (the existing royalty of 16.67% is expected to be offset against the new Extraction Tax).

	—	In March 2006, we settled for $14 million a dispute with the tax authorities regarding taxes on previous production.

Colombia


	—	In Colombia, BP’s net production averaged 55 mboe/d. The main part of the production comes from the Cusiana, Cupiagua and Cupiagua South Fields with increasing new production from the Cupiagua extension into the Recetor Association Contract and the Floreña and Pauto fields in the Piedemonte Association Contract. In March 2006, cumulative production from the BP operated fields reached 1 billion barrels since operations began in 1992.


	—	During 2005, the upgrade of the existing gas processing facilities (BP 24.8%) was completed, resulting in increased capacity from 40 to 180 mmscf/d.

Argentina and Bolivia


	—	In Argentina and Bolivia, activity is conducted through Pan American Energy (PAE), in which BP holds a 60% interest, and which is accounted for by the equity method. In 2005, total production of 136 mboe/d represented an increase of 5% over 2004, with oil increasing by 3% and gas by 7%. The main increase in oil production came from the continued focus on drilling and waterfloods in Golfo San Jorge in Argentina, where oil production was 58 mb/d compared to 56 mb/d in 2004. The field is now producing at its highest level since inception in 1958 and further expansion programmes are planned. PAE also has interests in gas pipelines, electricity generation plants and other midstream infrastructure assets.

	—	In Bolivia in May 2005, a new hydrocarbons law established a new production tax of 32% in addition to the existing 18% royalty. The tax was effective from May 19, 2005 and foreign oil and gas companies are required to sign new contracts conforming with the new law.

	—	In May 2006, the Bolivian government announced its intention to change contractual arrangements with foreign oil companies. The transitional arrangements are still being negotiated and the impact of these changes is being assessed.


	Africa

Algeria


	—	BP, through its joint operatorship of In Salah Gas with Statoil and the Algerian state company, Sonatrach, supplied 318 bcf (gross) of gas to markets in southern Europe during its first full year of production and started operations of the carbon dioxide (CO₂) capture system as part of the In Salah project (BP 33.15%). 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.

	—	BP, through its joint operatorship of In Amenas with Statoil and Sonatrach, continued to progress the development of the In Amenas project (BP 12.5%). First production was achieved in June 2006.

	—	Through Algeria’s sixth international licensing round, BP was awarded three exploration blocks, South East Illizi, Bourarhat South and Hassi Matmat.

Angola


	—	In Block 15 (BP 26.7%), Kizomba B commenced production in July 2005, four months ahead of schedule. Development of Kizomba C commenced in the first quarter of 2006.

	—	In Block 17 (BP 16.7%), development activities progressed on the Dalia project in line with expectations to commence production in the second half of 2006. Development on the Rosa project, a tie-back to Girassol hub, continued with first production planned for late 2007.

	—	In Block 18 (BP 50% and operator), work has continued on the Greater Plutonio development in line with expectations to commence production in 2007.

	—	In Block 31 (BP 26.7% and operator), a further four discoveries were made in 2005 and a further discovery was announced in 2006. There have been a total of ten discoveries that are at various stages of assessment of commercial viability.

Egypt


	—	In Egypt, the Gulf of Suez Petroleum Company (GUPCO), a joint venture operating company between BP and the Egyptian General Petroleum Corporation, carries out our operated oil and


		gas production operations. GUPCO operates eight PSAs in the Gulf of Suez and Western Desert and one PSA in the Mediterranean Sea encompassing more than forty fields.

	—	Following the blow-out and subsequent fire on the partner-operated Temsah North West platform (BP 50%) in the third quarter of 2004, the Temsah redevelopment progressed during 2005 with drilling completed in December. The project achieved first production ahead of schedule in the second quarter of 2006.

	—	In May 2005, BP and the Egyptian Ministry of Petroleum signed agreements to extend the Merged Concession Agreement by 20 years and the South Gharib concession by 10 years from the date of signing. These concessions represent approximately 80% of BP’s oil business in Egypt. These agreements will allow the maximization of the recovery of remaining reserves and provide for growth through future exploration activity.

	—	In the first quarter of 2005, BP sanctioned investment in the Saqqara field (BP 100%). The project is the development of the largest recent exploration success in Gulf of Suez. First production is expected in late 2007.


	Asia Pacific

Indonesia


	—	BP produces crude oil and supplies natural gas to the island of Java through its holding in the Offshore Northwest Java Production Sharing Agreement (BP 46%).

	—	During 2005, progress continued on the Tangguh LNG project (BP 37.2% and operator). The project development includes offshore platforms, pipelines and an LNG plant with two production trains. First gas is expected in late 2008.

Vietnam


	—	BP participates in the country’s largest project with foreign investment, the Nam Con Son gas project. This is an integrated resource and infrastructure project including offshore gas production, pipeline transportation system and power plant. In 2005, natural gas production was 346 mmcf/d gross, an increase of 39% over 2004. This increase was mainly due to high demand in the first half of the year as a result of an extended drought, which impacted hydro utilization. Gas sales from Block 6.1 (BP 35% and operator) are made under a long-term agreement for electricity generation in Vietnam, including the Phu My Phase 3 power plant (BP 33.33%).

	—	From January 1, 2006 BP’s interest in the Phu My Phase 3 power plant has been transferred to the Gas, Power and Renewables segment.

China


	—	The Yacheng offshore gas field (BP 34.3%) supplies, under a long-term contract, 100% of the natural gas requirement of Castle Peak Power Company, which provides around 50% of Hong Kong’s electricity. Some natural gas is also piped to Hainan Island, where it is sold to the Fuel and Chemical Company of Hainan, also under a long-term contract.

Australia


	—	We are one of six equal partners in the North West Shelf (NWS) Venture. Each partner holds a 16.7% interest in the infrastructure and oil reserves and a 15.8% interest in the gas reserves and condensate. The operation covers offshore production platforms, a floating production and storage vessel, trunklines, and onshore gas processing plants. The NWS Venture is currently the principal supplier to the domestic market in Western Australia. During 2005, a fifth LNG Train (4.7 million tonnes per annum design capacity) was sanctioned with first throughput expected in late 2008.


	Russia

TNK-BP


	—	TNK-BP (BP 50%) is an integrated oil company operating in Russia and the Ukraine. TNK-BP has proved reserves of 4.7 billion boe (including its 49.5% equity share of Slavneft), of which 3.8 billion are developed. In 2005, average liquids production was 1.8 million boe/d, an increase of just under 10% over 2004. Total production, including gas, exceeded 2 million boe/d for the first time in the third quarter of 2005. The production base is largely centered in West Siberia (Samotlor, Nizhnevartovskoye Neftedobyvarshee Predpriyatie, Nyagan and Megion), which contributes about 1.4 million boe/d, together with Volga Urals (Orenburg) contributing 0.4 million boe/d. About 55% of total oil production is currently exported as crude oil and 20% as refined product. Downstream, TNK-BP owns five refineries in Russia and the Ukraine (including Ryazan and Lisichansk), with throughput of 0.5 million barrels a day (25 million tonnes a year). In retail,TNK-BP supplies more than 2,100 filling stations in Russia and the Ukraine, with a share of the Moscow retail market in excess of 20%. The workforce currently is about 90,000 people.

	—	In December 2005, TNK-BP disposed of non-core producing assets in the Saratov region, along with the Orsk refinery and certain TNK-BP operated petrol stations. The disposals allow TNK-BP to streamline its operations and concentrate on strategic investments in projects with high-growth potential. This includes further extension drilling in the Ust Vakh area of the Samotlor field and in the Kamenoye field, as well as the greenfield Demiansky project in the Uvat area.

	—	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.

	—	BP’s investment in TNK-BP is held by the Exploration and Production business, and the results of TNK-BP are accounted for under the equity method in that segment.

	—	On January 14, 2005, TNK-BP announced the details of its plans to restructure the group in Russia. A new holding company — OAO TNK-BP Holding — has been formed and now owns TNK-BPs interests in OAO ONAKO, OAO Sidanco and OAO TNK. On March 1, 2005, shareholders of these latter three companies approved a scheme of accession to OAO TNK-BP Holding. Included in the announcement on January 14, were the terms of a voluntary offer to minority shareholders of 14 material subsidiaries of the TNK-BP group to exchange their shares for shares in OAO TNK-BP Holding. In September 2005, the voluntary exchange programme was completed with approximately 70% participation. In December 2005, the restructuring was completed with the accession of OAO ONAKO to OAO TNK-BP Holding. The restructuring has resulted in OAO TNK-BP Holding owning all the TNK-BP group’s material assets in Russia except for the group’s interests in OAO Rusia Petroleum, the OAO Slavneft group and the BP branded retail sites in Moscow and the Moscow region. TNK-BP will consider further accessions of material subsidiaries if these are believed to provide organizational advantages.

	—	On June 20, 2006 TNK-BP announced its intent to sell its interest in OAO Udmurtneft to Sinopec subject to various conditions.

Sakhalin


	—	BP participates in exploration activity through Elvaryneftegas (BP 49%), a joint venture with Rosneft. A first discovery was made in Sakhalin in October 2004, followed by a second in October 2005. Further exploratory drilling is planned during 2006.

Other

Middle East and Pakistan


	—	Production in the Middle East principally consists of the production entitlement of associates in Abu Dhabi, where we have equity interests of 9.5% and 14.7% in onshore and offshore concessions, respectively. In 2005, production in Abu Dhabi was 148 mb/d, up 4% from 2004 as a result of capacity enhancements and strong worldwide demand.

	—	In Pakistan, BP is one of the leading foreign operators producing 22% of the country’s oil and 6% of its natural gas on a gross basis in 2005.

Azerbaijan


	—	BP, as operator of the Azerbaijan International Operating Company (AIOC), manages and has a 34.1% interest in the Azeri-Chirag-Gunashli (ACG) oil fields in the Caspian Sea, offshore Azerbaijan. The Azeri project delivered first oil from central Azeri and West Azeri to Sangachal terminal on March 3, 2005 and January 3, 2006 respectively. Successive phases of the project include East Azeri scheduled to come on stream in 2007 and ACG Phase 3 — Deepwater Gunashli, which was approved in September 2004 and is expected to begin production in 2008.

	—	The Shah Deniz natural gas field (BP 25.5% and operator) remains on track to deliver first gas during the second half of 2006. The fourth and final pre-drill well was successfully suspended in January 2006, completing the Stage 1 pre-drill programme. The assembly and installation of the modules and associated equipment for the platform was completed in the first quarter of 2006 and installed on location in April. Commissioning and tie-in work for the platform, terminal and the South Caucasus Pipeline export pipelines is currently underway.

Midstream Activities


	*Oil and Natural Gas Transportation*

The Group has direct or indirect interests in certain crude oil transportation systems, the principal ones of which are the Trans Alaska Pipeline System (TAPS) in the USA and the Forties Pipelines System (FPS) in the UK sector of the North Sea. We also operate the Central Area Transmission System (CATS) for natural gas in the UK sector of the North Sea.

BP, as operator, manages and holds a 30.1% interest in the Baku-Tbilisi-Ceyhan (BTC) oil pipeline inaugurated in May 2005. BP, as operator of AIOC, also operates the Western Export Route Pipeline between Azerbaijan and the Black Sea coast of Georgia and the Azeri leg of the Northern Export Route Pipeline between Azerbaijan and Russia.

Our onshore US crude oil and product pipelines and related transportation assets are included under “Refining and Marketing” in this item. Revenue is earned on pipelines through charging tariffs. Our gas marketing business is described under “Gas, Power and Renewables” in this item.

Activity in oil and natural gas transportation during 2005 included:


	Alaska


	—	BP owns a 46.9% interest in TAPS, with the balance owned by four other companies. TAPS transported production from Alaska North Slope fields averaged 895 mb/d during 2005.

	—	Work progressed during 2005 on the strategic reconfiguration project to upgrade and automate four pump stations. This project will install electrically driven pumps at four critical pump stations, combined with increased automation and upgraded control systems. Startup of the reconfigured system is expected to occur in the fourth quarter of 2006.


	—	In December 2005, TAPS reached an operational milestone of transporting its 15 billionth barrel of oil.

	—	There are a number of unresolved protests regarding intrastate tariffs charged for shipping oil through TAPS. These protests were filed between 1986 and 2003 with the Regulatory Commission of Alaska (RCA). These matters are proceeding through the Alaska judicial and regulatory systems. Pending the resolution of these matters the RCA has imposed intrastate rates effective July 1, 2003 that are consistent with its 2002 Order requiring refunds to be made to TAPS shippers of intra-state crude oil.

	—	Tariffs for interstate and intrastate transportation on TAPS are calculated utilizing the Federal Energy Regulatory Commission (FERC) endorsed TAPS Settlement Methodology (TSM) entered into with the State of Alaska in 1985. In February 2006, FERC combined and consolidated all 2005 and 2006 rate complaints filed by the State, Anadarko, Tesoro and Tesoro Alaska. The complaints were filed on a variety of grounds. We are confident that the rates are in accordance with the TSM and are continuing to evaluate the disputes.

	—	The use of US-built and US-flagged ships is required when transporting Alaskan oil to markets in the USA. BP has begun replacing its US-flagged fleet as existing ships are retired in accordance with the Oil Pollution Act of 1990. For discussion of the Oil Pollution Act of 1990, see Environmental Protection — Maritime Oil Spill Regulations in this Item on page 70. BP has contracted for the delivery of four 1.3 million-barrel-capacity, double-hull tankers for use in transporting North Slope oil to West Coast refineries. The ships are being constructed by the National Steel and Shipbuilding Company in San Diego, CA. BP took delivery of the first of the fourstate-of-the-art double-hull tankers, the Alaskan Frontier, in August 2004, the second, the Alaskan Explorer, in March 2005 and the third, the Alaskan Navigator, in November 2005. The fourth is expected to be delivered in the second half of 2006.


	North Sea


	—	FPS (BP 100%) is an integrated oil and NGLs transportation and processing system that handles production from over 50 fields in the Central North Sea. The system has a capacity of more than 1 mmb/d, with average throughput in 2005 at 622 mb/d.

	—	BP operates and has a 29.5% interest in CATS, a 400-kilometre natural gas pipeline system in the central UK sector of the North Sea. The pipeline has a transportation capacity of 1.7 bcf/d to a natural gas terminal at Teesside in northeast England. CATS offers natural gas transportation services or transportation and processing via two 600 mmcf/d processing trains. In 2005, throughput was 1.14 bcf/d (gross), 336 mmcf/d (net).

	—	In addition, BP operates the Dimlington/ Easington gas processing terminal (BP 100%) on Humberside and the Sullom Voe Gas Terminal in the Shetlands.


	Asia (including the former Soviet Union)


	—	BP, as operator, manages and holds a 30.1% interest in the BTC oil pipeline. The 1,768 kilometre pipeline is expected to carry one million barrels of oil a day from the BP-operated ACG oilfield in the Caspian Sea to the eastern Mediterranean port of Ceyhan. Filling of the pipeline progressed during 2005 and loading of the first tanker at Ceyhan occurred in June 2006.

	—	The South Caucasus Pipeline for the transport of gas from Shah Deniz in Azerbaijan to the Turkish border is substantially complete. The pipeline is expected to be ready to receive first gas in the second half of 2006, in conjunction with thestart-up of Shah Deniz gas field. BP is the operator and holds a 25.5% interest.

	—	Through the LukArco joint venture, BP holds a 5.75% interest (with a 25% funding obligation) in the Caspian Pipeline Consortium (CPC) pipeline. CPC is a 1,510 kilometre pipeline from Kazakhstan to the Russian port of Novorossiysk and carries crude oil from the Tengiz field (BP 2.3%). In addition to our interest in LukArco, we hold a separate 0.87% interest (3.5%


		funding obligation) in CPC through a 49% holding in Kazakhstan Pipeline Ventures. In 2005, CPC total throughput reached 30.5 million tonnes. During 2005, negotiations continued between the CPC shareholders toward the approval of an expansion plan. The expansion will require the construction of ten additional pump stations, additional storage facilities and a third offshore mooring point.


	*Liquefied Natural Gas*

Within BP, Exploration and Production is responsible for the supply of LNG and the Gas, Power and Renewables business is responsible for the subsequent marketing and distribution of LNG (see details under Gas, Power and Renewables — New Market Development and LNG in this Item on page 63). BP Exploration and Production has interests in four major LNG plants. The Atlantic LNG plant in Trinidad (BP 34% in Train 1, 42.5% in Trains 2 and 3, and 37.8% in Train 4); in Indonesia through our interests in Sanga-Sanga PSA (BP 38%), which supplies natural gas to the Bontang LNG plant, and Tangguh (PSA, BP 37%), which is under construction; and in Australia through our share of LNG from the North West Shelf natural gas development (BP 16.7% infrastructure and oil reserves/15.8% gas and condensate reserves).

Significant activities during 2005 included the following:


	—	We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company, which in 2005 supplied 5.4 million tonnes (280 bcf) of LNG, down 8.5% on 2004.

	—	In Australia, we are one of six equal partners in the NWS Venture. Each partner holds a 16.7% interest in the infrastructure and oil reserves and a 15.8% interest in the gas reserves and condensate. The joint venture operation covers offshore production platforms, a floating production and storage vessel, trunklines, onshore gas processing plants and LNG carriers. In June 2005, we approved our investment in a fifth LNG train that is expected to process 4.7 million tonnes of LNG a year and will increase the plant’s capacity to 16.6 million tonnes a year. Construction started in July 2005 and the train is expected to be commissioned during the second half of 2008. NWS produced 11.7 million tonnes (533 bcf) of LNG, an increase of 26% on 2004.

	—	In Indonesia, BP is involved in two of the three LNG centres in the country. Firstly, BP participates in Indonesia’s LNG exports through its holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers around 17% of the total gas feed to Bontang, one of the world’s largest LNG plants. The Bontang plant produced 19.4 million tonnes (905 bcf) of LNG in 2005, a reduction of 1% on 2004.

	—	Also in Indonesia, BP has interests in the Tangguh LNG joint venture (BP 37% and operator) and in each of the Wiriagar (BP 38% and operator), Berau (BP 48% and operator) and Muturi (BP 1%) PSAs in Northwest Papua that will supply feed gas to the Tangguh LNG plant. In March 2005, Tangguh received key government approvals for the launch of two trains and is now executing the major construction contracts, withstart-up planned late in 2008. Tangguh is expected to be the third LNG centre in Indonesia, with an initial capacity of 7.6 million tonnes (388 bcf) per annum. Tangguh has signed sales contracts for delivery to China, Korea, and North America’s West Coast.

	—	In Trinidad, construction of the Atlantic LNG Train 4 (BP 37.8%) was completed in December 2005 with the first LNG cargo delivered in January 2006. Train 4 is now the largest producing LNG train in the world and is designed to produce 5.2 million tonnes (253 bcf) per annum of LNG. BP expects to supply at least two thirds of the gas to the train. The facilities will be operated under a tolling arrangement, with the equity owners retaining ownership of their respective gas. The LNG is expected to be sold in the USA, Dominican Republic, and other destinations at the option of the owners. BP’s net share of the capacity of Atlantic LNG Trains 1, 2, 3 and 4 is 6.5 million tonnes (305 bcf) of LNG per annum.

REFINING AND MARKETING

Our Refining and Marketing business is responsible for the supply and trading, refining, marketing and transportation of crude oil, petroleum and chemical products to wholesale and retail customers. BP markets its products in over 100 countries. We operate primarily in Europe and North America, but also market our products across Australasia and in parts of Southeast Asia, Africa and Central and South America.


	Year ended December 31,

	2005		2004		2003
-	)
							--($-
	million
Sales and other operating revenues for continuing operations		213,465		170,749		143,441
Profit before interest and tax from continuing operations (a)		6,442		6,544		3,235
Total assets		77,352		73,581		67,546
Capital expenditure and acquisitions		2,772		2,819		3,019
	($ per barrel)
Global Indicator Refining Margin (b)		8.60		6.31		4.08


(a)		Includes profit after interest and tax of equity-accounted entities.

(b)		The Global Indicator Refining Margin (GIM) is the average of regional industry indicator margins which we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. The refining margins are industry specific rather than BP specific measures, which we believe are useful to investors in analysing trends in the industry and their impact on our results. The margins are calculated by BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations and crude and product slate.

The changes in sales and other operating revenues are explained in more detail below:


		Year ended December 31,

		2005		2004		2003

Sale of crude oil through spot and term contracts	($ million)		36,992		21,989		22,224
Marketing, spot and term sales of refined products	($ million)		155,098		124,458		102,003
Other sales including non-oil and to other segments	($ million)		21,375		24,302		19,214

			213,465		170,749		143,441

Sale of crude oil through spot and term contracts	(mb/d)		2,464		2,312		2,387
Marketing, spot and term sales of refined products	(mb/d)		5,888		6,398		6,688

There are five areas of business in Refining and Marketing: Refining, Retail, Lubricants, Business to Business Marketing and Aromatics and Acetyls. Our strategy is to continue our focused investment in key assets and market positions. 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 to business sector.

Refining and Marketing manages a portfolio of assets that we believe are competitively advantaged across the chain of downstream activities. Such advantage may derive from several factors, including location (e.g. refinery proximity to market), operating cost and physical asset quality.

We are one of the major refiners of gasoline and hydrocarbon products in the USA, Europe and Australia. We have significant retail and business to business market positions in the USA, UK, Germany and the rest of Europe, Australasia, Africa and Southeast Asia and we are enhancing our presence in China. Refining and Marketing also includes the Aromatics and Acetyls business which maintains manufacturing positions globally, with an emphasis on Asia growth, particularly in China.

BP received citations from the US Occupational Safety and Health Administration (OSHA) in respect of the Texas City, Texas and Toledo, Ohio refineries. See Item 4 — Environmental Protection — Health, Safety and Environmental Regulation in this Item on page 68.

As a result of the sale of Innovene to INEOS, contracts were put in place for the sale and purchase of hydrocarbons, utilities and services between BP and INEOS, principally in the USA, UK, France, Belgium and the Netherlands. Agreements are in place between BP Refining and Marketing and INEOS at the Carson, Nerefco, Texas City, Toledo and Whiting refineries and the Geel chemical plant.

In June 2006, we announced our intention to sell the Coryton Refinery in the UK, which processes 172,000 barrels of crude oil a day.

In November 2005, BP and Sinopec established BP YPC Acetyls Company (BP 50%), a 500 thousand tonnes per annum (ktepa) acetic acid joint venture in Nanjing, China. The two companies previously signed a heads of agreement in May 2004 and a joint venture contract in March 2005. This world-scale joint venture is expected to be on stream at the end of 2007.

BP announced plans for a second purified terephthalic acid (PTA) plant at the BP Zhuhai Chemical Company Limited site in Guangdong Province, China, which received approval from the Chinese government in April 2006. The new plant will have operating capacity of 900,000 ktepa and is expected to come on stream at the end of 2007. It will be the first plant to use BP’s latest generation PTA technology.

The transaction announced in 2004 for the sale of BP’s 70% shareholding in BP Malaysia Sdn Bhd to Lembaga Tabung Angkatan Tentera (LTAT) was successfully concluded during 2005 and the disposal to Österreichische Mineralöl Verwaltung Aktiengesellschaft (OMV) of BP’s network of 70 retail sites in the Czech Republic, announced in October 2005, was completed in early 2006.

Resegmentation in 2006

Since the end of 2005, BP has made a number of organizational changes. With effect from January 1, 2006:


	—	Following the sale of Innovene to INEOS, the Shanghai SECCO Petrochemical Company Limited and Malaysia joint ventures, previously held in Other Businesses and Corporate, were transferred to Refining and Marketing.

	—	The formation of BP Alternative Energy has resulted in the transfer of certain mid-stream assets and activities to and from Gas, Power and Renewables:


	—	South Houston Green Power Cogeneration facility (in Texas City refinery) from Refining and Marketing to Gas, Power and Renewables.

	—	Watson Cogeneration facility (in Carson refinery) from Refining and Marketing to Gas, Power and Renewables.

	—	Transfer of Hydrogen for Transport from Gas, Power and Renewables to Refining and Marketing.

Texas City Refinery

On March 23, 2005, an explosion and fire occurred in the Isomerization Unit of BP Products North America, Inc.’s (BP Products) Texas City refinery as the unit was coming out of planned maintenance. Fifteen contractors died in the incident. Other contractors and employees were injured. In the third quarter of 2005, Texas City was the subject of a settlement with the U.S. Occupational Safety and Health Administration (OSHA), as BP Products and OSHA announced a settlement following OSHA’s investigations at the Texas City refinery after the March 23, 2005 explosion and fire. During 2005, BP Products made a provision of $700 million for fatality and personal injury compensation claims associated with the incident at its Texas City refinery. Following a review during the second quarter of 2006, an additional provision of $500 million was made which is reflected in the financial statements for the year ended December 31, 2005. See Item 18 — Financial Statements — Note 43 on pageF-114.

OSHA issued its citations alleging more than 300 violations of 13 different OSHA standards, and BP Products has agreed not to contest the citations. BP Products paid a $21.3 million fine and has undertaken a number of corrective actions designed to make the refinery safer. The settlement agreement addresses not only the March 23, incident, but also closes out other OSHA investigations at the refinery.

BP Products has agreed to:


	—	Hire a process safety expert at the refinery to review safety programs, offer recommendations and provide reports on the refinery’s progress;

	—	Hire an organizational expert at the refinery to study the refinery’s communication with respect to safety and commitment to safety and to offer recommendations for improvement;

	—	Improve health and safety training; and

	—	Develop an abatement plan addressing other corrective measures.

During 2005, the US Chemical Safety and Hazard Investigation Board recommended that BP appoint an independent panel to study the safety systems and cultures at its US refineries. BP’s chief executive, Lord Browne, commissioned a panel of eminent experts under the chairmanship of former US Secretary of State, James A Baker III, pursuant to this recommendation. BP is committed to providing complete co-operation to the Panel in support of this review. The Panel is expected to complete the review and present recommendations prior to the end of 2006. See also Environmental Protection — Health, Safety and Environmental Regulation in this Item on page 68 and Item 8 — Financial Information — Legal Proceedings on page 148.

In September 2005, hurricane Rita threatened the Texas City Refinery necessitating an entire plant shutdown. Hurricane Rita ultimately took a turn away from the refinery but the precautionary shutdown of an adjacent cogeneration facility, which provides the steam supply to the refinery, resulted in thermal cycling and damage to the Texas City plant’s27-mile steam system. This damage required extensive repair and maintenance to the steam system and on many gasoline production units. At the end of the year the plant’s steam system was restarted. Initial hydrocarbon production commenced at the end of March and ongoing recommissioning is planned to continue in a phased manner over the remainder of the year.

The site-wide shutdown of the Texas City refinery also impacted the Aromatics and Acetyls business’ co-located manufacturing capacity of paraxylenes (PX) and metaxylene. The PX unit resumed production in March and the metaxylene unit resumed in April, 2006. The remaining PX capacity at Texas City is expected to restart in line with the ongoing recommissioning of the refining units in a phased manner during 2006.

Refining

The Company’s global refining strategy is to own interests in and to operate strategically advantaged refineries that benefit from vertical integration with our marketing and trading operations as well as horizontal integration with other parts of the Group’s business. Refining’s focus is to maintain and improve competitive position through sustainable, safe, reliable and efficient operations of the refining system and disciplined investment for growth.

For BP, the strategic advantage of a refinery relates to the refinery’s location, the refinery’s scale and its configuration to produce fuels in line with the demand of the region from low-cost feedstocks. Efficient operations are measured primarily using regional refining surveys conducted by third parties. The surveys assess our competitive position against benchmarked industry measures for margin, energy efficiency and costs per barrel. Investments in our refineries are focused on maintaining our competitive position and developing the capability to produce the cleaner fuels that meet our customers’ and the communities’ requirements. Following the transfer of the Lavera, France and Grangemouth, UK, refineries from Refining and Marketing to Other businesses and corporate, effective January 1, 2005, our refining portfolio is weighted more heavily to the US, where margins are structurally higher.

The following table summarizes the BP Group interests and crude distillation capacities at December 31, 2005:


				Crude
				distillation
				capacities (a)

				(mb/d)
		Group interest (b)				BP
	Refinery	%		Total		share

UK	Coryton*		100.00		172		172

Total UK					172		172

Rest of Europe
France	Reichstett		17.00		84		14
Germany	Bayernoil		22.50		269		62
	Gelsenkirchen*		50.00		270		135
	Karlsruhe		12.00		308		37
	Lingen*		100.00		91		91
	Schwedt		18.75		230		43
Netherlands	Nerefco*		69.00		400		276
Spain	Castellón*		100.00		110		110

Total Rest of Europe					1,762		768

USA
California	Carson*		100.00		260		260
Washington	Cherry Point*		100.00		232		232
Indiana	Whiting*		100.00		405		405
Ohio	Toledo*		100.00		155		155
Texas	Texas City*		100.00		475		475

Total USA					1,527		1,527

Rest of World
Australia	Bulwer*		100.00		97		97
	Kwinana*		100.00		137		137
New Zealand	Whangerei		23.66		107		25
Kenya	Mombasa		17.00		90		15
South Africa	Durban		50.00		182		91

Total Rest of World					613		365

Total					4,074		2,832


*		Indicates refineries operated by BP.

(a)		Crude distillation capacity is gross rated capacity which is defined as the maximum achievable utilization of capacity(24-hour assessment) based on standard feed.

(b)		BP share of equity, which is not necessarily the same as BP share of processing entitlements.

The following table outlines by region the volume of crude oil and feedstock processed by BP for its own account and for third parties. Corresponding BP refinery capacity utilization data are summarized.


		Year ended December 31,

Refinery throughputs(a)		2005			2004			2003

		(thousand barrels per day)
UK			180			208			202
Rest of Europe			667			684			753
USA			1,255			1,373			1,386
Rest of World			297			342			382

Total			2,399			2,607			2,723

Refinery capacity utilization
Crude distillation capacity at December 31 (b)			2,832			2,823			2,983
Crude distillation capacity utilization (c)			87	%		93	%		91	%
	USA		82	%		95	%		91	%
	Europe		90	%		90	%		90	%
	Rest of World		88	%		87	%		94	%


(a)		Refinery throughput reflects crude and other feedstock volumes.

(b)		Crude distillation capacity is gross rated capacity which is defined as the maximum achievable utilization of capacity (24 hour assessment) based on standard feed.

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

BP’s 2005 refinery throughput decreased in the UK and Rest of Europe compared with 2004 primarily due to the transfer of the Grangemouth and Lavéra refineries from Refining and Marketing to the Olefins and Derivatives business reported within Other businesses and corporate, effective January 1, 2005. The decrease in the USA in 2005 was largely due to the impact of the shutdown of Texas City after hurricane Rita.

Marketing

Marketing comprises four business areas: Retail, Lubricants, Business to Business Marketing and Aromatics and Acetyls. We market a comprehensive range of refined products worldwide. These products include gasoline, gasoil, marine and aviation fuels, heating fuels, LPG, lubricants and bitumen. We also manufacture and market purified terephthalic acid, paraxylene, and acetic acid through our Aromatics and Acetyls business.


		Year ended December 31,

Sales of refined products(a)		2005		2004		2003

		(thousand barrels per day)
Marketing sales:
	UK (b)		355		322		275
	Rest of Europe		1,354		1,360		1,308
	USA		1,634		1,682		1,766
	Rest of World		599		638		620

Total marketing sales (c)			3,942		4,002		3,969
Trading/supply sales (d)			1,946		2,396		2,719

Total refined products			5,888		6,398		6,688

		($ million)
Proceeds from sale of refined products			155,098		124,458		102,002


(a)		Excludes sales to other BP businesses and the sale of Aromatics and Acetyls products.

(b)		UK area includes the UK-based international activities of Refining and Marketing.

(c)		Marketing sales are sales to service stations, end-consumers, bulk buyers, jobbers, i.e. third parties who own networks of a number of service stations and small resellers.

(d)		Trading/supply sales are sales to large unbranded resellers and other oil companies.

The following table sets out marketing sales by major product group:


	Year ended December 31,

Marketing sales by refined product	2005			2004		2003

	(thousand barrels per day)
Aviation fuel		499			494		530
Gasolines		1,603	��		1,675		1,714
Middle distillates		1,185			1,255		1,203
Fuel oil		379			343		296
Other products		276			235		226

Total marketing sales		3,942			4,002		3,969

Our aim is to increase total margin by focusing on both volumes and margin per unit. We do this by growing our customer base, both in existing and new markets, by attracting new customers and by covering a wider geographic area. We also work to improve the efficiency of our operations through reducing costs and improving our product mix. In addition, we recognize that our customers are demanding a wider choice of fuels, particularly fuels that are cleaner and more efficient. Through our integrated refining and marketing operations, we believe we are better able to meet these customer demands.

Marketing sales of refined products were 3,942 mb/d in 2005, compared with 4,002 mb/d in the previous year. The decrease was due mainly to the effects of the price increases as a result of supply disruption and market uncertainty.

BP enjoys a strong market share and leading technologies in the Aromatics and Acetyls business. In Asia, we continue to develop a strong position in PTA and acetic acids. Our investment is biased towards this high growth region, especially China.


	*Retail*

Our retail strategy focuses on investment in high growth metropolitan markets and the upgrading of our retail offers while driving operational efficiencies through portfolio optimisation.

There are two components of our retail offer: convenience and fuels. The convenience offer comprises sales of convenience items to customers from advantaged locations in metropolitan areas; whereas our fuels offer is deployed at locations in all our markets, in many cases without the convenience offer. We execute our convenience offer through a quality store format in each of our key markets, whether it is the BP Connect offer in Europe and the Eastern USA, the am/pm offer west of the Rocky Mountains in the USA, or the Aral offer in Germany. Each of these brands carries a very strong offer in itself, but we also aim to share best practices between them. Since 2003, we have also upgraded our fuel offer with the introduction of Ultimate gasoline and diesel products, which have greater efficiency and power and lesser environmental impact. In 2004 and 2005, we continued our roll-out of new generation Ultimate gasoline and diesel fuels, now available in the UK, Germany, Austria, Spain, Portugal, Greece, France, Poland, Turkey, Australia and the US.

We continue to focus on operational efficiencies through targeted portfolio upgrades for performance improvement that have increased our fuel throughput per site and our store sales per square meter. In 2005, across the network, same store sales growth at 1.9% exceeded estimated market growth of 0.8%.


	Year ended December 31,

Store sales(a)	2005		2004		2003

	($ million)
UK		628		655		567
Rest of Europe		3,069		3,090		3,000
USA		1,776		1,715		1,620
Rest of World		610		601		521

Total		6,083		6,061		5,708

Direct-managed		2,489		2,319		2,090
Franchise		3,533		3,623		3,508
Store alliances		61		119		110

Total		6,083		6,061		5,708


(a)	Store sales reported are sales through direct-managed stations, franchisees and the BP share of store alliances and joint ventures. Sales figures exclude sales taxes and lottery sales but includequick-service restaurant sales. Fuel sales are not included in these figures.

Our retail network is largely concentrated in Europe and the USA, with established operations in Australasia and Southern and Eastern Africa. We are developing networks in China with joint venture partners.


	Year ended December 31,

Retail Sites	2005		2004		2003

UK		1,300		1,300		1,300
Rest of Europe		7,900		8,000		8,200
USA (excluding jobbers)		3,100		3,900		4,100
USA jobbers		9,700		10,300		10,600
Rest of World		3,200		3,300		3,600

Total		25,200		26,800		27,800

BP’s worldwide network consists of over 25,000 locations branded BP, Amoco, ARCO and Aral compared with approximately 27,000 in the previous year. We expect the total number of sites carrying our brands to decline further in future years, reflecting the continued optimization of our retail network and efforts to increase the consistency of our site offer. We also continue to improve the efficiency of our retail asset network through a process of regular review. In 2005, we sold 488 Company owned sites (including all company owned sites in the Las Vegas, Washington and Detroit metro region) to dealers and jobbers who continue to operate these sites under the BP brand. We also divested 129 Company owned sites in 2005 and announced the divestment of BP’s Czech Republic retail network which was completed in early 2006.

In 2005, we continued the rollout of the BP Connect offer at sites in the UK and USA, consistent with our retail strategy of building on our advantaged locations, strong market positions and brand. The BP Connect sites include a distinctive food offer, large convenience store and a forecourt that provides our customers with cleaner fuels. The new BP Connect sites are those that are new to industry and those where extensive upgrading and remodeling has taken place. At December 31, 2005, over 630 BP Connect stations were open worldwide.

Through regular review and execution of business opportunities we continue to concentrate our ownership of real estate in markets designated for development of the convenience offer. At December 31, 2005, BP’s retail network in the USA comprised approximately 12,800 sites, of which approximately 9,700 were owned by jobbers. In the UK and the Rest of Europe, BP’s network comprised about 9,200 sites and 3,200 sites in the Rest of World.

The Joint Venture between BP and PetroChina (BP-PetroChina Petroleum Company Ltd) started operation in 2004. Located in Guangdong, one of the most developed provinces in China, 411 sites were operational at 31 December 2005. The JV plans to operate and manage a total network of 500 locations in the province. A Joint Venture with Sinopec, approved in the fourth quarter of 2004 with the establishment of BP-Sinopec (Zhejiang) Petroleum Co Ltd, commenced operations with 151 sites in Ningbo in 2005 with a further 71 sites transferred into the joint venture in May 2006. The JV plans to build, operate and manage a network of 500 sites in Hangzhou, Ningbo and Shaoxing.


	*Lubricants*

We manufacture and market lubricant products and also supply related products and services to business customers and end-consumers in over 60 countries directly, and to the rest of the world through local distributors. Our business is concentrated on the higher margin sectors of automotive lubricants, especially in the consumer sector, but also has a strong presence in business markets such as commercial vehicle fleets, aviation, marine and specialized industrial segments. Customer focus, distinctive brands and superior technology remain the cornerstone of our long-term strategy. BP markets through its two major brands, Castrol and BP, and several secondary brands including Duckhams, Veedol and Aral.

In the consumer sector of the automotive segment we supply lubricants, other products and related business services to intermediate customers (e.g., retailers, workshops) who in turn serve end-consumers (e.g., car, motorcycle and leisure craft owners) in the mature markets of Western Europe and North America and also in the fast growing markets of the developing world (e.g., Russia, China, India, Middle East, South America and Africa). The Castrol brand is recognized worldwide and we believe it provides us with a significant competitive advantage.

In commercial vehicle and general industrial markets we supply lubricants and lubricant-related services to the transportation industry and to automotive manufacturers.


	*Business to Business Marketing*

Business to Business Marketing encompasses marketing a comprehensive range of products to other businesses. This business aims to build relationships with customers that not only purchase a wide variety of products in large quantities but also additional services. Interfaces with Retail, Refining and Logistics play a crucial role in this business. We aim to attract more customers through innovation in multi-product offers and cleaner fuels, packaged with a range of value-added services and solutions.

Air BP is one of the world’s largest aviation businesses supplying aviation fuel and lubricants to the airline, military and general aviation sectors. It supplies customers in approximately 100 countries, has annual marketing sales of around 26,832 million liters (approximately 456,000 bbl/day) and has key relationships with most of the major commercial airlines. AirBP’s strategic aim is to strengthen its position in their existing markets (Europe/ US/ Asia Pacific) whilst creating opportunities in the emerging economies such as South America and China.

The LPG business sells bulk, bottled, automotive and wholesale products to a wide range of customers in over 16 countries. During the past few years, our LPG business has consolidated its position in established markets and pursued opportunities in new and emerging markets. BP remains one of the leading importers of LPG into the China market where we continued to grow our retail LPG business. LPG Marketing Product sales in 2005 were approximately 96,000 bbl/day.

Marine comprises three global businesses: Marine Fuels, Marine Lubricants, and Power Generation and Offshore, which supplies specialist lubricants to the power generation and offshore industry. Under the BP and Castrol brands, the business is the marine lubricants market leader and has a strong trading and bunker presence in the fuels market. The business has offices in 45 countries and operates in over 800 ports.

The Commercial Fuels business has activities in approximately 14 European countries and has marketing sales of approximately 616,000 bbl/day. The business markets fuels and heating oil, mostly aspick-up business at refineries, terminals and depots. As from 2006, this business will also manage the European Fleet services portfolio (serving commercial road transport customers).

Our Business to Business Marketing activities also include Industrial Lubricants (selling industrial lubricants and services to manufacturing companies in approximately 41 countries) and the supply of bitumen to the road and roofing industries. The business seeks to increase value by building from the technology, marketing and sales capabilities of a business to business operation.


	*Aromatics and Acetyls*

The Aromatics and Acetyls business is managed along three main products lines: PTA, PX, and Acetic Acid. PTA is a raw material for the manufacture of polyesters used in textiles, plastic bottles, fibres and films. PX is feedstock for the production of PTA. Acetic acid is a versatile chemical used in a variety of products such as paints, adhesives, and solvents. It is also used in the production of PTA. In addition to these three main products, we are involved in a number of other petrochemicals products namely napthalene dicarboxylate (NDC) which is used for photographic film and specialized packaging and ethyl acetate and vinyl acetate monomer (VAM) which are used in coatings and textile application.

Our Aromatics and Acetyls strategy is to invest to maintain our advantaged manufacturing positions globally, with an emphasis on Asia growth, particularly in China. We also work to advance our technology leadership position to yield both operating and capital cost advantages.

The following table shows BP production capacity at December 31, 2005. This production capacity is based on original design capacity of the plants plus expansions.


													Total — BP
							Acetic						share of
Geographical Area		PTA			PX		Acid			Other			capacity

		(thousand tonnes per year
UK
	Hull		—			—		677			664			1,341
Rest of Europe
Belgium
	Geel		1,044			520		—			—			1,564
USA
	Cooper River		1,330			—		—			—			1,330
	Decatur		1,100			1,121		—			27			2,248
	Texas City		—			1,282		527	(a)		122			1,931
Rest of World
Brazil
	São Paulo		143			—		—			—			143	(49% of Rhodiaco)
China
	Chongqing		—			—		169			52			221	(51% of YARACO) (b)
	Zhuhai		583			—		—			—			583
Indonesia
	Merak		250			—		—			—			250	(50% of PT Ami)
Korea
	Ulsan		550	(c)		—		229	(e)		56	(d)		835	(47% of SPC) (c);
															(34% of ASACCO) (d); (51% of SS-BP) (e)
	Seosan		339			—		—			—			339	(47% of SPC) (c)
Malaysia
	Kertih		—			—		544			—			544
	Kuantan		703			—		—			—			703
Taiwan
	Kaohsiung		825			—		—			—			825	(61% of CAPCO) (f)
	Taichung		458			—		—			—			458	(61% of CAPCO) (f)
	Mai Liao		—			—		162			—			162	(50% of FBPC) (g)

			7,325			2,923		2,308			921			13,477


(a)		Sterling Chemicals plant, the output of which is marketed by BP.

(b)		Yangtze River Acetyls Company.

(c)		Samsung-Petrochemicals Company Ltd.

(d)		Asian Acetyls Company Ltd.

(e)		Samsung-BP Chemicals Ltd.

(f)		China American Petrochemical Company Ltd.

(g)		Formosa BP Chemicals Corporation.

Further to the establishment of the BP YPC Acetyls Company and the plans for a second PTA plant at the BP Zhubai Chemical Company Limited site in Guandong Province, China, described previously, the following portfolio activity took place in the Aromatics and Acetyls business during the year:


	—	Yangtze River Acetyls Company (BP 51%) completed an expansion project in Chongqing, China in the third quarter of 2005 which increased capacity to 350 ktepa.

	—	A 300 ktepa acetic acid joint venture in Taiwan with Formosa Chemicals and Fibre Corporation (BP 50%) was successfully commissioned in December 2005.

	—	BP has announced the phased closure of two acetic acid plants at Hull, UK due to lack of scale and outdated technology. Combined capacity of the two plants was 380 ktepa. The first plant was shut down in the second quarter of 2005 and the remaining plant is expected to be shut down later in 2006.

	—	BP has announced that it is developing a 350 ktepa PTA expansion at Geel, Belgium. The project is expected to be operational in early 2008 and will increase the site PTA capacity to 1.4 ktepa.

Supply and Trading

The Group has a long established supply and trading activity responsible for delivering value across the overall crude and oil products supply chain. This activity identifies the best markets and prices for our crude oil, sources optimal feedstock to our refining assets and sources marketing activities with flexible and competitive supply. Additionally, the function creates incremental trading gains through holding commodity derivative contracts and trading inventory. To achieve these objectives in a liquid and volatile international market the Group enters into a range of commodity derivative contracts including exchange traded futures and options, over-the-counter options, swaps and forward contracts as well as physical term and spot contracts.

Exchange traded contracts are traded on liquid regulated markets which transact in key crude grades, such as Brent and West Texas Intermediate and the main product grades such as gasoline and gasoil. These exchanges exist in each of the key markets in the US, Western Europe and Far East. Over-the-counter contracts include a variety of options and most importantly swaps. These swaps price in relation to a wider set of grades than those traded through the exchanges where counterparties contract for differences between, for example, fixed and floating prices. The contracts we use are described in more detail below. Additionally, physical crude can be traded forward by using specific over-the-counter contracts pricing in reference to Brent and West Texas Intermediate grade. Over-the-counter crude forward sales contracts are used by BP to both buy and sell the underlying physical commodity as well as a risk management and trading instrument.

Risk management is undertaken when the Group is exposed to market risk primarily due to the timing of sales and purchases, which may occur for both commercial and operational reasons. For example, if the Group has delayed a purchase and has a lower than normal inventory level, the associated price exposure may be limited by taking an offsetting position in the most suitable commodity derivative contract described above. Where trading is undertaken, the Group actively combines a range of derivative contracts and physical positions to create incremental trading gains by arbitraging prices, typically between locations and time periods. This range of contract types includes futures, swaps, options and forward sale and purchase contracts, these contracts are described further below. The nature and purpose of this activity is broadly unchanged, though the volume of activity has grown slightly over the period 2003 to 2005.

Through these transactions the Group sells crude production into the market allowing more suitable higher margin crude to be supplied to our refineries. The Group may also actively buy and sell crude on a spot and term basis to further improve selections of crude for refineries. In addition, where refinery production is surplus to marketing requirements or can be sourced more competitively, it is sold into the market. This latter activity also encompasses opportunities to maximise the value of the

whole supply chain through the optimisation of storage and pipeline assets including the purchase of product components that are blended into finished products. The Group also owns and contracts for storage and transport capacity to facilitate this activity.

The range of transactions that the Group enters into is described below in more detail:


(a)	Exchange traded commodity derivatives

These contracts are typically in the form of futures and options traded on a recognized Exchange, such as Nymex, Simex, IPE and Chicago Board of Trade. Such contracts are traded in standard specifications for the main marker crude oils such as Brent and West Texas Intermediate and the main product grades such as gasoline and gas oil. Though potentially settled physically, these contracts are typically settled financially. Gains and losses, otherwise referred to as variation margins, are settled on a daily basis with the relevant Exchange. These contracts are used for the trading and risk management of both crude and products. Realized and unrealized gains and losses on exchange traded commodity derivatives are included in sales and other operating revenues for both IFRS and US GAAP.


(b)	Over-the-counter (OTC) contracts


	These contracts are typically in the form of forwards, swaps and options. OTC contracts are negotiated between two parties. They are not traded on an Exchange. These contracts can be used both as part of trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in sales and other operating revenues for both IFRS and US GAAP.

	The main grades of crude oil bought and sold forward using standard contracts are West Texas Intermediate and a standard North Sea crude blend (Brent, Forties and Osberg — BFO). Although the contracts specify physical delivery terms for each crude blend a significant volume are not settled physically. The contracts contain standard delivery, pricing and settlement terms. Additionally the BFO contract specifies a standard volume and tolerance given the physically settled transactions are delivered by cargo.

	Swaps are contractual obligations to exchange cash flows between two parties, one usually references a floating price whilst the other a fixed price with the net difference of the cash flows being settled. Options give the holder the right but not the obligation to buy or sell crude or oil products at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry, typically through netting agreements, to limit credit exposure and support liquidity.


(c)	Spot and term contracts

Spot contracts are contracts to purchase or sell crude and oil products at the market price prevailing on and around the delivery date. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. Spot transactions price around the bill of lading date when we take title to the inventory. These transactions result in physical delivery with operational and price risk. Spot and term contracts relate typically to purchases of crude for a refinery, sales of the Group’s oil production and sales of the Group’s oil products. For IFRS and US GAAP, spot and term sales are included in sales and other operating revenues, when title passes. Similarly, spot and term purchases are included in purchases for IFRS and US GAAP.

Refer to Item 11 — Quantitative and Qualitative Disclosures About Market Risk on page 162 for further information.

Transportation

Our Refining and Marketing business owns, operates or has an interest in extensive transportation facilities for crude oil, refined products and petrochemical feedstock.

We transport crude oil to our refineries principally by ship and through pipelines from our import terminals. We have interests in crude oil pipelines in Europe and in the US.

Bulk products are transported between refineries and storage terminals by pipeline, ship, barge, and rail. Onward delivery to customers is primarily by road. We have interests in major product pipelines in the UK, the Rest of Europe and in the US.

Shipping

We transport our products across the world’s oceans and along coastlines using a combination of BP operated vessels, time chartered and spot chartered vessels. In 2005, we continued to implement our strategy of increasing our operated shipping fleet in order to manage more effectively the risk of a major oil spill. This fleet transformation is ahead of the international requirements for phase-out of single-hulled vessels. See Environmental Protection — Maritime Oil Spill Regulations in this Item on page 70.


	*International Fleet*

In 2004, we managed an international fleet of 42 vessels including 34 Oil Tankers and eight LNG Gas Carriers. At the end of 2005 we had 52 international fleet vessels including 39 Medium Size Crude Carriers, four Very Large Crude Carriers, one North Sea Shuttle Tanker and eight LNG Gas Carriers. All of these are double-hulled. Of the eight LNG Carriers, BP manages five on behalf of joint ventures in which it is a participant and operates three LNG Carriers with a further four on order.


	*Regional and Specialist Vessels*

In addition to the international fleet we took delivery of a new double-hulled lube oil barge, three tugs and two offshore support vessels in 2005, to support BP businesses.

In Alaska, the leases on four vessels expired. We have taken delivery of the second and third of a four ship series of state of the art double-hulled tankers; the fourth and final one to be delivered into service later in 2006. The entire Alaska fleet of six vessels is now double-hulled.

The phase-out plan for the four heritage Amoco barges in the US was finalized in 2005 for completion in 2007.


	*Time Charter Vessels*

BP has 81 vessels on time charter, of which 66 are double-hulled and three double-bottomed. All of these vessels are enrolled in BP’s Time Charter Assurance programme which requires compliance with our HSSE requirements. We also spot charter additional vessels which are vetted prior to use to ensure they meet our safety and integrity standards.

The majority of our coastal vessels are time chartered. For example, in the UK, we completed the phase out of our single-hull tankers and replaced them with three new double-hulled coastal tankers on long term time charter.

For Greek and Turkish coastal trades, BP has partnered with two high-quality local operators and entered into time charters to provide ten new-build double-hulled coastal tankers.

GAS, POWER AND RENEWABLES

The strategic purpose of the Gas, Power and Renewables segment comprises three elements:


	i.	To capture distinctive world-scale gas market positions by accessing key pieces of infrastructure.

	ii.	To expand gross margin by providing distinctive products to selected customer segments and optimizing the gas and power value chains.

	iii.	To develop the world’s leading low-carbon power generation and wholesale marketing and trading businesses.

In 2005, the segment was organized into four main activities: marketing and trading; natural gas liquids (NGL); new market development and LNG; and solar and renewables. On January 1, 2005, a small US operation, the Hobb fractionator, which supplies petrochemicals feedstock was transferred from Gas, Power and Renewables to the Olefins and Derivatives business reported within Other businesses & corporate. The 2004 and 2003 data below has been restated to reflect this transfer.


	Year ended December 31,

	2005		2004		2003

	($ million)
Sales and other operating revenues from continuing operations		25,557		23,859		22,568
Profit before interest and tax from continuing operations (a)		1,104		954		578
Total assets		28,441		17,257		10,859
Capital expenditure and acquisitions		235		524		439


(a)		Includes profit after tax of equity-accounted entities.

The changes in sales and other operating revenues are explained in more detail below:


		Year ended December 31,

		2005		2004		2003

Gas marketing sales	($ million)		15,222		13,532		12,929
Other sales (including NGL marketing)	($ million)		10,335		10,327		9,639

	($ million)		25,557		23,859		22,568

Gas marketing sales volumes	mmcf/d		5,096		5,244		5,881
Natural gas sales by Exploration and Production	mmcf/d		4,747		3,670		3,923

We seek to maximize the value of our gas by targeting higher value customer segments in selected markets and to optimize supply around our physical and contractual rights to assets. Marketing and trading activities are focused on the relatively open and deregulated natural gas and power markets of North America, the United Kingdom and certain parts of continental Europe. Some small elements of long-term natural gas contracting activity are also still included within the Exploration and Production business segment because of the nature of gas markets and the long-term sales contracts.

New market development and LNG activities involve developing opportunities to capture sales for our upstream natural gas resources and are conducted in close collaboration with the Exploration and Production business. 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. Our strategy is to capture a greater share of the growth in the international demand for natural gas and is focused on markets which offer significant prospects for growth. For our undeveloped gas resources, we believe the key is to gain markets ahead of supply with a longer-term aim of allowing natural gas resources to move into the market with the same ease that oil does today. Our LNG activities involve the marketing of BP and third-party LNG.

Our NGLs business is engaged in the processing, fractionation and marketing of ethane, propane, butanes and pentanes extracted from natural gas. Our NGL activity is underpinned by our upstream asset base and serves third-party markets for both chemicals and clean fuels and also supplies BP’s refining activities. We have significant NGLs processing and marketing business in North America.

In response to the growing demand for cleaner fuels, BP is investing to offer a real alternative for the generation of power with low-carbon emissions. During the year, we announced our plans to invest in a new business called BP Alternative Energy, which aims to extend significantly our capabilities in solar, wind power, hydrogen power and gas-fired power generation. Our solar and renewables activities include the development, production and marketing of solar panels, the development of wind farms on certain Group sites, generation of electricity from hydrogen while reducing CO₂ emissions through its capture and storage underground and gas-fired power generation projects.

Capital expenditure for 2005 was $235 million compared with $524 million in 2004 and $439 million in 2003. Capital expenditure excluding acquisitions for 2006 is planned to be around $530 million. The increase versus the 2005 level is primarily due to investment in the Alternative Energy business.

Our policy toward natural gas price risk is described in Item 11 — Quantitative and Qualitative Disclosures About Market Risk on page 162.

Marketing and Trading Activities

Gas and power trading and marketing activity is undertaken in the US, Canada and the UK to dispose of BP’s gas and power production, manage market price risk, supply marketing customers as well as create incremental trading gains through the use of commodity derivative contracts. Additionally, this activity generates fee income and enhanced margins from sources such as the management of price risk on behalf of third party customers. These markets are large, liquid and volatile and the Group enters into these transactions on a large scale to meet these objectives.

In connection with the above activities, the Group uses a range of commodity derivative contracts and storage and transport contracts. These include commodity derivatives such as futures, swaps and options to manage price risk and forward contracts used to buy and sell gas and power in the market place. Using these contracts in combination with rights to access storage and transportation capacity allows the Group to access advantageous pricing differences between locations, time periods and arbitrage between markets. Gas futures and options are traded through exchanges whilst over-the-counter options and swaps are used for both gas and power transactions through bilateral arrangements. Futures and options are primarily used to trade the key index prices such as Henry Hub, whilst swaps can be tailored to price with reference to specific delivery locations where gas and power can be bought and sold. Over-the-counter forward contracts have evolved in both the US and UK markets enabling gas and power to be sold forward in a variety of locations and future periods. These contracts are used to both sell production into the wholesale markets and as trading instruments to buy and sell gas and power in future periods. The contracts we use are described in more detail below. Capacity contracts allow the Group to store, transport gas and transmit power between these locations. Additionally activity is undertaken to risk manage power generation margins related to the Texas City co-generation plant using a range of gas and power commodity derivatives.

The range of transactions that the Group enters into is described below in more detail:


(a)	Exchange traded commodity derivatives

Exchange traded commodity derivatives include gas and power futures contracts. Though potentially settled physically, these contracts are typically settled financially. Gains and losses, otherwise referred to as variation margins, are settled on a daily basis with the relevant Exchange. Realized and unrealized gains and losses on exchange traded commodity derivatives are included in sales and other operating revenues for both IFRS and US GAAP.


(b)	Over-the-counter (OTC) contracts


	These contracts are typically in the form of forwards, swaps and options. OTC contracts are negotiated between two parties. They are not traded on an Exchange. These contracts can be used both as part of trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in sales and other operating revenues for both IFRS and US GAAP.

	Highly developed markets exist in North America and the UK where gas and power can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price with delivery and settlement at a future date. Although these contracts specify delivery terms for the underlying commodity, in practice a significant volume of these transactions are not settled physically. This can be achieved by transacting offsetting sale or purchase contracts for the same location and delivery period that are offset during the scheduling of delivery or despatch. The contracts contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically volume is the main variable term.

	Swaps are contractual obligations to exchange cash flows between two parties, one usually references a floating price whilst the other a fixed price with the net difference of the cash flows being settled. Options give the holder the right but not the obligation to buy or sell crude or oil products at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry, typically through netting agreements, to limit credit exposure and support liquidity.


(c)	Spot and term contracts

Spot contracts are contracts to purchase or sell a commodity at the market price prevailing on the delivery date. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. Spot transactions price around the bill of lading date when we take title to the inventory. These transactions result in physical delivery with operational and price risk. Spot and term contracts relate typically to purchases of third party gas and sales of the Group’s gas production to third parties. For IFRS and US GAAP, spot and term sales are included in sales and other operating revenues, when title passes. Similarly, spot and term purchases are included in purchases for IFRS and US GAAP.

Refer to Item 5 — Operating and Financial Review — Gas, Power and Renewables on page 90 and Item 11 — Quantitative and Qualitative Disclosures About Market Risk on page 162 for further information.

North America

BP is one of the leading wholesale marketers and traders of natural gas in North America, the world’s largest natural gas market, a business which has been built on the foundation of our position as the continent’s leading producer of gas based on volumes. The gas activity in the US and Canada has grown as the Group increased its scale through both organic growth of operations and through the acquisition of smaller marketing and trading companies increasing reach into additional markets. At the same time this has occurred, the overall volumes in these markets have also increased. The Group also trades power in addition to selling and risk managing production from the Texas City co-generation facility in the US.

The scale of our gas and power businesses in North America grew over the period 2003 to 2005 because of a number of factors: (i) further establishing a position built on the market exit of two key competitors; (ii) our investment in transportation and storage facilities; (iii) expansion of our staff in our supply and trading activity and (iv) acquisitions of smaller trading and marketing companies. The OTC

market for NGLs developed during this period, but the scale of activity was not significant in the context of the Group’s overall operations or overall supply and trading activity.

Our North American natural gas marketing and trading strategy seeks to provide unconstrained market access for BP’s equity gas. Our marketing strategy targets higher value customer segments through fully utilizing our rights to store and transport gas. These assets include those owned by BP and those contractually accessed through agreements with third parties such as pipelines and terminals.

United Kingdom

The natural gas market in the UK is significant in size and is one of the most progressive in terms of deregulation when compared with other European markets. BP is one of the largest producers of natural gas in the UK based on volumes. The majority of natural gas sales are to power generation companies and to other gas wholesalers via long-term supply deals. Some of the natural gas continues to be sold under long-term natural gas supply contracts that were entered into prior to market deregulation. In addition to the marketing of BP gas, commodity derivative contracts are used actively in combination with assets and rights to store and transport gas to generate trading gains. This may include storing physical gas to sell in future periods or moving gas between markets to access higher prices. Commodity contracts such as over-the-counter forward contracts can be used to achieve this whilst other commodity contracts such as futures and options can be used to manage the market risk relating to changes in prices. Over the period 2003 to 2005 this activity has declined in line with an overall reduction in the liquidity of the traded markets.

In the first quarter of 2005 we sold our 10% interest in the Interconnector, a1.9-bcf/d,240-kilometre,40-inch diameter subsea natural gas pipeline between Bacton in the UK and Zeebrugge in Belgium.

Rest of Europe

We are building a natural gas and power marketing and trading business in Europe. Our interest in the European market is driven by the size and growth potential of the market, deregulation and the proximity of BP natural gas supplies.

In Europe, our main marketing activities are currently in Spain. The Spanish natural gas market has continued to grow and is now deregulated ahead of the deadlines set by European law. Since April 2000, we have built a market position which currently places us as the leading foreign entrant into the Spanish gas market. In July 2002, we purchased 5% of the shares in Enagas, the owner and operator of the majority of the high pressure Spanish gas transport grid and three of Spain’s four regasification terminals.

Natural Gas Liquids

BP is one of the leading producers and marketers of NGLs, based on sales volumes, in North America. NGLs, which are produced from gas chiefly sourced out of Alberta, Canada and the US onshore and Gulf Coast, are used as a heating fuel and as a feedstock for refineries and chemicals plants. NGLs are sold to petrochemical plants and refineries, including our own, at prevailing market prices. In addition, a significant amount of NGLs are marketed on a wholesale basis under annual supply contracts that provide for price redetermination based on prevailing market prices.

We operate natural gas processing facilities across North America with a total capacity of 6.4 billion cubic feet per day (bcf/d). These facilities, which we own or have an interest in, are located in major production areas across North America including Alberta, Canada, the US Rockies, the San Juan basin and coast of the Gulf of Mexico. We also own or have an interest in fractionation plants (which process the natural gas liquids stream into its separate component products) in Canada and the USA, and own or lease storage capacity in Alberta, Eastern Canada, the US Gulf Coast as well as West Coast and mid-

continent regions. Our NGL processing capacity utilization in 2005 was 70%, despite disruptions to supply following the Gulf of Mexico hurricanes.

In the UK we operate one plant and we are a partner (33.33%) in a gas processing plant in Egypt with 1.1 bcf/d of gas processing capacity, which commenced gas processing in the fourth quarter of 2004.

The Group established a NGL trading activity in 2002 to augment certain of our activities in the US. This activity is responsible for delivering value across the overall NGL supply chain, sourcing optimal feedstock to our processing assets and securing marketing activities with flexible and competitive supply but primarily to create incremental trading gains through using storage capacity, inventory and commodity derivative contracts by arbitraging seasonal price differences. To achieve this objective, a range of commodity derivative contracts includingover-the-counter options, swaps and physical forward contracts are used.

Over-the-counter contracts include a variety of options and most importantly swaps. These swaps price in relation to a wider set of products than can be achieved through the exchanges where counterparties contract for differences between, for example, fixed and floating prices. The contracts we use are similar to those for gas and power which are described in greater detail within the Marketing and Trading section above. Additionally, physical NGLs can be traded forward by using specificover-the-counter contracts. Over-the-counter forward sales contracts are used by BP to both buy and sell the physical commodity as well as a hedging tool and to arbitrage between the different markets. The scale and application of these contracts as described has increased from 2003 to 2005, flattening out in 2005, as this new activity has become established.

New Market Development and LNG

Our new market development and LNG activities are focused on establishing international market positions to create maximum value from our upstream natural gas resources and on capturing complementary third-party LNG supply to complement our equity flows.

BP Exploration and Production has interests in major existing LNG projects in Trinidad and Tobago, ADGAS in Abu Dhabi, the North West Shelf in Australia and we also supply gas (from Virginia Indonesia Co.) to the Bontang LNG project in Indonesia. Additional LNG supplies are being pursued through expansions of existing LNG plants in Trinidad and Tobago, the North West Shelf in Australia and greenfield developments such as Tangguh in Indonesia.

We continue to access major growth markets for the Group’s equity gas. In Asia Pacific, agreements for the supply of LNG from the Tangguh development (BP 37.16%) were signed with POSCO and K Power for supply to South Korea and with Sempra for supply to Mexico and US markets. Together with an earlier agreement to supply LNG to China, markets for more than 7 million tonnes a year (9.7 bcma) of Tangguh LNG have been secured. In March 2005, Tangguh received key government approvals for the two train launch and is now executing the major construction contracts, withstart-up planned in late 2008.

In the Atlantic and Mediterranean regions, significant progress was also made in creating opportunities to supply LNG to North American and European gas markets. In the UK, we, inco-operation with Sonatrach (the national oil company of Algeria), have access rights to the initial capacity of 0.45 bcf/d at the Isle of Grain terminal. The terminal was commissioned July 2005 with the first cargo sourced by BP. In Egypt, we signed an agreement with Egyptian Natural Gas Holding Company (EGAS) to purchase 1.45 billion cubic metres per year of LNG.

BP continues to progress options for new terminal development in the US. The most advanced is the proposed 1.2 billion cubic feet per day Crown Landing terminal to be located on the Delaware River in New Jersey. The Federal Energy Regulatory Commission (FERC) granted its approval for the siting, construction and operation of this project on June 15, 2006. BP continues to work with the state agencies in New Jersey to complete state permitting requirements and with the relevant federal, state

and local authorities to put in place security plans for the facility and associated shipping activities. BP is also monitoring the progress of a proceeding filed by the State of New Jersey against the State of Delaware in the United States Supreme Court concerning New Jersey’s jurisdiction over developments on its shores, including the project’s loading jetty that extends into the Delaware River. The Court has agreed to hear the case. This new access point to market, together with existing capacity rights at Cove Point in Maryland, US, Bilbao, Spain and Isle of Grain, UK, should provide important opportunities to maximize the value of the Group’s gas supplies from Trinidad, Egypt and elsewhere.

In Southeast China, the construction of the Guangdong LNG Terminal and Trunkline Project (BP 30%) continues on track. Pre-commissioning cargo arrived in early June 2006 with first commissioning cargo delivery expected around the middle of 2006. These are under the gas purchase agreement signed with Australia LNG in October 2002 that will involve deliveries from the North West Shelf project (BP 16.7% infrastructure and oil reserves/15.8% gas and condensate reserves).

Solar and Renewables

Global market trends indicate a general move towards greener energy sources, including solar, wind and hydrogen. BP intends to participate in this developing market.

2005 has seen strong industry demand for photovoltaic products, although constrained by the global shortage of polysilicon. In 2005, BP Solar achieved sales of 105 megawatts (MW) an increase of 6% versus 2004 (2004 99 MW and 2003 71 MW).

BP Solar’s main production facilities are located in Frederick, Maryland USA; Madrid, Spain; Sydney, Australia; and Bangalore, India. We are on track to expand our production capacity to 200MW by the end of 2006, with 140MW already built in support of our strategic growth plans announced in October 2004. The deployment of the additional capacity depends upon availability of polysilicon.

In China, BP Solar set up a joint venture with SunOasis to produce and market solar panels, aimed largely at bringing power to remote rural areas in China.

We are building expertise in wind energy and implementing wind projects on selected BP sites. In 2005, we completed construction of 9 MW wind farm at our oil terminal in Amsterdam, the Netherlands. We continue to operate our 22.5 MW wind farm at the Nerefco oil refinery (both the refinery and wind farm are jointly owned with Chevron (BP 69%)) in the Netherlands, which provides electricity to the local grid.

Other Activities

We participate in power projects that support the marketing and sale of our natural gas and in cogeneration projects (i.e., power plants that produce more than one type of energy, typically power and steam) on certain BP refining and manufacturing sites.

We operate a 776 MW gas-fired power generation facility and an associated LNG regasification facility at Bilbao, Spain (BP 25% share in each). The construction of K Power’s (BP 35%) 1,074 MW gas fired combined cycle power project at Gwangyang, Korea has continued andstart-up activities have commenced. Unit 1, having capacity of 535 MW, was commissioned in February 2005, whilst Unit 2, having the remaining capacity, is under testing and is expected to be commissioned in the third quarter of 2006. The 570 MW cogeneration plant at Texas City, Texas (50:50 joint venture with Cinergy Solutions, Inc.), which commenced operations in early 2004, supplies power and steam to BP’s largest refining and petrochemicals complex. BP supplies natural gas to the Texas City plant and will use excess generation capacity to support power marketing and trading activities. Following the explosion and fire at the Texas City refinery on March 23, 2005, the cogeneration plant was shut down. It was restarted as part of the refinery’s phased recommissioning in March 2006. The construction of a 50 MW cogeneration plant near Southampton, UK (BP 100%) is now complete and commercialstart-up took place in the first half of 2005.

In November 2005, we disposed of a 400 MW gas-fired power plant at Great Yarmouth in the UK (BP 100%).

OTHER BUSINESSES AND CORPORATE

Other businesses and corporate comprises Finance, the Group’s aluminium asset, its investments in PetroChina and Sinopec (both divested in early 2004), interest income and costs relating to corporate activities worldwide. In addition, for the periods shown, it included the portion of Olefins and Derivatives not included in the sale of Innovene to INEOS. This includes the equity-accounted investments in China (the SECCO petrochemicals complex) and Malaysia (Polyethylene Malaysia Sdn Bhd and Ethylene Malaysia Sdn Bhd). These investments were transferred to Refining and Marketing, effective January 1, 2006. On October 10, 2003 we completed the sale of our 50% interest in PT Kaltim Prima Coal to PT Bumi Resources.


	Year ended December 31,

	2005			2004		2003

	($ million)
Sales and other operating revenues for continuing operations		668			546		515
Profit (loss) before interest and tax from continuing operations (a)		(1,191	)		164		(253	)
Total assets		12,756			22,292		19,595
Capital expenditure and acquisitions		905			2,300		973


(a)		Includes profit after interest and tax of equity-accounted entities.

Financecoordinates the management of the Group’s major financial assets and liabilities. From locations in the UK, Europe, the USA and the Asia Pacific region, it provides the link between BP and the international financial markets and makes available a range of financial services to the Group including supporting the financing of BP’s projects around the world.

Aluminium. Our aluminium business is a non-integrated producer and marketer of rolled aluminium products, headquartered in Louisville, Kentucky, USA. Production facilities are located in Logan County, Kentucky and are jointly owned with Alcan Aluminum. The primary activity of our aluminium business is the supply of aluminium coil to the beverage can business.

Research, technology and engineeringactivities are carried out by each of the major business segments on the basis of a distributed programme coordinated by a technology coordination group. This body provides leadership for scientific, technical and engineering activities throughout the Group and in particular promotes cross-business initiatives and the transfer of best practice between businesses. In addition, a group of eminent industrialists and academics form the Technology Advisory Council, which advises senior management on the state of technology within the Group and helps identify current trends and future developments in technology.

Research and development is carried out using a balance of internal and external resources. Involving third parties in the various steps of technology development and application enables a wider range of technology solutions to be considered and implemented, improving the productivity of research and development activities.

Across the Group, expenditure on research for 2005 was $502 million, compared with $439 million in 2004 and $349 million in 2003.

Insurance. The Group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the Group. Losses will therefore be borne as they arise, rather than being spread over time through insurance premiums with attendant transaction costs. This position is reviewed periodically.

REGULATION OF THE GROUP’S BUSINESS

BP’s exploration and production activities are conducted in many different countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as licence acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licences and contracts under which these oil and gas interests are held vary from country to country. These leases, licences and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licences or production sharing agreements.

Licences (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a licence, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind.

Production sharing agreements entered into with a government entity or state company generally obligate BP to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any.

In certain countries, separate licences are required for exploration and production activities and, in certain cases, production licences are limited to a portion of the area covered by the exploration licence. Both exploration and production licences are generally for a specified period of time (except for licences in the United States which remain in effect until production ceases). The term of BP’s licences and the extent to which these licences may be renewed vary by area.

In general, BP is required to pay income tax on income generated from production activities (whether under a licence or production sharing agreement). In addition, depending on the area, BP’s production activities may be subject to a range of other taxes, levies and assessments, including special petroleum taxes and revenue taxes. The taxes imposed upon oil and gas production profits and activities may be substantially higher than those imposed on other activities, particularly in Angola, Norway, the UK, Russia, South America and Trinidad.

BP’s other activities are also subject to a broad range of legislation and regulations in various countries in which it operates.

Health, safety and environmental regulations are discussed in more detail in Environmental Protection in this Item on page 68.

ENVIRONMENTAL PROTECTION

Health, Safety and Environmental Regulation

The Group is subject to numerous national and local environmental laws and regulations concerning its products, operations and activities. Current and proposed fuel and product specifications under a number of environmental laws will have a significant effect on the production, sale and profitability of many of our products. Environmental laws and regulations also require the Group to remediate or otherwise redress the effects on the environment of prior disposal or release of chemicals or petroleum substances by the Group or other parties. Such contingencies may exist for various sites including refineries, chemicals plants, natural gas processing plants, oil and natural gas fields, service stations, terminals and waste disposal sites. In addition, the Group may have obligations relating to prior asset sales or closed facilities. Provisions for environmental restoration and remediation are made when aclean-up is probable and the amount is reasonably determinable. Generally, their timing coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provisions made are considered by management to be sufficient for known requirements.

The extent and cost of future environmental restoration, remediation and abatement programmes are often inherently difficult to estimate. They depend on the magnitude of any possible contamination, the timing and extent of the corrective actions required, technological feasibility and BP’s share of liability relative to that of other solvent responsible parties. Though the costs of future restoration and remediation could be significant, and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the Group’s overall results of operations or financial position. Refer to Item 18 — Financial Statements — Note 43 on page F-114 for the amounts provided in respect of environmental remediation and decommissioning.

The Group’s operations are also subject to environmental and common law claims for personal injury and property damage caused by the release of chemicals, hazardous materials or petroleum substances by the Group or others. Twenty two proceedings involving governmental authorities are pending or known to be contemplated against BP and certain of its subsidiaries under federal, state or local environmental laws, each of which could result in monetary sanctions of $100,000 or more. No individual proceeding is, nor are the proceedings as a group, expected to be material to the Group’s results of operations or financial position.

On March 23, 2005, an explosion and fire occurred in the Isomerization Unit of BP Products’ Texas City refinery as the unit was coming out of planned maintenance. Fifteen contractors died in the incident and many others were injured. In 2005, BP Products finalized, or is currently in process of negotiating, settlements in respect of fatalities and personal injury claims arising from the incident. The first trial of the unresolved claims is scheduled for September, 2006. The US Occupational Safety and Health Administration (OSHA), the US Chemical Safety and Hazard Investigation Board (CSB), the US Environmental Protection Agency and the Texas Commission on Environmental Quality, among other agencies, have conducted or are conducting investigations. At the conclusion of their investigation, OSHA issued citations alleging more than 300 violations of 13 different OSHA standards, and BP Products agreed not to contest the citations. BP Products settled that matter with OSHA on September 22, 2005, paying a $21.3 million penalty and undertaking a number of corrective actions designed to make the refinery safer. OSHA referred the matter to the US Department of Justice for criminal investigation, and the Department of Justice has opened an investigation. At the recommendation of the CSB, BP appointed an independent safety panel, the BP US Refineries Independent Safety Review Panel, under the chairmanship of James A Baker III. Other government legal actions are pending.

OSHA has also issued two OSHA citations to the BP Products’ Toledo, Ohio refinery on April 24, 2006. The penalty assessed for both citations was $2.4 million. The citations were based on two OSHA standards: the Process Safety Management Standard (29 CFR 1910.119) and the Hazardous (Classified) Locations Standard (29 CFR 1910.307). BP Products North America Inc. filed a notice of contest with OSHA on May 16, 2006 challenging the citations. This matter will be assigned to an administrative law

judge with the Occupational Safety and Health Review Commission, which is an agency independent of OSHA. The procedures followed before the Review Commission are similar to those followed in federal judicial cases.

On March 2, 2006, a crude oil spill of an estimated 4,200 to 4,800 bbls occurred on a low pressure transit line in Alaska’s North Slope Prudhoe Bay field operated by BP. The spill was reported to all the appropriate government agencies as soon as it was discovered and the portion of the line with the leak was shut down. The pipeline leak was caused by internal corrosion. The spill impacted approximately two acres of frozen tundra. Cleanup and rehabilitation of the area is complete and environmental damage to the tundra is expected to be minimal. US and State of Alaska investigations of the incident have been initiated. The Pipeline and Harzardous Materials Safety Administration (PHMSA), an agency of the US Department of Transportation, issued a Corrective Action Order to BP on March 15, 2006, regarding the three Prudhoe Bay oil transit lines and BP is in discussion with PHMSA on assuring compliance with the corrective actions outlined in the order.

Management cannot predict future developments, such as increasingly strict requirements of environmental laws and the resulting enforcement policies thereunder, that might affect the Group’s operations or affect the exploration for new reserves or the products sold by the Group. A risk of increased environmental costs and impacts is inherent in particular operations and products of the Group and there can be no assurance that material liabilities and costs will not be incurred in the future. In general, the Group does not expect that it will be affected differently from other companies with comparable assets engaged in similar businesses. Management believes that the Group’s activities are in compliance in all material respects with applicable environmental laws and regulations.

For a discussion of the Group’s environmental expenditures see Item 5 — Operating and Financial Review — Environmental Expenditure on page 91.

BP operates in over 100 countries worldwide. In all regions of the world, BP has processes designed to ensure compliance with applicable regulations. In addition, each individual in the Group is required to comply with BP health, safety and environment policies as embedded in the BP Code of Conduct. Our partners, suppliers and contractors are also encouraged to adopt them. The Group is working with the equity-accounted entity TNK-BP to develop management information to allow for the assessment and measurement of their activities in relation to health, safety and environment regulations and obligations. This document focuses primarily on the US and the EU, where approximately 65% of our property, plant and equipment is located, and on two issues of a global nature: climate change programmes and maritime oil spills regulations.

Climate Change Programmes

In December 1997, at the Third Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) in Kyoto, Japan, the participants agreed on a system of differentiated internationally legally binding targets for the first commitment period of 2008 to 2012. The Kyoto treaty came into force in 2005, committing the 156 participating countries to making emissions reductions and the EU Emissions Trading Scheme came into operation. However, Kyoto was only designed as a first step and policy makers are now discussing what new agreement might follow it in 2012 and how all significant countries can be involved. The issue was discussed by the G8 group of world leaders at their July summit and at the United Nations Climate Change meeting in Montreal in December. The impact of the Kyoto agreements on global energy (and oil and gas) demand is expected to be small (see International Energy Agency World Energy Outlook 2004).

Market mechanisms to allow optimum utilization of resources to meet the national Kyoto targets are being considered, developed or implemented by individual countries and also internationally through the EU. The relative success of these systems will determine the extent to which alternative fiscal or regulatory measures may be applied. Some EU member States have indicated that they require energy product taxes to enable them to meet their Kyoto commitments within the EU burden sharing agreement.

In July 2003, final agreement was reached on a Directive establishing a scheme for greenhouse gas (GHG) emission allowance trading within the EU, and in January 2005, the scheme entered into force, capping the GHG emissions of major industrial emitters. Member states have finalized their National Allocation Plans, setting out how emission allowances will be allocated. BP was well prepared for the EU emission trading system (ETS), building on our experiences from our own internal emissions trading system (operated between 1999-2001) and the UK ETS. We are approaching the EU ETS on a regional, integrated basis to optimize compliance and value for BP. We began the year with 30 participating operations but, following divestments in the fourth quarter, we ended 2005 with 18, which represent around a quarter of our reported global GHG emissions.

Since 1997, BP has been actively involved in policy debate. We also ran a global programme that reduced our operational GHG emissions by 10% between 1998 and 2001. We continue to look at two principal kinds of emissions: emissions generated from our operations such as refineries, chemicals plants and production facilities — operational emissions; and emissions generated by our customers when they use the fuels and products that we sell — product emissions. Since 2001 we have been aiming to offset, through energy efficiency projects, half of the underlying operational GHG emission increases that result from our growing business. After four years, we estimate that emissions growth of some 10 million tonnes has been offset by around 5 million tonnes of sustainable reductions. With regard to our products, in 2005 we announced our plans to invest $8 billion over 10 years in a business called BP Alternative Energy. This new business aims to lead the market in low-carbon power generated from the sun, wind, natural gas and hydrogen.

Maritime Oil Spill Regulations

Within the United States, the Oil Pollution Act of 1990 (OPA 90) imposes oil spill prevention requirements, spill response planning obligations and spill liability for tankers and barges transporting oil and for offshore facilities such as platforms and onshore terminals. To ensure adequate funding for response to oil spills and compensation for damages, when not fully covered by a responsible party, OPA 90 created a$1-billion fund which is funded by a tax on imported and domestic oil. In addition to federal law (OPA 90) which imposes liability for oil spills on the owners and operators of the carrying vessel, some states implemented statutes also imposing liability on the shippers or owners of oil spilled from such vessels. Alaska, Washington, Oregon and California are among these states. The exposure of BP to such liability is mitigated by the vessels’ marine liability insurance which has a maximum limit of $1 billion for each accident or occurrence. OPA 90 also provides that all new tank vessels operating in US waters must have double hulls and existing tank vessels without double hulls must be phased out by 2015. BP contracted with National Steel and Ship Building Company (NASSCO) for the construction of four double-hull tankers in San Diego, California. The first of these new vessels began service in 2004, demise chartered to and operated by Alaska Tanker Company (ATC) which transports BP Alaskan crude oil from Valdez. NASSCO delivered two more in 2005, and delivery of the last is expected in 2006. At the end of 2005, the ATC fleet consisted of six tankers, all double-hulled.

Outside the United States, the BP operated fleet of tankers is subject to international spill response and preparedness regulations that are typically promulgated through the International Maritime Organization (IMO) and implemented by the relevant flag state authorities. The International Convention for the Prevention of Pollution From Ships (Marpol 73/78) requires vessels to have detailed shipboard emergency and spill prevention plans. The International Convention on Oil Pollution, Preparedness, Response andCo-Operation requires vessels to have adequate spill response plans and resources for response anywhere the vessel travels to. These conventions and separate Marine Environmental Protection Circulars also stipulate the relevant state authorities around the globe that require engagement in the event of a spill. All of these requirements together are addressed by the vessel owners in Shipboard Oil Pollution Emergency Plans. BP Shipping’s liabilities for oil pollution damage under the United States Oil Pollution Act 1990 and outside the United States under the 1969/1992 International Convention on Civil Liability for Oil Pollution Damage (CLC) are covered by marine liability insurance having a maximum limit of $1 billion for each accident or occurrence. This insurance cover is provided by three mutual insurance associations (P&I Clubs), The United Kingdom

Steam Ship Assurance Association (Bermuda) Limited, The Britannia Steam Ship Insurance Association Limited and The Standard Steamship Owners’ Protection and Indemnity Association (Bermuda) Limited. With effect from February 20, 2006 two new complementary voluntary oil pollution compensation schemes were introduced by tanker owners, supported by their P&I Clubs, with the agreement of the International Oil Pollution Compensation Fund at the IMO. Pursuant to both of these schemes, tanker owners will voluntarily assume a greater liability for oil pollution compensation in the event of a spill of persistent oil than is provided for in CLC. The first scheme, The Small Tanker Owners’ Pollution Indemnification Agreement (STOPIA) provides for a minimum liability of 20 million Special Drawing Rights (around $29 million) for a ship at or below 29,548 gross tons, while the second scheme, The Tanker Owners’ Pollution Indemnification Agreement (TOPIA) provides for the tanker owner to take a 50% stake in the 2003 Supplementary Fund, i.e. an additional liability of up to 273.5 million Special Drawing Rights (around $406 million). Both STOPIA and TOPIA will only apply to tankers whose owners are party to these agreements and who have entered their ships with P&I Clubs in the International Group of P&I Clubs, thereby benefiting from those Clubs’ pooling and re-insurance arrangements. All of BP Shipping’s managed and time chartered vessels will participate in STOPIA and TOPIA.

At the end of 2005, the international fleet we managed numbered 44 oil tankers, all double-hulled with an average age of less than two years and eight LNG ships with an average age of seven years. The international fleet renewal programme will continue into the future and should see three new double-hulled oil tankers, four new very large liquefied petroleum gas carriers and four new liquefied natural gas carriers delivered between 2006 and 2008. In addition to its own fleet, BP will continue to charter quality ships; currently these vessels include both single and double-hulled designs but BP Shipping is accelerating the phase in of double-hulled vessels only by 2008; all vessels will continue to be vetted prior to each use as part of BP’s effort to ensure they are operated and maintained to meet BP’s standards.

United States Regional Review

The following is a summary of significant US environmental issues and legislation affecting the Group.

The Clean Air Act and its regulations require, among other things, stricter fuel specifications and sulphur reductions; enhanced monitoring of major sources of specified pollutants; stringent air emission limits and operating permits for chemical plants, refineries, marine and distribution terminals; and risk management plans for storage of hazardous substances. This law affects BP facilities producing, refining, manufacturing and distributing oil and products as well as the fuels themselves. Federal and state controls on ozone, particulate matter, carbon monoxide, benzene, sulphur, MTBE, nitrogen dioxide, oxygenates and Reid Vapor Pressure impact BP’s activities and products in the US. BP is continually adapting its business to these rules and has the know-how to produce quality and competitive products in compliance with their requirements. Beginning January 2006, all gasoline produced by BP will meet the Environmental Protection Agency’s (EPA’s) stringent low sulphur standards. Furthermore, by June 2006, at least 80% of the highway diesel fuel produced each year by BP will have to meet a sulphur cap of 15 parts per million (ppm) and then 100% beginning January 2010. By June 2007, all non-road diesel fuel production will have to meet a sulphur cap of 500 ppm and then 15 ppm by June 2012.

The Energy Policy Act of 2005 will also require several changes to the US fuels market with the following fuel provisions; elimination of the Federal Reformulated Gasoline (RFG) oxygen requirement in May 2006; establishment of a renewable fuels mandate — 4 billion gallons in 2006, increasing to 7.5 billion in 2012; consolidation of the summertime RFG VOC standards for Region 1 and 2; provision to allow the Ozone Transport Commission states on the east coast to opt any area into RFG; and a provision to allow states to repeal the 1 psi Reid Vapor Pressure waiver for 10 percent ethanol blends.

In 2001, BP entered into a consent decree with the EPA and several states that settled alleged violations of various Clean Air Act requirements related largely to emissions of sulphur dioxide and nitrogen oxides at BP’s refineries. Implementation of the decrees requirements continues.

In March 2003 and January 2005, the South Coast Air Quality Management District filed civil lawsuits against BP’s Carson, California refinery, seeking penalties of approximately $600 million for various alleged air quality violations. In March 2005, BP, without admitting liability, agreed to settle all outstanding claims for $25 million in cash penalties and approximately $6 million in past emissions fees. BP further agreed to provide $30 million over ten years in community benefit programmes and $20 million in new refinery projects aimed at reducing emissions. In 2005, BP paid approximately $56 million in environmental and safety fines and penalties in the US, over 90% of which was paid in settlement of matters in Texas and California.

A plea agreement between BP Exploration (Alaska) Inc. (BPXA) and the US Justice Department, and the associated period of organizational probation, ended on January 31, 2005. Pursuant to this plea agreement BPXA developed and implemented a nationwide environmental management system consistent with the best environmental practices at Group facilities engaged in oil exploration, drilling and/or production in the US and its territories.

The Clean Water Act is designed to protect and enhance the quality of US surface waters by regulating the discharge of wastewater and other discharges from both onshore and offshore operations. Facilities are required to obtain permits for most surface water discharges, install control equipment and implement operational controls and preventative measures, including spill prevention and control plans. Requirements under the Clean Water Act have become more stringent in recent years, including coverage of storm and surface water discharges at many more facilities and increased control of toxic discharges. New regulations are expected that could require, for example, modifications of water intake structures and additional wastewater treatment systems at some facilities.

The Resource Conservation and Recovery Act (RCRA) regulates the storage, handling, treatment, transportation and disposal of hazardous and non-hazardous wastes. It also requires the investigation and remediation of certain locations at a facility where such wastes have been handled, released or disposed of. BP facilities generate and handle a number of wastes regulated by RCRA and have units that have been used for the storage, handling or disposal of RCRA wastes that are subject to investigation and corrective action.

Under the Comprehensive Environmental Response, Compensation, and Liability Act (also known as CERCLA or Superfund), waste generators, site owners, facility operators and certain other parties are strictly liable for part or all of the cost of addressing sites contaminated by spills or waste disposal regardless of fault or the amount of waste sent to a site. Additionally, each state has laws similar to CERCLA.

BP has been identified as a Potentially Responsible Party (PRP) under CERCLA and similar state statutes at approximately 800 sites. A PRP has joint and several liability for site remediation costs under some of these statutes and so BP may be required to assume, among other costs, the share attributed to insolvent, unidentified or other parties. BP has the most significant exposure for remediation costs at 67 of these sites. For the remaining sites, the number of PRPs can range up to 200 or more. BP expects its share of remediation costs at these sites to be small in comparison to the major sites. BP has estimated its potential exposure at all sites where it has been identified as a PRP and has established provisions accordingly. BP does not anticipate that its ultimate exposure at these sites individually, or in aggregate, will be significant except as reported for Atlantic Richfield Company in the matters below.

The United States and the State of Montana seek to hold Atlantic Richfield Company liable for environmental remediation, related costs and natural resource damages arising out of mining-related activities by Atlantic Richfield’s predecessors in the upper Clark Fork River Basin (‘the basin’). The estimated future cost of performing selected and proposed remedies in certain areas in the basin will

likely exceed $350 million. In addition, EPA filed an action, entitled US vs. Atlantic Richfield Company, to recover past and future response costs that EPA incurred at the basin sites. In 2004, Atlantic Richfield agreed to pay $50 million plus interest to resolve EPA’s claims for past costs at most sites in the basin, and the parties’ consent decree settlement was approved by the court in January 2005. On a parallel track, a pending lawsuit by the state, entitled Montana vs. Atlantic Richfield Company, seeks to recover damages for alleged natural resources injuries in the basin. The United States also has claims for injury to natural resources on federal property. In 1999, Atlantic Richfield settled most of the State’s claims for damages, as well as all natural resource damage claims asserted by a local Native American Tribe. The parties have not resolved the United States’ claims, and they have not settled the State’s claims for approximately $182.5 million in restoration damages at three sites in the basin. Atlantic Richfield Company has challenged certain government cost estimates and asserted defences and counterclaims to certain remaining claims. Past settlements among the parties may provide a framework for possible future settlement of the remaining claims in the basin.

The Group is also subject to other claims for natural resource damages (NRD) under CERCLA, OPA, and other federal and state laws. NRD claims have been asserted by government trustees against a number of Group operations. This is a developing area of the law which could impact the cost of addressing environmental conditions at some sites in the future.

In the US, many environmental cleanups are the result of strict groundwater protection standards at both the state and federal level. Contamination or the threat of contamination of current or potential drinking water resources can result in stringent cleanup requirements, but some states have addressed contamination of nonpotable water resources using similarly strict standards. BP has encouraged risk-based approaches to these issues and seeks to tailor remedies at its facilities to match the level of risk presented by the contamination.

Other significant legislation includes the Toxic Substances Control Act which regulates the development, testing, import, export and introduction of new chemical products into commerce; the Occupational Safety and Health Act which imposes workplace safety and health, training and process standards to reduce the risks of physical and chemical hazards and injury to employees; and the Emergency Planning and CommunityRight-to-Know Act which requires emergency planning and spill notification as well as public disclosure of chemical usage and emissions. In addition, the US Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration, regulates in a comprehensive manner the transportation of the Company’s products such as gasoline and chemicals to protect the health and safety of the public.

BP is subject to the Marine Transportation Security Act and the Department of Transportation Hazardous Materials security compliance regulations in the United States. These regulations require many of our US businesses to conduct Security Vulnerability Assessments and prepare security mitigation plans which require the implementation of upgrades to security measures, the appointment and training of a designated security person and the submission of plans for approval and inspection.

BP has a national spill response team, the BP Americas Response Team (BART), consisting of approximately 250 trained emergency responders at Group locations throughout North America. Supporting the BART are six Regional Response Incident Management Teams and five HAZMAT Strike Teams. Collectively, these teams are ready to assist in a response to a major incident.

See also Item 8 — Financial Information — Consolidated Statements and Other Financial Information — Legal Proceedings on page 148.

European Union Regional Review

Within the EU, member states either apply the Directives of the European Commission directly or enact domestic provisions. By joint agreement, EU Directives may also be applied within countries outside Europe.

A European Commission Directive for a system of Integrated Pollution Prevention and Control (IPPC) was approved in 1996. This system requires permitting through the application of Best Available

Techniques (BAT) taking into account the costs and benefits. In the event that the use of BAT is likely to result in the breach of an environmental quality standard, plant emissions must be reduced further. All plants must have a permit in accordance with the requirements of the IPPC Directive by November 2007. The Directive encompasses most activities and processes undertaken by the oil and petrochemical industry within the EU and consequently requires capital and revenue expenditure across BP sites. The European Commission has embarked upon a process of review which will result in recommendations for amendments to the IPPC Directive in 2006.

The EU Large Combustion Plant Directive sets emission limit values for sulphur dioxide, nitrogen oxides and particulates from large combustion plants. It also required phased reductions in emissions from existing large combustion plants at the latest by April 1, 2001. A revised Large Combustion Plant Directive has been agreed and implementation was required by November 27, 2002. Plants will have to comply by 2008. The second important set of air emission regulations affecting BP European operations is the Air Quality Framework Directive and its three daughter Directives on ambient air quality assessment and management, which prescribe, among other things, ambient limit values for sulphur dioxide, oxides of nitrogen, particulate matter, lead, carbon monoxide, ozone, cadmium, arsenic, nickel, mercury and polyaromatic hydrocarbons. Measured or modelled exceedences of air quality limit values will require local action to reduce emissions and may impact any BP operations whose emissions contribute to such exceedences. The European commission has proposed a consolidation of framework and daughter directives together with the inclusion of additional requirements.

In 2005, The European Commission published its Thematic Strategy on Air Pollution (TSAP) and an accompanying proposal to consolidate existing ambient air quality legislation and introducing new controls on the concentration of fine particles (PM 2.5 — particulate matter less than 2.5 microns diameter) in ambient air. The TSAP outlines EU-wide objectives to reduce the health and environmental impacts of air quality and a wide range of measures to be taken. These measures include: the ambient air quality proposal mentioned above; revisions to the National Emissions Ceilings Directive; new emission limits for light and heavy duty diesel vehicles; new controls on smaller combustion plant; and further control of evaporative losses from vehicle refuelling at service stations.

The EU has set stringent objectives to control exhaust emissions from vehicles, which are being implemented in stages. Maximum sulphur levels for gasoline and diesel of 50 ppm and a 35% maximum aromatic content for gasoline were both agreed to apply from 2005. Agreement was reached in December 2002 on a further Directive to make petrol and diesel with a maximum sulphur content of 10 ppm mandatory throughout the EU from January 2009, and from 2005 member states will also have to supply low-sulphur fuel at enough locations to allow the circulation of new low-emission engines requiring the cleaner fuel. Further measures on sulphur levels of shipping fuels and/or reduction of emissions using such fuels started to take effect in 2006. Restrictions and measures include sulphur levels in fuels of 0.1% for inland vessels by January 2010 and 1.5% for passenger ships by May 19, 2006. The chief impact on BP is likely to arise from installation of flue gas desulphurization on ships and higher cost fuel. The overall impact is not expected to be material to the Group’s results of operations or financial position.

In Europe there is no overall soil protection regulation, although proposals on measures will be presented by the Commission in 2006. Certain individual member states have soil protection policies, but each has its own contaminated land regulations. There are common principles behind these regulations, including a risk based approach and recognition of costs versus benefits.

A European Commission proposal for new European chemical policy — REACH (Registration, Evaluation and Authorization of Chemicals) — was amended and voted separately at the end of 2005 by the European Council and Parliament. The remaining part of the adoption should present no significant obstacles and the new regulation is now expected to enter into force by mid-2007. All chemical substances manufactured or imported in the EU above 1 tonne per annum (about 30,000) will require a new pre-registration within the following 18 months, a registration within a 3 to 11- year time-phased period from adoption (actual date depends on volume bands or classification with high volumes and hazardous substances first). Only time-limited authorizations will be given to substances of ‘high

concern’. A new European Chemical Agency will be established in Helsinki by mid-2008. Crude oil and natural gas are exempt. For BP, REACH will impact all refining petroleum products, petrochemicals, lubricants and other chemicals. An initial estimate suggests costs in the range $50,000-100,000 each for the internal preparation, pre-registration and registration of several hundred substances and preparations.

The European Commission adopted a Directive on Environmental Liability on April 21, 2004. The proposal seeks to implement a liability approach for damage to biodiversity and land, and for services lost from high-risk operations by April 30, 2007. Member states are considering how to implement the regime. Possibilities of damage insurance, increased preventive provisions, injunctive relief and right of preventive action by third parties are also possible.

Other environment-related existing regulations which may have an impact on BP’s operations include: the Major Hazards Directive which requires emergency planning, public disclosure of emergency plans and ensuring that hazards are assessed, and effective emergency management systems are in place; the Water Framework Directive which includes protection of groundwater; and the Framework Directive on Waste to ensure that waste is recovered or disposed without endangering human health and without using processes or methods which could harm the environment.

PROPERTY, PLANTS AND EQUIPMENT

BP has freehold and leasehold interests in real estate in numerous countries throughout the world, but no one individual property is significant to the Group as a whole. See Exploration and Production heading under this Item for a description of the Group’s significant reserves and sources of crude oil and natural gas. Significant plans to construct, expand or improve specific facilities are described under each of the business headings within this Item.

ORGANIZATIONAL STRUCTURE

The significant subsidiary undertakings of the Group at December 31, 2005 and the Group percentage of ordinary share capital (to nearest whole number) are set out below. The principal country of operation is generally indicated by the company’s country of incorporation or by its name. Those held directly by the Company are marked with an asterisk (*), the percentage owned being that of the Group unless otherwise indicated. Refer to Item 18 — Financial Statements — Note 30 on page F-75, Item 18 — Financial Statements — Note 31 on page F-78 and Note 51 on page F-144 for information on significant joint ventures and associated undertakings of the Group.


		Country of
Subsidiaries	%	incorporation	Principal activities

International
BP Chemicals Investments	100	England	Petrochemicals
BP Exploration Operating Co.	100	England	Exploration and production
BP Global Investments*	100	England	Investment holding
BP International*	100	England	Integrated oil operations
BP Oil International	100	England	Integrated oil operations
BP Shipping*	100	England	Shipping
Burmah Castrol*	100	Scotland	Lubricants
Algeria
BP Amoco Exploration (In Amenas)	100	Scotland	Exploration and production
BP Exploration (El Djazair)	100	Bahamas	Exploration and production
Angola
BP Exploration (Angola)	100	England	Exploration and production
Australia
BP Oil Australia	100	Australia	Integrated oil operations
BP Australia Capital Markets	100	Australia	Finance
BP Developments Australia	100	Australia	Exploration and production
BP Finance Australia	100	Australia	Finance
Azerbaijan
Amoco Caspian Sea Petroleum	100	British Virgin Islands	Exploration and production
BP Exploration (Caspian Sea)	100	England	Exploration and production
Canada
BP Canada Energy	100	Canada	Exploration and production
BP Canada Finance	100	Canada	Finance
Egypt
BP Egypt Co.	100	US	Exploration and production
BP Egypt Gas Co.	100	US	Exploration and production
France
BP France	100	France	Refining and marketing and petrochemicals
Germany
Deutsche BP	100	Germany	Refining and marketing and petrochemicals


		Country of
Subsidiaries	%	incorporation	Principal activities

Netherlands
BP Capital	100	Netherlands	Finance
BP Nederland	100	Netherlands	Refining and marketing
New Zealand
BP Oil New Zealand	100	New Zealand	Marketing
Norway
BP Norge	100	Norway	Exploration and production
Spain
BP España	100	Spain	Refining and marketing
South Africa
BP Southern Africa*	75	South Africa	Refining and marketing
Trinidad
BP Trinidad (LNG)	100	Netherlands	Exploration and production
BP Trinidad and Tobago	70	US	Exploration and production
UK
BP Capital Markets	100	England	Finance
BP Chemicals	100	England	Petrochemicals
BP Oil UK	100	England	Refining and marketing
Britoil	100	Scotland	Exploration and production
Jupiter Insurance	100	Guernsey	Insurance
US
Atlantic Richfield Co.	100	US
BP America*	100	US
BP America Production Company	100	US
BP Amoco Chemical Company	100	US	Exploration and production, gas,
BP Company North America	100	US	power and renewables, refining
BP Corporation North America	100	US	and marketing, pipelines and
BP Products North America	100	US	petrochemicals
BP West Coast Products	100	US
The Standard Oil Company	100	US
BP Capital Markets America	100	US	Finance

ITEM 4A — UNRESOLVED STAFF COMMENTS

None.

ITEM 5 — OPERATING AND FINANCIAL REVIEW

GROUP OPERATING RESULTS


	Year ended December 31,

	2005		2004		2003

	($ million except per share
	amounts
Sales and other operating revenues from continuing operations (a)		239,792		192,024		164,653
Profit from continuing operations (a)		22,133		17,884		12,681
Profit for the year		22,317		17,262		12,618
Profit for the year attributable to BP shareholders		22,026		17,075		12,448
Profit attributable to BP shareholders per ordinary share — cents		104.25		78.24		56.14
Dividends paid per ordinary share — cents		34.85		27.70		25.50


(a)		Excludes Innovene which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. See Item 18 — Financial Statements — Note 5 on page F-35.

The business environment in 2005 was stronger than in 2004, with higher oil and gas realizations and higher refining and olefins margins but lower retail marketing margins.

Crude oil prices reached record highs in 2005 in nominal terms, driven by continued oil demand growth and low surplus oil production capacity. The dated Brent price averaged $54.48 per barrel, an increase of more than $16 per barrel above the $38.27 per barrel average seen in 2004, and varied between $38.21 and $67.33 per barrel. Hurricanes Katrina and Rita severely disrupted oil and gas production in the Gulf of Mexico for an extended period, but supply availability was maintained.

Natural gas prices in the US were also high during 2005 in the face of rising oil prices and hurricane-induced production losses. The Henry Hub First of the Month Index averaged $8.65 per mmbtu, up by around $2.50 per mmbtu compared with the 2004 average of $6.13 per mmbtu. High gas prices stimulated a fall in demand, especially in the industrial sector. UK gas prices were up strongly in 2005, averaging 40.71 pence per therm at the National Balancing Point, compared with a 2004 average of 24.39 pence per therm.

Refining margins also reached record highs in 2005, with the BP Global Indicator Margin averaging $8.60 per barrel. This reflected further oil demand growth and the loss of refining capacity as a result of the US hurricanes. The premium for light products above fuel oils remained exceptionally high, favouring upgraded refineries over less complex sites.

Retail margins weakened in 2005 as rising product prices and price volatility made their impact felt in a competitive marketplace.

The business environment in 2004 was affected by tight supplies in oil markets and by strong world economic growth.

The Brent price averaged $38.27 per barrel, an increase of more than $9 per barrel over the $28.83 per barrel average seen in 2003, driven by global oil demand growth and the physical disruption to US oil operations caused by hurricane Ivan. The price varied between $29.13 and $52.03 per barrel.

Natural gas prices in the US were stronger than in 2003. The Henry Hub First of the Month Index averaged $6.13 per mmbtu, up by more than $0.70 per mmbtu compared with the 2003 average of $5.37 per mmbtu. Prices fell slightly relative to oil prices as the levels of gas in storage rose sharply. UK gas prices were also up in 2004, averaging 24.39 pence per therm at the National Balancing Point compared with a 2003 average of 20.28 pence per therm.

Refining margins were high in 2004, despite weakening towards the end of the year. This reflected oil demand growth and higher refinery throughput levels. Retail margins weakened in 2004 compared with 2003, as rising product prices and price volatility made their impact in a competitive marketplace.

Business conditions in 2003 were affected by tight supplies in oil and gas markets and by the early signs of a world economic recovery, following two years of below-trend growth.

Average crude oil prices in 2003 were driven by supply disruptions in Venezuela, Nigeria and Iraq, OPEC market management and a recovery in oil demand growth following three exceptionally weak years. The Brent price averaged $28.83 per barrel, an increase of almost $4 per barrel over the $25.03 per barrel average seen in 2002 and moved in a range between $22.88 and $34.73 per barrel.

Natural gas prices in the USA were higher than in 2002. The Henry Hub First of the Month Index averaged $5.37 per mmbtu, up by more than $2 per mmbtu compared with the 2002 average of $3.22 per mmbtu. A combination of cold first quarter weather and weak domestic production kept working gas inventories relatively low for much of the year. UK gas prices were also up in 2003, averaging 20.28 pence per therm at the National Balancing Point versus a 2002 average of 15.78 pence per therm.

Refining margins weakened somewhat towards the end of the year reflecting low commercial product inventories in key US and European markets. Retail margins for the year were relatively strong, especially in the US and Europe. Petrochemicals margins remained depressed in 2003, coming under pressure from high feedstock prices.

Hydrocarbon production for subsidiaries decreased by 2.8% in 2005 reflecting a decrease of 3.9% for liquids and a decrease of 1.5% for natural gas. Increases in production in our new profit centres were more than offset by the effect of hurricanes, higher planned maintenance shutdowns and anticipated decline in our existing profit centres. Hydrocarbon production for equity-accounted entities increased by 7.8% reflecting an increase of 8.4% for liquids and an increase of 3.8% for natural gas. This increase primarily reflects increased production fromTNK-BP.

Hydrocarbon production for subsidiaries decreased by 7.2% in 2004, reflecting a decrease of 8.4% for liquids and a decrease of 5.8% for natural gas. The decrease includes 95 mboe/d impact of divestments. Hydrocarbon production for equity-accounted entities increased by 102% reflecting an increase of 108% for liquids and an increase of 69% for natural gas. This includes an increase of 108 mboe/d from the TNK-BP share of Slavneft from January 2004.

The increase in sales and other operating revenues (before the elimination of sales between businesses) for 2005 includes approximately $67 billion from higher prices related to marketing and other sales (spot and term contracts, petrochemicals products, oil and gas realizations and other sales) and $1 billion from foreign exchange movements due to sales in local currencies being translated into the US dollar. This was partly offset by a net decrease of approximately $11 billion from lower volumes of marketing and other sales and a decrease of around $1 billion related to lower production volumes of subsidiaries.

The increase in sales and other operating revenues (before the elimination of sales between businesses) for 2004 compared with 2003 includes approximately $44 billion from higher prices related to marketing and other sales (spot and term contracts, petrochemicals products, oil and gas realizations and other sales) and $8 billion from foreign exchange movements due to sales in local currencies being translated into the US dollar. This was partly offset by a net decrease of approximately $16 billion from lower volumes of marketing and other sales and a decrease of around $3 billion related to lower production volumes of subsidiaries.

Profit attributable to BP shareholders for the year ended December 31, 2005 was $22,026 million, including inventory holding gains of $3,027 million. Inventory holding gains or losses represent the difference between the cost of sales calculated using the average cost of supplies incurred during the year and the cost of sales calculated using thefirst-in first-out method. Profit attributable to BP

shareholders for the year ended December 31, 2004 was $17,075 million, including inventory holding gains of $1,643 million, and profit attributable to BP shareholders for the year ended December 31, 2003 was $12,448 million, including inventory holdings gains of $16 million.

The profit attributable to BP shareholders for the year ended December 31, 2005 includes profits from Innovene operations of $184 million, compared with losses of $622 million and $63 million in the years ended December 31, 2004 and December 31, 2003. The profit from Innovene for the year 2005 includes a loss on remeasurement to fair value of $591 million. Item 18 Financial Statements — Note 5 on page F-35 provides further financial information for Innovene.

Profit attributable to BP shareholders for the year ended December 31, 2005:


	—	includes net gains of $1,159 million on the sales of assets, primarily from our interest in the Ormen Lange field, and is after net fair value losses of $1,688 million on embedded derivatives, (these embedded derivatives are fair valued at each period end with the resulting gains or losses taken to the income statement), an impairment charge of $226 million in respect of fields in the Gulf of Mexico and a charge for impairment of $40 million relating to fields in the UK North Sea in Exploration and Production;

	—	includes net gains of $177 million principally on the divestment of a number of regional retail networks in the US, and is after a charge of $1,200 million in respect of fatality and personal injury compensation claims associated with the incident at the Texas City refinery on March 23, 2005, a charge of $140 million relating to new, and revisions to existing, environmental and other provisions, an impairment charge of $93 million and a charge of $33 million for the impairment of an equity-accounted entity in Refining and Marketing;

	—	includes net gains of $55 million primarily on the disposal of BP’s interest in Interconnector and the disposal of an NGL plant in the US, and is after net fair value losses of $346 million on embedded derivatives and a credit of $6 million related to new, and revisions to existing, environmental and other provisions in the Gas, Power and Renewables segment; and

	—	includes net gains on disposal of $38 million, and is after a net charge of $278 million related to new, and revisions to existing, environmental and other provisions and the reversal of environmental provisions no longer required, a charge of $134 million relating to the separation of the Olefins and Derivatives business and net fair value losses of $13 million on embedded derivatives in Other businesses and corporate.

Profit attributable to BP shareholders for the year ended December 31, 2004:


	—	is after an impairment charge of $267 million in respect of fields in the deepwater Gulf of Mexico and US onshore, an impairment charge of $108 million in respect of a gas processing plant in the USA and a field in the Gulf of Mexico Shelf, an impairment charge of $60 million in respect of the partner operated Temsah platform in Egypt following a blow-out, a net loss on disposal of $65 million, a charge of $35 million in respect of Alaskan tankers that are no longer required and, in addition, following the lapse of the sale agreement for oil and gas properties in Venezuela, $31 million of the previously booked impairment was reversed in Exploration and Production;

	—	is after net losses on disposal of $261 million, a charge of $206 million related to new, and revisions to existing, environmental and other provisions, a charge of $195 million for the impairment of the petrochemicals facilities at Hull, UK and a charge of $32 million for restructuring, integration and rationalization in Refining and Marketing;

	—	includes net gains on disposal of $56 million in the Gas, Power and Renewables segment; and

	—	includes net gains on disposal of $1,164 million primarily related to the sale of our interests in PetroChina and Sinopec and a credit of $66 million primarily resulting from the reversal of vacant space provisions in the UK and US, and is after a charge of $283 million related to new,


		and revisions to existing, environmental and other provisions and a charge of $102 million relating to the separation of the Olefins and Derivatives business in Other businesses and corporate.

Profit attributable to BP shareholders for the year ended December 31, 2003:


	—	includes net gains on disposal of $1,188 million, and is after impairment charges and asset writedowns of $1,013 million and restructuring charges of $117 million in Exploration and Production;

	—	is after a $369 million charge in relation to new, and revisions to existing, environmental and other provisions, Veba integration costs of $287 million, net losses on disposal of $214 million and a credit of $10 million arising from the reversal of restructuring provisions in Refining and Marketing;

	—	is after net losses on disposal of $6 million on Gas, Power & Renewables; and

	—	includes a credit of $648 million relating to a US medical plan, net gains on disposal of $139 million and a credit of $5 million resulting from a reduction in the provision for costs associated with the closure of polypropylene capacity in the USA, and is after a charge of $213 million in respect of new, and revisions to existing, environmental and other provisions and a charge of $110 million in respect of provisions for future rental payments on surplus property in Other businesses and corporate; and

	—	is after a credit of $280 million related to tax restructuring benefits.

Refer to Environmental Expenditure in this Item on page 91 for more information on environmental charges.

The primary additional factors contributing to the increase in profit attributable to BP shareholders for the year ended December 31, 2005 are higher liquids and gas realizations, higher refining margins and higher contributions from the operating business within the Gas, Power and Renewables segment; partially offset by lower retail marketing margins, higher costs (including the Thunder Horse incident, the Texas City refinery shutdown and planned restructuring actions) and significant volatility arising under IFRS fair value accounting.

In addition to the factors above, the increase in the 2004 result compared with 2003 primarily reflects higher liquids and gas realizations, higher refining margins with some offset from lower marketing margins, higher contributions from the natural gas liquids and solar businesses and the impact of higher oil and gas production volumes. These increases were partly offset by higher costs and portfolio impacts.

Profits and margins for the Group and for individual business segments can vary significantly from period to period as a result of changes in such factors as oil prices, natural gas prices and refining margins. Accordingly, the results for the current and prior periods do not necessarily reflect trends, nor do they provide indicators of results for future periods.

Through non-US subsidiaries, BP conducts limited marketing, licensing and trading activities and technical studies in Iran and with Iranian counterparties including the National Iranian Oil Company (NIOC) and affiliated entities and has a small representative office in Iran. BP believes that these activities are immaterial to the Group. In addition, BP has interests in, and is the operator for, two fields outside of Iran in which NIOC and an affiliated entity have interests. However, BP does not seek to obtain from the government of Iran licenses or agreements for oil and gas projects in Iran and does not own or operate any refineries or chemicals plants in Iran.

Employee numbers decreased from 103,700 at December 31, 2003 to 102,900 at December 31, 2004 to 96,200 at December 31, 2005. The decrease in 2005 resulted primarily from the sale of Innovene.


	Year ended December 31,

Capital expenditure and acquisitions	2005			2004			2003

	($ million)
Exploration and Production		10,149			9,654			9,398
Refining and Marketing		2,669			2,692			2,945
Gas, Power and Renewables		235			524			439
Other businesses and corporate		885			940			815

Capital expenditure		13,938			13,810			13,597
Acquisitions and asset exchanges		211			2,841			6,026

		14,149			16,651			19,623
Disposals		(11,200	)		(4,961	)		(6,356	)

Net investment		2,949			11,690			13,267

Capital expenditure and acquisitions in 2005, 2004 and 2003 amounted to $14,149 million, $16,651 million and $19,623 million, respectively. There were no significant acquisitions in 2005. Acquisitions during 2004 included $1,354 million for including TNK’s interest in Slavneft within TNK-BP and $1,355 million for the acquisition of Solvay’s interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America. Acquisitions in 2003 included $5,794 million for the acquisition of our interest in TNK-BP. Excluding acquisitions, capital expenditure for 2005 was $13,938 million compared with $13,810 million in 2004 and $13,597 million in 2003.

Finance Costs and Other Finance Expense

Finance costs comprises Group interest less amounts capitalized. Finance cost for continuing operations in 2005 was $616 million compared with $440 million in 2004 and $513 million in 2003. These amounts included a charge of $57 million arising from early redemption of finance leases in 2005 and a charge of $31 million in 2003 from early bond redemption. The charge for 2005 reflects higher interest costs partially offset by an increase in capitalized interest. The charge for 2004 reflects lower interest rates and lower debt buyback costs compared with 2003 offset by the inclusion of a full year’s equity-accounted interest for the TNK-BP joint venture.

Other finance expense includes net pension finance costs, the interest accretion on provisions and interest accretion on the deferred consideration for the acquisition of our investment in TNK-BP. Other finance expense for continuing operations in 2005 was $145 million compared with $340 million in 2004 and $532 million in 2003. The decrease in 2005 compared with 2004 primarily reflects a reduction in net pension finance costs. This is primarily due to a higher expected return on investment driven by a higher pension fund asset value at the start of 2005 compared with the start of 2004 while the expected long-term rate of return was similar. The decrease in 2004 compared with 2003 primarily reflects a reduction in net pension finance costs partly offset by a revaluation of environmental and other provisions at a lower discount rate and the inclusion of a full year’s charge for interest accretion on the deferred consideration for the investment in TNK-BP.

Taxation

The charge for corporate taxes for continuing operations in 2005 was $9,288 million, compared with $7,082 million in 2004 and $5,050 million in 2003. The effective rate was 30% in 2005, 28% in 2004 and 28% in 2003. The increase in the effective rate in 2005 is primarily due to a higher proportion of income in countries bearing higher tax rates, and other factors.

Business Results

Profit before interest and taxation from continuing operations, which is before finance costs, other finance expense, taxation and minority interests, was $32,182 million in 2005, $25,746 million in 2004 and $18,776 million in 2003.


	Exploration and Production


				Year ended December 31,

				2005		2004		2003

Sales and other operating revenues from continuing operations			($ million)		47,210		34,700		30,621
Profit before interest and tax from continuing operations (a)			($ million)		25,508		18,087		15,084
Results include:
	Exploration expense		($ million)		684		637		542
	Of which: Exploration expenditure written off		($ million)		305		274		297
Key statistics:
	Average BP crude oil realizations (b)
		UK	($ per barrel)		51.22		36.11		28.30
		USA	($ per barrel)		50.98		37.40		29.02
		Rest of World	($ per barrel)		48.32		34.99		26.91
		BP average	($ per barrel)		50.27		36.45		28.23
	Average BP NGL realizations (b)
		UK	($ per barrel)		37.95		31.79		20.08
		USA	($ per barrel)		31.94		25.67		18.39
		Rest of World	($ per barrel)		35.11		27.76		22.31
		BP average	($ per barrel)		33.23		26.75		19.26
	Average BP liquids realizations (b)(c)
		UK	($ per barrel)		50.45		35.87		27.80
		USA	($ per barrel)		47.83		35.41		27.23
		Rest of World	($ per barrel)		47.56		34.51		26.60
		BP average	($ per barrel)		48.51		35.39		27.25
	Average BP US natural gas realizations (b)
		UK	($ per thousand cubic feet)		5.53		4.32		3.19
		USA	($ per thousand cubic feet)		6.78		5.11		4.47
		Rest of World	($ per thousand cubic feet)		3.46		2.74		2.47
		BP average	($ per thousand cubic feet)		4.90		3.86		3.39
	Average West Texas Intermediate oil price		($ per barrel)		56.58		41.49		31.06
	Alaska North Slope US West Coast		($ per barrel)		53.55		38.96		29.59
	Average Brent oil price		($ per barrel)		54.48		38.27		28.83
	Average Henry Hub gas price (d)		($/mmbtu)		8.65		6.13		5.37
Total liquids production for subsidiaries (c)(e)			(mb/d)		1,423		1,480		1,615
Total liquids production for equity-accounted entities (c)(e)			(mb/d)		1,139		1,051		506
Natural gas production for subsidiaries (e)			(mmcf/d)		7,512		7,624		8,092
Natural gas production for equity-accounted entities (e)			(mmcf/d)		912		879		521
Total production for subsidiaries (e)(f)			(mboe/d)		2,718		2,795		3,011
Total production for equity-accounted entities (e)(f)			(mboe/d)		1,296		1,202		595


(a)		Includes profit after interest and tax of equity-accounted entities.

(b)		The Exploration and Production business does not undertake any hedging activity. Consequently, realizations reflect the market price achieved.

(c)		Crude oil and natural gas liquids.

(d)		Henry Hub First of Month Index.

(e)		Net of royalties.

(f)		Expressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Sales and other operating revenues for 2005 were $47 billion compared with $35 billion in 2004 and $31 billion in 2003. The increase in 2005 primarily reflected an increase of around $13 billion related to higher liquids and gas realizations partly offset by a decrease of around $1 billion due to slightly lower volumes of subsidiaries. The increase in 2004 reflected higher liquids and gas realizations of around $7 billion with an offset of around $3 billion due to lower production volumes (for subsidiaries) as a result of divestment activity in 2003.

Profit before interest and tax for the year ended December 31, 2005 was $25,508 million, including inventory holding gains of $17 million and gains of $1,159 million on the sales of assets, primarily from our interest in the Ormen Lange field, and is after net fair value losses of $1,688 million on embedded derivatives (these embedded derivatives are fair valued at each period end with the resulting gains or losses taken to the income statement), an impairment charge of $226 million in respect of fields in the Gulf of Mexico, a charge for impairment of $40 million relating to fields in the UK North Sea and a charge of $265 million on the cancellation of an intra-Group gas supply contract.

Profit before interest and tax for the year ended December 31, 2004 was $18,087 million, including inventory holding gains of $10 million, and is after an impairment charge of $267 million in respect of fields in the deepwater Gulf of Mexico and US onshore, an impairment charge of $108 million in respect of a gas processing plant in the USA and a field in the Gulf of Mexico Shelf, an impairment charge of $60 million in respect of the partner operated Temsah platform in Egypt following a blow-out, a net loss on disposal of $65 million and a charge of $35 million in respect of Alaskan tankers that are no longer required. In addition, following the lapse of the sale agreement for oil and gas properties in Venezuela, $31 million of the previously booked impairment was reversed.

Profit before interest and tax for the year ended December 31, 2003 was $15,084 million, including inventory holding gains of $3 million and net gains on disposal of $1,188 million (primarily related to gains on the sale of the UK North Sea Forties field together with a package of shallow water assets in the Gulf of Mexico and Repsol’s exercise of its option to acquire a further 20% interest in BP Trinidad & Tobago LLC and net losses resulting from the sale of various other upstream assets); and is after an impairment charge of $296 million for four fields in the Gulf of Mexico, following technical reassessment and re-evaluation of future investment options; impairment charges of $133 million and $49 million respectively for the Miller and Viscount fields in the UK North Sea as a result of a decision not to proceed with waterflood and gas import options and a reserve write-down respectively; an impairment charge of $105 million for the Yacheng field in China; an impairment charge of $108 million for the Kepadong field in Indonesia; and an impairment charge of $47 million for the Eugene Island/ West Cameron fields in the US as a result of reserve write-downs following completion of our routine full technical reviews. In addition, there were impairment charges of $217 million and $58 million for oil and gas properties in Venezuela and Canada respectively, based on fair value less costs to sell for transactions expected to complete in early 2004. Furthermore, there were restructuring charges of $117 million in respect of ongoing restructuring activities in the UK and North America.

In addition to the factors above, the primary reasons for the increase in profit before interest and tax for the year ended December 31, 2005 compared with the year ended December 31, 2004 are higher liquids and gas realizations contributing around $10,100 million and around $400 million from higher volumes (in areas not affected by hurricanes), offset partly by a decrease of around $900 million due to the hurricane impact on volumes, costs associated with hurricane repairs and Thunder Horse of around $200 million, and higher operating and revenue investment costs of around $1,700 million.

The primary additional reasons for the increase in profit before interest and tax for 2004 compared with 2003 are higher liquids and gas realizations of around $5,150 million combined with an increase of $400 million due to higher volumes, partly offset by adverse foreign exchange impacts and inflationary pressures of around $350 million, higher costs of around $650 million and increased equity-accounted interest and tax charges of around $1,000 million. The result of TNK-BP was included for a full-year in 2004 compared with four months in 2003.

Total production for the year 2005 was 2,718 mboe/d for subsidiaries and 1,296 mboe/d for equity-accounted entities compared with 2,795 mboe/d and 1,202 mboe/d respectively, a year ago. For subsidiaries, increases in production in our new profit centres were more than offset by the effect of the hurricanes, higher planned maintenance shutdowns and anticipated decline in our existing profit centres. For equity-accounted entities, this primarily reflects growth from TNK-BP.

Actual production for subsidiaries and equity-accounted entities in 2005, after adjusting for the impact of severe weather and the impact of higher prices on production sharing contracts, was 2,849 mboe/d and 1,296 mboe/d, respectively, compared with the range of between 2.85 and 2.9 mmboe/d for subsidiaries and between 1.25 and 1.3 mmboe/d for equity-accounted entities as previously indicated.

Total production for 2004 was 2,795 mboe/d for subsidiaries and 1,202 mboe/d for equity-accounted entities, compared with 3,011 mboe/d and 595 mboe/d, respectively, in 2003. For subsidiaries, the 7.2% decrease includes 95 mboe/d impact of divestments and for equity-accounted entities the increase of 102% includes an increase of 108 mboe/d from the TNK-BP share of Slavneft from January 2004.


	Refining and Marketing


			Year ended December 31,

			2005		2004		2003

Sales and other operating revenues from continuing operations		($ million)		213,465		170,749		143,441
Profit before interest and tax from continuing operations (a)		($ million)		6,442		6,544		3,235
Global Indicator Refining Margin (b)
	Northwest Europe	($/bbl)		5.47		4.28		2.62
	US Gulf Coast	($/bbl)		11.40		7.15		4.71
	Midwest	($/bbl)		8.19		5.08		4.54
	US West Coast	($/bbl)		13.49		11.27		7.06
	Singapore	($/bbl)		5.56		4.94		1.77
	BP average	($/bbl)		8.60		6.31		4.08
Refining availability (c)		(%)		92.9		95.4		95.5
Refinery throughputs		(mb/d)		2,399		2,607		2,723


(a)		Includes profit after interest and tax of equity-accounted entities.

(b)		The Global Indicator Refining Margin (GIM) is the average of regional industry indicator margins which we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. The refining margins are industry specific rather than BP specific measures, which we believe are useful to investors in analysing trends in the industry and their impact on our results. The margins are calculated by BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations and crude and product slate.

(c)		Refining availability is the weighted average percentage of the period that refinery units are available for processing, after taking account of downtime such as planned maintenance.

The changes in sales and other operating revenues are explained in more detail below:


		Year ended December 31,

		2005		2004		2003

Sale of crude oil through spot and term contracts	($ million)		36,992		21,989		22,224
Marketing, spot and term sales of refined products	($ million)		155,098		124,458		102,003
Other sales including non-oil and to other segments	($ million)		21,375		24,302		19,214

			213,465		170,749		143,441

Sale of crude oil through spot and term contracts	(mb/d)		2,464		2,312		2,387
Marketing, spot and term sales of refined products	(mb/d)		5,888		6,398		6,688

Sales and other operating revenues for 2005 was $213 billion compared with $171 billion in 2004 and $143 billion in 2003. The increase in 2005 compared with 2004 was principally due to an increase of around $31 billion in marketing, spot and term sales of refined products. This was due to higher prices of $39 billion and a positive foreign exchange impact due to a weaker dollar of $1 billion, partly offset by lower volumes of $9 billion. Additionally, sales of crude oil, spot and term contracts increased by $15 billion due to higher prices of $13 billion and higher volumes of $2 billion and other sales decreased by $3 billion, primarily due to lower volumes. The $28 billion increase in turnover in 2004 compared to 2003 was primarily due to due an increase in marketing, spot and term sales of refined products of around $23 billion. This was due to higher prices of $28 billion, a positive foreign exchange impact due to a weaker dollar of $8 billion and lower volumes of $13 billion. Additionally, sales of crude oil, spot and term contracts remained flat, reflecting higher prices of $1 billion offset by lower volumes of $1 billion. Other sales increased by around $5 billion, due to higher prices of $4 billion and higher volumes of $1 billion.

Profit before interest and tax for the year ended December 31, 2005 was $6,442 million, including inventory holding gains of $2,537 million and net gains of $177 million principally on the divestment of a number of regional retail networks in the US, and is after a charge of $1,200 million in respect of fatality and personal injury compensation claims associated with the incident at the Texas City refinery on March 23, 2005, a charge of $140 million relating to new, and revisions to existing, environmental and other provisions, an impairment charge of $93 million and a charge of $33 million for the impairment of an equity-accounted entity.

Profit before interest and tax for the year ended December 31, 2004 was $6,544 million, including inventory holding gains of $1,304 million, and is after net losses on disposal of $261 million (principally related to plant closures and exit from businesses, the disposal of our interest in the Singapore Refining Company Private Limited, the closure of the lubricants operation of the Coryton Refinery in the UK and the disposal of our European speciality intermediates businesses), a charge of $206 million related to new, and revisions to existing, environmental and other provisions, a charge of $195 million for the impairment of the petrochemicals facilities at Hull, UK and a charge of $32 million for restructuring, integration and rationalization.

Profit before interest and tax for the year ended December 31, 2003 was $3,235 million, including inventory holding gains of $43 million and is after a $369 million charge in relation to new, and revisions to existing, environmental and other provisions, Veba integration costs of $287 million (see below), net losses on disposal of $214 million (including the sale of retail assets, the Group’s European oil speciality products business, refinery and retail interests in Germany and Central Europe and pipeline interests in the US) and a credit of $10 million arising from the reversal of restructuring provisions.

The primary additional reasons for the increase in profit before interest and tax for the year ended December 31, 2005, compared with the year ended December 31, 2004 were improved refining margins contributing approximately $2,000 million, offset by lower retail marketing margins reducing profits by approximately $720 million, a reduction of around $870 million due to the shutdown of the

Texas City refinery, along with other storm related supply disruptions to a number of our US based businesses, an adverse impact of around $400 million due to fair value accounting for derivatives (see explanation below) and a reduction of around $430 million due to rationalization and efficiency programme charges, mainly across our marketing activities in Europe.

Where derivative instruments are used to manage certain economic exposures that cannot themselves be fair valued or accounted for as hedges, timing differences in relation to the recognition of gains and losses occur. These economic exposures primarily relate to inventories held in excess of normal operating requirements that are not designated as held for trading and fair valued, and forecast transactions to replenish inventory. Gains and losses on derivative commodity contracts are recognized immediately through the income statement whilst gains and losses on the related physical transaction are recognized when the commodity is sold.

Additionally, IFRS requires that inventory designated as held for trading is fair valued using period end spot prices whilst the related derivative instruments are valued using forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices resulting in quarterly timing differences.

The full year average 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. Our purchased energy costs and operating and investment costs were higheryear-on-year due to refinery repair, manufacturing integrity costs and the initial charges for the rationalization and efficiency programmes mentioned above. Refining throughputs at 2,399 mb/d were lower than in 2004 due primarily to the impact of disposal of the Mersin and Singapore refineries in 2004 and reduced availability at the Texas City refinery due to the explosion at 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. Refining availability was 92.9% compared with 95.4% in 2004. Marketing volumes were around 1% lower than 2004 due primarily to the effects of price increases as a result of supply disruption in the USA.

The increase in profit before interest and tax for 2004 compared with 2003 is primarily due to stronger refining margins contributing approximately $2,900 million, offset by a decrease in marketing margins of approximately $200 million, the impact of weaker US dollar of approximately $250 million and charges of around $310 million related primarily to a review of carrying value of fixed and current marketing assets. The increase was further offset by higher purchased energy costs of around $100 million and portfolio impacts of around $100 million. Refining throughputs at 2,607 mb/d were 4% lower than in 2003 due principally to the disposal of BP’s interests in the Singapore Refining Company Private Limited, the closure of refining operations at the ATAS Refinery in Mersin, south eastern Turkey and the disposal of the Bayernoil refinery in Germany in the second quarter of 2003. Refining availability for the year was 95.4% compared with 95.5% in 2003 and marketing volumes were relatively flat compared with 2003.

The integration of Veba, which began in February 2002, was essentially completed during 2003. The 2003 charges of $287 million relating to the Veba acquisition comprised some $46 million of severance costs, $37 million of other integration costs such as consulting, studies and internal project teams, $48 million of system infrastructure and application costs and the balance of $156 million related to additional synergy projects. 2003 cash outflows related to these charges were approximately $260 million.


	Gas, Power and Renewables


		Year ended December 31,

		2005		2004		2003

Sales and other operating revenues from continuing operations	($ million)		25,557		23,859		22,568
Profit before interest and tax from continuing operations (a)	($ million)		1,104		954		578


(a)		Includes profit after interest and tax of equity-accounted entities.

The changes in sales and other operating revenues are explained in more detail below:


		Year ended December 31,

		2005		2004		2003

Gas marketing sales	($ million)		15,222		13,532		12,929
Other sales (including NGL marketing)	($ million)		10,335		10,327		9,639

	($ million)		25,557		23,859		22,568

Gas marketing sales volumes	mmcf/d		5,096		5,244		5,881
Natural gas sales by Exploration and Production	mmcf/d		4,747		3,670		3,923

Sales and other operating revenues for 2005 was $26 billion compared with $24 billion in 2004. Gas marketing sales increased by $1.7 billion as price increases of $2.1 billion more than offset lower volumes of $0.4 billion. Other sales (including NGL marketing) remained flat reflecting $0.1 billion related to higher prices and $0.1 billion to lower volumes. Sales and other operating revenues for 2004 was $24 billion compared with $23 billion in 2003. Gas marketing sales increased by $0.6 billion as price increases of $1.8 billion more than offset lower volumes of $1.2 billion, and other sales (including NGL marketing) increased by around $0.7 billion of which $2.1 billion related to higher prices and $1.4 billion to lower volumes. Gas marketing sales volumes declined in 2004 and 2005 due to production and customer portfolio changes and, in 2005, production loss caused by hurricanes in the Gulf of Mexico.

Profit before interest and tax for the year ended December 31, 2005 was $1,104 million, including inventory holding gains of $95 million, compensation of $265 million received on the cancellation of an intra-Group gas supply contract and net gains of $55 million primarily on the disposal of BP’s interest in Interconnector, a power plant in the UK and an NGL plant in the US, and is after net fair value losses of $346 million on embedded derivatives and a credit of $6 million related to new, and revisions to existing, environmental and other provisions.

Profit before interest and tax for the year ended December 31, 2004 was $954 million, including inventory holding gains of $39 million and a net gain on disposal of $56 million.

Profit before interest and tax for the year ended December 31, 2003 was $578 million, including inventory holding gains of $6 million and is after a net loss on disposal of $6 million resulting from several small transactions.

The additional factors contributing to the increase in profit before interest and tax for the year ended December 31, 2005, compared with the equivalent period in 2004 are higher contributions from the operating businesses of around $170 million.

In addition to the factors above, the principal additional factors contributing to the increase in profit before interest and tax in 2004 compared with 2003 were a higher contribution from the natural gas liquids and solar businesses of approximately $350 million due to higher unit margins and higher volumes.


	Other Businesses and Corporate


		Year ended December 31,

		2005			2004		2003

Sales and other operating revenues from continuing operations	($ million)		668			546		515
Profit (loss) before interest and tax from continuing operations (a)(b)	($ million)		(1,191	)		164		(253	)


(a)		Includes profit after interest and tax of equity-accounted entities.

(b)		Includes the portion of Olefins and Derivatives not included in the sale of Innovene to INEOS. This includes the equity-accounted investments in China and Malaysia that were part of the Olefins and Derivatives business. These investments have been transferred to Refining and Marketing effective January 1, 2006.

The loss before interest and tax for the year ended December 31, 2005 was $1,191 million, including a net gain on disposal of $38 million, and is after inventory holding losses of $5 million, a net charge of $278 million relating to new, and revisions to existing, environmental and other provisions and the reversal of environmental provisions no longer required, a charge of $134 million in respect of the separation of the Olefins and Derivatives business and net fair value losses of $13 million on embedded derivatives.

The profit before interest and tax for the year ended December 31, 2004 was $164 million, including inventory holding gains of $8 million, net gains on disposals of $1,164 million primarily related to the sale of our interests in PetroChina and Sinopec and a credit of $66 million primarily resulting from the reversal of vacant space provisions in the UK and the US, and is after a charge of $283 million related to new, and revisions to existing, environmental and other provisions, and a charge of $102 million relating to the separation of the Olefins and the Derivatives business.

The loss before interest and tax for the year ended December 31, 2003 was $253 million including a credit of $648 million relating to a US medical plan, net gains on disposal of $139 million (primarily comprising gains on the sale of our interest in PT Kaltim Prima Coal, an Indonisian coal mining company, and gains and losses on other smaller transactions) and a credit of $5 million resulting from a reduction in the provision for costs associated with the closure of polypropylene capacity in the USA and is after inventory holding losses of $1 million, a charge of $213 million in respect of new, and revisions to existing, environmental and other provisions and a charge of $110 million in respect of provisions for future rental payments on surplus property.

Environmental Expenditure


	Year ended December 31,

	2005		2004		2003

	($ million)
Operating expenditure		494		526		498
Clean-ups		43		25		45
Capital expenditure		789		524		546
Additions to environmental remediation provision		565		587		599
Additions to decommissioning provision		1,023		286		1,159

Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal maintenance expenditure. The

figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute.

Environmental operating expenditures for 2005 were broadly in line with 2004. The increase in capital expenditure is largely related to clean fuels investment. Similar levels of operating and capital expenditures are expected in the foreseeable future. In addition to operating and capital expenditures, we also create provisions for future environmental remediation. Expenditure against such provisions is normally in subsequent periods and is not included in environmental operating expenditure reported for such periods. The charge for environmental remediation provisions in 2005 includes $512 million resulting from a reassessment of existing site obligations and $53 million in respect of provisions for new sites.

Provisions for environmental remediation are made when aclean-up is probable and the amount reasonably determinable. Generally, their timing coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.

The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions and also the Group’s share of liability. Although the cost of any future remediation could be significant and may be material to the result of operations in the period in which it is recognized, we do not expect that such costs will have a material effect on the Group’s financial position or liquidity. We believe our provisions are sufficient for known requirements; and we do not believe that our costs will differ significantly from those of other companies engaged in similar industries, or that our competitive position will be adversely affected as a result.

In addition, we make provisions on installation of our oil- and gas-producing assets and related pipelines to meet the cost of eventual decommissioning. On installation of oil or natural gas production facility a provision is established which represents the discounted value of the expected future cost of decommissioning the asset. Additionally, we undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments. The level of increase in the decommissioning provision varies with the number of new fields coming on stream in a particular year and the outcome of the periodic reviews.

Provisions for environmental remediation and decommissioning are usually set up on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’.

Further details of decommissioning and environmental provisions appear in Item 18 — Financial Statements — Note 43 on page F-114. See also Item 4 — Information on the Company — Environmental Protection on page 68.

Insurance

The Group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the Group. Losses will therefore be borne as they arise rather than being spread over time through insurance premiums with attendant transaction costs. This position will be reviewed periodically.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flow


	Year ended December 31,

	2005			2004			2003

	($ million)
Net cash provided by operating activities of continuing operations		25,751			24,047			15,955
Net cash provided by (used in) operating activities of Innovene operations		970			(669	)		348

Net cash provided by operating activities		26,721			23,378			16,303
Net cash used in investing activities		(1,729	)		(11,331	)		(9,281	)
Net cash used in financing activities		(23,303	)		(12,835	)		(6,803	)
Currency translation differences relating to cash and cash equivalents		(88	)		91			121

Increase (decrease) in cash and cash equivalents		1,601			(697	)		340
Cash and cash equivalents at beginning of year		1,359			2,056			1,716

Cash and cash equivalents at end of year		2,960			1,359			2,056

Net cash provided by operating activities for the year ended December 31, 2005 was $26,721 million compared with $23,378 million for the equivalent period of 2004, reflecting an increase in profit before taxation from continuing operations of $6,455 million, an increase in net cash provided by operating activities of Innovene of $1,639 million, a lower charge for provisions, less payments of $1,210 million and an increase in dividends received from jointly controlled entities and associates of $634 million. This was partially offset by an increase in income taxes paid of $2,640, an increase of $1,320 million in working capital requirements, an increase in earnings from jointly controlled entities and associates of $1,263 million, a higher net credit for impairment and gain/ loss on sale of businesses and fixed assets of $775 million, an increase in interest paid of $429 million and an increase in the net operating charge for pensions and other post-retirement benefits, less contributions of $351 million.

Net cash provided by operating activities for the year ended December 31, 2004 was $23,378 million compared with $16,303 million in 2003. This reflects an increase in profit before taxation from continuing operations of $7,235 million, the absence of discretionary funding for the Group’s pension plans of $2,533, an increase in dividends received from jointly controlled entities and associates of $1,651 million (primarily due to the dividend from TNK-BP) and an increase in depreciation, depletion and amortization of $453 million. This was partially offset by an increase in income taxes paid of $1,584, an increase in earnings from jointly controlled entities and associates of $1,066 million, an increase of $1,054 million in working capital requirements and a decrease of $1,017 million in net cash provided by Innovene operations.

Net cash used in investing activities was $1,729 million compared with $11,331 million and $9,281 million for the equivalent periods of 2004 and 2003. The reduction in 2005 reflects an increase in disposal proceeds of $6,239 million, primarily from the sale of Innovene, and a decrease in spending on acquisitions of $2,693 million. The increase in 2004 compared with 2003 reflects a reduction in disposal proceeds of $1,395 million, increased acquisition spending of $191 million and increased capital expenditure of $401 million.

Net cash used in financing activities was $23,303 million compared with $12,835 million in 2004 and $6,803 million in 2003. The higher outflow in 2005 reflects an increase in the net repurchase of ordinary share capital of $4,107, higher repayments of long-term financing of $2,616 million, a net decrease of $1,433 million in short-term debt, and increases in equity dividends paid to BP shareholders of $1,318 million and to minority interest of $794 million. The higher outflow in 2004 compared with 2003 reflects an increase in the net repurchase of ordinary share capital of $5,319 million, lower proceeds from long-term financing of $1,647 million and an increase in equity dividends paid to BP

shareholders of $387 million, partially offset by lower repayments of long-term financing of $1,356 million.

The Group has had significant levels of capital investment for many years. Capital investment, excluding acquisitions, was $13.9 billion in 2005, $13.8 billion in 2004 and $13.6 billion in 2003. Sources of funding are completely fungible, but the majority of the Group’s funding requirements for new investment come from cash generated by existing operations. The Group’s level of net debt, that is debt less cash and cash equivalents, was $20.3 billion at the end of 2003, $21.7 billion at the end of 2004 and was $16.2 billion at the end of 2005. The lower level of debt at the end of 2005 reflects the receipt of the Innovene disposal proceeds in December 2005.

Over the period 2003 to 2005 our cash inflows and outflows were balanced, with sources and uses both totalling $89 billion. During that period, the price of Brent has averaged $40.52/bbl. The following table summarizes the three year sources and uses of cash:


Sources			Uses

	($ billion)			($ billion)
Net cash provided by operating activities		66	Capital expenditure		40
Divestments		23	Acquisitions		5
			Net repurchase of shares		20
			Dividends to BP shareholders		19
			Dividends to Minority Interest		1
			Movement in net debt		4

		89			89

Significant acquisitions made for cash were more than offset by divestitures. Net investment over the same period has averaged $7.3 billion per year. Dividends to BP shareholders, which grew on average by 14.3% per year in dollar terms, used $19 billion. Net repurchase of shares was $20 billion, which includes $21 billion in respect of our share buyback programme less proceeds from share issues. Finally, cash was used to strengthen the financial condition of certain of our pension funds. In the last three years, $3.7 billion has been contributed to funded pensions plans.

Trend Information

We expect to grow cash flows underpinned by the following:


	—	We expect to grow production in a $40/bbl price environment.

	—	We aim to control cost increases below inflation.

	—	We plan to maintain capital expenditure at around $15 billion in 2006 and grow it at about $0.5 billion a year to 2008.

	—	We expect to continue to high grade our portfolio and expect divestments to be an ongoing rate of around $3 billion a year.

As noted above, we expect capital expenditure, excluding acquisitions, to be around $15 billion in 2006; the exact level will depend on a number of things including sector-specific cost escalation above levels we have seen so far, time critical and material one-off investment opportunities which further our strategy and any acquisition opportunities that may arise. At present, we do not expect any of these things to affect our capital expenditure. Refer to Item 4 for further information.

The UK Government’s announced increase in the North Sea supplemental tax rate will, when enacted, result in higher tax charges. This increase will have two effects; first to create a one-time deferred tax charge of around $600 million and second to increase the ongoing Group effective tax rate by 2%. The full year aggregate effective tax rate is expected to be around 39%.

Total production for 2006 is estimated at an average of between 2.8 and 2.85 mmboe/d for subsidiaries and between 1.3 and 1.35 mmboe/d for equity-accounted entities; these estimates are based the Group’s asset portfolio at January 1, 2006, anticipated start-ups in 2006 and Brent at $40/bbl, before any 2006 disposal effects, and before any effects of prices above $40/bbl on volumes in Production Sharing Agreements. The daily production of the Gulf of Mexico Shelf assets, whose sale was announced in April 2006, is estimated at 27 mboe.

The most important determinants of cash flows in relation to our oil and natural gas production are the prices of these commodities. In a stable price environment, cash flows from currently developed proved reserves are expected to decline in a manner consistent with anticipated production decline rates. Development activities associated with recent discoveries, as well as continued investment in these producing fields, are expected to more than offset this decline, resulting in increased operating cash flows over the next few years. Cash flows from equity-accounted entities are expected to be in the form of dividend payments.

Dividends and Other Distributions to Shareholders and Gearing

Our dividend policy is to grow the dividend per share progressively. In pursuing this policy and in setting the levels of dividends we are guided by several considerations, including:


	—	the prevailing circumstances of the Group;

	—	the future investment patterns and sustainability of the Group;

	—	the future trading environment. It does seem that oil prices may have a support level of at least $40/bbl in the medium term. We continue to use our planning assumption of $25/bbl for testing the downside in the balance between investment and total distributions to shareholders.

We remain committed to returning the excess of net cash provided by operating activities less net cash used in investing activities to our investors where this is in excess of investment and dividend needs.

We plan to continue our programme of share buybacks, subject to market conditions and constraints. Since the inception of the share repurchase programme in 2000 until the end of 2005 we have repurchased some 2,662 million shares at a cost of $25.2 billion, reducing the number of shares in issue (after accounting for the issuance of shares under employee stock programmes and to AAR in respect of TNK) by 9%. During the first quarter of 2006, we bought back 349 million shares, at a cost of $4 billion.

Our financial framework includes a gearing band of 20-30% which is intended to provide an efficient capital structure and the appropriate level of financial flexibility. Our aim is to return gearing, which was 17% at December 31, 2005, to the lower half of the band.

The discussion above and following contains forward-looking statements with regard to future cash flows, future levels of capital expenditure and divestments, future production volumes, working capital, the renewal of borrowing facilities, shareholder distributions and share buybacks and expected payments under contractual and commercial commitments. These forward-looking statements are based on assumptions which management believes to be reasonable in the light of the Group’s operational and financial experience, however, no assurance can be given that the forward-looking statements will be realized. You are urged to

read the cautionary statement under Item 3 — Key Information — Forward-Looking Statements on page 12 and Item 3 — Key Information — Risk Factors on pages 10 and 11 which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. The Company provides no commitment to update the forward-looking statements or to publish financial projections for forward-looking statements in the future.

Financing the Group’s Activities

The Group’s principal commodity, oil, is priced internationally in US dollars. Group policy has been to minimize economic exposure to currency movements by financing operations with US dollar debt wherever possible, otherwise by using currency swaps when funds have been raised in currencies other than US dollars.

The Group’s finance debt is almost entirely in US dollars and at December 31, 2005 amounted to $19,162 million (2004 $23,091 million) of which $8,932 million (2004 $10,184 million) was short term.

Net debt was $16,202 million at the end of 2005, a decrease of $5,530 million compared with 2004. The ratio of net debt to net debt plus equity was 17% at the end of 2005 and 22% at the end of 2004. The ratio of 17% at December 31, 2005 reflects stronger cash flows both from underlying operations and the sale of Innovene.

The maturity profile and fixed/floating rate characteristics of the Group’s debt are described in Item 18 — Financial Statements — Notes 38 and 41 on pages F-97 and F-107, respectively.

We have in place a European Debt Issuance Programme (DIP) under which the Group may raise $8 billion of debt for maturities of one month or longer. At June 28, 2006, the amount drawn down against the DIP was $6,988 million.

Commercial paper markets in the USA and Europe are a primary source of liquidity for the Group. At December 31, 2005 the outstanding commercial paper amounted to $1,911 million (2004 $4,180 million).

BP believes that, taking into account the substantial amounts of undrawn borrowing facilities available, the Group has sufficient working capital for foreseeable requirements.

In addition to reported debt, BP uses conventional off balance sheet arrangements such as operating leases and borrowings in joint ventures and associates. At December 31, 2005 the Group’s share of third party borrowings of joint ventures and associates was $3,266 million (2004 $2,821 million) and $970 million (2004 $1,048 million) respectively. These amounts are not reflected in the Group’s debt on the balance sheet.

The Group has issued third party guarantees under which amounts outstanding at December 31, 2005 are summarized below. Some guarantees outstanding are in respect of borrowings of joint ventures and associates noted above.


	Guarantees expiring by period

													2011 and
	Total		2006		2007		2008		2009		2010		thereafter

	($ million
Guarantees issued in respect of:
Borrowings of joint ventures and associates		1,228		69		217		119		121		104		598
Liabilities of other third parties		736		161		470		28		25		5		47

At December 31, 2005 contracts had been placed for authorized future capital expenditure estimated at $7,596 million. Such expenditure is expected to be financed largely by cash flow from operating activities. The Group also has access to significant sources of liquidity in the form of committed facilities and other funding through the capital markets. At December 31, 2005, the Group

had available undrawn committed borrowing facilities of $4,500 million ($4,500 million at December 31, 2004).

Contractual Commitments

The following table summarizes the Group’s principal contractual obligations at December 31, 2005. Further information on borrowings and finance leases is given in Item 18 — Financial Statements — Note 41 on page F-107 and further information on operating leases is given in Item 18 — Financial Statements — Note 18 on page F-58.


Expected payments by period under	Payments due by period
contractual
obligations and commercial													2011 and
commitments	Total		2006		2007		2008		2009		2010		thereafter

	($ million)
Borrowings (a)		18,381		5,418		3,274		2,317		2,258		572		4,542
Finance lease obligations		1,236		78		78		80		80		82		838
Operating leases		10,609		1,569		1,473		1,069		1,009		953		4,536
Decommissioning liabilities		9,511		181		212		188		175		163		8,592
Environmental liabilities		2,501		499		367		332		314		313		676
Pensions and other postretirement benefits (b)		21,438		1,357		1,345		1,343		870		870		15,653
Purchase obligations (c)		126,725		87,696		11,473		5,081		3,694		2,871		15,910


(a)		Expected payments exclude interest payments on borrowings.

(b)		Represents the expected future contributions to funded pension plans and payments by the Group for unfunded pension plans and the expected future payments for postretirement benefits.

(c)		Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2006 include purchase commitments existing at December 31, 2005 entered into principally to meet the Group’s short term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Item 11 — Quantitative And Qualitative Disclosures About Market Risk on page 162.

The following table summarizes the nature of the Group’s unconditional purchase obligations.


	Payments due by period

Purchase obligations payments due													2011 and
by period	Total		2006		2007		2008		2009		2010		thereafter

	($ million)
Crude oil and oil products		45,688		39,767		1,663		754		732		707		2,065
Natural gas		41,823		25,541		3,783		2,329		1,622		1,240		7,308
Chemicals and other refinery feedstocks		11,376		5,043		1,348		669		404		404		3,508
Utilities		21,415		15,586		3,779		611		402		104		933
Transportation		3,184		1,036		496		338		260		208		846
Use of facilities and services		3,239		723		404		380		274		208		1,250

Total		126,725		87,696		11,473		5,081		3,694		2,871		15,910

The following table summarizes the Group’s capital expenditure commitments at December 31, 2005 and the proportion of that expenditure for which contracts have been placed. The Group expects its total capital expenditure excluding acquisitions to be around $15 billion in 2006 and to increase by about $0.5 billion a year through 2008.


Capital expenditure commitments
including amounts for which contracts													2011 and
have been placed	Total		2006		2007		2008		2009		2010		thereafter

	($ million)
Committed on major projects		19,254		8,498		4,060		2,179		1,392		879		2,246
Amounts for which contracts have been placed		7,596		4,767		1,551		696		428		138		16

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Group’s business activities may not be available. The Group has long-term debt ratings of Aa1 and AA+, assigned respectively by Moody’s and Standard & Poor’s.

The Group has access to a wide range of funding at competitive rates through the capital markets and banks. It co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management centrally. The Group believes it has access to sufficient funding, including through the commercial paper markets, and also has undrawn committed borrowing facilities to meet currently foreseeable borrowing requirements. At December 31, 2005, the Group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,500 million expiring in 2006 (2004 $4,500 million expiring in 2005 and 2003 $3,700 million expiring in 2004). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. The Group expects to renew these facilities on an annual basis. Certain of these facilities support the Group’s commercial paper programme.

Credit Risk

Credit risk is the potential exposure of the Group to loss in the event of non-performance by a counterparty. The credit risk arising from the Group’s normal commercial operations is controlled by individual operating units within guidelines. In addition, as a result of its use of derivatives to manage market risk, the Group has credit exposures through its dealings in the financial and specialized oil, natural gas and power markets. The Group controls the related credit risk through credit approvals, limits, use of netting arrangements and monitoring procedures. Counterparty credit validation, independent of the dealers, is undertaken before contractual commitment.

OUTLOOK

World economic growth appears robust. The US appears to have rebounded in the first quarter, Europe continues to show promise of an acceleration of growth, and Asia and Latin America are growing at or around trend. The near-term global outlook is for sustained growth.

Crude oil prices averaged $61.79 per barrel (Dated Brent) in the first quarter of 2006, an increase of nearly $5 per barrel from the fourth quarter 2005 and more than $14 per barrel above the same period last year. Prices rebounded in face of a disruption of Nigerian supplies and heightened geopolitical concerns. Ample inventories and increased OPEC production capacity have failed to stem the increase. Oil prices are expected to remain strong.

US natural gas prices averaged $9.01/mmbtu (Henry Hub first of month index) in the first quarter, nearly $4/mmbtu below the fourth quarter of last year. Demand weakness has more than offset supply lost following last year’s hurricanes, resulting in a substantial gain in inventories relative to seasonal norms. Mild winter weather has contributed to demand softness. As a result, prices have fallen below parity with residual fuel oil. US gas prices are expected to track broadly with oil prices but are vulnerable to further relative declines if inventories remain well above average.

UK gas prices (National Balancing Point day-ahead) in the first quarter averaged 70 pence per therm, up from 65.3 pence per therm in the fourth quarter and 32 pence per therm above the same period last year. Cold weather and the closure of the Rough storage facility in mid-March prompted a brief price spike above 150 pence per therm amid concerns about physical supply availability. Prompt prices have recently fallen below 30 pence per therm.

Global average refining margins softened to $6.28/bbl in the first quarter compared with $7.60/bbl in the fourth quarter of 2005. US refinery operations are still recovering from last autumn’s hurricanes and a heavy maintenance programme has extended into the second quarter. During the second quarter, refining margins have risen in anticipation of the US driving season and the switch from MTBE to ethanol-blended reformulated gasoline and are likely to remain underpinned in the near term.

During the first quarter, an initial improvement in retail margins reversed resulting in an overall decline during the quarter. This was against a backdrop of increasing product prices, particularly in February and March. A further rise in wholesale gasoline and crude prices is evident during the second quarter and marketing margins are expected to remain volatile.

CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS

Adoption of International Financial Reporting Standards

For all periods up to and including the year ended December 31, 2004, BP prepared its financial statements in accordance with UK GAAP. BP, together with all other EU companies listed on an EU stock exchange, was required to prepare consolidated financial statements in accordance with IFRS as adopted by the EU with effect from January 1, 2005. The Annual Report and Accounts for the year ended December 31, 2005 comprises BP’s first consolidated financial statements prepared under International Financial Reporting Standards.

In preparing these financial statements, the Group has complied with all International Financial Reporting Standards applicable for periods beginning on or after January 1, 2005. In addition, BP has also decided to adopt early IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’, the amendment to IAS 19 ‘Amendment to International Accounting Standard IAS 19 Employee Benefits: Actuarial Gains and Losses, Group Plans and Disclosures’, the amendment to IAS 39 ‘Amendment to International Accounting Standard IAS 39 Financial Instruments: Recognition and Measurement: Cash Flow Hedge Accounting of Forecast Intragroup Transactions’ and IFRIC 4 ‘Determining whether an Arrangement contains a Lease’. The EU has adopted all standards and interpretations adopted by BP for its 2005 reporting.

The general principle that should be applied on first-time adoption of IFRS is that standards in force at the first reporting date (for BP, December 31, 2005) should be applied retrospectively. However, IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ (IFRS 1) contains a number of exemptions that companies are permitted to apply. BP has taken the following exemptions:


	—	Comparative information on financial instruments is prepared in accordance with UK GAAP and the Group has adopted IAS 32 ‘Financial Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39) from January 1, 2005.

	—	IFRS 3 ‘Business Combinations’ has not been applied to acquisitions of subsidiaries or of interests in jointly controlled entities and associates that occurred before January 1, 2003.

	—	Cumulative currency translation differences for all foreign operations are deemed to be zero at January 1, 2003.

	—	The Group has recognized all cumulative actuarial gains and losses on pensions and other postretirement benefits as at January 1, 2003 directly in equity.

	—	IFRS 2 ‘Share-based Payment’ has been applied retrospectively to all share-based payments that had not vested before January 1, 2003.

As indicated above, BP adopted IAS 32 and IAS 39 with effect from January 1, 2005 and, as permitted under IFRS 1, the Group has not restated comparative information. Had IAS 32 and IAS 39 been applied from January 1, 2003, the following adjustments would have been necessary in the financial statements for the years ended December 31, 2004 and 2003:


	—	All derivatives, including embedded derivatives, would have been brought on to the balance sheet at fair value.

	—	Available-for-sale investments would have been carried at fair value rather than at cost.

The principal differences for the Group between reporting on the basis of UK GAAP and IFRS are as follows:


	—	Ceasing to amortize goodwill.

	—	Setting up deferred taxation on acquisitions; inventory valuation differences; and unremitted earnings of subsidiaries, jointly controlled entities and associates.

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	—	Expensing a greater proportion of major maintenance costs.

	—	No longer recognizing dividends proposed but not declared as a liability at the balance sheet date.

	—	Recognizing an expense for the fair value of employee share option schemes.

	—	Recording asset swaps on the basis of fair value.

	—	Recognizing changes in the fair value of embedded derivatives in the income statement.

Further information regarding the impact of adopting IFRS is shown in Item 18 — Financial Statements — Note 3 on page F-30 and Note 52 on page F-145.

The new accounting policies adopted by the Group are summarized in Item 18 — Financial Statements — Note 1 on page F-12.

Inherent in the application of many of the accounting policies used in the preparation of the financial statements is the need for BP management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the accounts and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from the estimates and assumptions used. The following summary provides further information about the critical accounting policies that could have a significant impact on the results of the Group and should be read in conjunction with the Notes on Financial Statements.

The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the consolidated financial statements are in relation to oil and natural gas accounting, including the estimation of reserves, the recoverability of asset carrying values, deferred taxation, contingent liabilities, provisions and liabilities, pensions and other postretirement benefits.


	*Oil and Natural Gas Accounting*

Accounting for oil and gas exploration and development activity is subject to special accounting rules that are unique to the oil and gas industry. In the absence of an IFRS dealing specifically with oil and gas accounting (IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’ only addresses limited areas), BP continues to have regard to the accounting guidance for oil and gas companies contained in the UK Statement of Recommended Practice, ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ (UK SORP).

The Group follows the successful efforts method of accounting for its oil and natural gas exploration and production activities.

The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs.

Licence and property acquisition costs are initially capitalized within intangible assets. These costs are amortized on a straight-line basis until such time as either exploration drilling is determined to be successful or it is unsuccessful and all costs are written off. Each property is reviewed on an annual basis to confirm that drilling activity is planned and that it is not impaired. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off.

For exploration wells and exploratory-type stratigraphic test wells, costs directly associated with the drilling of wells are temporarily capitalized within intangible fixed assets, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. The determination is usually made within one year after well completion, but can take longer, depending on the complexity of the geological structure. If the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploration wells that discover potentially economic quantities of oil and gas

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and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.

For complicated offshore exploration discoveries, it is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review, on at least an annual basis, to confirm the continued intent to develop, or otherwise extract value from, the discovery. If this is no longer the case, the costs are immediately expensed.

Once a project is sanctioned for development, the carrying values of licence and property acquisition costs and exploration and appraisal costs are transferred to production assets within property, plant and equipment. Field development costs subject to depreciation are expenditures incurred to date, together with sanctioned future development expenditure approved by the Group.

The capitalized exploration and development costs for proved oil and gas properties (which include the costs of drilling unsuccessful wells) are amortized on the basis of oil-equivalent barrels that are produced in a period as a percentage of the estimated proved reserves.

The estimated proved reserves used in theseunit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of theunit-of-production amortization are as follows:


	—	Proved developed reserves for producing wells.

	—	Total proved reserves for development costs.

	—	Total proved reserves for licence and property acquisition costs.

	—	Total proved reserves for future decommissioning costs.

The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property’s book value (see discussion of impairment of fixed assets and goodwill below).

Given the large number of producing fields in the Group’s portfolio, it is unlikely that any changes in reserve estimates, year on year, will have a significant effect on prospective charges for depreciation.

US GAAP requires theunit-of-production depreciation rate to be calculated on the basis of development expenditure incurred to date and proved developed reserves. If production commences before all development wells are drilled, a portion of the development costs incurred to date should be excluded from the unit-of production depreciation rate. In respect of the Group’s portfolio of fields there is no material difference between the Group’s charge for depreciation determined on an IFRS basis and on a US GAAP basis.


	*Oil and Natural Gas Reserves*

BP estimates its proved reserves based on guidance contained in the UK SORP. This differs from the basis for determining reserve required by the US Securities and Exchange Commission. In estimating its reserves under UK SORP, BP uses long-term planning prices; these are the long term price assumptions on which the Group makes decisions to invest in the development of a field. Using planning prices for estimating proved reserves removes the impact of the volatility inherent in using year-end spot prices on our reserve base and on cash flow expectations over the long term. The Group’s planning prices for estimating reserves through the end of 2005 were $25/bbl for oil and

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$4.00/mmbtu for natural gas. Applying higher year-end prices to reserve estimates and assuming they apply to theend-of-field life has the effect of increasing proved reserves associated with concessions (tax and royalty arrangements) for which additional development opportunities become economic at higher prices or where higher prices make it more economic to extend the life of a field. On the other hand, applying higher year-end prices to reserves in fields subject to PSAs has the effect of decreasing proved reserves from those fields because higher prices result in lower volume entitlements. We believe that our long-term planning price assumptions provide the most appropriate basis for estimating oil and gas reserves and we will continue to use this basis for our UK reporting.

In determining ‘reasonable certainty’ for UK SORP purposes, BP applies a number of additional internally imposed assessment principles, such as the requirement for internal approval and final investment decision (which we refer to as project sanction), or for such project sanction within six months and, for additional reserves in existing fields, the requirement that the reserves be included in the business plan and scheduled for development within three years. These principles are also applied for SEC reporting purposes.

The Company’s proved reserves estimates for the year ended December 31, 2005 reported in this Form 20-F reflect year-end prices and some adjustments which have been made vis-à-vis individual asset reserve estimates based on different applications of certain SEC interpretations of SEC regulations relating to the use of technology (mainly seismic) to estimate reserves in the reservoir away from wellbores and the reporting of fuel gas (i.e. gas used for fuel in operations on the lease) within proved reserves. The 2005 year-end marker prices used were Brent $58.21/bbl and Henry Hub $9.52/mmbtu. The other 2005 movements in proved reserves, are reflected in the tables showing movements in oil and gas reserves by region in Item 18 — Financial Statements — Supplementary Oil and Gas Information on pages S-1 and S-5.

The Group manages its hydrocarbon resources in three major categories: prospect inventory, non-proved resources and proved reserves. When a discovery is made, volumes transfer from the prospect inventory to the non-proved resource category. The reserves move through various non-proved resources sub-categories as their technical and commercial maturity increases through appraisal activity. Reserves in a field will only be categorized as proved when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction, or for sanction expected within six months. Internal approval and final investment decision are what we refer to as project sanction.

At the point of sanction, all booked reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. The first PD bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking to the start of production. Adjustments may be made to booked reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

The Group reassesses its estimate of proved reserves on an annual basis. The estimated proved reserves of oil and natural gas are subject to future revision. As discussed below, oil and natural gas reserves have a direct impact on certain amounts reported in the financial statements.

Proved reserves do not include reserves that are dependent on the renewal of exploration and production licences, unless there is strong evidence to support the assumption of such renewal.


	*Recoverability of Asset Carrying Values*

BP assesses its fixed assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable. Such indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. The assessment for impairment entails comparing the carrying value of the

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cash generating unit and associated goodwill with the recoverable amount of the asset, that is, the higher of net realizable value and value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products.

For oil and natural gas properties, the expected future cash flows are estimated based on the Group’s plans to continue to produce and develop proved and associated risk-adjusted probable and possible reserves. Expected future cash flows from the sale or production of reserves are calculated based on the Group’s best estimate of future oil and gas prices. Prices for oil and natural gas used for future cash flow calculations are assumed to decline from existing levels in equal steps during the next three years to the long-term planning assumptions as at December 31, 2005 ($25 per barrel and $4.00 per mmbtu for Brent and Henry Hub respectively). Previously, the long-term planning assumptions were a Brent oil price of $20 per barrel and a Henry Hub gas price of $3.50 per mmbtu. These long-term planning assumptions are subject to periodic review and modification. The estimated future level of production is based on assumptions about future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

Charges for impairment are recognized in the Group’s results from time to time as a result of, among other factors, adverse changes in the recoverable reserves from oil and natural gas fields, low plant utilization or reduced profitability. If there are low oil prices or natural gas prices or refining margins or marketing margins over an extended period, the Group may need to recognize significant impairment charges.

Irrespective of whether there is any indication of impairment, BP is required to test for impairment any goodwill acquired in a business combination. The Group carries goodwill of approximately $10.4 billion on its balance sheet, principally relating to the Atlantic Richfield and Burmah Castrol acquisitions. In testing goodwill for impairment, the Group uses a similar approach to that described above. The cash-generating units for impairment testing in this case are one level below business segments. As noted above, if there are low oil prices or natural gas prices or refining margins or marketing margins for an extended period, the Group may need to recognize significant goodwill impairment charges.


	*Deferred Taxation*

The Group has approximately $5 billion of carry forward tax losses in the UK and Germany, which would be available to offset against future taxable income. Carry forward tax losses in other taxing jurisdictions have not been recognized as deferred tax assets, and are unlikely to have a significant effect on the Group’s tax rate in future years.


	*Provisions and Liabilities*

The Group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest asset removal obligations facing BP relate to the removal and disposal of oil and natural gas platforms and pipelines around the world. The estimated discounted costs of dismantling and removing these facilities are accrued on the installation of those facilities, reflecting our legal obligations at that time. A corresponding asset of an amount equivalent to the provision is also created within property, plant and equipment. This asset is depreciated over the expected life of the production facility or pipeline. Most of these removal events are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public expectations. Consequently, the timing and amounts

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of future cash flows are subject to significant uncertainty. Changes in the expected future costs are reflected in both the provision and tangible asset.

Decommissioning provisions associated with downstream and petrochemicals facilities are generally not provided for, as such potential obligations cannot be measured, given their indeterminate settlement dates. The Group performs periodic reviews of its downstream and petrochemicals long-lived assets for any changes in facts and circumstances that might require the recognition of a decommissioning provision.

The timing and amount of future expenditures are reviewed annually, together with the interest rate to be used in discounting the cash flows. The interest rate used to determine the balance sheet obligation at the end of 2005 was 2.0%, unchanged from the end of 2004. The interest rate represents the real rate (i.e. adjusted for inflation) on long-dated government bonds.

Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past operations or events that can be reasonably estimated. The timing of recognition requires the application of judgement to existing facts and circumstances, which can be subject to change. Since the actual cash outflows can take place many years in the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and circumstances.

A change in estimate of a recognized provision or liability would result in a charge or credit to net income in the period in which the change occurs (with the exception of decommissioning costs as described above).

In particular, provisions for environmentalclean-up and remediation costs are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes inclean-up technology.

The provision for environmental liabilities is reviewed at least annually. The interest rate used to determine the balance sheet obligation at December 31, 2005 was 2.0%, the same rate as at the previous balance sheet date.

As further described in Item 18 — Financial Statements — Note 49 on page F-141, the Group is subject to claims and actions. The facts and circumstances relating to particular cases are evaluated regularly in determining whether it is ‘probable’ that there will be a future outflow of funds and, once established, whether a provision relating to a specific litigation should be adjusted. Accordingly, significant management judgement relating to contingent liabilities is required, since the outcome of litigation is difficult to predict.


	*Pensions and Other Postretirement Benefits*

Accounting for pensions and other postretirement benefits involves judgement about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, rates of return on plan assets, determination of discount rates for measuring plan obligations, healthcare cost-trend rates and rates of utilization of healthcare services by retirees. These assumptions are based on the environment in each country. Determination of the projected benefit obligations for the Group’s defined benefit pension and postretirement plans is important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The assumptions used may vary from year to year, which will affect future results of operations. Any differences between these assumptions and the actual outcome also affect future results of operations.

Pension and other postretirement benefit assumptions are discussed and agreed with the independent actuaries in December each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surplus and deficits recorded on the Group’s balance sheet, and pension and postretirement expense for the following year.

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The pension assumptions at December 31, 2005 and 2004 under IAS 19 are summarized below.


	UK				Other				USA

	2005		2004		2005		2004		2005		2004

	(%)
Rate of return on assets		7.0		7.0		5.5		6.0		8.0		8.0
Discount rate		4.75		5.25		4.0		5.0		5.5		5.75
Future salary increases		4.25		4.0		3.25		4.0		4.25		4.0
Future pension increases		2.5		2.5		1.75		2.5		nil		nil
Inflation		2.5		2.5		2.0		2.5		2.5		2.5

The assumed rate of investment return and discount rate have a significant effect on the amounts reported. A one-percentage-point change in these assumptions for the principal plans would have the following effects:


	One-percentage point

	Increase			Decrease

	($ million)
Investment return:
Effect on pension expense in 2006		(346	)		348
Discount rate:
Effect on pension expense in 2006		(78	)		93
Effect on pension obligation at December 31, 2005		(4,911	)		6,379

The assumptions used in calculating the charge for US postretirement benefits are consistent with those shown above for US pension plans. The assumed future US healthcare cost trend rate is shown below.


															2013 and
															subsequent
	2006		2007		2008		2009		2010		2011		2012		years

	(%)
Beneficiaries aged under 65		9.0		8.0		7.0		6.0		5.5		5.0		5.0		5.0
Beneficiaries aged over 65		11.0		9.5		8.5		7.5		6.5		6.0		5.5		5.0

The assumed US healthcare cost trend rate has a significant effect on the amounts reported. A one-percentage-point change in the assumed US healthcare cost trend rate would have the following effects:


	One-percentage point

	Increase		Decrease

	($ million)
Effect on US postretirement benefit expense in 2006		32		(26	)
Effect on US postretirement obligation at December 31, 2005		388		(319	)


	*Impact of New International Financial Reporting Standards*

In August 2005, the International Accounting Standards Board (IASB) issued IFRS 7 ‘Financial Instruments — Disclosures’ which is effective for annual periods beginning on or after January 1, 2007, with earlier adoption encouraged. Upon adoption, the Group will disclose additional information about its financial instruments, their significance and the nature and extent of risks to which they give rise. More specifically, the Group will be required to disclose the fair value of its financial instruments and its risk exposure in greater detail. There will be no effect on reported income or net assets. No decision has been made on whether to early adopt this standard.

Also in August 2005, ‘IAS 1 Amendment — Presentation of Financial Statements: Capital Disclosures’ was issued by the IASB, which requires disclosures of an entity’s objectives, policies and

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processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and the consequences of any non-compliance. This is effective for annual periods beginning on or after January 1, 2007. There will be no effect on the Group’s reported income or net assets.

‘IAS 21 Amendment — Net Investment in a Foreign Operation’ was issued in December 2005. The amendment clarifies the requirements of IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’ regarding an entity’s investment in foreign operations. This amendment is effective for annual periods beginning on or after January 1, 2006, and was adopted by the EU in May 2006. There will be no material impact on the Group’s reported income or net assets as a result of adoption of this amendment.

The IASB issued an amendment to the fair value option in IAS 39 ‘Financial Instruments: Recognition and Measurement’ in June 2005. The option to irrevocably designate, on initial recognition, any financial instruments as ones to be measured at fair value with gains and losses recognized in profit and loss has now been restricted to those financial instruments meeting certain criteria. The criteria are where such designation eliminates or significantly reduces an accounting mismatch, when a group of financial assets, financial liabilities or both are managed and their performance is evaluated on a fair value basis in accordance with a documented risk management or investment strategy, and when an instrument contains an embedded derivative that meets particular conditions. The Group has not designated any financial instruments as being at-fair-value-through-profit-and-loss, thus there will be no effect on the Group’s reported income or net assets as a result of adoption of this amendment.

In August 2005, the IASB issued amendments to IAS 39 ‘Financial Instruments: Recognition and Measurement’ and IFRS 4 ‘Insurance Contracts regarding Financial Guarantee Contracts’. These amendments require the issuer of financial guarantee contracts to account for them under IAS 39 as opposed to IFRS 4 unless an issuer has previously asserted explicitly that it regards such contracts as insurance contracts and has used accounting applicable to insurance contracts. In these instances the issuer may elect to apply either IAS 39 or IFRS 4. Under the amended IAS 39, a financial guarantee contract is initially recognized at fair value and is subsequently measured at the higher of (a) the amount determined in accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’ and (b) the amount initially recognized, less, when appropriate, cumulative amortization recognized in accordance with IAS 18 ‘Revenue’. The amendment to IAS 39 is effective for accounting periods beginning on or after January 1, 2006. This standard impacts guarantees given by Group companies in respect of associates and joint ventures as well as in respect of other third parties; these will need to be recorded in the Group’s financial statements at fair value.

Several interpretations have been issued by the International Financial Reporting Interpretations Committee (IFRIC) that will become effective for future financial reporting periods.

IFRIC 5 ‘Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’ sets out the accounting and disclosures required with regard to decommissioning funds. This interpretation is effective for annual accounting periods beginning on or after January 1, 2006 and has been adopted by the EU.

IFRIC 6 ‘Liabilities Arising from Participating in a Specific Market — Waste Electrical and Electronic Equipment’ provides guidance on the recognition of liabilities for waste management under the EU Directive on waste electrical and electronic equipment in respect of sales of household equipment before a certain date. This interpretation is effective for annual accounting periods beginning on or after December 1, 2005 and has been adopted by the EU.

IFRIC 7 ‘Applying IAS 29 for the First Time’ provides detailed guidance on the application of IAS 29 ‘Financial Reporting in Hyperinflationary Economies’ in the accounting period in which hyperinflation is first observed. This interpretation is effective for annual accounting periods beginning on or after March 1, 2006 and was adopted by the EU in May 2006.

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IFRIC 8 ‘Scope of IFRS 2’ clarifies that IFRS 2 ‘Share-based Payment’ is applicable to arrangements where an entity makes share-based payments for nil consideration, or where the consideration is less than the fair value of the options granted. This interpretation is effective for annual accounting periods beginning on or after May 1, 2006 and has yet to be adopted by the EU. This is expected in summer 2006.

IFRIC 9 ‘Reassessment of Embedded Derivatives’ clarifies that an entity is required to assess whether an embedded derivative should be separated from the host contract and accounted for as a derivative when the entity first becomes a party to the contract. Subsequent reassessment is prohibited unless there is a change in the terms of the contract that significantly modifies the cash flows that would otherwise be required under the contract, in which case reassessment is required. This interpretation is effective for annual accounting periods beginning on or after June 1, 2006 and has yet to be adopted by the EU. This is expected in summer 2006.

It is not anticipated that any of these interpretations will materially affect the Group’s reported income or net assets.

US Generally Accepted Accounting Principles

The consolidated financial statements of the BP Group are prepared in accordance with IFRS, which differs in certain respects from US GAAP. The principal differences between US GAAP and IFRS for BP Group reporting are discussed in Item 18 — Financial Statements — Note 55 on page F-191.


	*Impact of New US Accounting Standards*

Inventory. In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 151 ‘Inventory Costs — an amendment of ARB No. 43, Chapter 4’ (SFAS 151). SFAS 151 requires that items, such as idle facility expense, excessive spoilage, double freight and re-handling costs, be recognized as current-period charges. SFAS 151 also requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for accounting periods beginning after June 15, 2005. The Group adopted SFAS 151 with effect from July 1, 2005. The adoption of SFAS 151 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Discontinued operations. In November 2004, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 03-13 ‘Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’ (EITF 03-13). Under EITF 03-13, a disposed component of an enterprise is classified as a discontinued operation only where the ongoing entity has no significant continuing direct cash flows and does not retain an interest, contract or other arrangement sufficient to enable the entity to exert significant influence over the disposed component’s operating and financial policies after disposal. EITF 03-13 is effective for a component of an enterprise that is either disposed of or classified as held for sale in accounting periods beginning after December 15, 2004. Applying EITF 03-13 led to the conclusion that the Innovene operations were not discontinued operations for US GAAP (see Item 18 — Financial Statements — Note 55 on page F-191).

Revenue. In September 2005, the FASB ratified the consensus reached by the EITF regarding Issue No. 04-13 ‘Accounting for Purchases and Sales of Inventory with the Same Counterparty’ (EITF 04-13). EITF 04-13 addresses accounting issues that arise when a company both sells inventory to and buys inventory from another entity in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw material,work-in-process or finished goods. At issue is whether the revenue, inventory cost and cost of sales should be recorded at fair value or whether the transactions should be classified as nonmonetary transactions. EITF 04-13 requires purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another be

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combined and recorded as exchanges measured at the book value of the item sold. EITF 04-13 is effective for new arrangements entered into and modifications or renewals of existing arrangements in accounting periods beginning after March 15, 2006. The adoption of EITF 04-13 is not expected to have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or shareholders’ equity, as adjusted to accord with US GAAP.

Nonmonetary asset exchanges. In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 ‘Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29’ (SFAS 153). SFAS 153 eliminates the Accounting Principles Board Opinion No. 29 exception for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS 153 is effective for nonmonetary asset exchanges occurring in accounting periods beginning after June 15, 2005. The Group adopted SFAS 153 with effect from January 1, 2005. The adoption of SFAS 153 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Share-based payments. In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) ‘Share-Based Payment’ (SFAS 123R). SFAS 123R, which is a revision of Statement of Financial Accounting Standards No. 123 ‘Accounting for Stock-Based Compensation’ (SFAS 123), supersedes APB Opinion No. 25 ‘Accounting for Stock Issued to Employees’. Under SFAS 123R, share-based payments to employees and others are required to be recognized as an expense in the income statement based on their fair value. Pro forma disclosure is no longer a permitted alternative.

Effective January 1, 2005, as part of the adoption of IFRS, the Group adopted International Financial Reporting Standard 2 ‘Share-based Payment’ (IFRS 2). IFRS 2 requires the recognition of expense when goods or services are received from employees or others in consideration for equity instruments or amounts that are based on the value of an entity’s equity instruments. The recognition and measurement provisions of IFRS 2 are similar to those of SFAS 123R.

In adopting IFRS 2, the Company elected to restate prior period results to recognize the expense associated with equity-settled share-based payment transactions that were not fully vested as January 1, 2003 and the liability associated with cash-settled share-based payment transactions as of January 1, 2003.

The Group adopted SFAS 123R using the modified prospective transition method with effect from January 1, 2005.

Taxation. In December 2004, the FASB issued Staff Position No. 109-1 ‘Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004’ (FSP 109-1). FSP 109-1, effective upon issuance, requires that the manufacturers’ deduction provided for under the American Jobs Creation Act of 2004 (the Jobs Creation Act) be accounted for as special deduction in accordance with FASB Statement of Financial Accounting Standards No. 109, ‘Accounting for Income Taxes,’ rather than a tax rate reduction. The manufacturers’ deduction will be recognized by the Group in the year the benefit is earned.

In December 2004, the FASB issued Staff Position No. 109-2 ‘Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004’ (FSP 109-2). The Jobs Creation Act provides a special one-time provision allowing earnings of certain non-US companies to be repatriated to a US parent company at a reduced tax rate. FSP 109-2, effective upon issuance, permits additional time beyond the financial reporting period of enactment in order to evaluate the effect of the Jobs Creation Act without undermining an entity’s assertion that repatriation of non-US earnings to a US parent company is not expected within the foreseeable future. The repatriation provision of the Jobs Creation Act did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

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Provisions. In March 2005, the FASB issued FASB Interpretation No. 47 ‘Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143’ (Interpretation 47). Under Interpretation 47, a conditional asset retirement obligation represents an unconditional obligation to perform an asset retirement activity where the timing or method of settlement is conditional on a future event that may or may not be within the control of the entity. Interpretation 47 clarifies that an entity is required to recognize a liability, when incurred, for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation is factored into the measurement of the liability when sufficient information exists. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. Interpretation 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Interpretation 47 is effective for fiscal years ending after December 15, 2005. The Group adopted Interpretation 47 with effect from January 1, 2005. The adoption of Interpretation 47 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Fixed assets. FASB Statement of Financial Accounting Standards No. 19 ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’ (SFAS 19) requires the cost of drilling an exploratory well (exploration or exploratory-type stratigraphic test wells) to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, SFAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain situations. Subsequent to the issuance of SFAS 19, as a result of the increasing complexity of oil and gas projects due to drilling in remote and deepwater offshore locations, entities increasingly require more than one year to complete all of the activities that permit recognition of proved reserves. In addition, because of new technologies, in certain situations additional exploratory wells may no longer be required before a project can commence.

In April 2005, the FASB issued Staff Position No. 19-1 ‘Accounting for Suspended Well Costs’ (FSP 19-1). FSP 19-1 amends SFAS 19 to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if an entity obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well is assumed to be impaired, and its costs, net of any salvage value, is charged to expense. FSP 19-1 provides a number of indicators that would be considered in order to demonstrate that sufficient progress was being made in assessing the reserves and the economic viability of the project. FSP 19-1 is effective for accounting periods beginning after April 4, 2005. Early application of the guidance is permitted in periods for which financial statements have not yet been issued.

BP’s accounting policy is that 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. 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. The Group adopted FSP 19-1 with effect from January 1, 2004. No previously capitalized costs were expensed upon the adoption of FSP 19-1.

Accounting changes and error corrections. In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154 ‘Accounting Changes and Error Corrections, a replacement of APB

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Opinion No. 20 and FASB Statement No. 3’ (SFAS 154). SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for the accounting for, and reporting of, a change in accounting principle. SFAS 154 requires retrospective application to prior period financial statements of a voluntary change in accounting principle unless it is impracticable. Previously, most voluntary changes in accounting principle were recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 also requires that a change in the method of depreciation, amortization or depletion for long-lived nonfinancial assets be accounted for as a change in accounting estimate that is effected by a change in accounting principle. Previously, such changes were reported as a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in accounting periods beginning after December 15, 2005. The adoption of SFAS 154 is not expected to have a significant effect on profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

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ITEM 6 —	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

DIRECTORS AND SENIOR MANAGEMENT

The following lists the Company’s directors and senior management as at June 28, 2006.


		Initially elected
Name		or appointed

P D Sutherland	Non-executive chairman (a)(e)	Chairman since May 1997
		Director since July 1995
Sir Ian Prosser	Non-executive deputy	Deputy chairman since
	chairman (a)(b)(c)(e)	February 1999
		Director since May 1997
The Lord Browne of Madingley	Executive director (group chief executive)	September 1991
Dr D C Allen	Executive director (group chief of staff)	February 2003
P B P Bevan	Group general counsel	September 1992
S Bott	Executive vice president, human resources	March 2005
I C Conn	Executive director, (group executive officer, strategic resources)	July 2004
V Cox	Executive vice president, Gas, Power & Renewables	July 2004
Dr B E Grote	Executive director (chief financial officer)	August 2000
Dr A B Hayward	Executive director (chief executive, Exploration and Production)	February 2003
A G Inglis	Deputy chief executive, Exploration and Production	July 2004
J A Manzoni	Executive director (chief executive, Refining and Marketing)	February 2003
J H Bryan	Non-executive director (a)(b)(c)	December 1998
A Burgmans	Non-executive director (a)(d)	February 2004
E B Davis, Jr	Non-executive director (a)(b)(c)	December 1998
D J Flint	Non-executive director (a)(c)	January 2005
Dr D S Julius	Non-executive director (a)(b)(e)	November 2001
Sir Tom McKillop	Non-executive director (a)(b)(d)	July 2004
Dr W E Massey	Non-executive director (a)(d)(e)	December 1998


(a)		Member of the chairman’s committee.

(b)		Member of the remuneration committee.

(c)		Member of the audit committee.

(d)		Member of the ethics and environment assurance committee.

(e)		Member of the nomination committee

Mr M H Wilson resigned as a non-executive director on February 28, 2006. Mr H M P Miles retired as a non-executive director on April 20, 2006. At the Company’s Annual General Meeting (AGM) the following directors retired, offered themselves for re-election and were duly re-elected: Dr D C Allen, The Lord Browne of Madingley, Mr J H Bryan, Mr A Burgmans, Mr I C Conn, Mr E B Davis, Jr, Mr D J Flint, Dr B E Grote, Dr A B Hayward, Dr D S Julius, Sir Tom McKillop, Mr J A Manzoni, Dr W E Massey, Sir Ian Prosser, and Mr P D Sutherland.

The biographies of the directors and senior management are set out below.

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P D Sutherland, KCMG — Peter Sutherland (60) rejoined BP’s board in 1995, having been a non-executive director from 1990 to 1993, and was appointed chairman in 1997. He is non-executive chairman of Goldman Sachs International and a non-executive director of The Royal Bank of Scotland Group.

Sir Ian Prosser — Sir Ian (62) joined BP’s board in 1997 and was appointed non-executive deputy chairman in 1999. He retired as chairman of Intercontinental Hotels Group PLC, previously Bass PLC, in 2003. He was a non-executive director of The Boots Company from 1984 to 1996, of Lloyds Bank PLC from 1988 to 1995 and of Lloyds TSB Group PLC from 1995 to 1999. In 2000, he was appointed a non-executive director of GlaxoSmithKline and in 2004 he was appointed a non-executive director of Sara Lee Corporation.

The Lord Browne of Madingley, FREng — Lord Browne (58) joined BP in 1966 and subsequently held a variety of Exploration and Production and Finance posts in the US, UK and Canada. He was appointed an executive director in 1991 and group chief executive in 1995. He is a non-executive director of Intel Corporation and Goldman Sachs Group Inc. He was knighted in 1998 and made a life peer in 2001.

Dr D C Allen — David Allen (51) joined BP in 1978 and subsequently undertook a number of Corporate and Exploration and Production roles in London and New York. He moved to BP’s Corporate Planning function in 1986, becoming group vice president in 1999. He was appointed an executive vice president and group chief of staff in 2000 and an executive director of BP in 2003. He is a director of BP Pension Trustees Ltd.

P B P Bevan — Peter Bevan (62) joined BP after qualifying as a solicitor with a City of London firm. He worked initially in the law department of BP Chemicals. He became group general counsel in 1992 following roles as manager of the Legal function of BP Exploration, assistant company secretary and deputy group legal adviser. He was appointed an executive vice president of BP p.l.c. in 1998.

S Bott — Sally Bott (57) joined BP in March 2005 as an executive vice president responsible for human resources management. She joined Citibank in 1970 and following a variety of roles, was appointed a vice president in human resources in 1979 subsequently holding a series of positions as a human resources director to sectors of Citibank. In 1994, she joined BZW, an investment bank, as head of human resources and in 1996 became group human resources director of Barclays Group. From 2000 to early 2005, she was managing director and head of global human resources at Marsh Inc., insurance brokers.

I C Conn — Iain Conn (43) joined BP in 1986. Following a variety of roles in oil trading, commercial refining, marketing, Exploration and Production, in 2000 he became group vice president of BP’s Refining and Marketing business. From 2002 to 2004, he was chief executive of Petrochemicals. He was appointed group executive officer with a range of regional and functional responsibilities and an executive director in July 2004. He was appointed to the board of Rolls-Royce Group plc in January 2005. He is chairman of BP Pension Trustees Ltd.

V Cox — Vivienne Cox (47) joined BP in 1981. Following a series of commercial roles, she was appointed chief executive of Air BP in 1998. From 1999 until 2001 she was group vice president in BP Oil responsible for business to business marketing in oil, supply and trading. In 2001, she became group vice president integrated supply and trading and in 2004 she was appointed an executive vice president, additionally responsible for Gas, Power and Renewables. She also became responsible for BP Alternative Energy following its launch in late 2005.

Dr B E Grote — Byron Grote (58) joined BP in 1987 following the acquisition of The Standard Oil Company of Ohio, where he had worked since 1979. He became group treasurer in 1992 and in 1994 regional chief executive in Latin America. In 1999, he was appointed an executive vice president of Exploration and Production, and chief executive of Chemicals in 2000. He was appointed an executive director of BP in 2000 and chief financial officer in 2002. He was appointed to the boards of Unilever PLC and Unilever NV in May 2006.

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Dr A B Hayward — Tony Hayward (49) joined BP in 1982. He became a director of Exploration and Production in 1997, the segment in which he had previously held a series of roles. In 2000, he was made group treasurer and an executive vice president in 2002. He was appointed chief operating officer for Exploration and Production in 2002 and an executive director of BP in 2003. He is a non-executive director of Corus Group.

A G Inglis — Andrew Inglis (47) joined BP in 1980 working on various North Sea Projects. Following a series of commercial roles in BP Exploration, in 1996 he became chief of staff, Exploration and Production. From 1997 until 1999, he was responsible for leading BP’s activities in the Deepwater Gulf of Mexico. In 1999, he was appointed vice president of BP’s US western gas business unit and in 2004 he became executive vice president and deputy chief executive of Exploration and Production.

J A Manzoni — John Manzoni (46) joined BP in 1983. He became group vice president for European marketing in 1999 and BP regional president for the eastern US in 2000. In 2001, he became an executive vice president and chief executive for BP’s Gas and Power segment. He was appointed chief executive of the Refining and Marketing segment in 2002 and an executive director of BP in 2003. He is a non-executive director of SABMiller plc.

J H Bryan — John Bryan (69) joined BP’s board in 1998, having previously been a director of Amoco. He serves on the boards of General Motors Corporation and Goldman Sachs Group Inc. He retired as chairman of Sara Lee Corporation in 2001. He is chairman of Millennium Park Inc. in Chicago.

A Burgmans — Antony Burgmans (59) joined BP’s board in 2004. He was appointed to the board of Unilever in 1991. In 1999, he became chairman of Unilever NV and vice chairman of Unilever PLC. He was appointed non-executive chairman of Unilever NV and Unilever PLC in 2005. He is also a member of the supervisory board of ABN AMRO Bank NV.

E B Davis, Jr — Erroll B Davis, Jr (61) joined BP’s board in 1998, having previously been a director of Amoco. He was chairman and chief executive officer of Alliant Energy, relinquishing this dual appointment in July 2005. He continued as chairman of Alliant Energy until February 1, 2006, leaving to become chancellor of the University System of Georgia. He is a non-executive director of PPG Industries, Union Pacific Corporation and the US Olympic Committee.

D J Flint, CBE — Douglas Flint (50) joined BP’s board in January 2005. He trained as a chartered accountant and became a partner at KPMG in 1988. In 1995, he was appointed group finance director of HSBC Holdings plc. He was chairman of the Financial Reporting Council’s review of the Turnbull Guidance on Internal Control. Between 2001 and 2004, he served on the Accounting Standards Board and the advisory council of the International Accounting Standards Board.

Dr D S Julius, CBE — DeAnne Julius (57) joined BP’s board in 2001. She began her career as a project economist with the World Bank in Washington. From 1986 until 1997, she held a succession of posts, including chief economist at British Airways and Royal Dutch Shell Group. From 1997 to 2001, she was a full-time member of the Monetary Policy Committee of the Bank of England. She is chairman of the Royal Institute of International Affairs and a non-executive director of Lloyds TSB Group PLC, Serco and Roche Holdings SA.

Sir Tom McKillop — Sir Tom (63) joined BP’s board in July 2004. Sir Tom was chief executive of AstraZeneca PLC from the merger of Astra AB and Zeneca Group PLC in 1999 until December 31, 2005. He was a non-executive director of Lloyds TSB Group PLC until 2004 and is chairman of The Royal Bank of Scotland Group.

Dr W E Massey — Walter Massey (68) joined BP’s board in 1998, having previously been a director of Amoco. He is president of Morehouse College, a non-executive director of Motorola, Bank of America and McDonald’s Corporation and a member of President Bush’s Council of Advisors on Science & Technology.

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COMPENSATION

The remuneration committee determines the terms of engagement and remuneration of the executive directors and monitors the policies applied by the group chief executive in remunerating other senior executives.

Policy on Executive Directors’ Remuneration

During 2004, the committee carried out a comprehensive and independent review of all elements of remuneration policy for executive directors, culminating in a shareholder resolution at the 2005 AGM approving the renewal of the Executive Directors’ Incentive Plan (EDIP).

The committee seeks to ensure that, in determining remuneration policy, there is a clear link between the Company’s purpose, the business plans and executive reward. The following key principles guide its policy:


	—	Policy for the remuneration of executive directors will be determined and regularly reviewed independently of executive management and will set the tone for the remuneration of other senior executives.

	—	The remuneration structure will support and reflect BP’s stated purpose to maximize long-term shareholder value.

	—	The remuneration structure will reflect a just system of rewards for the participants.

	—	The overall quantum of all potential remuneration components will be determined by the exercise of informed judgement of the independent remuneration committee, taking into account the success of BP and the competitive global market.

	—	The majority of the remuneration will be linked to the achievement of demanding performance targets that are independently set and reflect the creation of long-term shareholder value.

	—	A significant personal shareholding will be developed in order to align executive and shareholder interests.

	—	Assessment of performance will be quantitative and qualitative and will include exercise of informed judgement by the remuneration committee within a framework that takes account of sector characteristics and is approved by shareholders.

	—	The committee will be proactive in obtaining an understanding of shareholder preferences.

	—	Remuneration policy and practices will be as transparent as possible, both for participants and shareholders.

	—	The wider scene, including pay and employment conditions elsewhere in the Group, will be taken into account, especially when determining annual salary increases.

Elements of Remuneration

The executive directors’ total remuneration will consist of salary, annual bonus, long-term incentives, pensions and other benefits. This reward structure will be regularly reviewed by the committee to ensure that it is achieving its objectives.

In 2006, over three-quarters of executive directors’ potential direct remuneration will again be performance-related.


	*Salary*

The committee expects to review salaries in 2006. In doing so, the committee considers both top Europe-based global companies and the US oil and gas sector; each of these groups is defined and

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analysed by the committee’s independent external remuneration advisers. The committee then assesses the market information and advice and applies its judgement in setting the salary levels.


	*Annual Bonus*

Each executive director is eligible to participate in an annual performance-based bonus scheme. The committee reviews and sets bonus targets and levels of eligibility annually.

For 2006, the target level is 120% of base salary (except for Lord Browne, for whom, as group chief executive, it is considered appropriate to have a target of 130%). In normal circumstances, the maximum payment level for substantially exceeding targets will continue to be 150% (165% for the group chief executive) of base salary. In exceptional circumstances, outstanding performance may be recognized by bonus payments moderately above the 150% (and 165%) levels at the discretion of the remuneration committee. Similarly, bonuses may be reduced where the committee considers that this is warranted and, in exceptional circumstances, bonuses can be reduced to zero.

The committee recognizes that it is responsible to shareholders to use its discretion in a reasonable and informed manner in the best interests of the Company and that it has a corresponding duty to be accountable and transparent as to the manner in which it exercises its discretion. The committee will explain any significant exercise of discretion in the subsequent directors’ remuneration report.

Executive directors’ annual bonus awards for 2006 will be based on a mix of demanding financial targets, based on the Company’s annual plan and leadership objectives established at the beginning of the year, in accordance with the following weightings:


	—	50% financial and operational metrics from the annual plan, principally earnings before interest, tax, depreciation and amortization (EBITDA) and return on average capital employed (ROACE).

	—	30% annual strategic milestones taken from the five-year Group business plan, including those relating to technology, operational actions and business development.

	—	20% individual performance against leadership objectives and living the values of the Group, which incorporates BP’s Code of Conduct.

In assessing the final outcome of the individual bonuses each year, the committee will also carefully review the underlying performance of the Group in the context of the five-year Group business plan, as well as looking at competitor results, analysts’ reports and the views from the chairmen of other BP board committees. All the calculations are reviewed by Ernst & Young.


	*Long-term Incentives*

Long-term incentives will continue to be provided under the EDIP. It has three elements within its framework: a share element, a share option element and a cash element. The committee does not currently intend to use either the share option or cash elements but, in exceptional circumstances, may do so.

Each executive director participates in the EDIP. The committee’s policy, subject to unforeseen circumstances, is that this should continue until the EDIP expires or is renewed in 2010.

The committee’s policy continues to be that each executive director should hold shares equivalent in value to 5 x the director’s base salary within five years of being appointed an executive director. This policy is reflected in the terms of the EDIP, as shares awarded under the share element will only be released at the end of the three-year retention period (as described below) if the minimum shareholding guidelines have been met.

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	Share Element

The committee may make conditional share awards (performance shares) to executive directors, which will only vest to the extent that a demanding performance condition imposed by the committee is met at the end of a three-year performance period.

The maximum number of performance shares that may be awarded to an executive director in any one year will be determined at the discretion of the remuneration committee and will not normally exceed 5.5 x base salary and, in the case of the group chief executive, 7.5 x base salary.

In addition to the performance condition described below, the committee will have an overriding discretion, in exceptional circumstances, to reduce the number of shares that vest (or to provide that no shares vest).

The shares that vest will normally be subject to a compulsory retention period determined by the committee, which will not normally be less than three years. This gives executive directors a six-year incentive structure and is designed to ensure that their interests are aligned with those of shareholders. Where shares vest under awards made in 2005 and future years, the executive director will receive additional shares representing the value of reinvested dividends on these shares.

For share element awards in 2006, the performance condition will (as in 2005) relate to BP’s total shareholder return (TSR) performance against the other oil majors (ExxonMobil, Shell, Total and Chevron) over a three-year period. The committee will have the discretion to amend this peer group in appropriate circumstances, for example, in the case of any significant consolidations in the industry. TSR is calculated by taking the share price performance of a company over the period, assuming dividends to be reinvested in the Company’s shares. All share prices will be averaged over the three months before the beginning and end of the performance period and will be measured in US dollars. At the end of the performance period, the TSR performance of each of the companies will be ranked to establish the relative total return to shareholders over the period. Shares under the award will vest as to 100%, 70% and 35% if BP achieves first, second or third place respectively; no shares will vest if BP achieves fourth or fifth place.

The committee considers that relative TSR is the most appropriate measure of performance for BP’s long-term incentives for executive directors as it best reflects the creation of long-term shareholder value. Relative performance of the peer group is particularly key in order to minimize the influence of sector-specific effects, including oil price.

The committee is mindful of the possibility that a simple ranking system may in some circumstances give rise to distorted results in view of the broad similarity of the oil majors’ underlying businesses, the small size of the comparator group and inherent imperfections in measurement. To counter this, the committee will have the ability to exercise discretion in a reasonable and informed manner to adjust (upwards or downwards) the vesting level derived from the ranking if it considers that the ranking does not fairly reflect BP’s underlying business performance relative to the comparator group.

The exercise of this discretion would be made after a broad analysis of the underlying health of BP’s business relative to competitors, as shown by a range of other measures including, but not limited to, ROACE, earnings per share (EPS) growth, reserves replacement and cash flow. This will enable a more comprehensive review of long-term performance, with the aims of tempering anomalies created by relying solely on a formula-based approach and ensuring that the objectives of the plan are met.

It is anticipated that the need to use discretion is most likely to arise where the TSR performance of some companies is clustered, so that a relatively small difference in TSR performance would produce a major difference in vesting levels. In these circumstances, the committee will have power to adjust the vesting level, normally by determining an average vesting level for the companies affected by the clustering.

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In line with its policy on transparency, the committee will explain any adjustment to the relative TSR ranking in the next directors’ remuneration report following the vesting.

The committee may amend the performance conditions if events occur that would make the amended condition a fairer measure of performance and provided that any amended condition is no easier to satisfy.

For 2006, all executive directors will receive performance share awards on the above basis, over a maximum number of shares set by reference to 5.5 x base salary. For awards under the share element in future years, the committee may continue with the same performance condition or may impose a different condition, which it considers to be no less demanding.

As group chief executive, Lord Browne is eligible for performance share awards of up to 7.5 x base salary. The committee has determined that, while the largest part of this should relate to the TSR measure described above, it continues to be appropriate that a specific part (up to 2 x base salary) should be based on long-term leadership measures. These will focus on sustaining BP’s financial, strategic and organizational health and will include, but not be limited to, maintenance of BP’s performance culture and the continued development of BP’s business strategy, executive talent and internal organization. As with the TSR part of his award, this part will be measured over a three-year performance period.


	Share Element Awards Made in Previous Years

Awards for the period 2005-2007 were made on the same basis as described above. For outstanding awards of performance units made under the plans for the periods 2003-2005 and 2004-2006, the previous performance conditions will apply for the three-year performance periods in each of the plans. The primary measure is BP’s shareholder return against the market (SHRAM), which accounts for nearly two-thirds of the potential total award, the remainder being assessed on BP’s relative ROACE and EPS growth.

BP’s SHRAM is measured against the companies in the FTSE All World Oil & Gas Index. Companies within the index are weighted according to their market capitalization at the beginning of each three-year period in order to give greatest emphasis to oil majors. BP’s ROACE and EPS growth are measured against ExxonMobil, Shell, Total and Chevron. All calculations are reviewed by Ernst & Young to ensure that they meet an independent objective standard. The relative position of the Company within the comparator group determines the number of shares awarded per performance unit, subject to a maximum of two shares per unit.


	Share Option Element

The share option element of the EDIP permits options to be granted to executive directors at an exercise price no lower than the market value of a share at the date the option is granted. The committee does not currently intend to use this element.


	Cash Element

The cash element allows the committee to grant long-term cash-based incentives. This element has not been used since the EDIP was established in 2000 and the committee would only do so in special circumstances.


	*Pensions*

Executive directors are eligible to participate in the appropriate pension schemes applying in their home countries.

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	*Other Benefits*


	Benefits and Other Share Schemes

Executive directors are eligible to participate in regular employee benefit plans and in all-employee share schemes and savings plans applying in their home countries. Benefits in kind are not pensionable.


	Resettlement Allowance

Expatriates may receive a resettlement allowance for a limited period.

2005 Remuneration for Executive Directors

Amounts shown are in the currency received by executive directors. For information, the average exchange rate for 2005 was £1 = $1.82. Annual bonus is shown in the year it was earned.


	Annual remuneration										Long-term remuneration

											Share element of EDIP/ LTPPs

																			2005-2007
											2002-2004 plan				2003-2005 plan				plan
											(vested in Feb				(vested in Feb				(awarded in
											2005)				2006)				Apr 2005)

					2005
					Non-cash
					benefits														Potential
	2005		2005 annual		and other		2005		2004		Actual				Actual				maximum
	Salary		performance		emoluments		total		total		Shares		Value		shares		Value		performance
	‘000		bonus ‘000		‘000		‘000		‘000		vested(b)		‘000(a)		vested (b)		‘000(c)		shares (d)

The Lord Browne of Madingley		£1,451		£1,750		£90		£3,291		£3,744		356,667		£1,958		474,384		£3,064		2,006,767
Dr D C Allen		£431		£480		£12		£923		£1,036		60,000		£329		147,783		£955		436,623
I C Conn(e)		£421		£450		£43		£914		£542		51,750		£284		68,250		£441		415,832
Dr B E Grote		$923		$1,100		—		$2,023		$2,103		136,960		$1,419		175,229		$1,979		501,782
Dr A B Hayward		£431		£460		£14		£905		£1,061		55,125		£303		147,783		£955		436,623
J A Manzoni		£431		£440		£47		£918		£1,071		60,000		£329		147,783		£955		436,623


(a)		Based on market price on date of award (£5.49 per share/$62.15 per ADS).

(b)		Gross award of shares based on a performance assessment by the remuneration committee and on the other terms of the plan. Sufficient shares are sold to pay for tax applicable. Remaining shares are held in trust for current directors for the three-year retention period, when they are released to the individual.

(c)		Based on the market price on date of award (£6.46 per share/$67.76 per ADS).

(d)		Maximum potential shares that could vest at the end of the three-year period depending on performance.

(e)		2004 remuneration reflects that received by Mr Conn from his appointment as executive director on July 1, 2004.


	*Salary*

Base salaries for all executive directors were reviewed relative to top Europe-based global companies and the US oil and gas sector. Having taken account of market movements and performance, the committee awarded a 5% increase in base salaries with effect from July 1, 2005 for all executive directors except Mr Conn, whose increase was slightly higher to bring him to the same level as his peers.


	*Annual Bonus*

The measures and weightings described earlier form the framework within which the remuneration committee determined the annual bonuses for the executive directors.

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The committee made evaluations against each of the measures: financial, metrics and milestones, and individual. The financial measures were taken from the annual plan principally on cash flow. Cash flow was strong. Amounts received from the divestment of non-strategic assets significantly exceeded internal targets (principally due to the Innovene disposal) and these, along with other actions and successes, more than offset reductions in cash flow caused by adverse events. Production rates, allowing for the impact of oil prices on production-sharing contracts and weather-related downtime, were within internal expectations.

Annual strategic metrics and milestones were taken from the five-year Group business plan. There is a wide range of measures, including those relating to people, safety, environment, technology and organization as well as operations and business development. The Group continued to perform well, developing business in Russia, India and elsewhere. New fields came on stream in the US, Angola, Azerbaijan and Trinidad & Tobago. A new Code of Conduct was launched and employees were trained in its application. Safety performance was impaired by the incident at the Texas City refinery.

Individual performance against leadership objectives was reviewed by the committee, as was the underlying performance of the Group in the context of the five-year plan, together with competitor results and positioning. Results are in line with or exceed expectations.

The committee also considered this performance in the light of the significant events during the year, both positive and negative. These included the high prices of oil and gas; the overall financial performance of the Group; the disposal of non-strategic assets, principally Innovene; the financial and other consequences of the incident at the Texas City refinery and the repairs to the Thunder Horse platform; and the effects of the hurricanes in the Gulf of Mexico. The scale and the impact of all of these events were taken into account in determining the annual bonuses.


	*Long-term Performance-based Components*


	Share Element of EDIP and Long Term Performance Plans (LTPPs)

Under the share element of the EDIP and the Long Term Performance Plans (LTPPs), performance units were until 2004 granted at the beginning of the three-year period and converted into an award of shares at the end of the period, depending on performance. There is a maximum of two shares per performance unit. For 2005 and future years, grants of performance shares are made, being the maximum number of shares that could vest (as described in compensation — Elements of Remuneration — Long-Term Incentives — Share Element in this Item on page 117). In the table following, performance units that have yet to convert to shares are expressed as the maximum number of shares into which they could convert (based on the maximum 2:1 ratio). This achieves consistency of disclosure between the two periods.

For the 2003-2005 share element of the EDIP and the LTPPs, BP’s performance was assessed in terms of SHRAM, ROACE and EPS growth. BP’s three-year SHRAM was measured against the companies in the FTSE All World Oil & Gas Index. Companies within the index are weighted according to their market capitalization at the beginning of each three-year period in order to give greatest emphasis to oil majors. BP’s ROACE and EPS were measured against ExxonMobil, Shell, Total and Chevron. Based on a performance assessment of 75 points out of 200 (0 for SHRAM, 50 for ROACE and 25 for EPS growth), the committee made awards of shares to executive directors as highlighted in the 2003-2005 lines of the table following.

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The following table summarizes the LTPPs and share elements of the executive directors’ remuneration for 2005.


							Share element/ LTPP interests						Interests vested in 2005

					Market price		Potential maximum										Market
					of each share		performance shares (a)										price of
			Date of		at date of								Number of				each
			award of		award of								ordinary				share at
	Performance		performance		performance		At Jan 1,		Awarded		At Dec 31,		shares				vesting
	period		shares		shares £		2005		2005		2005		vested (b)		Vesting date		date £

The Lord Browne of Madingley		2002-2004		Feb 18, 2002		5.73		951,112		—		—		356,667		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		1,265,024		—		1,265,024		474,384		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		1,268,894		—		1,268,894		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		2,006,767		2,006,767		—		—		—
Dr D C Allen		2002-2004		Mar 6, 2002		5.99		160,000		—		—		60,000		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		394,088		—		394,088		147,783		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		376,470		—		376,470		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		436,623		436,623		—		—		—
I C Conn (c)		2002-2004		Mar 6, 2002		5.99		138,000		—		—		51,750		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		182,000		—		182,000		68,250		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		182,000		—		182,000		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		415,832		415,832		—		—		—
Dr B E Grote		2002-2004		Feb 18, 2002		5.73		365,226		—		—		136,960		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		467,276		—		467,276		175,229		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		425,338		—		425,338		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		501,782		501,782		—		—		—
Dr A B Hayward		2002-2004		Mar 6, 2002		5.99		147,000		—		—		55,125		Feb, 9 2005		5.49
		2003-2005		Feb 17, 2003		3.96		394,088		—		394,088		147,783		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		376,470		—		376,470		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		436,623		436,623		—		—		—
J A Manzoni		2002-2004		Mar 6, 2002		5.99		160,000		—		—		60,000		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		394,088		—		394,088		147,783		Feb 13, 2006		6.46
		2004-2006		Feb 25, 2004		4.25		376,470		—		376,470		—		—		—
		2005-2007		Apr 28, 2005		5.33		—		436,623		436,623		—		—		—
Former Directors
R L Olver		2002-2004		Feb 18, 2002		5.73		392,592		—		—		147,222		Feb 9, 2005		5.49
		2003-2005		Feb 17, 2003		3.96		548,276		—		548,276		205,604		Feb 13, 2006		6.46


(a)		BP’s performance is measured against the oil sector. For the periods 2003-2005 and 2004-2006, the performance measure is SHRAM, which is measured against the FTSE All World Oil & Gas Index, and ROACE and EPS growth, which are measured against ExxonMobil, Shell, Total and Chevron. For the 2005-2007 period, the performance condition is TSR measured against ExxonMobil, Shell, Total and Chevron. Each performance period ends on December 31 of the third year.

(b)		Represents awards of shares made at the end of the relevant performance period based on performance achieved under rules of the plan.

(c)		Mr Conn elected to defer to 2006 the determination of whether LTPP awards should be made for the 2000-2002 performance period. As this period ended prior to his appointment as a director, the award is not included in this table.

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Share Options

The table below represents the interests of executive directors in options over ordinary shares during 2005.


													Market
													price at		Date from
	Option		At Jan 1,						At Dec 31,		Option		date of		which first		Expiry
	type		2005		Granted		Exercised		2005		price		exercise		exercisable		date

The Lord Browne of Madingley		SAYE		4,550		—		—		4,550		£3.50		—		Sept 1, 08		Feb 28, 09
		EDIP		408,522		—		—		408,522		£5.99		—		May 15, 01		May 15, 07
		EDIP		1,269,843		—		—		1,269,843		£5.67		—		Feb 19, 02		Feb 19, 08
		EDIP		1,348,032		—		—		1,348,032		£5.72		—		Feb 18, 03		Feb 18, 09
		EDIP		1,348,032		—		—		1,348,032		£3.88		—		Feb 17, 04		Feb 17, 10
		EDIP		1,500,000		—		—		1,500,000		£4.22		—		Feb 25, 05		Feb 25, 11
Dr D C Allen		EXEC		37,000		—		—		37,000		£5.99		—		May 15, 03		May 15, 10
		EXEC		87,950		—		—		87,950		£5.67		—		Feb 23, 04		Feb 23, 11
		EXEC		175,000		—		—		175,000		£5.72		—		Feb 18, 05		Feb 18, 12
		EDIP		220,000		—		—		220,000		£3.88		—		Feb 17, 04		Feb 17, 10
		EDIP		275,000		—		—		275,000		£4.22		—		Feb 25, 05		Feb 25, 11
I C Conn		SAYE		1,355		—		1,355		—		£4.98		£6.38		Sep 1, 05		Feb 28, 06
		SAYE		1,456		—		—		1,456		£3.50		—		Sep 1, 08		Feb 28, 09
		SAYE		1,186		—		—		1,186		£3.86		—		Sep 1, 09		Feb 28, 10
		SAYE		—		1,498		—		1,498		£4.41		—		Sep 1, 10		Feb 28, 11
		EXEC		72,250		—		—		72,250		£5.67		—		Feb 23, 04		Feb 23, 11
		EXEC		130,000		—		—		130,000		£5.72		—		Feb 18, 05		Feb 18, 12
		EXEC		160,000		—		—		160,000		£3.88		—		Feb 17, 06		Feb 17, 13
		EXEC		126,000		—		—		126,000		£4.22		—		Feb 25, 07		Feb 25, 14
Dr B E Grote (a)		SAR		35,200		—		—		35,200	$	25.27		—		Mar 6, 99		Mar 6, 06
		SAR		40,000		—		—		40,000	$	33.34		—		Feb 28, 00		Feb 28, 07
		BPA		10,404		—		—		10,404	$	53.90		—		Mar 15, 00		Mar 14, 09
		BPA		12,600		—		—		12,600	$	48.94		—		Mar 28, 01		Mar 27, 10
		EDIP		40,182		—		—		40,182	$	49.65		—		Feb 19, 02		Feb 19, 08
		EDIP		58,173		—		—		58,173	$	48.82		—		Feb 18, 03		Feb 18, 09
		EDIP		58,173		—		—		58,173	$	37.76		—		Feb 17, 04		Feb 17, 10
		EDIP		58,333		—		—		58,333	$	48.53		—		Feb 25, 05		Feb 25, 11
Dr A B Hayward		SAYE		3,302		—		—		3,302		£5.11		—		Sept 1, 06		Feb 28, 07
		EXEC		34,000		—		—		34,000		£5.99		—		May 15, 03		May 15, 10
		EXEC		77,400		—		—		77,400		£5.67		—		Feb 23, 04		Feb 23, 11
		EXEC		160,000		—		—		160,000		£5.72		—		Feb 18, 05		Feb 18, 12
		EDIP		220,000		—		—		220,000		£3.88		—		Feb 17, 04		Feb 17, 10
		EDIP		275,000		—		—		275,000		£4.22		—		Feb 25, 05		Feb 25, 11
J A Manzoni		SAYE		878		—		—		878		£4.52		—		Sept 1, 07		Feb 28, 08
		SAYE		2,548		—		—		2,548		£3.50		—		Sept 1, 08		Feb 28, 09
		SAYE		847		—		—		847		£3.86		—		Sept 1, 09		Feb 28, 10
		EXEC		12,000		—		12,000		—		£2.04		£5.52		Feb 28, 98		Feb 28, 05
		EXEC		34,000		—		—		34,000		£5.99		—		May 15, 03		May 15, 10
		EXEC		72,250		—		—		72,250		£5.67		—		Feb 23, 04		Feb 23, 11
		EXEC		175,000		—		—		175,000		£5.72		—		Feb 18, 05		Feb 18, 12
		EDIP		220,000		—		—		220,000		£3.88		—		Feb 17, 04		Feb 17, 10
		EDIP		275,000		—		—		275,000		£4.22		—		Feb 25, 05		Feb 25, 11

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The closing market prices of an ordinary share and of an ADS on December 31, 2005 were £6.19 and $64.22 respectively. During 2005, the highest closing market prices were £6.84 and $72.27 respectively and the lowest closing market prices were £5.04 and $56.61 respectively.


EDIP	—	Executive Directors’ Incentive Plan adopted by shareholders in April 2005 as described in Compensation — Elements of Remuneration — Long-Term Incentives in this Item on page 116.
BPA	—	BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP.
SAR	—	Stock Appreciation Rights under BP America Inc. Share Appreciation Plan.
SAYE	—	Save As You Earn employee share scheme.
EXEC	—	Executive Share Option Scheme. These options were granted to the relevant individuals prior to their appointments as directors and are not subject to performance conditions.


(a)		Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.

Pensions

In the table below, amounts are shown in the currency received. For information, the average exchange rate for 2005 was £1 = $1.82. Lord Browne, Dr Allen, Mr Conn, Dr Hayward and Mr Manzoni accrued pension benefits in pounds sterling (the currency of payment). Similarly, Dr Grote accrued pension benefits in US dollars.


							Transfer		Transfer		Amount of
					Additional		value of		value of		B-A less
			Accrued		pension earned		accrued		accrued		contributions
			pension		during the year		benefit (b) at		benefit (b) at		made by the
	Service at		entitlement at		ended		Dec 31, 2004		Dec 31, 2005		director in
	Dec 31, 2005		Dec 31, 2005		Dec 31, 2005 (a)		A		B		2005

	(thousand)
The Lord Browne of Madingley (UK)		39 years		£991		£47		£17,170		£19,979		£2,809
Dr D C Allen (UK)		27 years		£200		£17		£2,754		£3,433		£679
I C Conn (UK)		20 years		£147		£20		£1,542		£2,124		£582
Dr B E Grote (US)		26 years		$570		$105		$5,529		$6,681		$1,152
Dr A B Hayward (UK)		24 years		£207		£19		£2,680		£3,408		£728
J A Manzoni (UK)		22 years		£163		£15		£1,958		£2,518		£560


(a)		Additional pension earned during the year includes an inflation increase of 3.5%.

(b)		Transfer values have been calculated in accordance with version 8.1 of guidance note GN11 issued by the actuarial profession.


	*UK Directors*

UK directors are members of the regular BP Pension Scheme. Scheme members’ core benefits are non-contributory. They include a pension accrual of 1/60th of basic salary for each year of service, subject to a maximum of two-thirds of final basic salary, and a dependant’s benefit of two-thirds of the member’s pension. Bonuses are not pensionable for UK directors. The scheme pension is not integrated with state pension benefits.

Normal retirement age is 60, but scheme members who have 30 or more years’ pensionable service at age 55 can elect to retire early without an actuarial reduction being applied to their pension.

In accordance with the Company’s past practice for executive directors who retire from BP on or after age 55 having accrued at least 30 years’ service, Lord Browne remains eligible for consideration for a payment from the Company of an ex-gratia lump-sum superannuation payment equal to one year’s

123

base salary following his retirement. All matters relating to such superannuation payments are considered by the remuneration committee. Any such payment would be additional to his pension entitlements referred to above. No other executive director is eligible for consideration for a superannuation payment on retirement, because the remuneration committee decided in 1996 that appointees to the board after that time should cease to be eligible for consideration for such a payment.

The UK government has made important changes to the operation and taxation of UK pensions, which come into effect from April 6, 2006 and affect all UK employees. The remuneration committee has reviewed and approved proposals by the Company that maintain the pension promise for all UK employees but that deliver pension benefits in excess of the new lifetime allowance of £1.5 million (or personal lifetime allowance as at April 6, 2006 under statute if higher) via an unapproved, unfunded pension arrangement paid by the Company direct.

The trustee directors of the BP Pension Scheme have reviewed, in accordance with its statutory obligation, the actuarial basis under which cash equivalent transfer values are payable to all UK employees who participate in that scheme. Consistent with evolving actuarial practice, the trustee directors have resolved to base cash equivalent transfer values on a similar basis to that underlying the Company’s accounts, including allowance for improving longevity in accordance with standard tables; this has the effect of increasing cash equivalent transfer values for the UK executive directors on average by about 15%. Although the change became effective in January 2006, the table above shows both December 31, 2004 and December 31, 2005 transfer value figures on the new basis.


	*US Director*

As a US director, Dr Grote participates in the US BP Retirement Accumulation Plan (US plan), which features a cash balance formula. The current design of the US plan became effective on July 1, 2000.

Consistent with US tax regulations, pension benefits are provided through a combination of tax-qualified and non-qualified benefit restoration plans, as applicable.

The Supplemental Executive Retirement Benefit (supplemental plan) is a non-qualifiedtop-up arrangement that became effective on January 1, 2002 for US employees above a specified salary level.

The benefit formula is 1.3% of final average earnings, which comprise base salary and bonus in accordance with standard US practice (as specified under the qualified arrangement) multiplied by years of service, with an offset for benefits payable under all other BP qualified and non-qualified pension arrangements. This benefit is unfunded and therefore paid from corporate assets.

Dr Grote is an eligible participant under the supplemental plan and his pension accrual for 2005 includes the total amount that may become payable under all plans.

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Executive Directors’ Shareholdings


					At
Executive directors’ interest in BP ordinary	At		At		June 28,
shares or calculated equivalents	January 1, 2005		December 31, 2005		2006

Current directors
Dr D C Allen		408,342		443,742		530,933 (a	)
The Lord Browne of Madingley		2,031,279		2,242,954		2,522,840 (b	)
I C Conn		121,187		156,349		206,642 (c	)
Dr B E Grote		888,213		988,906		1,092,292 (d	)
Dr A B Hayward		206,084		305,543		399,466
J A Manzoni		196,336		275,743		369,191


(a)		Includes 25,368 shares held as ADSs.

(b)		Includes 58,713 shares held as ADSs.

(c)		Includes 39,466 shares held as ADSs.

(d)		Held as ADSs

In disclosing the above interests to the Company under the Companies Act 1985, directors did not distinguish their beneficial and non-beneficial interests.

Executive directors are also deemed to have an interest in such shares of the Company held from time to time by The BP Employee Share Ownership Plan (No. 2) to facilitate the operation of the Company’s option schemes.

No director has any interest in the preference shares or debentures of the Company, or in the shares or loan stock of any subsidiary company.


	*Past Directors*

During 2005, Mr Olver continued as a consultant to BP in relation to its activities in Russia and served as a BP-nominated director of TNK-BP Limited, a joint venture company owned 50% by BP. Under the consultancy agreement, he received £300,000 in fees in 2005 as well as reimbursement of costs and support for his role. He is also entitled to retain fees paid to him by TNK-BP up to a maximum of $120,000 a year for his role as a director, deputy chairman and chairman of the audit committee of TNK-BP Limited.

Policy on Non-Executive Directors Remuneration

The board sets the level of remuneration for all non-executive directors within the limit approved from time to time by shareholders. In line with BP’s governance policies, the remuneration of the chairman is set by the board rather than the remuneration committee, since the performance of the chairman is a matter for the board as a whole rather than any one committee.

The board has adopted the following policies to guide its current and future decision-making with regard to non-executive directors’ remuneration:


	—	Within the limits set by the shareholders from time to time, remuneration should be sufficient to attract, motivate and retain world-class non-executive talent.

	—	Remuneration of non-executive directors is set by the board and should be proportional to their contribution towards the interests of the Company.

	—	Remuneration practice should be consistent with recognized best-practice standards for non-executive directors’ remuneration.

	—	Remuneration should be in the form of cash fees, payable monthly.

125


	—	Non-executive directors should not receive share options from the Company.

	—	Non-executive directors should be encouraged to establish a holding in BP shares broadly related to one year’s base fee, to be held directly or indirectly in a manner compatible with their personal investment activities, and any applicable legal and regulatory requirements.


	*Elements of Remuneration*

Non-executive directors’ pay comprises cash fees, paid monthly, with increments for positions of additional responsibility, reflecting additional workload and consequent potential liability. For all non-executive directors, except the chairman, a fixed sum allowance is paid for transatlantic travel (or equivalent intercontinental travel) undertaken for the purpose of attending a board or board committee meeting. In addition, non-executive directors receive reimbursement of reasonable travel and related business expenses. No share or share option awards are made to any non-executive director in respect of service on the board.


	*Letters of Appointment*

Non-executive directors have letters of appointment, which recognize that, subject to the Articles of Association, their service is at the discretion of the shareholders. All directors stand for re-election at each annual general meeting.


	*Non-Executive Directors’ Annual Fee Structure*

The fees paid to non-executive directors are set by the board within the limit set by shareholders in accordance with the Articles. Shareholders approved an increase to this limit in 2004. All fees are fixed and paid in pounds sterling. Fees payable to non-executive directors were reviewed in 2005 by an ad hoc board committee comprising Mr Bryan (chairman), Dr Julius and Mr Burgmans. This ad hoc committee recommended an increase in fees to reflect the increase in director workload as well as increases in global market rates for independent/non-executive directors, since these fees were last reviewed in 2002. The board duly approved the recommended increases with effect from January 1, 2005.


	Year ended
	December 31,

	2005			2004

	(£ thousands)
Chairman (a)		500	(a)		390
Deputy chairman (b)		100	(b)		85
Board member		75			65
Committee chairmanship fee		20			15
Transatlantic attendance allowance (c)		5			5


(a)		The chairman is not eligible for committee chairmanship fees or transatlantic attendance allowance but has the use of a fully maintained office for Company business and a chauffeured car.

(b)		The deputy chairman receives a £25,000 (2004 £20,000) increment on top of the standard board fee. In addition, he is eligible for committee chairmanship fees and the transatlantic attendance allowance. The deputy chairman is currently chairman of the audit committee.

(c)		This allowance is payable to non-executive directors undertaking transatlantic or equivalent intercontinental travel for the purpose of attending a board meeting or board committee meeting.

126


	Year ended December 31,

	2005				2004

Remuneration of Non-Executive Directors
($($-	)

	thousand		(£ thousands		thousands		(£ thousands
J H Bryan		200		110		183		100
A Burgmans		164		90		97		53
E B Davis, Jr		200		110		192		105
D J Flint (c)		164		90		n/a		n/a
Dr D S Julius		195		107		137		75
Sir Tom McKillop		164		90		70		38
Dr W E Massey		237		130		210		115
H M P Miles *		164		90		137		75
Sir Ian Prosser		246		135		201		110
P D Sutherland		910		500		714		390
M H Wilson †		191		105		174		95
Directors who left the board in 2005
C F Knight (d)(e)		55		30		165		90
Sir Robin Nicholson (d)(f)(g)		58		32		165		90


(a)		Sterling payments converted at the average 2005 exchange rate of £1 = $1.82.

(b)		Sterling payments converted at the average 2004 exchange rate of £1 = $1.83.

(c)		Appointed on January 1, 2005

(d)		Retired at AGM on April 14, 2005

(e)		Also received a superannuation gratuity of £79,000 following his retirement.

(f)		Also received £20,000 each year for serving as the board’s representative on the BP technology advisory council.

(g)		Also received a superannuation gratuity of £84,000 following his retirement.

*		Retired at AGM on April 20, 2006

†		Resigned as a non-executive director on February 28, 2006


	*Long-Term Incentives (Residual)*

Non-executive directors of Amoco Corporation were allocated restricted stock in the Amoco Non-Employee Directors’ Restricted Stock Plan by way of remuneration for their service on the board of Amoco Corporation prior to its merger with BP in 1998. On merger, interests in Amoco shares in the plan were converted into interests in BP ADSs. Under the terms of the plan, the restricted stock will vest on the retirement of the non-executive director having reached age 70 or on earlier retirement at the discretion of the board. Since the merger, no further entitlements have accrued to any director under the plan.

127


	Amoco Non-Employee Directors’ Restricted Stock Plan

The table below sets out the residual entitlements of non-executive directors who were formerly non-executive directors of Amoco Corporation under the Amoco Non-Employee Directors’ Restricted Stock Plan.


	Interest in BP ADSs
	at January 1, 2005		Date on which
	and December 31,		director reaches
	2005 (a)		age 70 (b)

J H Bryan		5,546		October 5, 2006
E B Davis, Jr		4,490		August 5, 2014
Dr W E Massey		3,346		April 5, 2008
Director who left the board in 2006
M H Wilson (c)		3,170		November 4, 2007


(a)		No awards were granted and no awards lapsed during the year. The awards were granted over Amoco stock prior to the merger but their notional weighted average market value at the date of grant (applying the subsequent merger ratio of 0.66167 of a BP ADS for every Amoco share) was $27.87 per BP ADS.

(b)		For the purposes of the regulations, the date on which the director retires from the board at or after the age of 70 is the end of the qualifying period. If the director retires prior to this date, the board may waive the restrictions.

(c)		Mr Wilson resigned from the board on February 28, 2006. In accordance with the terms of the plan, the board exercised its discretion to waive the restrictions on May 11, 2006 (when BP ADS closing price was $75.52) without payment by him. These awards over BP ADSs derived from awards over Amoco shares granted between April 26, 1994 and April 28, 1998.


	Superannuation Gratuities

In accordance with the Company’s long-standing practice, non-executive directors who retired from the board after at least six years’ service are, at the time of their retirement, eligible for consideration for a superannuation gratuity. The board is authorized to make such payments under the Company’s Articles. The amount of the payment is determined at the board’s discretion (having regard to the director’s period of service as a director and other relevant factors).

The board made superannuation gratuity payments during the year to the following former directors: Mr Knight £79,000 and Sir Robin Nicholson £84,000 (who both retired in 2005) and Mr Maljers £18,000 (who retired in 2004). These payments were in line with the policy arrangements agreed in 2002.

In May 2006, the board also approved superannuation gratuity payments to two directors, Mr Miles £46,000 and Mr Wilson £21,000, who each left the board in 2006.

In 2002, the board revised its policy with respect to superannuation gratuities so that: (i) non-executive directors appointed to the board after July 1, 2002 would not be eligible for consideration for such a payment; and (ii) while non-executive directors in service at July 1, 2002 would remain eligible for consideration for a payment, service after that date would not be taken into account by the board in considering the amount of any such payment.

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Non-Executive Directors’ Shareholdings


Non-Executive Directors’
interest in BP ordinary shares	At January 1,			At December 31,			At June 28,
or calculated equivalents	2005			2005			2006

J H Bryan		158,760	(a)		158,760	(a)		158,760	(a)
A Burgmans		10,000			10,000			10,000
E B Davis, Jr		66,349	(a)		67,610	(a)		68,271	(a)
D J Flint		—			15,000			15,000
Dr D S Julius		15,000			15,000			15,000
Sir Tom McKillop		20,000			20,000			20,000
Dr W E Massey		49,722	(a)		49,722	(a)		49,722	(a)
H M P Miles (b)		22,145			22,145			22,145	(d)
Sir Ian Prosser		16,301			16,301			16,301
P D Sutherland		30,079			30,079			30,079
M H Wilson (c)		60,000	(a)		60,000	(a)		60,000	(a)(e)
Directors who left the board in 2005		At January 1, 2005			At Retirement
C F Knight		98,578	(a)		98,782	(a)
Sir Robin Nicholson		4,020			4,052


(a)		Held as ADSs.

(b)		Retired at AGM on April 20, 2006

(c)		Resigned as a Director on February 28, 2006

(d)		At date of retirement.

(e)		At date of resignation.

In disclosing the above interests to the Company under the Companies Act 1985, directors did not distinguish their beneficial and non-beneficial interests.

No director has any interest in the preference shares or debentures of the Company, or in the shares or loan stock of any subsidiary company.

Total Remuneration


	*Remuneration of Directors and Senior Management*

The table below details remuneration of all directors and senior management as a group (21 persons at December 31, 2005).


	Year ended December 31,

	2005		2004		2003

	($ million)
Short-term employee benefits		25		24		20
Postretirement benefits		4		3		2
Share-based payment		27		20		20


	Short-term Employee Benefits

In addition to fees paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior management, salary and benefits earned during the year, plus bonuses awarded for the year.

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	Postretirement Benefits

The amounts represent the estimated cost to the Group of providing pensions and other post-retirement benefits to key management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.


	Share-based Payments

This is the cost to the Group of key management’s participating in share-based payment plans, as measured by the fair value of options and shares granted accounted for in accordance with IFRS 2 ‘Share-based payments’. The main plans in which key management have participated are the Executive Directors’ Incentive Plan (EDIP) (see Compensation — Policy on Executive Directors’ Remuneration — Elements of Remuneration — Long-Term Incentives in this Item on page 116), the Medium Term Performance Plan (MTPP) and the Long Term Performance Plan (LTPP) (described below).


	*Plans for Senior Employees*


	Medium Term Performance Plan (MTPP) (2005 onwards)

An equity-settled incentive share plan for senior employees driven by two performance measures over a three-year performance period. The award of shares is determined by comparing BP’s TSR against the other oil majors and, additionally, by comparing free cash flow (FCF) against a threshold established for the period. For a small group of particularly senior employees, only the TSR measure is applicable in determining the award. The number of shares awarded is increased to take account of the net dividends that would have been received during the performance period, assuming that such dividends had been reinvested. With regard to leaver provisions, the general rule is that leaving employment during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period.


	Long Term Performance Plan (LTPP) (pre-2005)

An equity-settled incentive share plan for senior employees driven by three performance measures over a three-year performance period. The primary measure is BP’s SHRAM versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative ROACE and EPS growth compared with the other oil majors. Shares are awarded at the end of the performance period and are then subject to a three-year restriction period. With regard to leaver provisions, the general rule is that leaving during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period. This plan was replaced by the MTPP for 2005 onwards.


	Deferred Annual Bonus Plan (DAB)

An equity-settled restricted share plan for senior employees. The award value is equal to 50% of the annual cash bonus awarded for the preceding performance year (the ‘performance period’). The shares are restricted for a period of three years (the ‘restriction period’). Shares accrue dividends during the restriction period and these are reinvested. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of the performance period, then the general rule is that this will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason. Similarly, if a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that the restricted shares will be forfeited. Special arrangements apply where the participant leaves for a qualifying reason.

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	Restricted Share Plan (RSP)

An equity-settled restricted share plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are no performance conditions but the shares are subject to a three-year restriction period. During the restriction period, shares accrue dividends, which are reinvested. With regard to leaver provisions, the general rule is that ceasing employment during the restriction period will result in the forfeit of shares. However, special arrangements apply where the participant leaves for a qualifying reason.


	BP Share Option Plan (BPSOP)

An equity-settled share option plan that applies to certain categories of employees. Participants are granted share options with an exercise price no lower than market price of a share immediately preceding the date of grant. There are no performance conditions and the options are exercisable between the third and 10th anniversaries of the grant date. The general rule is that the options will lapse if the participant leaves employment before the end of the third calendar year from the date of grant (and that vested options are exercisable within 3¹/2 years from the date of leaving). However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after the end of the calendar year of the date of grant. Share options are no longer offered to the most senior employees.

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BOARD PRACTICES


			Period during which the
			director has served in this
	Date of expiration of		office (from appointment
Directors’ Terms of Office	current term of office (a)		to June 2006)

Dr D C Allen		April 2007		3 years 4 months
The Lord Browne of Madingley		April 2007		14 years 9 months
J H Bryan (b)		April 2007		7 years 6 months
A Burgmans		April 2007		2 years 4 months
I C Conn		April 2007		1 year 11 months
E B Davis, Jr (b)		April 2007		7 years 6 months
D J Flint		April 2007		1 year 5 months
Dr B E Grote		April 2007		5 years 10 months
Dr A B Hayward		April 2007		3 years 4 months
Dr D S Julius		April 2007		4 years 7 months
Sir Tom McKillop		April 2007		1 year 11 months
J A Manzoni		April 2007		3 years 4 months
Dr W E Massey (b)		April 2007		7 years 6 months
Sir Ian Prosser		April 2007		9 years 1 month
P D Sutherland		April 2007		10 years 11 months


(a)		Shareholders approved an amendment to the Articles of Association such that at each AGM held after December 31, 2004, all directors shall retire from office and may offer themselves for re-election. Therefore all directors retired and offered themselves for re-election in accordance with the Articles of Association at the 2006 AGM.

(b)		Does not include service on the board of Amoco Corporation

Directors’ Service Contracts Providing for Benefits upon Termination of Employment

The service contracts of Dr Allen, Mr Conn, Dr Hayward and Mr Manzoni may be terminated by the Company at any time with immediate effect on payment in lieu of notice equivalent to one year’s salary or the amount of salary that would have been paid if the contract had terminated on the expiry of the remainder of the notice period.

Dr Grote’s service contract is with BP Exploration (Alaska) Inc. He is seconded to BP p.l.c. under a secondment agreement dated August 7, 2000 that had an unexpired term of two years at December 31, 2005. The secondment may be terminated by one month’s notice by either party and terminates automatically on the termination of Dr Grote’s service contract.

There are no other provisions for compensation payable on early termination of the above contracts. In the event of early termination under any of the above contracts by the Company other than for cause (or under a specific termination provision), the relevant director’s then current salary and benefits would be taken into account in calculating any liability of the Company.

Since January 2003, the committee has included a provision in new service contracts to allow for severance payments to be phased, where appropriate to do so. It will also consider mitigation to reduce compensation to a departing director, where appropriate to do so.

Governance and the Role of Our Board

The governance of companies continues to be under scrutiny. Regulators and commentators maintain their focus on structural elements. We believe too little attention is paid to the underlying

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purpose of governance. Governance lies at the heart of all the board does and it is the task our owners entrust to the board.

Governance is not an exercise in compliance nor is it a higher form of management. Governance is a more powerful concept. It has a clear objective: ensuring the pursuit of the Company’s purpose. The board’s activity is focused on this task, which is unique to it as the representative of BP’s owners. This task is discharged by the board through undertaking such activities as are necessary for the effective promotion of long-term shareholder interest. In promoting the long-term interest of shareholders, the board has to ensure that the business is responsive to the views of those with whom it comes into contact. This can include gaining an understanding of the environmental and social consequences of the Company’s actions. However, it remains a matter of business judgement as to how these consequences are properly taken into account in maximizing shareholder value.

Governance is the system by which the Company’s owners and their representatives on the board ensure that it pursues, does not deviate from and only allocates resources to its defined purpose.

As a Company, we recognize the importance of good governance and that it is a discrete task from management. Clarity of roles is key to our approach. Policies and processes depend on the people who operate them. Governance requires distinct skills and processes. Governance is overseen by the BP board, while management is delegated to the group chief executive by means of the board governance policies.

Our board governance policies use a coherent, principles-based approach, which anticipated many developments in UK governance regulation. These policies ensure that our board and management operate within a clear and efficient governance framework that places long-term shareholder interest at the heart of all we do.

To that end, our board exercises judgement in carrying out its work in policy-making, in monitoring executive action and in its active consideration of Group strategy. The board’s judgements seek to maximize the expected value of shareholders’ interest in the Company, rather than eliminate the possibility of any adverse outcomes.

Accountability to Shareholders

Our board is accountable in a variety of ways. It is required to be proactive in obtaining an understanding of shareholder preferences and to evaluate systematically the economic, social, environmental and ethical matters that may influence or affect the interests of our shareholders.


	*Reporting*

A number of formal communication channels are used to account to shareholders for the performance of the Company. These include the Annual Report and Accounts, the Annual Review, the Annual Report on Form 20-F, quarterly Forms 6-K and announcements made through stock exchanges on which BP shares are listed, as well as through the annual general meeting (AGM). BP is keen to promote the use of electronic platforms in the reporting arena.


	*Dialogue with Directors*

Presentations given at appropriate intervals to representatives of the investment community are available to all shareholders by internet broadcast or open conference call, details of which are given onwww.bp.com. Less formal processes include contacts with institutional shareholders by the chairman and other directors. This is supported by the dialogue with shareholders concerning the governance and operation of the Group maintained by the company secretary’s office, investor relations and other BP teams, which meet with investors and shareholder groups representing both large and small investors.

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Our board is accountable to shareholders for the performance and activities of the entire BP Group. It embeds shareholder interest in the goals established for the Company.


	*AGM and Voting*

The chairman and board committee chairmen were present at the 2005 and 2006 AGMs to answer shareholders’ questions and hear their views during the meeting. Members of the board met informally with shareholders afterwards. Given the size and geographical diversity of our shareholder base, we recognize that opportunities for shareholder interaction at the AGM are limited. However, all votes at shareholder meetings, whether by proxy or in person, are counted, since votes on all matters, except procedural issues, are taken by way of a poll. In 2005, we were pleased to note that voting levels increased to 62%, with more than 98% of votes being cast in line with the board’s recommendations, a trend that continued at the 2006 AGM.


	*Directors’ Elections*

Directors stand for re-election each year. New directors are subject to election at the first opportunity following their appointment. All names submitted to shareholders for election are accompanied by biographies. Voting levels demonstrate continued support for all our directors and affirm the board’s assertion of the independence of all our non-executive directors.

How our Board Governs the Company

The board’s governance policies outline its relationship with shareholders, the conduct of board affairs and the board’s relationship with the group chief executive. The policies recognize the board’s separate and unique role as the link in the chain of authority between the shareholders and the group chief executive. It is this unique task that gives the board its central role in governance.

The dual role played by the group chief executive and executive directors as both members of the board and leaders of the executive management is also recognized and addressed. The policies require a majority of the board to be composed of independent non-executive directors. To assure the integrity of the governance process, the relationship between the board and the group chief executive is governed by the non-executive directors, particularly through the work of the board committees they populate.

Recognizing that as a group its capacity is limited, our board reserves to itself the making of broad policy decisions. It delegates more detailed considerations involved in meeting its stated requirements either to board committees and officers (in the case of its own processes) or to the group chief executive (in the case of the management of the Company’s business activities). The board governs BP through setting general policy for the conduct of business (and, critically, by clearly articulating its goals) and by monitoring its implementation by the group chief executive.

To discharge its governance function in the most effective manner, our board has laid down rules for its own activities in a governance process policy. The process policy covers:


	—	The conduct of members at meetings.

	—	The cycle of board activities and the setting of agendas.

	—	The provision of timely information to the board.

	—	Board officers and their roles.

	—	Board committees — their tasks and composition.

	—	Qualifications for board membership and the process of the nomination committee.

	—	The evaluation and assessment of board performance.

	—	The remuneration of non-executive directors.

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	—	The process for directors to obtain independent advice.

	—	The appointment and role of the company secretary.

The responsibility for implementation of this policy is placed on the chairman.

The board-executive linkage policy sets out how the board delegates authority to the group chief executive and the extent of that authority. In its board goals policy, the board states what it expects the group chief executive to deliver.

The restrictions on the manner in which the group chief executive may achieve the required results are set out in the executive limitations policy. This policy sets boundaries on executive action, requiring due consideration of internal controls, risk preferences, financing, ethical behaviour, health, safety, the environment, treatment of employees and political considerations in any and all action taken in the course of our business. Through the goals and executive limitations policies, the board shapes BP’s values and standards.

Accountability in our Business

Our group chief executive outlines how he intends to deliver the required outcome in annual and medium-term plans, which also address a comprehensive assessment of the Group’s risks. Progress towards the expected outcome forms the basis of regular reports to the board that cover actual results and a forecast of results for the current year. The board considers annual and five-year plans for the Group and, in doing so, reviews the major influences and risks affecting the Group’s business.

The group chief executive is obliged through dialogue and systematic review to discuss with the board all material matters currently or prospectively affecting the Company and its performance and all strategic projects or developments. This key dialogue specifically includes any materially under-performing business activities and actions that breach the executive limitations policy and material matters of a social, environmental and ethical nature.

The board-executive linkage policy also sets out how the group chief executive’s performance will be monitored and recognizes that, in the multitude of changing circumstances, judgement is always involved. The systems set out in the board-executive linkage policy are designed to manage, rather than to eliminate, the risk of failure to achieve the goals or observe the executive limitations policy. They provide reasonable, not absolute, assurance against material misstatement or loss.

Who is on the Board?

The board is composed of nine non-executive directors, including the chairman and six executive directors. In total, four nationalities are represented on the board. Directors’ biographies are set out in this Item — Directors, Senior Management and Employees — Directors and Senior Management on page 112.

Governance policies and processes depend on the quality and commitment of the people who operate them.

As reported last year, the board is actively engaged in succession planning issues for both executive and non-executive roles. We reported in the past two years on our pursuit of an orderly process of evolution to refresh the composition of the board without compromising its continued effectiveness. To that end, we were delighted to welcome Mr Douglas Flint to the board in January 2005. At the AGM in April 2005, Sir Robin Nicholson and Mr Charles (Chuck) Knight retired and Mr Michael Miles stood down at the 2006 AGM. The chairmanships of the principal board committees were also reviewed during 2005; Dr Julius became chairman of the remuneration committee, succeeding Sir Robin Nicholson. The board committee reports in Board Practices — Board Committees in this Item on page 138 provide details on the chairmen and composition of these committees.

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The efficiency and effectiveness of the board are of paramount importance. Our board is large but this is necessary to allow sufficient executive director representation to cover the breadth of the Group’s business activities and sufficient non-executive representation to reflect the scale and complexity of BP and to staff our board committees. A board of this size allows orderly succession planning for key roles.

Board Independence

The qualification for board membership includes a requirement that all our non-executive directors be free from any relationship with the executive management of the Company that could materially interfere with the exercise of their independent judgement. In the board’s view, all our non-executive directors fulfil this requirement. It determined all non-executive directors who served during 2005 to be independent. All have received overwhelming endorsement at successive AGMs, at which they are now subject to annual election.

Mr Knight and Sir Robin Nicholson were appointed to the BP board in 1987 and Mr Miles was appointed in 1994. The length of their respective service on the board exceeds the nine years referred to in the Combined Code. The board considers that the experience and long-term perspective of each of these directors on BP’s business during its recent period of growth has provided a valuable contribution to the board, given the long-term nature of our business. The integrity and independence of character of these directors are beyond doubt. Both Mr Knight and Sir Robin retired at the 2005 AGM and Mr Miles retired at the 2006 AGM.

Those directors who joined the BP board in 1998 after service on the board of Amoco Corporation (Messrs Bryan, Massey, Wilson and Davis) are considered independent since the most senior executive management of BP comprises individuals who were not previously Amoco employees. While Amoco businesses and assets are a key part of the Group, the scope and scale of BP since its acquisition of the ARCO, Burmah Castrol and Veba businesses are fundamentally different from those of the former Amoco Corporation.

Annual elections for all directors and the provision of independent support to our board and board committees underscore our commitment to good governance practice.

The board has satisfied itself that there is no compromise to the independence of those directors who serve together as directors on the boards of outside entities (or who have other appointments in outside entities). Where necessary, our board ensures appropriate processes are in place to manage any possible conflict of interest.

Sir Robin Nicholson received fees during 2005 for representing the board on the BP technology advisory council. Since these fees relate to board representation, they did not compromise Sir Robin’s independence. Full details of these fees are disclosed in Compensation — Remuneration of Non-Executive Directors in this Item on page 127.

Directors’ Appointments, Retirement Policies and Insurance

The chairman and non-executive directors of BP are elected each year and, subject to BP’s Articles of Association, serve on the basis of letters of appointment. Executive directors of BP have service contracts with the Company. Details of all payments to directors are set out in Compensation in this Item on pages 115-131.

BP’s policy on directors’ retirement is as follows: executive directors retire at age 60, while non-executive directors ordinarily retire at the AGM following their 70th birthday. It is the board’s policy that non-executive directors are not generally expected to hold office for more than 10 years.

In accordance with BP’s Articles of Association, directors are granted an indemnity from the Company in respect of liabilities incurred as a result of their office, to the extent permitted by law. In respect of those liabilities for which directors may not be indemnified, the Company purchased and

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maintained a directors’ and officers’ liability insurance policy throughout 2005. This insurance cover was renewed at the beginning of 2006. Although their defence costs may be met, neither the Company’s indemnity nor insurance provides cover in the event that the director is proved to have acted fraudulently or dishonestly.

Board and Committees: Meetings and Attendance

In addition to the 2005 AGM (which 17 directors attended), the board met seven times during 2005: four times in the UK, twice in the US and once in China. Two of these meetings were two-day strategy discussions. 2005 saw a continued high number of committee meetings, a trend we expect to continue.

The board requires all members to devote sufficient time to the work of the board to discharge the office of director and to use their best endeavours to attend meetings.

Serving as a Director: Induction, Training and Evaluation


	*Induction*

Directors receive induction on their appointment to the board as appropriate, covering matters such as the operation and activities of the Group (including key financial, business, social and environmental risks to the Group’s activities), the role of the board and the matters reserved for its decision, the tasks and membership of the principal board committees, the powers delegated to those committees, the board’s governance policies and practices, and the latest financial information about the Group. The chairman is accountable for the induction of new board members.


	*Training*

Our directors are updated on BP’s business, the environment in which it operates and other matters throughout their period in office. Our directors are advised on their appointment of the legal and other duties and obligations they have as directors of a listed company. The board regularly considers the implications of these duties under the board governance policies. Our non-executive directors also receive training specific to the tasks of the particular board committees on which they serve.


	*Outside Appointments*

As part of their ongoing development, our executive directors are permitted to take up an external board appointment, subject to the agreement of our board. Executive directors retain any fees received in respect of such external appointments. Generally, outside appointments for executive directors are limited to one outside company board only, although our group chief executive, by exception, serves on two outside company boards. Our board is satisfied that these appointments do not conflict with his duties and commitment to BP. Non-executive directors may serve on a number of outside boards, always provided they continue to demonstrate the requisite commitment to discharge effectively their duties to BP. The nomination committee keeps the extent of directors’ other interests under review to ensure that the effectiveness of our board is not compromised.


	*Evaluation*

The board continued its ongoing evaluation processes to assess its performance and identify areas in which its effectiveness, policies or processes might be enhanced. A formal evaluation of board process and effectiveness was undertaken, drawing on internal resources. Individual questionnaires and interviews were completed; no individual performance problems were identified. The results showed an improvement from the previous evaluation, particularly in board committee process and activities, while also identifying areas for further improvement.

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Regular evaluation of board effectiveness underpins our confidence in BP’s governance policies and processes and affords opportunity for their development.

Separate evaluations of the remuneration, ethics and environment and audit assurance committees took place during the year. The use of external providers in the context of board evaluation is being kept under review.

The Chairman and Senior Independent Director

BP’s board governance policies require that neither the chairman nor deputy chairman are to be employed executives of the Group; throughout 2005 the posts were held by Mr Sutherland and Sir Ian Prosser respectively. Sir Ian also acts as our senior independent director and is the director whom shareholders may contact if they feel their concerns are not being addressed through normal channels.

Between board meetings, the chairman has responsibility for ensuring the integrity and effectiveness of the board/executive relationship. This requires his interaction with the group chief executive between board meetings, as well as his contact with other board members and shareholders. The chairman represents the views of the board to shareholders on key issues, not least in succession planning issues for both executive and non-executive appointments. The chairman and all the non-executive directors meet periodically as the chairman’s committee (see Board Practices — Board Committees in this Item on page 138). The performance of the chairman is evaluated each year at a meeting of the chairman’s committee, for which item of business he is not present. The company secretary reports to the chairman and has no executive functions.

Board Committees

The governance process policy allocates the tasks of monitoring executive actions and assessing performance to certain board committees. These tasks, rather than any terms of reference, prescribe the authority and the role of the board committees. Reports for each of the committees for 2005 appear below. In common with the board, each committee has access to independent advice and counsel as required and each is supported by the company secretary’s office, which is demonstrably independent of the executive management of the Group.

Audit Committee Report


	*Schedule and Composition*

The committee met 12 times during 2005 and comprised the following directors: Sir Ian Prosser (chairman), J H Bryan, E B Davis, Jr, D J Flint, H M P Miles, M H Wilson.

All members of the audit committee are non-executive directors whom the board has determined to be independent and who meet the requirements of the UK Combined Code and Rule 10A-3 of the US Securities Exchange Act of 1934. Together, the audit committee members continue to have the recent and relevant financial experience required to discharge the committee’s duties. Following his appointment to the committee this year, the board satisfied itself that Mr Flint as an individual possesses the financial experience identified in the UK Combined Code guidance and may be regarded as an audit committee financial expert as defined for purposes of disclosure in Item 16A of Form 20-F. See Item 16A — Audit Committee Financial Expert on page 174.

The external auditors’ lead partner, the BP general auditor (head of internal audit), together with the group chief financial officer, the chief accounting officer and the group controller, attend each meeting at the request of the committee chairman. During the year, the committee meets with the external auditor, without the executive management being present, and also meets in private session with the BP general auditor.

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	*Role and Authority*

The audit committee’s tasks are considered by the committee to be broader than those envisaged under Combined Code Provision C.3.2. The committee is satisfied that it addresses each of those matters identified as properly falling within an audit committee’s purview. The committee has full delegated authority from the board to address those tasks assigned to it. In common with the board and all committees, it may request any information from the executive management necessary to discharge its functions and may, where it considers it necessary, seek independent advice and counsel.


	*Process*

The committee structures its work programme so as to discharge its tasks, which include systematic monitoring and obtaining assurance that the legally required standards of disclosure are being fully and fairly observed and that the executive limitations relating to financial matters are being observed. Forward agendas are set each year to meet these requirements and to allow the committee to monitor (and seek assurance on) the management of the financial risks identified in the Company’s annual business plan. The committee chairman reports on the committee’s activities to the board meeting immediately following a committee meeting. Between meetings, the committee chairman reviews emerging issues as appropriate with the group chief financial officer, the external auditor and the BP general auditor. He is supported in this task by the company secretary’s office. During the year, external specialist legal and regulatory advice has also been provided to the committee by Sullivan & Cromwell LLP.


	*Activities in 2005*


	Financial Reports

During the year, the committee reviewed all annual and quarterly financial reports before recommending their publication on behalf of the board. In particular, the committee reviewed the implementation of International Financial Reporting Standards and their impact on the Group’s financial results and the restatement of comparative information. The committee discussed and constructively challenged judgements related to critical accounting policies and estimates drawing on prepared reports, presentations and independent advice from the external auditors.


	Internal Control and Risk Management

During the year, specific reports on risk management and internal control were reviewed for the Exploration and Production, Refining and Marketing, and Gas, Power and Renewables segments, along with the controls and systems underpinning the trading functions that service all BP’s businesses. Reviews were undertaken of the reporting interface between the Group and TNK-BP and of the planned disposal of the Innovene petrochemicals business. On a quarterly basis, the committee also monitored the Company’s progress in evaluating its internal controls in response to applicable requirements of Section 404 of the US Sarbanes-Oxley Act of 2002. Regular advice was also provided by the internal audit function, including an annual assessment of the effectiveness of the Company’s enterprise level controls.

Special topics considered during the year included capital project selection processes, the assessment of environmental and litigation provisions and accounting for long-term contractual commitments.


	Employee Concerns Reporting/Whistleblowing

The committee received regular reports of the matters raised through the employee concerns programme, OpenTalk, and, through this process, together with the receipt of quarterly fraud reports from internal audit, was alerted to instances of actual or potential concern related to the finances and financial accounting of the Group.

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	External Auditors

In addition to the lead partner’s attendance at all meetings, the committee regularly invited other relevant audit partners to participate during business segment reviews. Private meetings were held without executive management present.

The committee evaluated the performance of the external auditors and enquired into their independence, objectivity and viability. Independence was safeguarded by limiting non-audit services provided by the auditor to defined audit-related work and tax services that fall within specific categories. All such services were pre-approved by the committee and monitored quarterly. A new lead audit partner is appointed every five years, with other senior audit staff rotating every seven years; no senior staff connected with the BP audit may transfer to the Company.

After review of the audit engagement terms and proposed fees, the committee advised the board of its assessment and recommended that reappointment of the auditors be proposed at the AGM. Their reappointment was duly approved by shareholders at the AGM on April 14, 2005, and at the Company’s most recent AGM on April 20, 2006.


	Internal Audit

The committee agreed with the BP general auditor the programme to be undertaken during the year and the resources required. Twice-yearly reports of audit findings and management responses were reviewed in detail. Discussions of these reports contributed to the committee’s view of the effectiveness of the Company’s system of internal controls and hence its advice to the board on this matter. The committee also met privately with the BP general auditor, without the presence of executive management, and evaluated the performance of the function.


	Performance Evaluation

On an annual basis, the committee conducts a review of its process and performance. The form of review varies to encourage fresh thinking and this year involvedface-to-face interviews with individual members and with others in regular attendance. Outcomes were discussed at the committee’s November meeting. The committee concluded that few substantive changes were required but used the discussion to help shape the 2006 forward agenda and in particular to increase the frequency of the committee’s private meetings.

Ethics and Environment Assurance Committee Report


	*Schedule and Composition*

The committee met seven times during 2005 and comprised the following directors: Dr W E Massey (chairman), A Burgmans, H M P Miles, M H Wilson. Sir Tom McKillop joined the committee in May 2006, following the departures of Mr Miles and Mr Wilson.

All members of the ethics and environment assurance committee are independent non-executive directors. The external auditors’ lead partner and the BP general auditor (head of internal audit) attend each meeting at the request of the committee chairman.


	*Role and Authority*

The task of the committee is to monitor on behalf of the board matters relating to the executive management’s processes to address environmental, health and safety, security and ethical behaviour issues. The committee monitors the observance of the executive limitations relating to nonfinancial risks to the Group. Just as for the audit committee, it has the right to request any information from the executive management that it considers necessary to discharge its functions. The committee chairman reports on the committee’s activities to the board meeting immediately following a committee meeting.

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	*Process and Activities in 2005*

This committee has a broad remit because it covers all nonfinancial risks and must necessarily be selective in setting its agendas. These are focused on regular reports — such as health, safety and environment (HSE) reviews and compliance and ethics certification reports — that allow the committee to monitor and assess the observance of the executive limitations. In addition, the committee reviews specific risks that are identified in the Company’s annual plan and developments in business and functional areas that may emerge during the year. During 2005, the committee met specially to consider the incident at the Texas City refinery. It reviewed the causes of the accident and the implications for the Group of the lessons to be learned. The committee continues to monitor the executive management’s response and the strengthening of its safety and operational capability.

Other areas of specific focus during the year included:


	Business Continuity and Crisis Management

The committee received reports and reviewed the Group’s enhanced focus on bringing more consistency and resilience to these linked topics across all business segments and functions.


	Health, Safety and Environmental Performance

While overshadowed by events at Texas City, the progress in addressing road safety, employee health, greenhouse gas emissions, oil spills and plant integrity was considered during 2005. Specific attention was given to the progress made by TNK-BP in improving HSE standards in its operations in Russia.


	Regional Reviews

Most board-level monitoring is conducted through a business segment or functional dimension, but the committee also examines risks that require management at regional or country level. In 2005, risk reviews were undertaken for Africa, the Middle East and Alaska.


	Digital Security

The committee considered the Company’s response to the increasing international threats to communications and computing, threats heightened by the convergence and increased interconnectivity of technology infrastructure.

Remuneration Committee


	*Schedule and Composition*

The committee members are all non-executive directors. Dr Julius (chairman), Mr Bryan, Mr Davis, Sir Tom McKillop and Sir Ian Prosser were members of the committee throughout the year. Sir Robin Nicholson and Mr Knight retired from the committee at the 2005 AGM. Each member is now subject to annual re-election as a director of the Company. The board has determined all committee members to be independent. They have no personal financial interest, other than as shareholders, in the committee’s decisions. The committee met six times in the period under review. There was a full attendance record, except for Mr Davis and Sir Robin Nicholson who were each unable to attend one meeting and Mr Knight who was unable to attend two meetings. Mr Sutherland, as chairman of the board, attended all committee meetings.

The committee is accountable to shareholders through its annual report on executive directors’ remuneration. It will consider the outcome of the vote at the AGM on the directors’ remuneration report and take into account the views of shareholders in its future decisions. The committee values its dialogue with major shareholders on remuneration matters.

141


	*Advice*

Advice is provided to the committee by the company secretary’s office, which is independent of executive management and reports to the chairman of the board. Mr Aronson, an independent consultant, is the committee’s secretary and special adviser. Advice was also received from Mr Jackson (company secretary) and Mrs Martin (senior counsel, company secretary’s office).

The committee also appoints external professional advisers to provide specialist advice and services on particular remuneration matters. The independence of advice is subject to annual review.

The committee continued the engagement of Towers Perrin as its principal external adviser during 2005. Towers Perrin also provided limited ad hoc remuneration and benefits advice to parts of the Group, mainly comprising pensions advice in Canada, as well as providing some market information on pay structures. The committee also continued the engagement of Kepler Associates to advise on performance measurement. Kepler Associates also provided performance data and limited ad hoc advice on performance measurement to the Group.

Freshfields Bruckhaus Deringer provided legal advice on specific matters to the committee as well as providing some legal advice to the Group.

Ernst & Young reviewed the calculations in respect of financial-based targets that form the basis of the performance-related pay for the executive directors.

Lord Browne (group chief executive) was consulted on matters relating to the other executive directors who report to him and on matters relating to the performance of the Company. He was not present when matters affecting his own remuneration were considered.


	*Role and Authority*

The committee’s tasks are:


	—	To determine, on behalf of the board, the terms of engagement and remuneration of the group chief executive and the executive directors and to report on those to the shareholders.

	—	To determine, on behalf of the board, matters of policy over which the Company has authority relating to the establishment or operation of the Company’s pension scheme of which the executive directors are members.

	—	To nominate, on behalf of the board, any trustees (or directors of corporate trustees) of such scheme.

	—	To monitor the policies being applied by the group chief executive in remunerating senior executives other than executive directors.


	*Remuneration Committee Report*

Full details of executive directors’ remuneration is set out under Compensation in this Item on pages 115-131.

Chairman’s Committee report


	*Schedule and Composition*

The chairman’s committee met four times during 2005 and comprised all the non-executive directors.

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Role and Authority

The task of the committee is to consider broad issues of governance, including the performance of the chairman and the group chief executive, succession planning, the organization of the Group and any matters referred to it for an opinion from another board committee.


	*Process and Activities in 2005*

At its various meetings, the committee evaluated the performance of the chairman and the group chief executive, considered the plan for executive succession and considered a number of other broad matters of governance, including issues that spanned the remit of the other principal committees. Additionally, the committee addressed non-executive succession planning issues in co-ordination with the nomination committee.

Nomination Committee Report


	*Schedule and Composition*

The committee met twice during 2005 and comprised the following directors: P D Sutherland (chairman), Dr D S Julius (from the 2005 AGM), Dr W E Massey, Sir Robin Nicholson (retired at the 2005 AGM), Sir Ian Prosser. All members of the nomination committee have been determined by the board to be independent.


	*Role and Authority*

The task of the nomination committee is to identify and evaluate candidates for appointment and reappointment as director or company secretary of BP.


	*Process*

During the year, the nomination committee carried out a detailed review of the skills and expertise of the non-executive directors as part of the board succession planning described earlier. The committee receives external assistance as required. The committee consults with the group chief executive concerning the identification and appointment of new executive directors. External search consultants are retained in theUK/ Europe and in the US to assist the committee to identify potential candidates as non-executive directors.


	*Activities in 2005*

The committee considered the composition of the board and board committees in the context of forthcoming work programmes, BP’s strategy and business activities and retirements from the board. In its succession planning for both executive and nonexecutive directors, the committee is mindful of the requirements of the Group’s strategy and five-year plan. Board and committee evaluation processes informed its work in identifying the skills and experiences sought from potential candidates. Evaluations of the balance of skills and experience on the board are carried out in conjunction with the chairman’s committee. The committee keeps under review contingency planning for key executive and non-executive director roles. The nomination committee recommended to the board that 17 incumbent directors be proposed for re-election at the AGM.

All directors recommended for re-election were subsequently elected by shareholders at the 2005 AGM. All directors, save Mr Wilson, who resigned from the board on February 28, 2006, stood for election at the 2006 AGM and were re-elected by shareholders.

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EMPLOYEES


			Rest of				Rest of
	UK		Europe		USA		World		Total

Number of employees at December 31,
2005
Exploration and Production		3,100		700		5,600		7,600		17,000
Refining and Marketing		11,300		19,700		25,200		14,600		70,800
Gas, Power and Renewables		200		700		1,500		1,700		4,100
Other businesses and corporate		1,900		200		2,100		100		4,300

		16,500		21,300		34,400		24,000		96,200

2004
Exploration and Production		2,900		600		5,000		7,100		15,600
Refining and Marketing		10,400		19,500		26,500		13,400		69,800
Gas, Power and Renewables		200		800		1,400		1,600		4,000
Other businesses and corporate		4,000		5,000		4,000		500		13,500

		17,500		25,900		36,900		22,600		102,900

2003
Exploration and Production		3,000		700		4,600		6,800		15,100
Refining and Marketing		10,300		18,800		27,000		12,900		69,000
Gas, Power and Renewables		200		800		1,400		1,400		3,800
Other businesses and corporate		3,600		5,000		6,100		1,100		15,800

		17,100		25,300		39,100		22,200		103,700

Employee numbers decreased in 2005 compared with 2004 primarily due to the sale of Innovene.

The Company seeks to maintain constructive relationships with labour unions.

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SHARE OWNERSHIP

Directors and Senior Management

As at June 28, 2006, the following directors of BP p.l.c. held interests in BP ordinary shares of 25 cents each or their calculated equivalent as set out below:


Dr D C Allen	530,933	819,823	(b)
The Lord Browne of Madingley	2,522,840	3,768,016	(b)
I C Conn	206,642	799,032	(b)
Dr B E Grote	1,092,292	972,210	(b)
Dr A B Hayward	399,466	819,823	(b)
J A Manzoni	369,191	819,823	(b)
J H Bryan	158,760	—
A Burgmans	10,000	—
E B Davis, Jr	68,271	—
D J Flint	15,000	—
Dr D S Julius	15,000	—
Dr W E Massey	49,722	—
Sir Tom McKillop	20,000	—
Sir Ian Prosser	16,301	—
P D Sutherland	30,079	—

As at June 28, 2006, the following directors of BP p.l.c. held options under the BP Group share option schemes for ordinary shares or their calculated equivalent as set out below:


Dr D C Allen	794,950
The Lord Browne of Madingley	3,261,104
I C Conn	332,390
Dr B E Grote	1,427,190	(a	)
Dr A B Hayward	769,702
J A Manzoni	780,523


(a)		In addition to the above, Dr Grote holds 40,000 Stock Appreciation Rights (equivalent to 240,000 ordinary shares).

(b)		Performance shares awarded under the BP Executive Directors Incentive Plan. These represent the maximum possible vesting levels. The actual number of shares/ ADSs which vest will depend on the extent to which performance conditions have been satisfied over a three year period.

There are no directors or members of senior management who own more than 1% of the ordinary Shares outstanding. At June 28, 2006, all directors and senior management as a group held interests in 14,978,547 ordinary shares or their calculated equivalent and 8,541,794 options for ordinary shares or their calculated equivalent under the BP Group share options schemes.

Additional details regarding the options granted, including exercise price and expiry dates, are found in this item under the heading ‘Compensation — Share Options.’

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Employee Share Plans

Year ended December 31,

2005

2004

2003

(options thousands)

Employee share options granted during the year(a)

54,482

80,394

104,759


(a)	As share options are exercised continuously throughout the year, the weighted average share price during the year of $10.77 (2004 $8.95 and 2003 $6.81) is representative of the weighted average share price at the date of exercise. For the options outstanding at December 31, 2005, the exercise price ranges and weighted average remaining contractual lives are shown below.

BP offers most of its employees the opportunity to acquire a shareholding in the Company through savings-related and/or matching share plan arrangements. BP also uses long-term performance plans (see Item 18 — Financial Statements 18 — Note 46 on page F-133) and the granting of share options as elements of remuneration for executive directors and senior employees.


	*Savings and Matching Plans*


	BP ShareSave Plan

A savings-related share option plan, under which employees save on a monthly basis, over a three- or five-year period, towards the purchase of shares at a fixed price determined when the option is granted. This price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract; otherwise it lapses. The plan is run in the UK and options are granted annually, usually in June. Until 2003, a three-year savings plan was also run in a small number of other countries. Options will remain outstanding in respect of these countries until the end of June 2007. Participants leaving for a qualifying reason will have six months in which to use their savings to exercise their options on a pro-rated basis.


	BP ShareMatch Plans

Matching share plans, under which BP matches employees’ own contributions of shares up to a predetermined limit. The plans are run in the UK and in over 70 other countries. The UK plan is run on a monthly basis with shares being held in trust for five years before they can be released free of any income tax and national insurance liability. In other countries, the plan is run on an annual basis with shares being held in trust for three years. The plan is operated on a cash basis in those countries where there are regulatory restrictions preventing the holding of BP shares. When the employee leaves BP, all shares must be removed from trust and units under the plan operated on a cash basis must be encashed.


	*Cash Plans*


	Cash Options/ Stock Appreciation Rights (SARs)

These are cash-settled share-based payments available to certain employees that require the Group to pay the intrinsic value of the cash option/ SAR to the employee at the date of exercise. There are no performance conditions; however, participants must continue in employment with BP for the first three calendar years of the plan for the options/ SARs to vest. Special arrangements may apply for qualifying leavers. The options/ SARs are exercisable between the third and 10th anniversaries of the grant date.


	*Employee Share Ownership Plans (ESOP)*

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deducted in arriving at shareholders’ equity. See Item 18 — Financial Statements — Note 46 on page F-133. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the Group.

At December 31, 2005, the ESOPs held 14,560,003 shares (2004 8,621,219 shares and 2003 11,930,379 shares) for potential future awards, which had a market value of $156 million (2004 $84 million and 2003 $96 million).

Pursuant to the various BP Group share option schemes, the following options for ordinary shares of the Company were outstanding at June 28, 2006:


	Expiry	Exercise
Options	dates of	price
outstanding	options	per share

(shares)
436,611,63	6 2006-2016	$4.31-$11.92

Further details on share options appear in Item 18 — Financial Statements — Note 46 on page F-133.

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ITEM 7 — MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

MAJOR SHAREHOLDERS

At June 28, 2006, the Company has been notified that JPMorgan Chase Bank, as depositary for American Depositary Shares (ADSs), holds interests through its nominee, Guaranty Nominees Limited, in 6,187,041,879 ordinary shares (30.92% of the Company’s ordinary share capital). Legal and General plc hold interests in 698,383,277 ordinary shares (3.49% of the Company’s share capital).

At the date of this report the Company has also been notified of the following interests in preference shares. Co-operative Insurance Society Limited holds interests in 1,572,538 8% cumulative first preference shares (21.74% of that class) and 1,789,796 9% cumulative second preference shares (32.70% of that class). The National Farmers Union Mutual Insurance Society Ltd holds 945,000 8% cumulative first preference shares (13.07% of that class) and 987,000 9% cumulative second preference shares (18.03% of that class). Prudential plc holds interests in 528,150 8% cumulative first preference shares (7.30% of that class) and 644,450 9% cumulative second preference shares (11.77% of that class). Royal & SunAlliance Insurance plc holds interests in 287,500 8% cumulative first preference shares (3.97% of that class) and 250,000 9% cumulative second preference shares (4.57% of that class). Ruffer Limited Liability Partnership holds interests in 685,000 9% preference shares (12.51% of that class).

RELATED PARTY TRANSACTIONS

The Group had no material transactions with joint ventures and associated undertakings during the period commencing January 1, 2005 to the date of this filing. Transactions between the Group and its significant joint ventures and associates are summarized in Item 18 — Financial Statements — Note 30 on page F-75 and Item 18 — Financial Statements — Note 31 on page F-78.

In the ordinary course of its business the Group has transactions with various organizations with which certain of its directors are associated but, except as described in this report, no material transactions responsive to this item have been entered into in the period commencing January 1, 2005 to June 28, 2006.


ITEM 8 —	FINANCIAL INFORMATION

CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

Financial Statements

See Item 18 — Financial Statements.

Dividends

The total dividends announced and paid in 2005 were $7,359 million, compared with $6,041 million in 2004 and $5,654 million in 2003. Dividends per share for 2005 were 34.85 cents, compared with 27.70 cents per share in 2004 (an increase of 26%) and 25.50 cents per share in 2003 (an increase of 8.6% over 2003). For information on our policy on distributions to shareholders, refer to Item 5 — Operating and Financial Review — Liquidity and Capital Resources — Dividends and Other Distributions to Shareholders and Gearing on page 95.

Legal Proceedings

Save as disclosed in the following paragraphs, no member of the Group is a party to, and no property of a member of the Group is subject to, any pending legal proceedings which are significant to the Group.

On June 28, 2006, the U.S. Commodity Futures Trading Commission (CFTC) announced the filing of a civil enforcement action in the United States District Court for the Northern District of Illinois

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against BP Products North America, Inc. (BP Products), a wholly owned subsidiary of BP, alleging that BP Products manipulated the price of February 2004 TET physical propane. The CFTC also charges BP Products with attempting to manipulate the price of April 2003 TET physical propane. The CFTC is seeking permanent injunctive relief, disgorgement, restitution, and payment of civil monetary penalties. Concurrently, the U.S. Department of Justice filed a criminal complaint against a former BP Products employee, who entered a guilty plea. The former employee had previously been terminated by BP Products for failure to adhere to BP Group policies. BP denies that BP Products engaged in market manipulation and intends to defend the CFTC claims vigorously. BP believes that it has cooperated fully with the CFTC in its investigation of this matter and intends to assist the Department of Justice in its ongoing investigation.

Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 47% interest (reduced during 2001 from 50% by a sale of 3% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP’s combination with Atlantic Richfield. Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon which affect Alyeska and its owners, BP will defend the claims vigorously.

Since 1987, Atlantic Richfield Company, a current subsidiary of BP, has been named as aco-defendant in numerous lawsuits brought in the United States alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining which, along with a predecessor company, manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits (depending on plaintiff) seek various remedies including: compensation to lead-poisoned children; cost to find and remove lead paint from buildings; medical monitoring and screening programmes; public warning and education of lead hazards; reimbursement of government healthcare costs and special education for lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgement in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it

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has valid defenses and it intends to defend such actions vigorously and thus the incurrence of liability by Atlantic Richfield is remote. Consequently, BP believes that the impact of these lawsuits on the Group’s results of operations, financial position or liquidity will not be material.

For certain information regarding environmental proceedings see Item 4 — Environmental
Protection — United States Regional Review on page 71.

SIGNIFICANT CHANGES

None.

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ITEM 9 —	THE OFFER AND LISTING

Markets and Market Prices

The primary market for BP’s ordinary shares is the London Stock Exchange (LSE). BP’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index. BP’s ordinary shares are also traded on stock exchanges in France, Germany, Japan and Switzerland.

Trading of BP’s shares on the LSE is primarily through the use of the Stock Exchange Electronic Trading Service (SETS), introduced in 1997 for the largest companies in terms of market capitalization whose primary listing is the LSE. Under SETS, buy and sell orders at specific prices may be sent to the exchange electronically by any firm which is a member of the LSE, on behalf of a client or on behalf of itself acting as a principal. The orders are then anonymously displayed in the order book. When there is a match on a ‘buy’ and a ‘sell’ order, the trade is executed and automatically reported to the LSE. Trading is continuous from 8:00 a.m. to 4:30 p.m. UK time, but in the event of a 20% movement in the share price either way the LSE may impose a temporary halt in the trading of that company’s shares in the order book, to allow the market to re-establish equilibrium. Dealings in ordinary shares may also take place between an investor and a market-maker, via a member firm, outside the electronic order book.

In the United States and Canada the Company’s securities are traded in the form of ADSs, for which JPMorgan Chase Bank is the depositary (the Depositary) and transfer agent. The Depositary’s address is 1 Chase Manhattan Plaza, 40th Floor, New York, NY 10081, USA. Each ADS represents six ordinary shares. ADSs are listed on the New York Stock Exchange, and are also traded on the Chicago, Pacific and Toronto Stock Exchanges. ADSs are evidenced by American Depositary Receipts, or ADRs, which may be issued in either certificated or book entry form.

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The following table sets forth for the periods indicated the highest and lowest middle market quotations for the ordinary shares of BP p.l.c. for the periods shown. These are derived from the Daily Official List of the LSE, and the highest and lowest sales prices of ADSs as reported on the New York Stock Exchange composite tape.


					American
					Depositary
	Ordinary shares				Shares (a)

	High		Low		High		Low

	(Pence)				(Dollars)
Year ended December 31,
2001		647.00		478.00		55.20		42.20
2002		625.00		387.00		53.98		36.25
2003		458.00		348.75		49.59		34.67
2004		561.00		407.75		62.10		46.65
2005		686.00		499.00		72.75		56.60
Year ended December 31,
2004: First quarter		465.75		407.75		51.48		46.65
Second quarter		508.25		451.25		54.99		50.75
Third quarter		545.00		476.25		59.04		51.95
Fourth quarter		561.00		497.00		62.10		57.31
2005: First quarter		579.50		499.00		66.65		56.60
Second quarter		600.00		516.00		64.94		57.95
Third quarter		686.00		580.50		72.75		62.84
Fourth quarter		679.00		599.00		71.25		63.26
2006: First quarter		693.00		623.00		72.88		65.35
Second quarter (through June 28)		723.00		581.00		76.85		64.19
Month of
December 2005		667.00		610.50		69.25		63.26
January 2006		693.00		623.00		72.88		65.47
February 2006		677.50		630.00		72.58		66.01
March 2006		676.50		627.00		70.68		65.35
April 2006		723.00		662.00		76.85		69.49
May 2006		693.50		606.50		76.67		68.50
June (through June 28)		643.50		581.00		72.38		64.19


(a)	An ADS is equivalent to six ordinary shares.

Market prices for the ordinary shares on the LSE and in after-hours trading off the LSE, in each case while the New York Stock Exchange is open, and the market prices for ADSs on the New York Stock Exchange and other North American stock exchanges, are closely related due to arbitrage among the various markets, although differences may exist from time to time due to various factors including UK stamp duty reserve tax. Trading in ADSs began on the LSE on August 3, 1987.

On June 28, 2006, 1,031,125,732 ADSs (equivalent to 6,186,754,395 ordinary shares or some 30.92% of the total) were outstanding and were held by approximately 153,236 ADR holders. Of these, about 151,659 had registered addresses in the USA at that date. One of the registered holders of ADSs represents some 850,381 underlying holders.

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On June 28, 2006, there were approximately 329,764 holders of record of ordinary shares. Of these holders, around 1,458 had registered addresses in the USA and held a total of some 4,068,149 ordinary shares.

Since certain of the ordinary shares and ADSs were held by brokers and other nominees, the number of holders of record in the USA may not be representative of the number of beneficial holders or of their country of residence.

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ITEM 10 —	ADDITIONAL INFORMATION

MEMORANDUM AND ARTICLES OF ASSOCIATION

The following summarizes certain provisions of BP’s Memorandum and Articles of Association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act and BP’s Memorandum and Articles of Association. Information on where investors can obtain copies of the Memorandum and Articles of Association is described under the heading ‘Documents on Display’ under this Item.

On April 24, 2003, the shareholders of BP voted at the AGM to adopt new Articles of Association to consolidate amendments which have been necessary to implement legislative changes since the previous Articles of Association were adopted in 1983.

At the AGM held on April 15, 2004, shareholders approved an amendment to the Articles of Association such that at each AGM held after December 31, 2004, all directors shall retire from office and may offer themselves for re-election. There have been no further amendments to the Articles of Association.

Objects and Purposes

BP is incorporated under the name BP p.l.c. and is registered in England and Wales with registered number 102498. Clause 4 of BP’s Memorandum of Association provides that its objects include the acquisition of petroleum bearing lands; the carrying on of refining and dealing businesses in the petroleum, manufacturing, metallurgical or chemicals businesses; the purchase and operation of ships and all other vehicles and other conveyances; and the carrying on of any other businesses calculated to benefit BP. The memorandum grants BP a range of corporate capabilities to effect these objects.

Directors

The business and affairs of BP shall be managed by the directors.

The Articles of Association place a general prohibition on a director voting in respect of any contract or arrangement in which he has a material interest other than by virtue of his interest in shares in the Company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters:


	—	the giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the Company;

	—	any proposal in which he is interested concerning the underwriting of Company securities or debentures;

	—	any proposal concerning any other company in which he is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that he and persons connected with him are not the holder or holders of 1% or more of the voting interest in the shares of such company;

	—	proposals concerning the modification of certain retirement benefits schemes under which he may benefit and which has been approved by either the UK Board of Inland Revenue or by the shareholders; and

	—	any proposal concerning the purchase or maintenance of any insurance policy under which he may benefit.

The UK Companies Act requires a director of a company who is in any way interested in a contract or proposed contract with the company to declare the nature of his interest at a meeting of the directors of the company. The definition of ‘interest’ now includes the interests of spouses, children,

154

companies and Trusts. The directors may exercise all the powers of the company to borrow money, except that the amount remaining undischarged of all moneys borrowed by the company shall not, without approval of the shareholders, exceed the amount paid up on the share capital plus the aggregate of the amount of the capital and revenue reserves of the company. Variation of the borrowing power of the board may only be effected by amending the Articles of Association.

Remuneration of non-executive directors shall be determined in the aggregate by resolution of the shareholders. Remuneration of executive directors is determined by the remuneration committee. This committee is made up of non-executive directors only. Any director attaining the age of 70 shall retire at the next AGM. There is no requirement of share ownership for a director’s qualification.

Dividend Rights; Other Rights to Share in Company Profits; Capital Calls

If recommended by the directors of BP, BP shareholders may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the UK Companies Act. Dividends on ordinary shares are payable only after payment of dividends on BP preference shares. Any dividend unclaimed after a period of twelve years from the date of declaration of such dividend shall be forfeited and reverts to BP.

The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the Company’s intention to change its current policy of paying dividends in US dollars.

Apart from shareholders’ rights to share in BP’s profits by dividend (if any is declared), the Articles of Association provide that the directors may set aside:


	—	a special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares; and

	—	a general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the Company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares.

Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above.

Holders of shares are not subject to calls on capital by the Company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid.

Voting Rights

The Articles of Association of BP provide that voting on resolutions at a shareholders’ meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of BP preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights.

Holders of record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders’ meeting.

Record holders of BP ADSs also are entitled to attend, speak and vote at any shareholders’ meeting of BP by the appointment by the approved depositary, JPMorgan Chase Bank, of them as proxies in

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respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of ADSs are entitled to vote by supplying their voting instructions to the depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions.

Proxies may be delivered electronically.

Matters are transacted at shareholders’ meetings by the proposing and passing of resolutions, of which there are three types: ordinary, special or extraordinary.

An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. Special and extraordinary resolutions require the affirmative vote of not less than three-fourths of the persons voting at a meeting at which there is a quorum. Any AGM at which it is proposed to put a special or ordinary resolution requires 21 days’ notice. An extraordinary resolution put to the AGM requires no notice period. Any extraordinary general meeting at which it is proposed to put a special resolution requires 21 days’ notice; otherwise, the notice period for an extraordinary general meeting is 14 days.

Liquidation Rights; Redemption Provisions

In the event of a liquidation of BP, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of BP preference shares would be entitled to the sum of (i) the capital paid up on such shares plus, (ii) accrued and unpaid dividends and (iii) a premium equal to the higher of (a) 10% of the capital paid up on the BP preference shares and (b) the excess of the average market price over par value of such shares on the London Stock Exchange during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of ordinary shares.

Without prejudice to any special rights previously conferred on the holders of any class of shares, BP may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution determine (or, in the absence of any such resolutions, by determination of the directors), and may issue shares which are to be or may be redeemed.

Variation of Rights

The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that class or upon the adoption of an extraordinary resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the Articles of Association relating to proceedings at a general meeting apply, except that the quorum with respect to a meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class.

Shareholders’ Meetings and Notices

Shareholders must provide BP with a postal or electronic address in the UK in order to be entitled to receive notice of shareholders’ meetings. In certain circumstances, BP may give notices to shareholders by advertisement in UK newspapers. Holders of BP ADSs are entitled to receive notices under the terms of the deposit agreement relating to BP ADSs. The substance and timing of notices is described above under the heading Voting Rights.

Under the Articles of Association, the AGM of shareholders will be held within 15 months after the preceding AGM. All other general meetings of shareholders shall be called Extraordinary General Meetings and all general meetings shall be held at a time and place determined by the directors within the United Kingdom. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the meeting may be given in any lawful manner, including electronically. Powers exist for

156

action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending.

Limitations on Voting and Shareholding

There are no limitations imposed by English law or BP’s Memorandum or Articles of Association on the right of non-residents or foreign persons to hold or vote the Company’s ordinary shares or ADSs, other than limitations that would generally apply to all of the shareholders.

Disclosure of Interests in Shares

The UK Companies Act permits a public company, on written notice, to require any person whom the company believes to be or, at any time during the previous three years prior to the issue of the notice, to have been interested in its voting shares, to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer and receipt of dividends and other payments in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of BP ADSs.

MATERIAL CONTRACTS

None.

EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS

There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the ordinary shares or on the conduct of the Company’s operations.

There are no limitations, either under the laws of the UK or under the Articles of Association of BP p.l.c., restricting the right of non-resident or foreign owners to hold or vote BP ordinary or preference shares in the Company.

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TAXATION

This section describes the material United States federal income tax and UK taxation consequences of owning ordinary shares or ADSs to a US holder that holds the ordinary shares or ADSs as capital assets for tax purposes. It does not apply, however, to members of special classes of holders subject to special rules and holders that, directly or indirectly, hold 10% or more of the Company’s voting stock.

A US holder is any beneficial owner of ordinary shares or ADSs that is for United States federal income tax purposes (i) a citizen or resident of the United States, (ii) a United States domestic corporation, (iii) an estate whose income is subject to United States federal income taxation regardless of its source, or (iv) a trust if a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust.

This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations thereunder, published rulings and court decisions, and the taxation laws of the United Kingdom, all as currently in effect, as well as the income tax convention between the United States and the United Kingdom that entered into force on March 31, 2003 (the ‘Treaty’). These laws are subject to change, possibly on a retroactive basis.

For purposes of the Treaty and the estate and gift tax Convention (the ‘Estate Tax Convention’), and for United States federal income tax and UK taxation purposes, a holder of ADRs evidencing ADSs will be treated as the owner of the Company’s ordinary shares represented by those ADRs. Exchanges of ordinary shares for ADRs, and ADRs for ordinary shares, generally will not be subject to United States federal income tax or to UK taxation, other than stamp duty or stamp duty reserve tax, as described below.

This section is further based in part upon the representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.

Investors should consult their own tax advisor regarding the United States federal, state and local, the UK and other tax consequences of owning and disposing of ordinary shares and ADSs in their particular circumstances, and in particular whether they are eligible for the benefits of the Treaty.

Taxation of Dividends


	*United Kingdom Taxation*

Under current UK taxation law, no withholding tax will be deducted from dividends paid by the Company, including dividends paid to US holders. A shareholder that is a company resident for tax purposes in the United Kingdom generally will not be taxable on a dividend it receives from the Company. A shareholder who is an individual resident for tax purposes in the United Kingdom is entitled to a tax credit on cash dividends paid on ordinary shares or ADSs of the Company equal to one-ninth of the cash dividend.


	*United States Federal Income Taxation*

A US holder is subject to United States federal income taxation on the gross amount of any dividend paid by the Company out of its current or accumulated earnings and profits (as determined for United States federal income tax purposes). Dividends paid to a non-corporate US holder in taxable years beginning before January 1, 2011, that constitute qualified dividend income will be taxable to the holder at a maximum tax rate of 15%, provided that the holder has a holding period in the ordinary shares or ADSs of more than 60 days during the121-day period beginning 60 days before the ex-dividend date and meets other holding period requirements. Dividends paid by the Company with respect to the shares or ADSs will generally be qualified dividend income.

158

As noted above in this Item — United Kingdom Taxation, a US holder will not be subject to UK withholding tax. A US holder will include in gross income for United States federal income tax purposes the amount of the dividend actually received from the Company, and the receipt of a dividend will not entitle the US holder to a foreign tax credit.

For United States federal income tax purposes, a dividend must be included in income when the US holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend, and will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations. Dividends will be income from sources outside the United States, and generally will be ‘passive income’ or, in the case of certain US holders, ‘financial services income’ (or, for tax years beginning after December 31, 2006, ‘general category income’), which is treated separately from other types of income for purposes of computing the allowable foreign tax credit.

The amount of the dividend distribution on the ordinary shares or ADSs that is paid in pounds sterling will be the US dollar value of the pounds sterling payments made, determined at the spot pounds sterling/ US dollar rate on the date the dividend distribution is includible in income, regardless of whether the payment is in fact converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the pounds sterling dividend payment is includible in income to the date the payment is converted into US dollars will be treated as ordinary income or loss. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Distributions in excess of the Company’s earnings and profits, as determined for United States federal income tax purposes, will be treated as a return of capital to the extent of the US holder’s basis in the ordinary shares or ADSs and thereafter as capital gain, subject to taxation as described in this Item — Taxation of Capital Gains — United States Federal Income Taxation.

Taxation of Capital Gains


	*United Kingdom Taxation*

A US holder may be liable for both United Kingdom and United States tax in respect of a gain on the disposal of ordinary shares or ADSs if the US holder is (i) a citizen of the United States resident or ordinarily resident in the United Kingdom, (ii) a United States domestic corporation resident in the United Kingdom by reason of its business being managed or controlled in the United Kingdom or (iii) a citizen of the United States or a corporation that carries on a trade or profession or vocation in the United Kingdom through a branch or agency or, in respect of corporations for accounting periods beginning on or after January 1, 2003, through a permanent establishment, and that have used, held, or acquired the ordinary shares or ADSs for the purposes of such trade, profession or vocation of such branch, agency or permanent establishment. However, such persons may be entitled to a tax credit against their United States federal income tax liability for the amount of United Kingdom capital gains tax or UK corporation tax on chargeable gains (as the case may be) which is paid in respect of such gain.

Under the Treaty, capital gains on dispositions of ordinary shares or ADSs generally will be subject to tax only in the jurisdiction of residence of the relevant holder as determined under both the laws of the United Kingdom and the United States and as required by the terms of the Treaty.

Under the Treaty, individuals who are residents of either the United Kingdom or the United States and who have been residents of the other jurisdiction (the United States or the United Kingdom, as the case may be) at any time during the six years immediately preceding the relevant disposal of ordinary shares or ADSs may be subject to tax with respect to capital gains arising from a disposition of ordinary shares or ADSs of the Company not only in the jurisdiction of which the holder is resident at the time of the disposition but also in the other jurisdiction.

159


	*United States Federal Income Taxation*

A US holder that sells or otherwise disposes of ordinary shares or ADSs will recognize a capital gain or loss for United States federal income tax purposes equal to the difference between the US dollar value of the amount realized and the holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs. Capital gain of a non-corporate US holder that is recognized in taxable years beginning before January 1, 2011, is generally taxed at a maximum rate of 15% if the holder’s holding period for such ordinary shares or ADSs exceeds one year. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes. The deductibility of capital losses is subject to limitations.

Additional Tax Considerations


	*UK Inheritance Tax*

The Estate Tax Convention applies to inheritance tax. ADSs held by an individual who is domiciled for the purposes of the Estate Tax Convention in the US and is not for the purposes of the Estate Tax Convention a national of the UK will not be subject to UK inheritance tax on the individual’s death or on transfer during the individual’s lifetime unless, among other things, the ADSs are part of the business property of a permanent establishment situated in the UK used for the performance of independent personal services. In the exceptional case where ADSs are subject both to inheritance tax and to US federal gift or estate tax, the Estate Tax Convention generally provides for tax payable in the US to be credited against tax payable in the UK or for tax paid in the UK to be credited against tax payable in the US, based on priority rules set forth in the Estate Tax Convention.


	*UK Stamp Duty and Stamp Duty Reserve Tax*

The statements below relate to what is understood to be the current practice of the UK Inland Revenue under existing law.

Provided that the instrument of transfer is not executed in the UK and remains at all times outside the UK, and the transfer does not relate to any matter or thing done or to be done in the UK, no UK stamp duty is payable on the acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in the form of ADRs give rise to a liability to stamp duty reserve tax.

Purchases of ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer ordinary shares even if the agreement is made outside the UK between two non-residents. Purchases of ordinary shares outside the CREST system are subject either to stamp duty at a rate of 50 pence per £100 (or part), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser. A subsequent transfer of ordinary shares to the Depositary’s nominee will give rise to further stamp duty at the rate of £1.50 per £100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary shares at the time of the transfer.

A transfer of the underlying ordinary shares to an ADR holder upon cancellation of the ADSs without transfer of beneficial ownership will give rise to UK stamp duty at the rate of £5 per transfer.

An ADR holder electing to receive ADSs instead of a cash dividend will be responsible for the stamp duty reserve tax due on issue of shares to the Depositary’s nominee and calculated at the rate of 1.5% on the issue price of the shares. Current UK Inland Revenue practice is to calculate the issue price by reference to the total cash receipt (i.e, cash dividend plus the Refund if any) to which a US Holder would have been entitled had the election to receive ADSs instead of a cash dividend not been made. ADR holders electing to receive ADSs instead of the cash dividend authorize the Depositary to sell sufficient shares to cover this liability.

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DOCUMENTS ON DISPLAY

It is possible to read and copy documents referred to in this annual report on Form 20-F that have been filed with the SEC at the SEC’s public reference room located at 100 F Street NE, Washington, DC 20549. Please call the SEC at1-800-SEC-0330 for further information on the public reference rooms and their copy charges. The SEC filings are also available to the public from commercial document retrieval services and, for most recent BP periodic filings only, at the Internet world wide web site maintained by the SEC at www.sec.gov.

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ITEM 11 —	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Group is exposed to a number of different market risks arising from its normal business activities. Market risk is the possibility that changes in foreign currency exchange rates, interest rates, or oil and natural gas or power prices, will affect adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Group has developed policies aimed at managing the volatility inherent in certain of these natural business exposures and in accordance with these policies the Group enters into various transactions using derivative financial and commodity instruments (derivatives). Derivatives are contracts whose value is derived from one or more underlying financial or commodity instruments, indices or prices which are defined in the contract. The Group also trades derivatives in conjunction with its risk management activities.

All derivative activity, whether for risk management or trading, is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control, meeting generally accepted industry practice and reflecting the principles of the Group of Thirty Global Derivatives Study recommendations. Independent control functions monitor compliance with the Group’s policies. A Trading Risk Management Committee has oversight of the quality of internal control in the Group’s trading function. The control framework includes prescribed trading limits that are reviewed regularly by senior management, daily monitoring of risk exposure using value-at-risk principles, marking trading exposures to market and stress testing to assess the exposure to potentially extreme market situations. The Group’s operational, risk management and trading activities in oil, natural gas, power and financial markets are managed within a single integrated function that has the responsibility for ensuring high and consistent standards of control, making investments in the necessary systems and supporting infrastructure and providing professional management oversight.

In market risk management and trading, conventional exchange-traded derivatives such as futures and options are used, as well as non-exchange-traded instruments such as‘over-the-counter’ swaps, options and forward contracts.

IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39) prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge, and requires that any derivative that does not meet these criteria should be classified as held for trading purposes andmarked-to-market. BP adopted IAS 32 and IAS 39 with effect from January 1, 2005 without restating prior periods. Consequently, the Group’s accounting policy under UK GAAP has been used for 2004 and 2003. The policy under UK GAAP and the disclosures required by UK GAAP for derivative financial instruments are shown in Item 18 — Financial Statements — Note 38 on page F-97.

Where derivatives constitute a fair value hedge, the Group’s exposure to market risk created by the derivative is offset by the opposite exposure arising from the asset, liability or transaction being hedged. Gains and losses relating to derivatives designated as part of a cash flow hedge are taken to reserves and recycled through income as the hedged item is recognized. By contrast, where derivatives are held for trading purposes, realized and unrealized gains and losses are recognized in the period in which they occur.

The Group also has embedded derivatives held for trading. Prior to the development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil products. Post the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing formulae not related directly to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined to be derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The resulting fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.

Further information about BP’s use of derivatives, their characteristics and the IFRS accounting treatment thereof is given in Item 18 — Financial Statements — Note 1 and Note 37 on pagesF-12 andF-83.

162

There are minor differences in the criteria for hedge accounting under IFRS and SFAS No. 133 ‘Accounting for Derivative Instruments and Hedging Activities’. Prior to January 1, 2005, the Group did not designate any of its derivative financial instruments as part of hedged transactions under SFAS 133. As a result, all changes in fair value were recognized through earnings. See Item 18 — Financial Statements — Note 55 on page F-191 for further information.


	Foreign Currency Exchange Rate Risk

Fluctuations in exchange rates can have significant effects on the Group’s reported results. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates, and conversion differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the Group’s reported results.

The main underlying economic currency of the Group’s cash flows is the US dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign exchange management policy is to minimize economic and material transactional exposures arising from currency movements against the US dollar. The Group co-ordinates the handling of foreign exchange risks centrally, by netting off naturally occurring opposite exposures wherever possible, to reduce the risks, and then dealing with any material residual foreign exchange risks. The most significant residual exposures are capital expenditure and UK and European operational requirements. In addition, most of the Group’s borrowings are in US dollars or are hedged with respect to the US dollar. At December 31, 2005, the total of foreign currency borrowings not swapped into US dollars amounted to $424 million. The principal elements of this are $150 million of borrowings in euros, $76 million in sterling, $81 million in Canadian dollars and $83 million in Trinidad and Tobago dollars.

The following table provides information about the Group’s foreign currency derivative financial instruments. These include foreign currency forward exchange agreements (forwards), cylinder option contracts (cylinders), and purchased call options that are sensitive to changes in the sterling/ US dollar and euro/ US dollar exchange rates. Where foreign currency denominated borrowings are swapped into US dollars using forwards or cross currency swaps such that currency risk is completely eliminated, neither the borrowing nor the derivative are included in the table.

For forwards, the tables present the notional amounts and weighted average contractual exchange rates by contractual maturity dates and exclude forwards that have offsetting positions. Only significant forward positions are included in the tables. The notional amounts of forwards are translated into US dollars at the exchange rate included in the contract at inception. The fair value represents an estimate of the gain or loss which would be realized if the contracts were settled at the balance sheet date.

Cylinders consist of purchased call option and written put option contracts. For cylinders and purchased call options, the tables present the notional amounts of the option contracts at December 31, 2005 and the weighted average strike rates.

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The fair values for the foreign exchange contracts in the table below are based on market prices of comparable instruments (forwards) and pricing models which take into account relevant market data (options). These derivative contracts constitute a hedge; any change in the fair value or expected cash flows is offset by an opposite change in the market value or expected cash flows of the asset, liability or transaction being hedged.


			Notional amount by expected maturity date

																	Fair value
													Beyond				asset/
			2006		2007		2008		2009		2010		2010		Total		(liability)

			($ million)
At December 31, 2005
Forwards
	Receive sterling/pay US dollars
		Contract amount		1,749		128		25		6		5		22		1,935		(66	)
		Weighted average contractual exchange rate		1.78
	Receive sterling/pay euro
		Contract amount		67		1		—		—		—		—		68		1
		Weighted average contractual exchange rate	£	0.70
	Receive euro/pay US dollars
		Contract amount		1,253		102		26		11		8		30		1,430		(13	)
		Weighted average contractual exchange rate		1.22
Cylinders
	Receive sterling/pay US dollars
	Purchased call
		Contract amount		717		—		—		—		—		—		717		3
		Weighted average strike price		1.84
	Sold put
		Contract amount		717		—		—		—		—		—		717		(27	)
		Weighted average strike price		1.77
	Receive Euro/pay US dollars
	Purchased call
		Contract amount		706		—		—		—		—		—		706		3
		Weighted average strike price		1.29
	Sold put
		Contract amount		706		—		—		—		—		—		706		(23	)
		Weighted average strike price		1.21
Purchased call options
	Receive sterling/pay US dollars
	Purchased call
		Contract Amount		533		—		—		—		—		—		533		0
		Weighted average strike price		1.97
	Receive euro/pay US dollars
	Purchased call
		Contract Amount		207		—		—		—		—		—		207		0
		Weighted average strike price		1.42


(a)	Weighted average contractual exchange rates are expressed as US dollars per non-US dollar currency unit.

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			Notional amount by expected maturity date

																	Fair value
													Beyond				asset/
			2005		2006		2007		2008		2009		2009		Total		(liability)

			($ million)
At December 31, 2004
Forwards
	Receive sterling/pay US dollars
		Contract amount		2,559		136		61		21		9		35		2,821		253
		Weighted average contractual exchange rate		1.75
	Receive sterling/pay euro
		Contract amount		24		29		15		—		—		—		68		(2	)
		Weighted average contractual exchange rate		£0.72
	Receive euro/pay US dollars
		Contract amount		237		78		28		11		10		36		400		69
		Weighted average contractual exchange rate		1.18
	Pay euro/receive US dollars
		Contract amount		1,829		5		—		—		—		—		1,834		(5	)
		Weighted average contractual exchange rate		1.35
	Receive Norwegian krone/pay US dollars
		Contract amount		232		4		—		—		—		—		236		22
		Weighted average contractual exchange rate (a)		6.66
Cylinders
	Receive sterling/pay US dollars
	Purchased call
		Contract amount		904		—		—		—		—		—		904		32
		Weighted average strike price		1.87
	Sold put
		Contract amount		904		—		—		—		—		—		904		(3	)
		Weighted average strike price		1.75
Purchased call options
	Receive sterling/pay US dollars
	Purchased call
		Contract amount		1,467		—		—		—		—		—		1,467		18
		Weighted average strike price		1.97
	Receive euro/pay US dollars
	Purchased call
		Contract Amount		1,182		—		—		—		—		—		1,182		9
		Weighted average strike price		1.44


(a)	Weighted average contractual exchange rates are expressed as US dollars per non-US dollar currency unit except Norwegian krone which are expressed as krone per US dollar.

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Interest Rate Risk

BP is exposed to interest rate risk on short- and long-term floating rate instruments and as a result of the refinancing of fixed rate finance debt. The Group is exposed predominantly to US dollar LIBOR (London Inter-Bank Offer Rate) interest rates as borrowings are mainly denominated in, or are swapped into, US dollars. To manage the balance between fixed and floating rate debt, the Group enters into interest rate and cross-currency swaps in which the Group agrees to exchange, at specified intervals, the difference between fixed and variable rate interest amounts calculated by reference to an agreed notional principal amount. The proportion of floating rate debt at December 31, 2005 was 96% of total finance debt outstanding.

The following table shows, by major currency, the Group’s finance debt at December 31, 2005 and 2004 and the weighted average interest rates achieved at those dates through a combination of borrowings and other interest rate sensitive instruments entered into to manage interest rate exposure.


	Fixed rate debt						Floating rate debt

	Weighted		Weighted				Weighted
	average		average time				average
	interest		for which				interest
	rate		rate is fixed		Amount		rate		Amount		Total

	(%)		(years)		($ million)		(%)		($ million)		($ million)
At December 31, 2005
US dollar		7		11		665		5		18,073		18,738
Sterling		—		—		—		6		76		76
Euro		—		—		—		3		150		150
Other currencies		9		14		157		12		41		198

Total loans						822				18,340		19,162

At December 31, 2004
US dollar		7		11		707		3		21,789		22,496
Sterling		—		—		—		5		96		96
Euro		—		—		—		3		297		297
Other currencies		9		15		167		8		35		202

Total loans						874				22,217		23,091

The Group’s earnings are sensitive to changes in interest rates over the forthcoming year as a result of the floating rate instruments included in the Group’s finance debt at December 31, 2005. These include the effect of interest rate and currency swaps and forwards utilized to manage interest rate risk. If the interest rates applicable to floating rate instruments were to have increased by 1% on January 1, 2006, the Group’s 2006 earnings before taxes would decrease by approximately $180 million. This assumes that the amount and mix of fixed and floating rate debt, including finance leases, remains unchanged from that in place at December 31, 2005 and that the change in interest rates is effective from the beginning of the year. Where the interest rate applicable to an instrument is reset during a quarter it is assumed that this occurs at the beginning of the quarter and remains unchanged for the rest of the year. In reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change continually. Furthermore the effect on earnings shown by this analysis does not consider the effect of an overall reduction in economic activity which could accompany such an increase in interest rates.

Derivatives Held For Trading

In conjunction with the risk management activities discussed above the Group also trades interest rate and foreign exchange rate derivatives and, in addition, undertakes trading and risk management of certain specified commodities. In order to disclose a complete picture of activities in relation to

166

commodity derivatives, all activity (trading and risk management) is included in aggregate in the following tables.

The Group’s operational, risk management and trading activities in oil, natural gas, power and financial markets are managed within a single integrated function. The Group’s risk management policy requires the management of only certain short-term exposures in respect of its equity share of production and certain of its refinery and marketing activities. These risks are managed in combination with the Group’s supply and trading activities.

To this end, the Group’s supply and trading function uses the full range of conventional financial and commodity derivatives available in the related commodity markets. Natural gas swaps, options and futures are used to convert specific sale and purchase contracts from fixed prices to market prices. Swaps are also used to manage exposures to gas price differentials between locations. The Group’s oil supply and trading activities undertake the full range of conventional derivative financial and commodity instruments and physical cargoes available in the commodity markets. Power trading is undertaken using a combination of over-the-counter forward contracts and other derivative contracts including options and futures. This activity is on both a standalone basis and in conjunction with gas derivatives in relation to gas generated power margin. In addition, NGL’s are traded around certain US inventory locations using over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories.

The Group measures its market risk exposure, i.e., potential gain or loss in fair value, on its trading activity using value-at-risk techniques. These techniques are based on a variance/ covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of theend-of-day exposures, and the history of one-day price movements, together with the correlation of these price movements. The Group calculates value-at-risk for the bulk of instruments and exposures in the held-for-trading category, other than the UK North Sea natural gas embedded derivatives, for which a sensitivity analysis is calculated.

The Group has calculated previously and published value-at-risk expressed to three standard deviations for the internal delegation of market risk limits and control purposes. This is equivalent to a 99.7% confidence interval or a probability of one day per year where the daily gain or loss will exceed the calculated value-at-risk if the portfolio was left unchanged. In order to improve the practical application of this tool, the Group has adopted a 95% confidence level, or calculation to 1.65 standard deviations. This has the effect of increasing the expected frequency of occasions when the daily gain or loss may exceed the calculated value-at-risk to one per month if the portfolio is left unchanged. This provides a better opportunity for verifying models and assumptions and improving accuracy of the value-at-risk calculation. For completeness, 2005 value-at-risk data has been disclosed using both the 99.7% and 95% confidence levels but in future only value-at-risk data on a 95% basis will be disclosed.

The value-at-risk model takes account of derivative financial instrument types such as interest rate forward and futures contracts, swap agreements, options and swaptions, foreign exchange forward and futures contracts, swap agreements and options, and oil, natural gas and power price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as held for trading positions are also included in these calculations. The value-at-risk calculation for oil, natural gas, NGL and power price exposure also includes cash-settled commodity contracts such as forward contracts. For options, a linear approximation is included in the value-at-risk models.

167

The following table shows values-at-risk for held for trading activities described above.


							At
	High		Low		Average		December 31,

	($ million)
Value at risk on three standard deviations:
2005
Interest rate trading		2		—		—		—
Foreign exchange trading		9		2		4		2
Oil price trading		145		31		60		56
Natural gas and NGL price trading		71		9		26		30
Power price trading		30		4		14		16
2004
Interest rate trading		1		—		—		—
Foreign exchange trading		4		1		1		1
Oil price trading		55		18		29		45
Natural gas and NGL price trading		42		11		23		18
Power price trading		18		2		8		7
2003
Interest rate trading		1		—		—		—
Foreign exchange trading		4		—		2		1
Oil price trading		34		17		26		27
Natural gas and NGL price trading		29		4		16		18
Power price trading		13		—		4		6


							At
	High		Low		Average		December 31,

	($ million)
Value at risk on 1.65 standard deviations:
2005
Interest rate trading		1		—		—		—
Foreign exchange trading		5		1		2		1
Oil price trading		80		17		33		31
Natural gas and NGL price trading		39		6		15		17
Power price trading		16		2		7		9
2004
Interest rate trading		1		—		—		—
Foreign exchange trading		2		1		1		1
Oil price trading		30		10		16		25
Natural gas and NGL price trading		23		6		13		10
Power price trading		10		1		4		4
2003
Interest rate trading		1		—		—		—
Foreign exchange trading		2		—		1		1
Oil price trading		19		9		14		15
Natural gas and NGL price trading		16		2		9		10
Power price trading		7		—		2		3

168


	*Sensitivity Analysis of Embedded Derivatives*

Detailed below for the embedded derivatives is a sensitivity of the fair value to immediate 10% favourable and adverse changes in the key assumptions.


	At December 31, 2005

Remaining contract terms		3 to 13 years
Contractual/notional amount		8,220 million therms
Discount rate — nominal risk free		4.5%
Fair value liability		$2,590 million


	At December 31, 2005

				Gas oil
	Natural			and fuel			Power			Discount
	gas price			oil price			price			rate

	($ million)
Favourable 10% change		408			30			(63	)		34
Unfavourable 10% change		(427	)		(45	)		58			(34	)


	At December 31, 2004

Remaining contract terms		4 to 14 years
Contractual/ notional amount		10,409 million therms
Discount rate — nominal risk free		4.5%
Fair value liability		$817 million


	At December 31, 2004

				Gas oil
	Natural			and fuel			Power			Discount
	gas price			oil price			price			rate

	($ million)
Favourable 10% change		129			9			(20	)		11
Unfavourable 10% change		(135	)		(14	)		18			(11	)

These sensitivities are hypothetical and should not be considered to be predictive of future performance. Changes in fair value generally cannot be extrapolated because the relationship of change in assumption to change in fair value may not be linear. Also, in this table, the effect of a variation in a particular assumption on the fair value of the embedded derivatives is calculated independently of any change in another assumption. In reality, changes in one factor may contribute to changes in another, which may magnify or counteract the sensitivities. Furthermore, the estimated fair values as disclosed should not be considered indicative of future earnings on these contracts.

169

The following tables show the changes during the year in the net fair value of derivatives held for trading purposes for the years 2005 and 2004.


									Fair value
	Fair value		Fair value			Fair value			natural gas			Fair value
	interest		exchange			oil			and NGL			power
	rate		rate			price			price			price
	contracts		contracts			contracts			contracts			contracts

	($ million)
Fair value of contracts at January 1, 2005		—		(54	)		(171	)		558			177
Contracts realized or settled in the year		—		23			175			(735	)		76
Fair value of new contracts when entered into during the year		—		—			—			24			10
Fair value of over-the-counter options at inception		—		—			(73	)		(65	)		(9	)
Change in fair value due to changes in valuation techniques or key assumptions		—		—			—			—			—
Other changes in fair values		—		54			8			747			(71	)

Fair value of contracts at December 31, 2005		—		23			(61	)		529			183

Fair value of contracts at January 1, 2004		—		(24	)		(169	)		302			134
Contracts realized or settled in the year		—		9			173			230			54
Fair value of new contracts when entered into during the year		—		—			—			15			—
Fair value of over-the-counter options at inception		—		—			(33	)		58			(3	)
Change in fair value due to changes in valuation techniques or key assumptions		—		—			—			—			—
Other changes in fair values		—		(39	)		(142	)		(47	)		(8	)

Fair value of contracts at December 31, 2004		—		(54	)		(171	)		558			177

The following tables show the changes during the year in the net fair value of embedded derivatives held for trading purposes for the years 2005 and 2004.


	Fair value			Fair value
	interest			natural
	rate			gas price
	contracts			contracts

	($ million)
Fair value of contracts at January 1, 2005		(17	)		(659	)
Contracts realized or settled in the year		—			138
Fair value of new contracts when entered into during the year		—			—
Change in fair value due to changes in valuation techniques or key assumptions		—			—
Other changes in fair values		(13	)		(1,990	)

Fair value of contracts at December 31, 2005		(30	)		(2,511	)

Fair value of contracts at January 1, 2004		(12	)		(301	)
Contracts realized or settled in the year		—			—
Fair value of new contracts when entered into during the year		—			—
Change in fair value due to changes in valuation techniques or key assumptions		—			—
Other changes in fair values		(5	)		(358	)

Fair value of contracts at December 31, 2004		(17	)		(659	)

170

The following table shows the fair value of ‘day one profit’ deferred on the balance sheet.


	Fair value
	natural			Fair value
	gas and			power
	NGL price			price
	contracts			contracts

	($ million)
Fair value of contracts not recognized through the income statement at January 1, 2005		(15	)		—
Fair value of new contracts at inception not recognized in the income statement		(14	)		(10	)
Fair value recycled from equity into the income statement		—			—
Other changes in fair values		—			—

Fair value of contracts not recognized through profit at December 31, 2005		(29	)		(10	)


	Fair value
	natural			Fair value
	gas and			power
	NGL price			price
	contracts			contracts

	($ million)
Fair value of contracts not recognized through the income statement at January 1, 2004		—			—
Fair value of new contracts at inception not recognized in the income statement		(15	)		—
Fair value recycled from equity into the income statement		—			—
Other changes in fair values		—			—

Fair value of contracts not recognized through profit at December 31, 2004		(15	)		—

The following tables show the net fair value of derivatives held for trading at December 31, 2005 and 2004 analyzed by maturity period and by methodology of fair value estimation.


	Fair value of contracts at December 31, 2005

	Maturity																	Total
	less than			Maturity			Maturity			Maturity		Maturity			Over			fair
	1 year			1-2 years			2-3 years			3-4 years		4-5 years			5 years			value

	($ million)
Prices actively quoted		(100	)		(86	)		46			42		33			(8	)		(73	)
Prices sourced from observable data or market corroboration		660			(48	)		(41	)		60		(11	)		—			620
Prices based on models and other valuation methods		3			(2	)		3			75		2			46			127

		563			(136	)		8			177		24			38			674


	Fair value of contracts at December 31, 2004

	Maturity														Total
	less than		Maturity			Maturity		Maturity		Maturity			Over		fair
	1 year		1-2 years			2-3 years		3-4 years		4-5 years			5 years		value

	($ million)
Prices actively quoted		105		(90	)		13		21		17			15		81
Prices sourced from observable data or market corroboration		128		130			39		28		34			—		359
Prices based on models and other valuation methods		4		2			1		2		(1	)		62		70

		237		42			53		51		50			77		510

171

Prices actively quoted refers to the fair value of contracts valued in whole using prices actively quoted, for example, exchange-traded and UK National Balancing Point (NBP) contracts. Prices provided by other external sources refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data or internal inputs, for example, swaps and physical forward contracts. Prices based on models and other valuation methods refers to the fair value of a contract valued in part using internal models due to the absence of quoted prices, includingover-the-counter options. The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $130 million.

The following tables show the net fair value of embedded derivatives held for trading at December 31, 2005 and 2004 analyzed by maturity period and by methodology of fair value estimation.


	Fair value of contracts at December 31, 2005

	Maturity																		Total
	less than			Maturity			Maturity			Maturity			Maturity			Over			fair
	1 year			1-2 years			2-3 years			3-4 years			4-5 years			5 years			value

	($ million)
Prices actively quoted		—			—			—			—			—			—			—
Prices sourced from observable data or market corroboration		51			28			—			—			—			—			79
Prices based on models and other valuation methods		(674	)		(542	)		(426	)		(231	)		(182	)		(565	)		(2,620	)

		(623	)		(514	)		(426	)		(231	)		(182	)		(565	)		(2,541	)


	Fair value of contracts at December 31, 2004

	Maturity																		Total
	less than			Maturity			Maturity			Maturity			Maturity			Over			fair
	1 year			1-2 years			2-3 years			3-4 years			4-5 years			5 years			value

	($ million)
Prices actively quoted		—			—			—			—			—			—			—
Prices sourced from observable data or market corroboration		150			9			—			—			—			—			159
Prices based on models and other valuation methods		(247	)		(206	)		(141	)		(102	)		(57	)		(82	)		(835	)

		(97	)		(197	)		(141	)		(102	)		(57	)		(82	)		(676	)


ITEM 12 —	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable

172

PART II


ITEM 13 —	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.


ITEM 14 —	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.


ITEM 15 —	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company maintains ‘disclosure controls and procedures’ as such term is defined in Exchange Act Rule 13a-15(e), that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including the Company’s group chief executive and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, our management, including the group chief executive and chief financial officer, recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. Further, in the design and evaluation of our disclosure controls and procedures our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Also, we have investments in certain unconsolidated entities. As we do not control these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries. Because of the inherent limitations in a cost-effective control system, mis-statements due to error or fraud may occur and not be detected. The Company’s disclosure controls and procedures have been designed to meet, and management believe that they meet, reasonable assurance standards.

During 2005, a review was undertaken into the accounting treatment under US GAAP forover-the-counter forward contracts in oil, gas, NGLs and power in the context of the review undertaken for final transition to IFRS. As a result of this review the Group reassessed its recognition of revenues associated with these contracts under US GAAP and determined that these contracts should be reported net. Under the provisions of APB 20 the Company’s management concluded that the change represented the correction of an accounting error. In addition, in connection with the preparation of the Form 20-F for the year ended December 31, 2005, the Company identified additional transactions which should also have been presented net under US GAAP. As a result of these matters, revenues and cost of sales for US GAAP were restated, and the Company’s Annual Report on Form 20-F for the year ended December 31, 2004 was amended. The restatement for US GAAP purposes did not impact the Group’s profit for the year as adjusted to accord with US GAAP, profit per ordinary share, cash flow or financial position.

Following the review of the accounting treatment for over-the counter forward contracts under US GAAP, the Group improved its disclosure controls and procedures by changing its US GAAP accounting policy for OTC forward contracts to conform to US GAAP, training the accounting staff regarding the policy change, implementing changes in its internal reporting systems to process and

173

report sale and purchase contracts, in accordance with Group US GAAP accounting policy for such transactions and increasing management oversight of compliance therewith.

The Company’s management, with the participation of the Company’s group chief executive and the chief financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this annual report. While the improvements in the Company’s disclosure controls and procedures described in the preceding paragraph had largely been implemented by the end of 2005, the Group subsequently identified additional transactions which should also have been presented net under US GAAP. As a result of the identification of these additional transactions which should have been presented net under US GAAP, the group chief executive and the chief financial officer have determined that the Company’s disclosure controls and procedures as of December 31, 2005 were not effective to provide reasonable assurance that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act was recorded, processed, summarized and reported within the time period specified in the rules and forms of the SEC.

Apart from the failure to account for certain OTC forward contracts on a net basis under US GAAP, the Company’s management has not identified any other deficiencies that would have led the Company’s management to conclude that the Group’s disclosure controls and procedures were ineffective for the period covered by this annual report. As the Company is not currently required to report on management’s assessment of the effectiveness of the Group’s internal controls over financial reporting the Company has not undertaken the kind of review of such controls that would be required in order to make such a report.

Changes in Internal Controls

The improvements in disclosure controls and procedures relating to the accounting treatment for OTC forward contracts under US GAAP implemented during 2005, as described above, also constituted changes in the Group’s internal controls over financial reporting.

Aside from these improvements, there were no changes in the Group’s internal controls over financial reporting that occurred during the period covered by this Form 20-F that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

ITEM 16A — AUDIT COMMITTEE FINANCIAL EXPERT

Douglas Flint joined the board as a non-executive director on January 1, 2005 and joined the audit committee on March 16, 2005. He is group finance director of HSBC Holdings plc, and a former member of the Accounting Standards Board and the Standards Advisory Council of the International Accounting Standards Board. The Board determined that Mr Flint met the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and that Mr Flint may be regarded as an audit committee financial expert as defined for purposes of disclosure in Item 16A of Form 20-F.

ITEM 16B — CODE OF ETHICS

The Company has adopted a Code of Ethics for its group chief executive, deputy group chief executive, chief financial officer, the general auditor, group chief accounting officer and group controller as required by the provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued by the SEC. There have been no amendments to, or waivers from, the Code of Ethics relating to any of those officers. The Code of Ethics has been filed as an exhibit to this report.

In June 2005, BP published a Code of Conduct which is applicable to all employees.

ITEM 16C — PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Audit Committee has established policies and procedures for the engagement of the independent registered public accounting firm, Ernst & Young LLP, to render audit and certain

174

assurance and tax services. The policies provide for pre-approval by the audit committee of specifically defined audit, audit-related, tax and other services that are not prohibited by regulatory or other professional requirements. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young relative to that of other potential service providers. These services are for a fixed term.

Under the policy, pre-approval is given for specific services within the following categories: advice on accounting, auditing and financial reporting matters; internal accounting and risk management control reviews (excluding any services relating to information systems design and implementation); non-statutory audit; project assurance and advice on business and accounting process improvement (excluding any services relating to information systems design and implementation relating to BP’s financial statements or accounting records); due diligence in connection with acquisitions, disposals and joint ventures; income tax and indirect tax compliance and advisory services; and employee tax services (excluding tax services that could impair independence); and provision of Ernst & Young publications. Additionally, any proposed service not included in the pre-approved services, must be approved in advance prior to commencement of the engagement. The Audit Committee has delegated to the Chair of the Audit Committee authority to approve permitted services provided that the Chair reports any decisions to the committee at its next scheduled meeting.


		Year ended
		December 31,

		2005			2004			2003

		($ million)
Audit fees — Ernst & Young
	Group audit		47			27			18
	Audit-related regulatory reporting		6			7			5
	Statutory audit of subsidiaries		23			16			13

			76			50			36
Innovene operations			(8	)		(2	)		(2	)

Continuing operations			68			48			34

Fees for other services — Ernst & Young
Further assurance services
	Acquisition and disposal due diligence		2			7			9
	Pension scheme audits		1			1			1
	Other further assurance services		7			9			9

			10			17			19
Tax services
	Compliance services		10			13			17
	Advisory services		—			1			2

			10			14			19
Innovene operations			(1	)		(1	)		—

Continuing operations			19			30			38

The audit fees payable to Ernst & Young are reviewed by the Audit Committee in the context of other global companies for cost effectiveness. The committee keeps under review the scope and results of audit work, its cost-effectiveness and the independence and objectivity of the auditors. It requires the auditors to rotate their lead audit partner every five years.

175

Other further assurance services within Further assurance services include $4 million (2004 $3 million and 2003 $2 million) in respect of advice on accounting, auditing and financial reporting matters; $nil (2004 $1 million and 2003 $1 million) in respect of internal accounting and risk management control reviews; $3 million (2004 $3 million and 2003 $2 million) in respect of non-statutory audits and $nil (2004 $2 million and 2003 $3 million) in respect of project assurance and advice on business and accounting process improvement.

The tax compliance services relate to income tax and indirect tax compliance and employee tax services.

Fees paid to major firms of accountants other than Ernst & Young for other services amount to $151 million (2004 $82 million and 2003 $44 million).

ITEM 16D — EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.


ITEM 16E —	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

The following table provides details of ordinary shares repurchased.


					Total number
					of shares purchased as		Maximum number
					part of publicly		of shares that may yet
	Total number of		Average price paid		announced		be purchased under
	shares purchased (a)		per share		programmes		the programme (b)

			($)
2005
January (c)		57,900,000		9.71		57,900,000
February (d)		69,500,000		10.41		69,500,000
March		65,725,000		10.86		65,725,000
April		62,656,000		10.38		62,656,000
May		63,627,000		10.13		63,627,000
June		76,385,000		10.53		76,385,000
July		161,074,724		11.02		161,074,724
August		108,525,357		11.56		108,525,357
September		62,517,400		11.99		62,517,400
October		133,833,000		11.12		133,833,000
November		121,578,400		11.23		121,578,400
December		76,384,600		11.32		76,384,600
2006
January		70,000,000		11.67		70,000,000
February		139,785,200		11.41		139,785,200
March		139,294,200		11.41		139,294,200
April		107,608,638		12.22		107,608,638
May		149,312,153		12.33		149,312,153
June (through June 28)		118,823,000		11.31		118,823,000


(a)	All share purchases were open market transactions.


(b)	At the AGM on April 20, 2006, authorization was given to repurchase up to 2 billion ordinary shares in the period to the next AGM or July 19, 2007, the latest date by which an AGM must be held. This authorization is renewed annually at the AGM.


(c)	Shares repurchased for cancellation.


(d)	Includes 18,900,000 shares repurchased for cancellation and 50,600,000 shares held in treasury.

176

The following table provides details of share purchases made by ESOP Trusts.


					Total number
					of shares purchased as	Maximum number of
					part of publicly	shares that may yet
	Total number of		Average price paid		announced	be purchased under
	shares purchased		per share		programmes (a)	the programme (a)

			($)
2005
January		143,789		9.79
February		7,128,864		10.47
March		6,271,709		10.39
April		239		9.53
May		—		—
June		3,690		10.82
July		10,000,000		11.69
August		—		—
September		2,030		10.33
October		—		—
November		—		—
December		3,028		9.35
2006
January		41,068		11.24
February		1,638,669		11.33
March		6,198,758		11.47
April		—		—
May		13,829		12.37
June (through June 28)		10,001,371		10.93


(a)	No shares were repurchased pursuant to a publicly announced plan. Transactions represent the purchase of ordinary shares by ESOP Trusts to satisfy future requirements of employee share schemes.

177

PART III


ITEM 17 —	FINANCIAL STATEMENTS

Not applicable.


ITEM 18 —	FINANCIAL STATEMENTS

The following financial statements, together with the reports of the Independent Registered Public Accounting Firm thereon, are filed as part of this annual report:


		Page

Report of Independent Registered Public Accounting Firm			F-1
Consent of Independent Registered Public Accounting Firm			F-2
Consolidated Statement of Income for the Years Ended December 31, 2005, 2004, and 2003			F-3
Consolidated Balance Sheet at December 31, 2005, 2004 and 2003			F-4
Consolidated Statement of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003			F-5
Consolidated Statement of Recognized Income and Expense for the Years Ended December 31, 2005, 2004, and 2003			F-6
Consolidated Statement of Changes in BP Shareholders’ Equity for the Years Ended December 31, 2005, 2004, and 2003			F-7
Notes to Financial Statements			F-12
	The following supplementary information is filed as part of this annual report:
Supplementary Oil and Gas Information (Unaudited)			S-1
Schedule for the Years Ended December 31, 2005, 2004, and 2003 Schedule II Valuation and Qualifying Accounts			S-15

ITEM 19 — EXHIBITS

The following documents are filed as part of this annual report:


	Exhibit 1.			Memorandum and Articles of Association of BP p.l.c.*
	Exhibit 4.1			The BP Executive Directors’ Incentive Plan**
	Exhibit 4.2			Directors’ Service Contracts**
	Exhibit 4.3			Medium Term Performance Plan
	Exhibit 4.4			Deferred Annual Bonus Plan
	Exhibit 7.			Computation of Ratio of Earnings to Fixed Charges (Unaudited)
	Exhibit 8.			Subsidiaries
	Exhibit 11.			Code of Ethics*
	Exhibit 12.			Rule 13a — 14(a) Certifications
	Exhibit 13.			Rule 13a — 14(b) Certifications#


*	Incorporated by reference to the Company’s Annual Report on Form 20-F for the year ended December 31, 2003.

**	Incorporated by reference to the Company’s Annual Report on Form 20-F for the year ended December 31, 2004.


#	Furnished only.

The total amount of long-term debt securities of the Registrant and its subsidiaries authorized under any one instrument does not exceed 10% of the total assets of BP p.l.c. and its subsidiaries on a consolidated basis. The Company agrees to furnish copies of any or all such instruments to the Securities and Exchange Commission upon request.

178

BP p.l.c. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To:		The Board of Directors BP p.l.c.

We have audited the accompanying consolidated balance sheets of BP p.l.c. as of December 31, 2005, 2004 and 2003, and the related consolidated statements of income, cash flows, recognized income and expense, and changes in BP shareholders’ equity for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 18. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of BP p.l.c. at December 31, 2005 and 2004, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2005, in accordance with International Financial Reporting Standards as adopted by the European Union which differ in certain respects from United States generally accepted accounting principles (see Note 55 of Notes to Financial Statements). Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 37 of Notes to Financial Statements, the Group changed its method of accounting for derivative financial instruments in 2005.


	/s/ ERNST & YOUNG LLP

	Ernst & Young LLP

London, England

June 30, 2006

F-1

BP p.l.c. AND SUBSIDIARIES

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference of our report dated June 30, 2006, with respect to the consolidated financial statements and schedule of BP p.l.c. included in this Annual Report (Form 20-F) for the year ended December 31, 2005 in the following Registration Statements:

Registration Statements on Form F-3 (File Nos.333-9790,333-65996 and333-110203) of BP p.l.c.;

Registration Statement on Form F-3 (File No. 333-83180) of BP Australia Capital Markets Limited, BP Canada Finance Company, BP Capital Markets p.l.c., BP Capital Markets America Inc. and BP p.l.c.; and

Registration Statements on Form S-8 (File Nos.33-21868,333-9020,333-9798,333-79399,333-34968,333-67206,333-74414,333-102583,333-103923,333-103924,333-119934,333-123482,333-123483,333-132619,333-131584 and333-131583) of BP p.l.c.


	/s/ ERNST & YOUNG LLP

	Ernst & Young LLP

London, England

June 30, 2006

F-2

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME


				Years ended December 31,

		Note		2005		2004			2003

				($ million, except per share amounts)
Sales and other operating revenues			7		239,792		192,024			164,653
Earnings from jointly controlled entities — after interest and tax			8		3,083		1,818			826
Earnings from associates — after interest and tax			8		460		462			388
Interest and other revenues			9		613		615			746

Total revenues					243,948		194,919			166,613
Gains on sale of businesses and fixed assets			10		1,538		1,685			1,895

Total revenues and other income					245,486		196,604			168,508
Purchases					163,026		128,055			111,190
Production and manufacturing expenses					21,592		17,330			14,130
Production and similar taxes			11		3,010		2,149			1,723
Depreciation, depletion and amortization			12		8,771		8,529			8,076
Impairment and losses on sale of businesses and fixed assets			13		468		1,390			1,801
Exploration expense			19		684		637			542
Distribution and administration expenses			15		13,706		12,768			12,270
Fair value (gain) loss on embedded derivatives			37		2,047		—			—

Profit before interest and taxation from continuing operations					32,182		25,746			18,776
Finance costs			21		616		440			513
Other finance expense			22		145		340			532

Profit before taxation from continuing operations					31,421		24,966			17,731
Taxation			23		9,288		7,082			5,050

Profit from continuing operations					22,133		17,884			12,681
Profit (loss) from Innovene operations			5		184		(622	)		(63	)

Profit for the year					22,317		17,262			12,618

Attributable to
	BP shareholders				22,026		17,075			12,448
	Minority interest				291		187			170

					22,317		17,262			12,618

Profit for the year attributable to BP shareholders*					22,026		17,075			12,448
Dividend requirements on preference shares*					2		2			2

Profit for the year applicable to ordinary shares*					22,024		17,073			12,446

Profit per ordinary share — cents
Basic			26		104.25		78.24			56.14
Diluted			26		103.05		76.87			55.61

Dividends announced and paid per ordinary share — cents					34.85		27.70			25.50

Average number outstanding of 25 cents ordinary shares (in thousands)					21,125,902		21,820,535			22,170,741


*	A summary of the adjustments to profit for the year attributable to BP shareholders which would be required if generally accepted accounting principles in the United States had been applied instead of International Financial Reporting Standards as adopted by the EU is given in Note 55.

The Notes to Financial Statements are an integral part of this Statement.

F-3

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


				December 31,

		Note		2005		2004		2003

				($ million)
Noncurrent assets
	Property, plant and equipment		27		85,947		93,092		88,607
	Goodwill		28		10,371		10,857		10,592
	Intangible assets		29		4,772		4,205		4,471
	Investments in jointly controlled entities		30		13,556		14,556		12,909
	Investments in associates		31		6,217		5,486		4,868
	Other investments		32		967		394		1,452

	Fixed assets				121,830		128,590		122,899
	Loans				821		811		852
	Other receivables		34		770		429		495
	Derivative financial instruments		37		3,652		898		534
	Prepayments and accrued income				1,269		354		957
	Defined benefit pension plan surplus		44		3,282		2,105		1,680

					131,624		133,187		127,417

Current assets
	Loans				132		193		182
	Inventories		33		19,760		15,645		11,597
	Trade and other receivables		34		40,902		37,099		27,881
	Derivative financial instruments		37		9,726		5,317		1,891
	Prepayments and accrued income				1,598		1,671		1,375
	Current tax receivable				212		159		92
	Cash and cash equivalents		35		2,960		1,359		2,056

					75,290		61,443		45,074

Total assets					206,914		194,630		172,491

Current liabilities
	Trade and other payables		36		42,136		38,540		29,740
	Derivative financial instruments		37		9,083		5,074		4,145
	Accruals and deferred income				5,970		4,482		2,266
	Finance debt		41		8,932		10,184		9,456
	Current tax payable				4,274		4,131		3,441
	Provisions		43		1,602		715		735

					71,997		63,126		49,783

Noncurrent liabilities
	Other payables		36		1,935		3,581		4,630
	Derivative financial instruments		37		3,696		158		344
	Accruals and deferred income				3,164		699		864
	Finance debt		41		10,230		12,907		12,869
	Deferred tax liabilities		23		16,258		16,701		16,051
	Provisions		43		9,954		8,884		7,864
	Defined benefit pension plan and other postretirement benefit plan deficits		44		9,230		10,339		9,822

					54,467		53,269		52,444

Total liabilities					126,464		116,395		102,227

Net assets					80,450		78,235		70,264

Equity
	Share capital				5,185		5,403		5,552
	Reserves				74,476		71,489		63,587

BP shareholders’ equity*					79,661		76,892		69,139
Minority interest					789		1,343		1,125

Total equity					80,450		78,235		70,264


*	A summary of the adjustments to BP shareholders’ equity which would be required if generally accepted accounting principles in the United States had been applied instead of International Financial Reporting Standards as adopted by the EU is given in Note 55.

The Notes to Financial Statements are an integral part of this Balance Sheet.

F-4

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS


					Years ended December 31,

			Note		2005			2004			2003

					($ million)
Operating activities
	Profit before taxation from continuing operations					31,421			24,966			17,731
		Adjustments to reconcile profits before tax to net cash provided by operating activities
		Exploration expenditure written off		19		305			274			297
		Depreciation, depletion and amortization		12		8,771			8,529			8,076
		Impairment and (gain) loss on sale of businesses and fixed assets		10, 13		(1,070	)		(295	)		(94	)
		Earnings from jointly controlled entities and associates		8		(3,543	)		(2,280	)		(1,214	)
		Dividends received from jointly controlled entities and associates				2,833			2,199			548
		Interest receivable				(479	)		(284	)		(212	)
		Interest received				401			331			186
		Finance costs		21		616			440			513
		Interest paid				(1,127	)		(698	)		(1,007	)
		Other finance expense		22		145			340			532
		Share-based payments				278			224			208
		Net operating charge for pensions and other postretirement benefits, less contributions				(435	)		(84	)		(2,913	)
		Net charge for provisions, less payments				1,100			(110	)		171
		(Increase) decrease in inventories				(6,638	)		(3,182	)		(657	)
		(Increase) decrease in other current and noncurrent assets				(16,427	)		(10,225	)		(2,981	)
		Increase (decrease) in other current and noncurrent liabilities				18,628			10,290			1,575
		Income taxes paid				(9,028	)		(6,388	)		(4,804	)

Net cash provided by operating activities of continuing operations						25,751			24,047			15,955
Net cash provided by (used in) operating activities of Innovene operations				5		970			(669	)		348

Net cash provided by operating activities						26,721			23,378			16,303

Investing activities
	Capital expenditures					(12,281	)		(12,286	)		(11,885	)
	Acquisitions, net of cash acquired					(60	)		(1,503	)		(211	)
	Investment in jointly controlled entities					(185	)		(1,648	)		(2,630	)
	Investment in associates					(619	)		(942	)		(987	)
	Proceeds from disposal of property, plant and equipment			6		2,803			4,236			6,177
	Proceeds from disposal of businesses			6		8,397			725			179
	Proceeds from loan repayments					123			87			76
	Other					93			—			—

Net cash used in investing activities						(1,729	)		(11,331	)		(9,281	)

Financing activities
	Net repurchase of shares					(11,315	)		(7,208	)		(1,889	)
	Proceeds from long-term financing					2,475			2,675			4,322
	Repayments of long-term financing					(4,820	)		(2,204	)		(3,560	)
	Net increase (decrease) in short-term debt					(1,457	)		(24	)		(2	)
	Dividends paid
		BP shareholders		25		(7,359	)		(6,041	)		(5,654	)
		Minority interest				(827	)		(33	)		(20	)

Net cash used in financing activities						(23,303	)		(12,835	)		(6,803	)

Currency translation differences relating to cash and cash equivalents						(88	)		91			121

Increase (decrease) in cash and cash equivalents						1,601			(697	)		340
Cash and cash equivalents at beginning of year						1,359			2,056			1,716

Cash and cash equivalents at end of year						2,960			1,359			2,056

The Notes to Financial Statements are an integral part of this Statement.

F-5

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF RECOGNIZED INCOME AND EXPENSE


				Years ended December 31,

		Note		2005			2004			2003

				($ million)
Currency translation differences					(2,502	)		2,283			3,656
Exchange gain on translation of foreign operations transferred to gain or loss on sale of businesses and fixed assets					(315	)		(78	)		—
Actuarial gain relating to pensions and other postretirement benefits					975			107			76
Available-for-sale investments marked to market					322			—			—
Available-for-sale investments — recycled to the income statement					(60	)		—			—
Cash flow hedges marked to market					(212	)		—			—
Cash flow hedges — recycled to the income statement					36			—			—
Cash flow hedges — recycled to the balance sheet					—			—			—
Unrealized gain on acquisition of further investment in equity-accounted investments					—			94			—
Tax on currency translation differences					11			(208	)		(37	)
Tax on exchange gain on translation of foreign operations transferred to gain or loss on sale of businesses and fixed assets					95			—			—
Tax on actuarial gain (loss) relating to pensions and other postretirement benefits					(356	)		96			(16	)
Tax on available-for-sale investments					(72	)		—			—
Tax on cash flow hedges					63			—			—
Tax on share-based payment accrual					—			39			5

Net income recognized directly in equity					(2,015	)		2,333			3,684
Profit for the year					22,317			17,262			12,618

Total recognized income and expense relating to the year					20,302			19,595			16,302

Change in accounting policy — adoption of IAS 32 and IAS 39 on January 1, 2005			52		(243	)

Total recognized income and expense since last annual accounts					20,059

Attributable to
	BP shareholders				19,768			19,408			16,132
	Minority interest				291			187			170

					20,059			19,595			16,302

The Notes to Financial Statements are an integral part of this Statement.

F-6

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN BP SHAREHOLDERS’ EQUITY

The Company’s authorized ordinary share capital at December 31, 2005, 2004 and 2003 was 36 billion shares of 25 cents each, amounting to $9 billion. In addition the Company has authorized preference share capital of 12,750,000 shares of £1 each ($21 million).

The allotted, called up and fully paid share capital at December 31, was as follows:


		Years ended December 31,

		2005						2004						2003

		Shares						Shares						Shares
Issued		(thousands)			($ million)			(thousands)			($ million)			(thousands)			($ million)

8% cumulative first preference shares of £1 each			7,233			12			7,233			12			7,233			12
9% cumulative second preference shares of £1 each			5,473			9			5,473			9			5,473			9

						21						21						21

Ordinary shares of 25 cents each January 1,			21,525,978			5,382			22,122,610			5,531			22,378,651			5,595
	Employee share schemes		68,500			17			62,224			16			32,889			8
	Atlantic Richfield		13,644			3			29,288			7			9,786			2
	Issue of ordinary share capital for TNK-BP		108,629			27			139,096			35			—			—
	Repurchase of ordinary share capital		(1,059,706	)		(265	)		(827,240	)		(207	)		(298,716	)		(74	)

December 31,			20,657,045			5,164			21,525,978			5,382			22,122,610			5,531

						5,185						5,403						5,552

Authorized
8% cumulative first preference shares of £1 each			7,250						7,250						7,250
9% cumulative second preference shares of £1 each			5,500						5,500						5,500
Ordinary shares of 25 cents each			36,000,000						36,000,000						36,000,000


(a)	Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On ashow-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.

	In the event of the winding up of the Company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.

The Notes to Financial Statements are an integral part of this Statement.

F-7

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN BP SHAREHOLDERS’ EQUITY (Continued)


				Share		Capital
	Share			premium		redemption		Merger		Other			Own			Treasury
	capital			account		reserve		reserve		reserve			shares			shares

	($ million)
At December 31, 2004		5,403			5,636		730		27,162		44			(82	)		—
Adoption of IAS 39		—			—		—		—		—			—			—

At January 1, 2005		5,403			5,636		730		27,162		44			(82	)		—
Currency translation differences (net of tax)		—			—		—		—		—			12			—
Exchange gain on translation of foreign operations transferred to (profit) or loss on sale (net of tax)		—			—		—		—		—			—			—
Actuarial gain (loss) (net of tax)		—			—		—		—		—			—			—
Employee share schemes (a)		17			436		—		—		—			—			3
Atlantic Richfield (b)		3			76		—		28		(28	)		—			—
Issue of ordinary share capital for TNK-BP (c)		27			1,223		—		—		—			—			—
Purchase of shares by ESOP trusts		—			—		—		—		—			(251	)		—
Available-for-sale investments marked to market (net of tax)		—			—		—		—		—			—			—
Available-for-sale investments recycling (net of tax)		—			—		—		—		—			—			—
Repurchase of ordinary share capital (d)		(265	)		—		19		—		—			—			(10,601	)
Share-based payments (net of tax) (e)		—			—		—		—		—			181			—
Cash flow hedges marked to market (net of tax)		—			—		—		—		—			—			—
Cash flow hedges recycling (net of tax)		—			—		—		—		—			—			—
Profit for the year		—			—		—		—		—			—			—
Dividends (f)		—			—		—		—		—			—			—

At December 31, 2005		5,185			7,371		749		27,190		16			(140	)		(10,598	)

At January 1, 2004		5,552			3,957		523		27,077		129			(96	)		—
Currency translation differences (net of tax)		—			—		—		—		—			(7	)		—
Exchange gain on translation of foreign operations transferred to (profit) or loss on sale (net of tax)		—			—		—		—		—			—			—
Actuarial gain (loss) (net of tax)		—			—		—		—		—			—			—
Unrealized gain on acquisition of further investment in equity-accounted investments		—			—		—		—		—			—			—
Employee share schemes (a)		16			311		—		—		—			—			—
Atlantic Richfield (b)		7			153		—		85		(85	)		—			—
Issue of ordinary share capital for TNK-BP (c)		35			1,215		—		—		—			—			—
Purchase of shares by ESOP trusts		—			—		—		—		—			(147	)		—
Repurchase of ordinary share capital (d)		(207	)		—		207		—		—			—			—
Share-based payments (net of tax) (e)		—			—		—		—		—			168			—
Profit for the year		—			—		—		—		—			—			—
Dividends (f)		—			—		—		—		—			—			—

At December 31, 2004		5,403			5,636		730		27,162		44			(82	)		—

At January 1, 2003		5,616			3,794		449		27,033		173			(159	)		—
Currency translation differences (net of tax)		—			—		—		—		—			(8	)		—
Actuarial gain (loss) (net of tax)		—			—		—		—		—			—			—
Employee share schemes (a)		8			127		—		—		—			—			—
Atlantic Richfield (b)		2			36		—		44		(44	)		—			—
Purchase of shares by ESOP trusts		—			—		—		—		—			(63	)		—
Repurchase of ordinary share capital (d)		(74	)		—		74		—		—			—			—
Share-based payments (net of tax) (e)		—			—		—		—		—			134			—
Increased minority participation		—			—		—		—		—			—			—
Profit for the year		—			—		—		—		—			—			—
Dividends (f)		—			—		—		—		—			—			—

At December 31, 2003		5,552			3,957		523		27,077		129			(96	)		—

F-8

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN BP SHAREHOLDERS’ EQUITY (Continued)


Foreign
currency						Cash
translation			Available-for-sale			flow			Retained			BP shareholders’			Minority			Total
reserve			investments			hedges			earnings (g)			equity			interest			equity

			($ million)
	5,616			—			—			32,383			76,892			1,343			78,235
	—			230			(118	)		(355	)		(243	)		—			(243	)

	5,616			230			(118	)		32,028			76,649			1,343			77,992
	(2,453	)		(35	)		(3	)		—			(2,479	)		(18	)		(2,497	)
	(220	)		—			—			—			(220	)		—			(220	)
	—			—			—			619			619			—			619
	—			—			—			(1	)		455			—			455
	—			—			—			—			79			—			79
	—			—			—			—			1,250			—			1,250
	—			—			—			—			(251	)		—			(251	)
	—			232			—			—			232			—			232
	—			(42	)		—			—			(42	)		—			(42	)
	—			—			—			(750	)		(11,597	)		—			(11,597	)
	—			—			—			231			412			—			412
	—			—			(149	)		—			(149	)		—			(149	)
	—			—			36			—			36			—			36
	—			—			—			22,026			22,026			291			22,317
	—			—			—			(7,359	)		(7,359	)		(827	)		(8,186	)

	2,943			385			(234	)		46,794			79,661			789			80,450

	3,619			—			—			28,378			69,139			1,125			70,264
	2,075			—			—			—			2,068			64			2,132
	(78	)		—			—			—			(78	)		—			(78	)
	—			—			—			203			203			—			203
	—			—			—			94			94			—			94
	—			—			—			—			327			—			327
	—			—			—			—			160			—			160
	—			—			—			—			1,250			—			1,250
	—			—			—			—			(147	)		—			(147	)
	—			—			—			(7,548	)		(7,548	)		—			(7,548	)
	—			—			—			222			390			—			390
	—			—			—			17,075			17,075			187			17,262
	—			—			—			(6,041	)		(6,041	)		(33	)		(6,074	)

	5,616			—			—			32,383			76,892			1,343			78,235

	—			—			—			23,323			60,229			638			60,867
	3,619			—			—			—			3,611			20			3,631
	—			—			—			60			60			—			60
	—			—			—			—			135			—			135
	—			—			—			—			38			—			38
	—			—			—			—			(63	)		—			(63	)
	—			—			—			(1,999	)		(1,999	)		—			(1,999	)
	—			—			—			200			334			—			334
	—			—			—			—			—			317			317
	—			—			—			12,448			12,448			170			12,618
	—			—			—			(5,654	)		(5,654	)		(20	)		(5,674	)

	3,619			—			—			28,378			69,139			1,125			70,264

F-9

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN BP SHAREHOLDERS’ EQUITY (Continued)

Share capital. The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue.

Share premium account. The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.

Capital redemption reserve. The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.

Merger reserve. The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares.

Other reserve. The balance on the other reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares to be issued in the ARCO acquisition on the exercise of ARCO share options.

Own shares. Own shares represent BP shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment arrangements.

Treasury shares. Treasury shares represent BP shares repurchased and available for issue.

Foreign currency translation reserve. The foreign currency translation reserve is used to record exchange differences arising from the translations of the financial statements of foreign operations. It is also used to record the effect of hedging net investments in foreign operations.

Available-for-sale investments. This reserve records the changes in fair value on available-for-sale investments. On disposal, the cumulative changes in fair value are recycled to the income statement.

Cash flow hedges. This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. On maturity, the cumulative gain or loss is recycled to the income statement or balance sheet as appropriate.

Retained earnings. The balance held on this reserve is the accumulated retained profits of the Group.


(a)	Employee share schemes. During the year 68,499,852 ordinary shares (2004 62,224,092 and 2003 32,889,234 ordinary shares) were issued under the BP, Amoco and Burmah Castrol employee share schemes.


(b)	Atlantic Richfield. During the year 13,644,462 ordinary shares (2004 29,288,178 and 2003 9,786,396 ordinary shares) were issued in respect of Atlantic Richfield employee share option schemes.


(c)	Issue of ordinary share capital for TNK-BP. During the year the company issued 108,628,984 ordinary shares (2004 139,095,888 ordinary shares) as the second (2004 first) tranche of deferred consideration for the acquisition of the investment in TNK-BP.

(d)

Repurchase of ordinary share capital. During the year the company purchased 1,059,706,481 ordinary shares (2004 827,240,360 and 2003 298,716,391 ordinary shares) for a total consideration of $11,597 million (2004 $7,548 million and 2003 $1,999 million), of which 76,800,000 were cancelled and 982,906,481 were retained in treasury. All the shares repurchased in 2004 and 2003 were cancelled. At December 31, 2005, 982,624,971 shares of nominal value $246 million were held in treasury. Transaction costs of share repurchases amounted to $63 million (2004 $43 million and 2003 $11 million).

F-10

BP p.l.c. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN BP SHAREHOLDERS’ EQUITY (Concluded)


(e)	See Note 46 —Share-based payments.

(f)	See Note 25 — Dividends.

(g)	See Note 45 — Retained earnings.

The Notes to Financial Statements are an integral part of this Statement.

F-11

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS


Note 1 —	Significant accounting policies


	*Presentation of financial information*

The consolidated financial statements for the year ended December 31, 2005 were authorized on June 30, 2006. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union (IFRS). International Financial Reporting Standards as adopted by the European Union differ in certain respects from International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB). However, the consolidated financial statements for the years presented would be no different had the Group applied International Financial Reporting Standards as issued by the IASB.


	*Basis of preparation*

This is the first year in which the Group has prepared its financial statements under IFRS and the comparative financial information has been restated from UK generally accepted accounting practice (UK GAAP) to comply with IFRS. Reconciliations to IFRS from the previously published UK GAAP primary financial statements are shown in Note 52. The accounting policies that follow set out those policies that apply in preparing the consolidated financial statements for the year ended December 31, 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 December 31 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 intercompany balances and transactions, including unrealized profits arising from intragroup 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

F-12

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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

F-13

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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. Nonmonetary 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. Nonmonetary 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.


	*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 January 1, 2003 is stated at the previous UK GAAP carrying amount.

F-14

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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.


	*Noncurrent assets held for sale*

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

Noncurrent 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.

F-15

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)


	*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 other 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.

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

F-16

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 aunit-of-production 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. Theunit-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

F-17

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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. As explained in Note 52, 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’.

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 asheld-to-maturity 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

F-18

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 which 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.

F-19

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)


	*Inventories*

Inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by thefirst-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*

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

F-20

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 January 1, 2005, such derivative financial instruments are initially recognized at fair value on the date on which a derivative

F-21

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 nonfinancial 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 nonfinancial 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.

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 nonfinancial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the nonfinancial asset or liability.

F-22

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 nonfinancial 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.

F-23

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 postretirement benefits is described below.


	*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.

F-24

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 postretirement 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

F-25

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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:


	—	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.

F-26

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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 (ESOPs), 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, realized and unrealized gains and losses on exchange traded and over-the-counter commodity derivative contracts held for trading purposes 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.

F-27

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 1 —	Significant accounting policies (continued)

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

Note 1 — Significant accounting policies (continued)


	*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.

Impact of new International Financial Reporting Standards

In August 2005, the IASB issued IFRS 7 ‘Financial Instruments – Disclosures’ which is effective for annual periods beginning on or after January 1, 2007, with earlier adoption encouraged. This standard has been adopted by the EU. Upon adoption, the Group will disclose additional information about its financial instruments, their significance and the nature and extent of risks to which they give rise. More specifically, the Group will be required to disclose the fair value of its financial instruments and its risk exposure in greater detail. There will be no effect on reported income or net assets. No decision has been made on whether to early adopt this standard.

Also in August 2005, ‘IAS 1 Amendment — Presentation of Financial Statements: Capital Disclosures’ was issued by the IASB, which requires disclosures of an entity’s objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and the consequences of any non-compliance. This is effective for annual periods beginning on or after January 1, 2007. This standard has been adopted by the EU. There will be no effect on the Group’s reported income or net assets.

‘IAS 21 Amendment — Net Investment in a Foreign Operation’ was issued in December 2005. The amendment clarifies the requirements of IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’ regarding an entity’s investment in foreign operations. This amendment is effective for annual periods beginning on or after January 1, 2006, and was adopted by the European Union (EU) in May 2006. There will be no material impact on the Group’s reported income or net assets as a result of adoption of this amendment.

F-28

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 1 — Significant accounting policies (continued)

In August 2005, the IASB issued amendments to IAS 39 ‘Financial Instruments: Recognition and Measurement’ and IFRS 4 ‘Insurance Contracts regarding Financial Guarantee Contracts’. These amendments require the issuer of financial guarantee contracts to account for them under IAS 39 as opposed to IFRS 4 unless an issuer has previously asserted explicitly that it regards such contracts as insurance contracts and has used accounting applicable to insurance contracts. In these instances the issuer may elect to apply either IAS 39 or IFRS 4. Under the amended IAS 39, a financial guarantee contract is initially recognized at fair value and is subsequently measured at the higher of (a) the amount determined in accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’ and (b) the amount initially recognized, less, when appropriate, cumulative amortization recognized in accordance with IAS 18 “Revenue”. The amendment to IAS 39 is effective for accounting periods beginning on or after 1 January 2006. This standard impacts guarantees given by Group companies in respect of associates and joint ventures as well as in respect of other third parties; these will need to be recorded in the Group’s financial statements at fair value.

Several interpretations have been issued by the International Financial Reporting Interpretations Committee (IFRIC) that will become effective for future financial reporting periods.

F-29

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

It is not anticipated that any of these interpretations will materially affect the Group’s reported income or net assets.

Note 2 — Resegmentation

With effect from January 1, 2005, there have been the following changes to the business segments reported by the Group:


	(a)	The Mardi Gras pipeline system in the Gulf of Mexico has been transferred from Exploration and Production to Refining and Marketing.


	(b)	The aromatics and acetyls operations and the petrochemicals assets that are integrated with our Gelsenkirchen refinery in Germany have been transferred from the former Petrochemicals segment to Refining


and Marketing.


	(c)	The olefins and derivatives operations have been transferred from the former Petrochemicals segment to the Olefins and Derivatives business. The legacy historical results of other petrochemicals assets that had been divested during 2004 and 2003 are included within Other


businesses and corporate.


	(d)	The Grangemouth and Lavéra refineries have been transferred from Refining and Marketing to the Olefins and Derivatives business to maintain existing operating synergies with the co-located olefins and


derivatives operations.


	(e)	A small US operation, the Hobbs fractionator, which supplies petrochemicals feedstock, has been transferred from Gas, Power and Renewables to


the Olefins and Derivatives business.

The Olefins and Derivatives business is reported within Other businesses and corporate. This reorganization was a precursor to seeking to divest the Olefins and Derivatives business. As indicated in Note 5, Discontinued operations, during 2005 we divested Innovene and show its activities as discontinued operations in these accounts. Innovene represented the majority of the Olefins and Derivatives business.

Comparative financial and operating information is shown after resegmentation and the adoption of International Financial Reporting Standards.

Note 3 — Sales and other operating revenues

BP uses commodity derivative financial instruments to manage its exposure to market price risk associated with oil, natural gas NGLs and power and for trading purposes. These contracts include exchange traded commodity derivatives, such as futures and options traded on a recognized Exchange, over-the-counter swaps, forwards and options. Apart from over-the-counter forward contracts, all realized and unrealized gains and losses on these contracts are included in sales and other operating revenues.

F-30

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 3 — Sales and other operating revenues (continued)

The Group’s accounting policy has been to present oil, natural gas, NGL and power over-the-counter forward sale and purchase contracts gross in the income statement. Unrealized gains and losses are included in sales and other operating revenues.

During 2005, a review was undertaken into the presentation of over-the-counter forward contracts and related activity in the context of the final transition to IFRS for the Group’s 2005 year end financial reporting. This review concluded that revenues associated with over-the-counter forward contracts where market mechanisms, similar to exchange traded instruments, have developed for financial net settlement and where frequent buying and selling patterns are present which are not part of the Group’s risk management activities, but are indicative of the intent to generate profits from short term differences in prices, should be presented net.

The impact of this change is to reduce sales and other operating revenues and purchases, but has no effect on reported profit, cash flows and the balance sheet.

This change was originally reported in the UK Annual Report and Accounts for the year ended December 31, 2005. Subsequently the Group identified certain further adjustments to Sales and other operating revenues and Purchases. These further adjustments have been reflected in the consolidated statement of income for each of the three years in the period ending December 31, 2005 included herein. The following table sets out the impact on these line items for all periods presented as originally reported and as restated for the subsequent further adjustments. The information presented below includes the impact of the Innovene operations for all periods presented:


		Year ended December 31,

		2005		2004		2003

		($ million)
Sales and other operating revenues
	As originally reported		261,841		211,155		178,403
	As restated		252,168		203,303		173,615
Purchases
	As originally reported		180,786		143,837		122,055
	As restated		171,113		135,985		117,267

This change is a transition adjustment from UK GAAP to IFRS and should be read in conjunction with Note 52 — First-time adoption of International Financial Reporting Standards.

F-31

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 3 — Sales and other operating revenues (continued)

Sales and other operating revenues


	Year ended December 31, 2004

										Other			Consolidation								Consolidation
	Exploration			Refining			Gas, Power			businesses			adjustment								adjustment			Total
	and			and			and			and			and			Total		Innovene			and			continuing
	Production			Marketing			Renewables			corporate			eliminations			Group		operations			eliminations			operations

	($ million)
By business — as reported in Form 20-F for 2004
Segment revenues		34,700			192,917			83,320			17,994			(43,999	)		284,932		(17,448	)		6,169			273,653
Less: sales between businesses		(24,756	)		(10,632	)		(2,442	)		(6,169	)		43,999			—		6,169			(6,169	)		—

Third party sales		9,944			182,285			80,878			11,825			—			284,932		(11,279	)		—			273,653

By business — as restated
Segment revenues		34,700			170,749			23,859			17,994			(43,999	)		203,303		(17,448	)		6,169			192,024
Less: sales between businesses		(24,756	)		(10,632	)		(2,442	)		(6,169	)		43,999			—		6,169			(6,169	)		—

Third party sales		9,944			160,117			21,417			11,825			—			203,303		(11,279	)		—			192,024


	Year ended December 31, 2003

										Other			Consolidation								Consolidation
	Exploration			Refining			Gas, Power			businesses			adjustment								adjustment			Total
	and			and			and			and			and			Total		Innovene			and			continuing
	Production			Marketing			Renewables			corporate			eliminations			Group		operations			eliminations			operations

	($ million)
By business — as reported in Form 20-F for 2004
Segment revenues		30,621			159,263			65,639			13,978			(36,993	)		232,508		(13,463	)		4,501			223,546
Less: sales between businesses		(22,885	)		(7,644	)		(1,963	)		(4,501	)		36,993			—		4,501			(4,501	)		—

Third party sales		7,736			151,619			63,676			9,477			—			232,508		(8,962	)		—			223,546

By business — as restated
Segment revenues		30,621			143,441			22,568			13,978			(36,993	)		173,615		(13,463	)		4,501			164,653
Less: sales between businesses		(22,885	)		(7,644	)		(1,963	)		(4,501	)		36,993			—		4,501			(4,501	)		—

Third party sales		7,736			135,797			20,605			9,477			—			173,615		(8,962	)		—			164,653

F-32

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 3 — Sales and other operating revenues (continued)


	Year ended December 31, 2004

				Rest of						Rest of
	UK			Europe			USA			World			Total

	($ million)
By geographical area — as reported in Form 20-F for 2004
Segment revenues		81,155			54,570			130,652			67,777			334,154
Less: sales attributable to Innovene operations		(6,067	)		(9,712	)		(4,060	)		(467	)		(20,306	)

Segment revenues from continuing operations		75,088			44,858			126,592			67,310			313,848
Less: sales between areas		(18,846	)		(1,396	)		(1,539	)		(10,188	)		(31,969	)
Less: sales by continuing operations to Innovene		(5,263	)		(896	)		(2,064	)		(3	)		(8,226	)

Third party sales of continuing operations		50,979			42,566			122,989			57,119			273,653

By geographical area — as restated
Segment revenues		59,615			52,540			86,358			48,534			247,047
Less: sales attributable to Innovene operations		(2,365	)		(7,682	)		(4,109	)		(672	)		(14,828	)

Segment revenues from continuing operations		57,250			44,858			82,249			47,862			232,219
Less: sales between areas		(18,846	)		(1,396	)		(1,539	)		(10,188	)		(31,969	)
Less: sales by continuing operations to Innovene		(5,263	)		(896	)		(2,064	)		(3	)		(8,226	)

Third party sales of continuing operations		33,141			42,566			78,646			37,671			192,024


	Year ended December 31, 2003

				Rest of						Rest of
	UK			Europe			USA			World			Total

	($ million)
By geographical area — as reported in Form 20-F for 2004
Segment revenues		54,971			50,703			108,910			52,314			266,898
Less: sales attributable to Innovene operations		(5,719	)		(8,670	)		(3,226	)		(374	)		(17,989	)

Segment revenues from continuing operations		49,252			42,033			105,684			51,940			248,909
Less: sales between areas		(6,953	)		(3,160	)		(714	)		(8,258	)		(19,085	)
Less: sales by continuing operations to Innovene		(3,947	)		(876	)		(1,455	)		—			(6,278	)

Third party sales of continuing operations		38,352			37,997			103,515			43,682			223,546

By geographical area — as restated
Segment revenues		36,253			48,138			79,092			38,316			201,799
Less: sales attributable to Innovene operations		(1,879	)		(6,105	)		(3,265	)		(534	)		(11,783	)

Segment revenues from continuing operations		34,374			42,033			75,827			37,782			190,016
Less: sales between areas		(6,953	)		(3,160	)		(714	)		(8,258	)		(19,085	)
Less: sales by continuing operations to Innovene		(3,947	)		(876	)		(1,455	)		—			(6,278	)

Third party sales of continuing operations		23,474			37,997			73,658			29,524			164,653

F-33

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 3 — Sales and other operating revenues (concluded)


	Purchases

Year ended

December 31, 2004

December 31, 2003

Total

Continuing

Total

Continuing

Group

operations

Group

operations

($ million)

As reported in Form 20-F for 2004

217,614

209,684

176,160

170,083

As restated

135,985

128,055

117,267

111,190

Note 4 — Acquisitions


	*Acquisitions in 2005*

BP made a number of minor acquisitions in 2005 for a total consideration of $84 million. All these business combinations were accounted for using the acquisition method of accounting. No significant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $27 million arose on these acquisitions. There was also additional goodwill on the Solvay acquisition of $59 million (see below).


	*Acquisitions in 2004*


	Year ended December 31, 2004

	Book value on			Fair value
	acquisitions			adjustments			Fair value

	($ million)
Property, plant and equipment		703			760			1,463
Intangible assets		15			—			15
Current assets (excluding cash)		721			—			721
Cash and cash equivalents		36			—			36
Trade and other payables		(329	)		—			(329	)
Deferred tax liabilities		—			(185	)		(185	)
Defined benefit pension plan deficits		(3	)		—			(3	)
Net investment in equity-accounted entities transferred to full consolidation		(547	)		(94	)		(641	)

Net assets acquired		596			481			1,077

Goodwill								328

Consideration								1,405

On November 2, 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. On completion, the two entities, which manufacture and market high-density polyethylene, became wholly owned subsidiaries of BP. The total consideration for the acquisition was $1,391 million, subject to final closing adjustments. There were closing adjustments and selling costs in 2005 amounting to $59 million. These created additional goodwill of $59 million, which was written off. See Note 14 — Impairment of goodwill, for further

F-34

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 4 — Acquisitions (continued)

information. Other minor acquisitions were made for a total consideration of $14 million. All business combinations have been accounted for using the acquisition method of accounting. The fair value of the property, plant and equipment has been estimated by determining the net present value of future cash flows. No significant adjustments were made to the other assets and liabilities acquired. The assets and liabilities acquired as part of the 2004 acquisitions are shown in aggregate in the table above.


	*Acquisitions in 2003*

BP made a number of minor acquisitions in 2003 for a total consideration of $232 million. All these business combinations were accounted for using the acquisition method of accounting. No significant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $5 million arose on these acquisitions.

Note 5 — Discontinued operations

BP announced on October 7, 2005 its intention to sell Innovene, its olefins, derivatives and refining group, to INEOS. The transaction became unconditional on December 9, 2005 on receipt of European Commission clearance and was completed on December 16, 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 included within Other businesses and corporate.

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 year ended December 31, 2005. 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 and on disposal of the discontinued operation. That is, the income and expenses of Innovene are reported separately from the continuing operations of the BP Group. The table below provides further detail of the amount shown on the income statement. The income statements for prior periods have been restated to conform to this style of presentation.

In the cash flow statement, the cash provided by the operating activities of Innovene has been separated from that of the rest of the Group and reported as a single line item.

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. The originally announced transaction value of $9,000 million has been reduced by the value of certain liabilities transferred to INEOS and certain assets retained by BP on closing.

F-35

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 5 — Discontinued operations (concluded)

Financial information for the Innovene operations after Group eliminations is presented below.


		Years ended December 31,

		2005			2004			2003

		($ million)
Total revenues and other income			12,441			11,327			8,986
Expenses			11,709			12,041			9,034

Profit (loss) before interest and taxation			732			(714	)		(48	)
Other finance income (expense)			3			(17	)		(15	)

Profit (loss) before taxation and loss recognized on remeasurement to fair value less costs to sell and on disposal			735			(731	)		(63	)
Loss recognized on remeasurement to fair value less costs to sell and on disposal			(591	)		—			—

Profit (loss) before taxation from Innovene operations			144			(731	)		(63	)
Tax (charge) credit
	On profit (loss) before loss recognized on remeasurement to fair value less costs to sell and on disposal		(306	)		109			—
	On loss recognized on remeasurement to fair value less costs to sell and on disposal		346			—			—

Profit (loss) from Innovene operations			184			(622	)		(63	)

Earnings (loss) per share from Innovene operations — cents
	Basic		0.87			(2.85	)		(0.28	)
	Diluted		0.86			(2.79	)		(0.28	)

The cash flows of Innovene operations are presented below
	Net cash provided by (used in) operating activities		970			(669	)		348
	Net cash used in investing activities		(524	)		(1,731	)		(572	)
	Net cash provided by (used in) financing activities		(446	)		2,400			224

Further information is contained in Note 6 — Disposals.

F-36

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 6 — Disposals


	Years ended December 31,

	2005		2004		2003

	($ million)
Proceeds from the sale of Innovene operations		8,304		—		—
Proceeds from the sale of other businesses		93		725		179

Proceeds from the sale of businesses		8,397		725		179
Proceeds from the sale of property, plant and equipment		2,803		4,236		6,177

		11,200		4,961		6,356

Exploration and Production		1,416		914		4,801
Refining and Marketing		888		1,007		1,050
Gas, Power and Renewables		540		144		67
Other businesses and corporate		8,356		2,896		438

		11,200		4,961		6,356

As part of the strategy to upgrade the quality of its asset portfolio, the Group has an active programme to dispose of non-strategic assets. In the normal course of business in any particular year, the Group may sell interests in exploration and production properties, service stations and pipeline interests as well as non-core businesses.

Cash received during the year from disposals amounted to $11.2 billion (2004 $5.0 billion and 2003 $6.4 billion). The divestment of Innovene contributed $8.3 billion to this total. The major transactions in 2004 that generated over $2.3 billion of proceeds were the sale of the Group’s investments in PetroChina and Sinopec.

For 2003, the major disposals representing over $3.0 billion of the proceeds were the divestment of a further 20% interest in BP Trinidad and Tobago LLC, the sale of 50% of our interest in the In Amenas gas condensate project and 49% of our interest in the In Salah gas development in Algeria, and the sale of the UK North Sea Forties oil field, together with a package of 61 shallow-water assets in the Gulf of Mexico. The principal transactions generating the proceeds for each segment are described below.

Exploration and Production. The Group divested interests in a number of oil and natural gas properties in all three years. During 2005, the major transaction was the sale of the Group’s interest in the Ormen Lange field in Norway. In addition, the Group sold interests in oil and natural gas properties in Venezuela, Canada and the Gulf of Mexico. In 2004, in the US we sold 45% of our interest in King’s Peak in the deepwater Gulf of Mexico to Marubeni Oil & Gas, divested our interest in Swordfish, and additionally, we sold various properties including our interest in the South Pass 60 property in the Gulf of Mexico Shelf. In Canada, BP sold various assets in Alberta to Fairborne Energy. In Indonesia, we disposed of our interest in the Kangean Production Sharing Contract and our participating interest in the Muriah Production Sharing Contract. In 2003, the UK North Sea Forties oil field, together with a package of 61 shallow-water assets in the Gulf of Mexico, were sold to Apache. A 12.5% interest in the Tangguh liquefied natural gas project in Indonesia was sold to CNOOC. Interests in 14 UK Southern North Sea gas fields, together with associated pipelines and onshore processing facilities, including the Bacton terminal, were sold to Perenco. BP sold 50% of its interest in the In Amenas gas condensate project and 49% of its interest in the In Salah gas development in Algeria to Statoil. In January 2003,

F-37

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 6 — Disposals (continued)

Repsol exercised its option to acquire a further 20% interest in BP Trinidad and Tobago LLC. BP’s interest in the company is now 70%. In February 2003, BP called its $420 million Exchangeable Bonds which were exchangeable for Lukoil American Depositary Shares (ADSs). Bondholders converted to ADSs before the redemption date.

Refining and Marketing. The churn of retail assets represents a significant element of the total in all three years. During 2005, the Group sold a number of regional retail networks in the US and in addition its retail network in Malaysia. During 2004, major asset transactions included the sale of the Singapore refinery, the divestment of the European speciality intermediate chemicals business, and the Cushing and other pipeline interests in the US. As a condition of the approval of the acquisition of Veba in 2002, BP was, amongst other things, required to divest approximately 4% of its retail market share in Germany and a significant portion of its Bayernoil refining interests. The sale of 494 retail sites in the northern and northeastern part of Germany to PKN Orlen and the sale of retail and refinery assets in Germany and Central Europe to OMV in 2003 completed the divestments required.

Gas, Power and Renewables. In 2005, the Group sold its interest in the Interconnector pipeline. During 2004, the Group sold its interest in two Canadian natural gas liquids plants.

Other businesses and corporate. 2005 includes the proceeds from the sale of Innovene. The disposal of the Group’s investments in PetroChina and Sinopec were the major transactions in 2004. In addition, the Group sold its US speciality intermediate chemicals and fabrics and fibres businesses. In 2003, the Group sold its 50% interest in Kaltim Prima Coal, an Indonesian company, and completed the divestment of the former Burmah Castrol speciality chemicals business Sericol and Fosroc Mining.

Summarized financial information for the sale of businesses is shown below.


		Years ended December 31,

		2005			2004			2003

		($ million)
The disposals comprise the following
	Noncurrent assets		6,452			1,046			104
	Other current assets		4,779			477			111
	Noncurrent liabilities		(364	)		(44	)		(7	)
	Other current liabilities		(2,488	)		(59	)		(1	)

			8,379			1,420			207
Profit (loss) on sale of businesses			18			(695	)		(28	)

Total consideration and net cash inflow			8,397			725			179


	*Subsequent transactions*

On April 19, 2006, BP announced the sale of its producing properties on the Outer Continental Shelf of the Gulf of Mexico to Apache Corporation for $1.3 billion. The properties are in waters less than 1,200 feet deep and include 18 producing fields (11 which are operated) covering 92 blocks with estimated reserves of 59 million barrels of oil equivalent and average daily production of 27 mboe. Completion of the sale is expected in mid-2006 once regulatory approvals have been received. The assets held for sale at the date of the announcement amounted to $1,160 million and liabilities directly associated with the assets held for sale amounted to $399 million. The gain to be realized on the sale, to be reported in 2006, is expected to be $0.5 billion.

F-38

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 6 — Disposals (concluded)

On June 27, 2006 BP announced its intention to sell its refinery at Coryton, UK. The assets held for sale at the date of the announcement amounted to approximately $1,200 million and liabilities directly associated with the assets held for sale amounted to approximately $600 million.

Note 7 — Segmental analysis

The Group’s primary format for segment reporting is business segments and the secondary format is geographical segments. The risks and returns of the Group’s operations are primarily determined by the nature of the different activities that the Group engages in, rather than the geographical location of these operations. This is reflected by the Group’s organizational structure and the Group’s internal financial reporting systems.

BP has three reportable operating segments: Exploration and Production; Refining and Marketing; and Gas, Power and Renewables. Exploration and Production’s activities include oil and natural gas exploration and field development and production, together with pipeline transportation and natural gas processing. The activities of Refining and Marketing include oil supply and trading as well as refining and petrochemicals manufacturing and marketing. Gas, Power and Renewables activities include marketing and trading of natural gas, natural gas liquids, new market development, liquefied natural gas (LNG) and solar and renewables. The Group is managed on an integrated basis.

Other businesses and corporate comprises Finance, the Group’s aluminum asset, interest income and costs relating to corporate activities and also the portion of O&D not included in the sale of Innovene to INEOS.

The accounting policies of operating segments are the same as those described in Note 1 — Significant accounting policies.

Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenue, segment expense and segment result include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation.

The Group’s geographical segments are based on the location of the Group’s assets. The UK and US are significant countries of activity for the Group; the other geographical segments are determined by geographical location.

Sales to external customers are based on the location of the seller, which in most circumstances is not materially different from the location of the customer. Crude oil and LNG are commodities for which there is an international market and buyers and sellers can be widely separated geographically. The UK segment includes the UK-based international activities of Refining and Marketing.

F-39

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)



											Other			Consolidation									Consolidation
		Exploration			Refining			Gas, Power			businesses			adjustment									adjustment			Total
		and			and			and			and			and			Total			Innovene			and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group			operations			eliminations^(a)			operations

		($ million)
Year ended December 31, 2005
Sales and other operating revenues
Segment revenues			47,210			213,465			25,557			21,295			(55,359	)		252,168			(20,627	)		8,251			239,792
Less: sales between businesses			(32,606	)		(11,407	)		(3,095	)		(8,251	)		55,359			—			8,251			(8,251	)		—

Third party sales			14,604			202,058			22,462			13,044			—			252,168			(12,376	)		—			239,792

Results
Profit (loss) before interest and tax			25,508			6,442			1,104			(523	)		(208	)		32,323			(668	)		527			32,182
Finance costs and other finance expense			—			—			—			—			(758	)		(758	)		(3	)		—			(761	)

Profit (loss) before taxation			25,508			6,442			1,104			(523	)		(966	)		31,565			(671	)		527			31,421
Taxation			—			—			—			—			(9,248	)		(9,248	)		133			(173	)		(9,288	)

Profit (loss) for the year			25,508			6,442			1,104			(523	)		(10,214	)		22,317			(538	)		354			22,133

Includes
	Equity-accounted income		3,238			238			19			34			—			3,529			14			—			3,543

Assets and liabilities as at December 31, 2005
Segment assets			93,479			77,352			28,441			12,756			(5,326	)		206,702
Tax receivable			—			—			—			—			212			212

Total assets			93,479			77,352			28,441			12,756			(5,114	)		206,914

Includes
	Equity-accounted investments		14,657			4,012			483			621			—			19,773
Segment liabilities			(20,387	)		32,227			(23,346	)		(15,358	)		4,548			(86,770	)
Current tax payable			—			—			—			—			(4,274	)		(4,274	)
Finance debt			—			—			—			—			(19,162	)		(19,162	)
Deferred tax liabilities			—			—			—			—			(16,258	)		(16,258	)

Total liabilities			(20,387	)		(32,227	)		(23,346	)		(15,358	)		(35,146	)		(126,464	)

Year ended December 31, 2005
Other segment information
Capital expenditure
	Intangible assets		989			451			31			10			—			1,481
	Property, plant and equipment		8,751			2,036			199			779			—			11,765
	Other		497			285			5			116			—			903

Total			10,237			2,772			235			905			—			14,149

Depreciation, depletion and amortization			6,033			2,392			225			533			—			9,183			(412	)		—			8,771
Impairment			266			93			—			59			—			418			(59	)		—			359
Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations			—			—			—			591			—			591			(591	)		—			—
Losses on sale of businesses and fixed assets			39			64			—			6			—			109			—			—			109
Gains on sale of businesses and fixed assets			1,198			241			55			47			—			1,541			(3	)		—			1,538

F-40

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)



											Other			Consolidation									Consolidation
		Exploration			Refining			Gas, Power			businesses			adjustment									adjustment			Total
		and			and			and			and			and			Total			Innovene			and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group			operations			eliminations^(a)			operations

		($ million)
Year ended December 31, 2004
Sales and other operating revenues
Segment revenues			34,700			170,749			23,859			17,994			(43,999	)		203,303			(17,448	)		6,169			192,024
Less: sales between businesses			(24,756	)		(10,632	)		(2,442	)		(6,169	)		43,999			—			6,169			(6,169	)		—

Third party sales			9,944			160,117			21,417			11,825			—			203,303			(11,279	)		—			192,024

Results
Profit (loss) before interest and tax			18,087			6,544			954			(362	)		(191	)		25,032			526			188			25,746
Finance costs and other finance expense			—			—			—			—			(797	)		(797	)		17			—			(780	)

Profit (loss) before taxation			18,087			6,544			954			(362	)		(988	)		24,235			543			188			24,966
Taxation			—			—			—			—			(6,973	)		(6,973	)		(53	)		(56	)		(7,082	)

Profit (loss) for the year			18,087			6,544			954			(362	)		(7,961	)		17,262			490			132			17,884

Includes
	Equity-accounted income		1,985			259			6			18			—			2,268			12			—			2,280

Assets and liabilities as at December 31, 2004
Segment assets			85,808			73,581			17,257			22,292			(4,467	)		194,471
Tax receivable			—			—			—			—			159			159

Total assets			85,808			73,581			17,257			22,292			(4,308	)		194,630

Includes
	Equity-accounted investments		14,327			4,486			573			656			—			20,042
Segment liabilities			(16,214	)		(28,903	)		(12,384	)		(18,886	)		3,915			(72,472	)
Current tax payable			—			—			—			—			(4,131	)		(4,131	)
Finance debt			—			—			—			—			(23,091	)		(23,091	)
Deferred tax liabilities			—			—			—			—			(16,701	)		(16,701	)

Total liabilities			(16,214	)		(28,903	)		(12,384	)		(18,886	)		(40,008	)		(116,395	)

Year ended December 31, 2004
Other segment information
Capital expenditure
	Intangible assets		406			670			25			5			—			1,106
	Property, plant and equipment		8,696			1,960			328			690			—			11,674
	Other		1,906			189			171			1,605			—			3,871

Total			11,008			2,819			524			2,300			—			16,651

Depreciation, depletion and amortization			5,583			2,540			210			679			—			9,012			(483	)		—			8,529
Impairment			404			195			—			891			—			1,490			(879	)		—			611
Losses on sale of businesses and fixed assets			227			371			—			416			—			1,014			(235	)		—			779
Gains on sale of businesses and fixed assets			162			104			56			1,365			—			1,687			(2	)		—			1,685

F-41

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)



											Other			Consolidation									Consolidation
		Exploration			Refining			Gas, Power			businesses			adjustment									adjustment			Total
		and			and			and			and			and			Total			Innovene			and			continuing
By business		Production			Marketing			Renewables			corporate			eliminations			Group			operations			eliminations^(a)			operations

		($ million)
Year ended December 31, 2003
Sales and other operating revenues
Segment revenues			30,621			143,441			22,568			13,978			(36,993	)		173,615			(13,463	)		4,501			164,653
Less: sales between businesses			(22,885	)		(7,644	)		(1,963	)		(4,501	)		36,993			—			4,501			(4,501	)		—

Third party sales			7,736			135,797			20,605			9,477			—			173,615			(8,962	)		—			164,653

Results
Profit (loss) before interest and tax			15,084			3,235			578			(108	)		(61	)		18,728			(145	)		193			18,776
Finance costs and other finance expense			—			—			—			—			(1,060	)		(1,060	)		15			—			(1,045	)

Profit (loss) before taxation			15,084			3,235			578			(108	)		(1,121	)		17,668			(130	)		193			17,731
Taxation			—			—			—			—			(5,050	)		(5,050	)		54			(54	)		(5,050	)

Profit (loss) for the year			15,084			3,235			578			(108	)		(6,171	)		12,618			(76	)		139			12,681

Includes
	Equity-accounted income		949			241			(5	)		14			—			1,199			15			—			1,214

Assets and liabilities as at December 31, 2003
Segment assets			79,446			67,546			10,859			19,595			(5,047	)		172,399
Tax receivable			—			—			—			—			92			92

Total assets			79,446			67,546			10,859			19,595			(4,955	)		172,491

Includes
	Equity-accounted investments		12,897			3,764			362			754			—			17,777
Segment liabilities			(15,723	)		(27,148	)		(6,584	)		(15,641	)		4,686			(60,410	)
Current tax payable			—			—			—			—			(3,441	)		(3,441	)
Finance debt			—			—			—			—			(22,325	)		(22,325	)
Deferred tax liabilities			—			—			—			—			(16,051	)		(16,051	)

Total liabilities			(15,723	)		(27,148	)		(6,584	)		(15,641	)		(37,131	)		(102,227	)

Year ended December 31, 2003
Other segment information
Capital expenditure
	Intangible assets		566			131			18			—			—			715
	Property, plant and equipment		8,390			2,750			243			266			—			11,649
	Other		6,236			138			178			707			—			7,259

Total			15,192			3,019			439			973			—			19,623

Depreciation, depletion and amortization			5,539			2,198			160			708			—			8,605			(529	)		—			8,076
Impairment			1,013			—			—			—			—			1,013			—			—			1,013
Losses on sale of businesses and fixed assets			403			318			17			50			—			788			—			—			788
Gains on sale of businesses and fixed assets			1,591			104			11			189			—			1,895			—			—			1,895

F-42

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)

(a)

In the circumstances of discontinued operations, International Accounting Standards require that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This adjustment has two offsetting elements: the net margin on crude refined by Innovene as substantially all crude for its refineries is supplied by BP and most of the refined products manufactured are taken by BP; and the margin on sales of feedstock from BP’s US refineries to Innovene’s manufacturing plants. The profits attributable to individual segments are not affected by this adjustment. Neither does this representation indicate the profits earned by continuing or Innovene operations, as if they were standalone entities, for past periods or likely to be earned in future periods.

F-43

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)


														Consolidation
														adjustment
					Rest of						Rest of			and
By geographical area		UK			Europe			USA			World			eliminations			Total

		($ million)
Year ended December 31, 2005
Sales and other operating revenues
Segment revenues			95,375			72,972			101,190			60,314			—			329,851
Less: sales attributable to Innovene operations			(2,610	)		(8,667	)		(4,309	)		(686	)		—			(16,272	)

Segment revenues from continuing operations			92,765			64,305			96,881			59,628			—			313,579
Less: sales between areas			(38,081	)		(5,013	)		(2,362	)		(16,541	)		—			(61,997	)
Less: sales by continuing operations to Innovene			(5,599	)		(4,640	)		(1,508	)		(43	)		—			(11,790	)

Third party sales of continuing operations			49,085			54,652			93,011			43,044			—			239,792

Results
Profit (loss) before interest and tax from continuing operations			1,167			5,206			12,639			13,170			—			32,182
Finance costs and other finance expense			(80	)		(268	)		(366	)		(47	)		—			(761	)

Profit before taxation from continuing operations			1,087			4,938			12,273			13,123			—			31,421
Taxation			(289	)		(1,646	)		(3,798	)		(3,555	)		—			(9,288	)

Profit for the year from continuing operations			798			3,292			8,475			9,568			—			22,133
Profit (loss) from Innovene operations			234			109			(165	)		6			—			184

Profit for the year			1,032			3,401			8,310			9,574			—			22,317

Includes
	Equity-accounted income		(8	)		18			86			3,447			—			3,543

Assets and liabilities as at December 31, 2005
Segment assets			44,007			26,560			79,838			64,129			(7,832	)		206,702
Tax receivable			2			158			6			46			—			212

Total assets			44,009			26,718			79,844			64,175			(7,832	)		206,914

Includes
	Equity-accounted investments		74			1,496			1,420			16,783			—			19,773
Segment liabilities			(25,079	)		(16,824	)		(34,146	)		(18,553	)		7,832			(86,770	)
Current tax payable			(798	)		(1,057	)		(678	)		(1,741	)		—			(4,274	)
Finance debt			(9,706	)		(433	)		(6,159	)		(2,864	)		—			(19,162	)
Deferred tax liabilities			(2,223	)		(936	)		(9,400	)		(3,699	)		—			(16,258	)

Total liabilities			(37,806	)		(19,250	)		(50,383	)		(26,857	)		7,832			(126,464	)

Year ended December 31, 2005
Other segment information
Capital expenditure
	Intangible assets		205			43			579			654			—			1,481
	Property, plant and equipment		1,340			919			4,804			4,702			—			11,765
	Other		53			18			86			746			—			903

Total			1,598			980			5,469			6,102			—			14,149

Depreciation, depletion and amortization			2,080			932			3,685			2,074			—			8,771
Exploration expense			32			2			425			225			—			684
Impairment			53			7			238			61			—			359
Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations			24			273			262			32			—			591
Losses on sale of businesses and fixed assets			—			37			8			64			—			109
Gains on sale of businesses and fixed assets			107			1,017			282			132			—			1,538

F-44

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 7 — Segmental analysis (continued)



															Consolidation
															adjustment
					Rest of						Rest of				and
By geographical area		UK			Europe			USA			World				eliminations			Total

		($ million)
Year ended December 31, 2004
Sales and other operating revenues
Segment revenues			59,615			52,540			86,358			48,534				—			247,047
Less: sales attributable to Innovene operations			(2,365	)		(7,682	)		(4,109	)		(672	)			—			(14,828	)

Segment revenues from continuing operations			57,250			44,858			82,249			47,862				—			232,219
Less: sales between areas			(18,846	)		(1,396	)		(1,539	)		(10,188	)			—			(31,969	)
Less: sales by continuing operations to Innovene			(5,263	)		(896	)		(2,064	)		(3	)			—			(8,226	)

Third party sales of continuing operations			33,141			42,566			78,646			37,671				—			192,024

Results
Profit (loss) before interest and tax from continuing operations			2,875			3,121			9,725			10,025				—			25,746
Finance costs and other finance expense			155			(261	)		(513	)		(161	)			—			(780	)

Profit before taxation from continuing operations			3,030			2,860			9,212			9,864				—			24,966
Taxation			(1,745	)		(779	)		(2,596	)		(1,962	)			—			(7,082	)

Profit for the year from continuing operations			1,285			2,081			6,616			7,902				—			17,884
Profit (loss) from Innovene operations			(327	)		(110	)		(96	)		(89	)			—			(622	)

Profit for the year			958			1,971			6,520			7,813				—			17,262

Includes
	Equity-accounted income		9			17			92			2,162				—			2,280

Assets and liabilities as at December 31, 2004
Segment assets			42,073			31,437			71,272			56,464				(6,775	)		194,471
Tax receivable			—			135			—			24				—			159

Total assets			42,073			31,572			71,272			56,488				(6,775	)		194,630

Includes
	Equity-accounted investments		338			1,951			1,556			16,197				—			20,042
Segment liabilities			(18,031	)		(18,049	)		(27,124	)		(16,043	)			6,775			(72,472	)
Current tax payable			(1,588	)		(712	)		(651	)		(1,180	)			—			(4,131	)
Finance debt			(13,237	)		(455	)		(6,360	)		(3,039	)			—			(23,091	)
Deferred tax liabilities			(3,177	)		(1,242	)		(9,011	)		(3,271	)			—			(16,701	)

Total liabilities			(36,033	)		(20,458	)		(43,146	)		(23,533	)			6,775			(116,395	)

Year ended December 31, 2004
Other segment information
Capital expenditure
	Intangible assets		170			4			404			528				—			1,106
	Property, plant and equipment		1,480			1,079			4,959			4,156				—			11,674
	Other		92			814			642			2,323				—			3,871

Total			1,742			1,897			6,005			7,007		��		—			16,651

Depreciation, depletion and amortization			2,030			930			3,906			1,663				—			8,529
Exploration expense			26			25			361			225				—			637
Impairment			—			—			570			41				—			611
Losses on sale of businesses and fixed assets			282			—			177			320				—			779
Gains on sale of businesses and fixed assets			—			—			133			1,552				—			1,685

F-45

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)



														Consolidation
														adjustment
					Rest of						Rest of			and
By geographical area		UK			Europe			USA			World			eliminations			Total

		($ million)
Year ended December 31, 2003
Sales and other operating revenues
Segment revenues			36,253			48,138			79,092			38,316			—			201,799
Less: sales attributable to Innovene operations			(1,879	)		(6,105	)		(3,265	)		(534	)		—			(11,783	)

Segment revenues from continuing operations			34,374			42,033			75,827			37,782			—			190,016
Less: sales between areas			(6,953	)		(3,160	)		(714	)		(8,258	)		—			(19,085	)
Less: sales by continuing operations to Innovene			(3,947	)		(876	)		(1,455	)		—			—			(6,278	)

Third party sales of continuing operations			23,474			37,997			73,658			29,524			—			164,653

Results
Profit (loss) before interest and tax from continuing operations			3,348			1,819			7,008			6,601			—			18,776
Finance costs and other finance expense			52			(258	)		(737	)		(102	)		—			(1,045	)

Profit before taxation from continuing operations			3,400			1,561			6,271			6,499			—			17,731
Taxation			(1,287	)		(725	)		(1,548	)		(1,490	)		—			(5,050	)

Profit for the year from continuing operations			2,113			836			4,723			5,009			—			12,681
Profit (loss) from Innovene operations			(150	)		166			(83	)		4			—			(63	)

Profit for the year			1,963			1,002			4,640			5,013			—			12,618

Includes
	Equity-accounted income		11			39			99			1,065			—			1,214

Assets and liabilities as at December 31, 2003
Segment assets			36,282			27,155			64,414			48,835			(4,287	)		172,399
Tax receivable			—			84			—			8			—			92

Total assets			36,282			27,239			64,414			48,843			(4,287	)		172,491

Includes
	Equity-accounted investments		188			2,052			2,146			13,391						17,777
Segment liabilities			(15,569	)		(16,162	)		(20,060	)		(12,906	)		4,287			(60,410	)
Current tax payable			(1,057	)		(522	)		(494	)		(1,368	)		—			(3,441	)
Finance debt			(11,804	)		(393	)		(7,295	)		(2,833	)		—			(22,325	)
Deferred tax liabilities			(2,973	)		(1,017	)		(8,636	)		(3,425	)		—			(16,051	)

Total liabilities			(31,403	)		(18,094	)		(36,485	)		(20,532	)		4,287			(102,227	)

Year ended December 31, 2003
Other segment information
Capital expenditure
	Intangible assets		1			77			289			348			—			715
	Property, plant and equipment		1,528			1,157			5,302			3,662			—			11,649
	Other		—			12			376			6,871			—			7,259

Total			1,529			1,246			5,967			10,881			—			19,623

Depreciation, depletion and amortization			1,952			819			3,937			1,368			—			8,076
Exploration expense			17			37			204			284			—			542
Impairment			183			—			343			487			—			1,013
Losses on sale of businesses and fixed assets			213			410			72			93			—			788
Gains on sale of businesses and fixed assets			931			259			—			705			—			1,895

F-46

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 8 — Earnings from jointly controlled entities and associates



		Profit (loss)
		before interest									Minority		Profit (loss)
		and tax			Interest			Tax			interest		for the year

		($million)
Year ended December 31, 2005
By business
	Exploration and Production		4,819			227			1,250			104		3,238
	Refining and Marketing		343			24			81			—		238
	Gas, Power and Renewables		34			7			8			—		19
	Other businesses and corporate		65			31			—			—		34

			5,261			289			1,339			104		3,529
Innovene operations			14			—			—			—		14

Continuing operations			5,275			289			1,339			104		3,543

Earnings from jointly controlled entities			4,615			232			1,196			104		3,083
Earnings from associates			660			57			143			—		460

			5,275			289			1,339			104		3,543

Year ended December 31, 2004
By business
	Exploration and Production		3,246			189			1,029			43		1,985
	Refining and Marketing		357			15			83			—		259
	Gas, Power and Renewables		15			7			2			—		6
	Other businesses and corporate		21			7			(4	)		—		18

			3,639			218			1,110			43		2,268
Innovene operations			9			(3	)		—			—		12

Continuing operations			3,648			215			1,110			43		2,280

Earnings from jointly controlled entities			3,017			167			989			43		1,818
Earnings from associates			631			48			121			—		462

			3,648			215			1,110			43		2,280

Year ended December 31, 2003
By business
	Exploration and Production		1,222			120			153			—		949
	Refining and Marketing		275			17			17			—		241
	Gas, Power and Renewables		(3	)		2			—			—		(5	)
	Other businesses and corporate		29			5			10			—		14

			1,523			144			180			—		1,199
Innovene operations			15			—			—			—		15

Continuing operations			1,538			144			180			—		1,214

Earnings from jointly controlled entities			1,028			102			100			—		826
Earnings from associates			510			42			80			—		388

			1,538			144			180			—		1,214

F-47

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 9 — Interest and other revenues


	Years ended
	December 31,

	2005			2004			2003

	($ million)
Dividends		52			37			36
Interest from loans and other investments		73			34			121
Other interest		324			244			184
Miscellaneous income		240			358			444

		689			673			785
Innovene operations		(76	)		(58	)		(39	)

Continuing operations		613			615			746

Note 10 — Gains on sale of businesses and fixed assets


		Years ended
		December 31,

		2005			2004			2003

		($ million)
Gains on sale of businesses
	Refining and Marketing		18			—			—

			18			—			—

Gains on sale of fixed assets
	Exploration and Production		1,198			162			1,591
	Refining and Marketing		223			104			104
	Gas, Power and Renewables		55			56			11
	Other businesses and corporate		47			1,365			189

			1,523			1,687			1,895

			1,541			1,687			1,895
Innovene operations			(3	)		(2	)		—

Continuing operations			1,538			1,685			1,895

The principal transactions giving rise to these gains for each segment are described below.


	*Gains on sale of fixed assets*

Exploration and Production. The Group divested interests in a number of oil and natural gas properties in all three years. The major divestment during 2005 was the sale of the Group’s interest in the Ormen Lange field in Norway. BP also sold various oil and gas properties in Trinidad & Tobago, Canada and the Gulf of Mexico. For 2004, divestments included interests in oil and natural gas properties in Australia, Canada and the Gulf of Mexico. In 2003, transactions included the divestment of a further 20% interest in BP Trinidad and Tobago LLC to Repsol, the sale of the Group’s 96.14% interest in the Forties oil field in the UK North Sea, the sale of a package of UK Southern North Sea gas fields and the divestment of our interest in the In Amenas gas condensate project in Algeria to Statoil.

F-48

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 10 — Gains on sale of businesses and fixed assets (concluded)

Refining and Marketing. During 2005, the Group divested a number of regional retail networks in the US. For 2004, divestments included the sale of the Cushing and other pipeline interests in the US and the churn of retail assets. In 2003, disposals included the sale of pipeline interests in the US.

Gas, Power and Renewables. In 2005, transactions included the disposal of the Group’s interest in the Interconnector pipeline. During 2004, the Group divested its interest in two natural gas liquids plants in Canada.

Other businesses and corporate. For 2004, the major disposals were the divestment of the Group’s investments in PetroChina and Sinopec. In 2003, the Group sold its 50% interest in Kaltim Prima Coal, an Indonesian company, its interest in AG International Chemical Company, a purified isophthalic acid associate in Japan, and certain other investments.

Additional information on the sale of businesses and fixed assets is given in Note 6 — Disposals.

Note 11 — Production and similar taxes


	Years ended December 31,

	2005		2004		2003

	($ million)
UK		495		335		300
Overseas		2,515		1,814		1,423

Continuing operations		3,010		2,149		1,723

F-49

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 12 — Depreciation, depletion and amortization


		Years ended December 31,

		2005		2004		2003

		($ million)
By business
Exploration and Production
	UK		1,663		1,642		1,612
	Rest of Europe		228		184		168
	USA		2,426		2,407		2,627
	Rest of World		1,716		1,350		1,132

			6,033		5,583		5,539

Refining and Marketing
	UK (a)		316		318		252
	Rest of Europe		687		645		606
	USA		1,092		1,246		1,063
	Rest of World		297		331		277

			2,392		2,540		2,198

Gas, Power and Renewables
	UK		47		37		34
	Rest of Europe		20		24		22
	USA		99		80		69
	Rest of World		59		69		35

			225		210		160

Other businesses and corporate
	UK		203		251		294
	Rest of Europe		130		204		166
	USA		187		199		205
	Rest of World		13		25		43

			533		679		708

By geographical area
UK (a)			2,229		2,248		2,192
Rest of Europe			1,065		1,057		962
USA			3,804		3,932		3,964
Rest of World			2,085		1,775		1,487

			9,183		9,012		8,605
Innovene operations			(412)		(483)		(529)

Continuing operations			8,771		8,529		8,076


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

F-50

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 13 — Impairment and losses on sale of businesses and fixed assets


		Years ended December 31,

		2005		2004		2003

		($ million)
Impairment
	Exploration and Production		266		404		1,013
	Refining and Marketing		93		195		—
	Other businesses and corporate		59		891		—

			418		1,490		1,013

Loss on sale of businesses or termination of operations Refining and Marketing			—		279		28
	Other businesses and corporate		—		416		—

			—		695		28

Loss on sale of fixed assets
	Exploration and Production		39		227		403
	Refining and Marketing		64		92		290
	Gas, Power and Renewables		—		—		17
	Other businesses and corporate		6		—		50

			109		319		760
Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations			591		—		—

			1,118		2,504		1,801
Innovene operations			(650)		(1,114)		—

Continuing operations			468		1,390		1,801


	*Impairment*

In assessing whether a write-down is required in the carrying value of a potentially impaired asset, its carrying value is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of the Group’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment charges described below is value in use. The Group generally estimates value in use using a discounted cash flow model. The future cash flows are usually adjusted for risks specific to the asset and discounted using a pre-tax discount rate of 10% (2004 9% and 2003 9%). This discount rate is derived from the Group’s post-tax weighted average cost of capital. A different pre-tax discount rate is used where the local tax rate is significantly different from the UK or US corporate tax rates.

Exploration and Production. During 2005, Exploration and Production recognized total charges of $266 million for impairment in respect of producing oil and gas properties. The major element of this was a charge of $226 million relating to fields in the Shelf and Coastal areas of the Gulf of Mexico. The triggers for the impairment tests were primarily the effect of Hurricane Rita, which extensively damaged certain offshore and onshore production facilities, leading to repair costs and higher estimates of the eventual cost of decommissioning the production facilities and, in addition, reduced estimates of

F-51

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 13 — Impairment and losses on sale of businesses and fixed assets (continued)

the quantities of hydrocarbons recoverable from some of these fields. The recoverable amount was based on management’s estimate of fair value less costs to sell consistent with recent transactions in the area. The remainder related to fields in the UK North Sea, which were tested for impairment following a review of the economic performance of these assets. During 2004, as a result of impairment triggers, reviews were conducted that have resulted in impairment charges of $83 million in respect of King’s Peak in the Gulf of Mexico, $20 million in respect of two fields in the Gulf of Mexico Shelf Matagorda Island area and $184 million in respect of various US onshore fields. A charge of $88 million was reflected in respect of a gas processing plant in the US and a charge of $60 million following the blow-out of the Temsah platform in Egypt. In addition, following the lapse of the sale agreement for oil and gas properties in Venezuela, $31 million of the previously booked impairment charge was released. The 2003 charge for impairment includes a charge of $296 million for four fields in the Gulf of Mexico, following technical reassessment and re-evaluation of future investment options; charges of $133 million and $49 million respectively for the Miller and Viscount fields in the UK North Sea as a result of a decision not to proceed with waterflood and gas import options and a reserve write-down respectively; a charge of $105 million for the Yacheng field in China; a charge of $108 million for the Kepadong field in Indonesia; and $47 million for the Eugene Island/ West Cameron fields in the US as a result of reserve write-downs following completion of our routine full technical reviews. In addition, there were impairment charges of $217 million and $58 million for oil and gas properties in Venezuela and Canada respectively, based on fair value less costs to sell for transactions expected to complete in early 2004.

Refining and Marketing. During 2005, certain retail assets were written down to fair value less costs to sell. With the formation of Olefins and Derivatives at the end of 2004, certain agreements and assets were restructured to reflect the arm’s-length relationship that would exist in the future. This has resulted in an impairment of the petrochemicals facilities at Hull, UK.

Other businesses and corporate. The impairment charge for 2005 relates to the write-off of additional goodwill on the Solvay transactions. In 2004, in connection with the Solvay transactions, the Group recognized impairment charges of $325 million for goodwill and $270 million for property, plant and equipment in BP Solvay Polyethylene Europe. As part of a restructuring of the North American Olefins and Derivatives businesses, decisions were taken to exit certain businesses and facilities, resulting in impairments and write-downs of $294 million.


	*Loss on sale of businesses or termination of operations*

The principal transactions that give rise to these losses for each segment are described below.

Refining and Marketing. In 2004, activities included the closure of two manufacturing plants at Hull, UK, which produced acids; the sale of the European speciality intermediate chemicals business; and the closure of the lubricants operation of the Coryton refinery in the UK and of refining operations at the ATAS refinery in Mersin, Turkey. For 2003, divestments included the sale of the Group’s European oil speciality products business.

Other businesses and corporate. For 2004, activities included the sale of the US speciality intermediate chemicals business; the sale of the fabrics and fibres business; and the closure of the linear alpha-olefins production facility at Pasadena, Texas.

F-52

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 13 — Impairment and losses on sale of businesses and fixed assets (concluded)


	*Loss on sale of fixed assets*

The principal transactions that give rise to these losses for each segment are described below.

Exploration and Production. The Group divested interests in a number of oil and natural gas properties in all three years. For 2004, this included interests in oil and natural gas properties in Indonesia and the Gulf of Mexico. In 2003, this included losses on exploration and production properties in China, Norway and the US.

Refining and Marketing. For 2004, the principal transactions contributing to the loss were divestment of the Singapore refinery and retail churn. For 2003, loss arose from retail churn and the sale of refinery and retail interests in Germany and central Europe.

Note 14 — Impairment of goodwill


	December 31,

	2005		2004		2003

	($ million)
Exploration and Production		4,371		4,371		4,371
Refining and Marketing		5,955		6,418		6,151
Gas, Power and Renewables		45		43		49
Other businesses and corporate		—		25		21

Goodwill as at December 31		10,371		10,857		10,592

Goodwill acquired through business combinations has been allocated first to segments and then down to the next level of cash-generating unit that is expected to benefit from the synergies of the acquisition. For Exploration and Production, goodwill has been allocated to each geographic region, that is UK, Rest of Europe, US and Rest of World, and for Refining and Marketing, goodwill has been allocated to strategic performance units (SPUs), namely Refining, Retail, Lubricants, Aromatics and Acetyls and Business Marketing.

In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (including goodwill) is compared with the recoverable amount of the cash-generating unit. The recoverable amount is the higher of fair value less costs to sell and value in use. In the absence of any information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in use.

The Group generally estimates value in use using a discounted cash flow model. The future cash flows are usually adjusted for risks specific to the asset and discounted using a pre-tax discount rate of 10% (2004 9% and 2003 9%). This discount rate is derived from the Group’s post-tax weighted average cost of capital. A different pre-tax discount rate is used where the local tax rate is significantly different from the UK or US corporate tax rates.

The five-year Group plan, which is approved on an annual basis by senior management, is the source for information for the determination of the various values in use. It contains implicit forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step to the preparation of this plan, various environmental assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior management. These

F-53

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 14 — Impairment of goodwill (continued)

environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability.

For the purposes of impairment testing, the Group’s oil price assumption is for the Brent oil price to drop from an average 2005 price of $55 per barrel in equal annual steps over the next three years to $25 per barrel in 2009 and to remain flat thereafter (2004 $38 per barrel stepping down to $20 per barrel in 2008 and beyond and 2003 $29 per barrel stepping down to $20 per barrel in 2007 and beyond). Similarly, Henry Hub natural gas prices drop from an average $8.65 per mmBtu in 2005 to $4.00 per mmBtu in 2009 and beyond (2004 $6.15 per mmBtu stepping down to $3.50 per mmBtu in 2008 and beyond and 2003 $5.35 per mmBtu stepping down to $3.50 per mmBtu in 2007 and beyond). These prices are adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas.


	*Exploration and Production*

The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field. The date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, the production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic models and key assumptions agreed by BP’s management for the purpose. Cash outflows and hydrocarbon production quantities for the first five years are agreed as part of the annual planning process. Thereafter, estimated production quantities and cash outflows up to the date of cessation of production are developed to be consistent with this.

The following table shows the carrying value of the goodwill allocated to each of the regions of the Exploration and Production segment and the amount by which the recoverable amount (value in use) exceeds the carrying amount of the goodwill and other noncurrent assets in the cash-generating units to which the goodwill has been allocated. No impairment charge is required.


			Rest of				Rest of
	UK		Europe		USA		World		Total

	($ million)
At December 31, 2005
Goodwill		341		—		3,515		515		4,371
Excess of recoverable amount over carrying amount		3,205		n/a		6,421		28,088		—

At December 31, 2004
Goodwill		341		—		3,515		515		4,371
Excess of recoverable amount over carrying amount		2,045		n/a		3,332		14,094		—

At December 31, 2003
Goodwill		341		—		3,515		515		4,371
Excess of recoverable amount over carrying amount		3,466		n/a		4,734		15,119		—

F-54

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 14 — Impairment of goodwill (continued)

The key assumptions required for the value in use estimation are the oil and natural gas prices, production volumes and the discount rate. To test the sensitivity of the excess of the recoverable amount over the carrying amount of goodwill and other noncurrent assets shown above (the headroom) to changes in production volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for these two key assumptions. Applying these gives an indication of the impact on the headroom of possible changes in the key assumptions.

On the basis of the rules of thumb using estimated 2006 production profiles extrapolated over an average 15-year production life, it is estimated that a long-term decrease of $1 per barrel in the price of Brent crude or $0.1 per mmBtu of Henry Hub gas with corresponding adjustments to other prices would cause the above excess of recoverable amount over carrying amount to be reduced by $3.3 billion in respect of oil production and $0.6 billion for gas production. Consequently, it is estimated that the long-term price of Brent crude that would cause the total recoverable amount to be equal to the total carrying amount of the goodwill and related noncurrent assets for individual cash-generating units would be of the order of $25 per barrel for the UK and $26 per barrel for the US. No reasonably possible change in oil or gas prices would cause the headroom in Rest of World to be reduced to zero.

Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by management as part of the long-term planning process. It is estimated that, if all our production were to be reduced by 10% for the whole of the next 15 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the individual cash-generating units to zero. Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amount of goodwill and other noncurrent assets to exceed their recoverable amount.


	*Refining and Marketing*

For all cash-generating units, the cash flows for the next five years are derived from the five-year Group plan. The cost inflation rate is assumed to be 2.5% (2004 2.5% and 2003 2.5%) throughout the period. For determining the value in use for each of the SPUs, cash flows for a period of 10 years have been discounted and aggregated with its terminal value.

Refining. Cash flows beyond the five-year period are extrapolated using a 2% growth rate (2004 4% and 2003 2%).

The key assumptions to which the calculation of value in use for the Refining unit is most sensitive are gross margins, production volumes and the terminal value. The value assigned to the gross margin is based on $5.25 per barrel global indicator margin (GIM), which is then adjusted for specific refinery configurations (2004 $2.70 per barrel and 2003 $2.70 per barrel), except in the first year of the plan period when a GIM of $7.25 is used, reflecting market conditions expected in the near term. The value assigned to the production volume is 900mmbbl a year (2004 900mmbbl and 2003 1,100mmbbl) and remains constant over the plan period. The value assigned to the terminal value assumption is 5 times earnings (2004 5 times and 2003 5 times), which is indicative of similar assets in the current market. These key assumptions reflect past experience and are consistent with external sources.

The Refining unit’s recoverable amount exceeds its carrying amount by $13.6 billion. Based on sensitivity analysis, it is estimated that if the GIM changes by $1 per barrel, the Refining unit’s value in use changes by $7.7 billion and, if there is an adverse change in the GIM of $1.75 per barrel, the

F-55

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 14 — Impairment of goodwill (continued)

recoverable amount of the Refining unit would equal its carrying amount. If the volume assumption changes by 5% the Refining unit’s value in use changes by $3.1 billion and if there is an adverse change in Refining volumes of 200mmbbl a year, the recoverable amount of the Refining unit would equal its carrying amount. If the multiple of earnings used in the terminal value changes by 1 then the Refining unit’s value in use changes by $1.7 billion. Management believes no reasonably possible change in the multiple of earnings used in the terminal value would lead to the Refining value in use being equal to its carrying amount.

Retail.The cash flows beyond the five-year period assume no growth in fuel margins (2004 1% decline and 2003 no growth), reflecting a competitive marketplace.

The key assumptions to which the calculation of value in use for the Retail unit is most sensitive are unit gross margins, branded marketing volumes, the terminal value and discount rate. The value assigned to the unit gross margin varies between markets. For the purpose of planning, each market develops a gross margin based on a market-specific reference price adjusted for the different income streams within the market and other market specific factors. The weighted average Retail reference margin used in the plan was 5.4 cents per litre (2004 4.6 cents per litre and 2003 4.3 cents per litre). The value assigned to the branded marketing volume assumption is 101 billion litres a year (2004 106 billion litres a year and 2003 107 billion litres a year). The unit gross margin assumptions decline on average by 0.8% a year over the plan period and marketing volume assumptions grow by an average of 2% a year over the plan period. The value assigned to the terminal value assumption is 6.5 times earnings (2004 6.5 times and 2003 6.5 times), which is indicative of similar assets in the current market. These key assumptions reflect past experience and are consistent with external sources.

The Retail unit’s recoverable amount exceeds its carrying amount by $1.5 billion. It is estimated that, if there is an adverse change in the unit gross margin of 7.5%, the recoverable amount of the Retail unit would equal its carrying amount. It is estimated that, if the volume assumption changes by 5%, the Retail unit’s value in use changes by $1 billion and, if there is an adverse change in Retail volumes of 8 billion litres a year, the recoverable amount of the Retail unit would equal its carrying amount. If the multiple of earnings used in the terminal value changes by 1 then the Retail unit’s value in use changes by $0.5 billion and, if the multiple of earnings falls to 3 times, then the Retail value in use would equal its carrying amount. A change of 1% in the discount rate would change the Retail value in use by $0.7 billion and, if the discount rate increases to 12%, the value in use of the Retail unit would equal its carrying amount.

Lubricants. Cash flows beyond the five-year period are extrapolated using a 3% sales volume growth rate (2004 3% and 2003 3%), which is lower than the long-term average growth rate for the first five years. The terminal value for the Lubricants unit represents cash flows discounted to perpetuity. For the Lubricants unit, the key assumptions to which the calculation of value in use is most sensitive are operating margin, sales volumes and the discount rate. The values assigned to the operating margin and sales volumes are 49 cents per litre (2004 51 cents per litre and 2003 55 cents per litre) and 3.3 billion litres a year (2004 3.3 billion litres and 2003 3.4 billion litres). These key assumptions reflect past experience.

The Lubricants unit’s recoverable amount exceeds its carrying amount by $4.0 billion. If there is an adverse change in the operating gross margin of 10 cents per litre, the recoverable amount of the Lubricants unit would equal its carrying amount. If the sales volume assumption changes by 5%, the Lubricants unit’s value in use changes by $1.1 billion and, if there is an adverse change in Lubricants sales volumes of 600 million litres, the recoverable amount of the Lubricants unit would equal its

F-56

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 14 — Impairment of goodwill (concluded)

carrying amount. A change of 1% in the discount rate would change the Lubricants unit’s value in use by $0.7 billion and, if the discount rate increases to 17%, the value in use of the Lubricants unit would equal its carrying amount.


	Refining		Retail		Lubricants		Other		Total

	($ million)
At December 31, 2005
Goodwill		1,388		832		3,612		123		5,955
Excess of recoverable amount over carrying amount		13,593		1,511		3,953		n/a		—

At December 31, 2004
Goodwill		1,404		878		4,008		128		6,418
Excess of recoverable amount over carrying amount		13,250		4,111		4,082		n/a		—

At December 31, 2003
Goodwill		1,398		907		3,703		143		6,151
Excess of recoverable amount over carrying amount		12,728		3,083		3,685		n/a		—


	*Other businesses and corporate*

In November 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. The total consideration for the acquisition was $1,391 million. See Note 4 — Acquisitions, for more information.

The methodology to determine the option exercise price was laid out in the original agreement creating the polyethylene joint venture. Management believed that this price was high compared with the likely recoverable amount for the businesses and conducted an impairment test.

The cash flows for the next five years were derived from the five-year Group plan. Cost inflation rate was assumed to be 2% throughout the period. For determining the value in use for each of the businesses, a period of 20 years was used, with a terminal value based on the value of working capital releases. Cash flows beyond the five-year period were extrapolated based on the final year of the five-year Group plan using unchanged margin and volume assumptions for the subsequent years.

The key assumptions to which the calculations of value in use were most sensitive were variable contribution margin, production volumes and discount rate. The values assigned to the variable contribution margin were rising across the plan period from $175 to $179 per tonne for Europe and $153 to $194 per tonne for US and annual sales volumes were also rising in the plan period from 1,065,000 tonnes to 1,273,000 tonnes in Europe and from 882,000 tonnes to 907,000 tonnes in the US. These key assumptions reflected past experience and were consistent with external sources.

The recoverable amount of the European business was $631 million lower than the acquisition fair values. This impairment was first applied to the goodwill amount of $325 million and the balance recognized against the carrying value of property, plant and equipment. The recoverable amount of the US business exceeded its carrying amount by $289 million. There were additional selling costs and closing adjustments of $59 million in 2005, which created additional goodwill of $59 million. This was impaired in 2005.

F-57

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 15 — Distribution and administration expenses


	Years ended December 31,

	2005			2004			2003

	($ million)
Distribution		13,187			12,325			11,570
Administration		1,325			1,284			1,384

		14,512			13,609			12,954
Innovene operations		(806	)		(841	)		(684	)

Continuing operations		13,706			12,768			12,270

Note 16 — Currency exchange gains and losses


	Years ended
	December 31,

	2005			2004			2003

	($ million)
Currency exchange (gains) and losses charged (credited) to income		94			55			(129	)
Innovene operations		(80	)		(13	)		(3	)

Continuing operations		14			42			(132	)

Note 17 — Research


	Years ended
	December 31,

	2005			2004			2003

	($ million)
Expenditure on research		502			439			349
Innovene operations		(128	)		(139	)		(115	)

Continuing operations		374			300			234

Note 18 — Operating leases


	Years ended
	December 31,

	2005			2004			2003

	($ million)
Minimum lease payments		1,841			1,840			1,447
Sub-lease rentals		(110	)		(109	)		(128	)

		1,731			1,731			1,319
Innovene operations		(49	)		(89	)		(68	)

Continuing operations		1,682			1,642			1,251

F-58

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 18 — Operating leases (concluded)

The minimum future lease payments excluding executory costs (before deducting related rental income from operating sub-leases of $718 million) were as follows:


		At December 31,

		2005		2004		2003

		($ million)
Payable within
	1 year		1,643		1,534		1,369
	2 to 5 years		4,666		3,778		3,783
	Thereafter		4,579		3,275		3,572

			10,888		8,587		8,724

The Group has entered into operating leases on ships, plant and machinery, commercial vehicles, land and buildings, including service station sites and office accommodation. The ship leases represent approximately 52% of the minimum future lease payments. The typical durations of the leases are as follows:


	Years

Ships		Up to 25
Plant and machinery		Up to 10
Commercial vehicles		Up to 15
Land and buildings		Up to 40

Generally these leases have no renewal options. There are no financial restrictions placed upon the lessee by entering into these leases. The Group also routinely enters into time charters and spot charters for ships on standard industry terms.

The following information is presented in compliance with the requirements of US GAAP.

The minimum future lease payments including executory costs of $439 million (after deducting related rental income from operating sub-leases of $718 million) were as follows:


	At December 31,
	2005

	($ million)
2006		1,569
2007		1,473
2008		1,069
2009		1,009
2010		953
Thereafter		4,536

		10,609

F-59

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 19 — Exploration for and evaluation of oil and natural gas resources

The following financial information represents the amounts included within the corresponding group and Exploration and Production segment totals for the exploration for and evaluation of oil and natural gas resources activity.


		Years ended December 31,

		2005		2004		2003

		($ million)
Exploration and evaluation costs
	Exploration expenditure written off		305		274		297
	Other exploration costs		379		363		245

Exploration expense for the year			684		637		542

Intangible assets			4,008		3,761		4,236

Net assets			4,008		3,761		4,236

Capital expenditure			950		754		579

Net cash used in operating activities			379		363		245
Net cash used in investing activities			950		754		579

Note 20 — Auditors’ remuneration


			Years ended December 31,

			2005						2004						2003

			UK			Total			UK			Total			UK			Total

			($ million)
Audit fees — Ernst & Young
	Group audit			25			47			13			27			8			18
	Audit-related regulatory reporting			3			6			4			7			2			5
	Statutory audit of subsidiaries			7			23			4			16			3			13

				35			76			21			50			13			36
Innovene operations				(8	)		(8	)		(2	)		(2	)		(2	)		(2	)

Continuing operations				27			68			19			48			11			34

Fees for other services — Ernst & Young
	Further assurance services
		Acquisition and disposal due diligence		2			2			6			7			9			9
		Pension scheme audits		—			1			—			1			—			1
		Other further assurance services		6			7			6			9			5			9
	Tax services
		Compliance services		5			10			3			13			3			17
		Advisory services		—			—			—			1			—			2

				13			20			15			31			17			38
Innovene operations				—			(1	)		—			(1	)		—			—

Continuing operations				13			19			15			30			17			38

F-60

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 20 — Auditors’ remuneration (concluded)

Audit fees for 2005 include $4 million of additional fees for 2004. Audit fees are included in the income statement within distribution and administration expenses.

The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young relative to that of other potential service providers. These services are for a fixed term.

Fees paid to major firms of accountants other than Ernst & Young for other services amount to $151 million (2004 $82 million and 2003 $44 million).

Note 21 — Finance costs


	Years ended December 31,

	2005			2004			2003

	($ million)
Bank loans and overdrafts		44			34			38
Other loans		828			573			600
Finance leases		38			37			34

Interest payable		910			644			672
Capitalized at 4.25% (2004 3% and 2003 3%) (a)		(351	)		(204	)		(190	)
Early redemption of borrowings and finance leases		57			—			31

Continuing operations		616			440			513


(a)	Tax relief on capitalized interest is $123 million (2004 $73 million and 2003 $68 million).

F-61

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 22 — Other finance expense


	Years ended December 31,

	2005			2004			2003

	($ million)
Interest on pension and other postretirement benefit plan liabilities		2,022			2,012			1,840
Expected return on pension and other postretirement benefit plan assets		(2,138	)		(1,983	)		(1,500	)

Interest net of expected return on plan assets		(116	)		29			340
Unwinding of discount on provisions		201			196			173
Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP		57			91			34
Change in discount rate for provisions (a)		—			41			—

		142			357			547
Innovene operations		3			(17	)		(15	)

Continuing operations		145			340			532


(a)	Revaluation of environmental and litigation and other provisions at a different discount rate.

Note 23 — Taxation


	*Tax on profit*


		Years ended December 31,

		2005			2004			2003

		($ million)
Current tax
	Charge for the year		10,511			7,217			5,061
	Adjustment in respect of prior years		(977	)		(308	)		(392	)

			9,534			6,909			4,669
Innovene operations			(910	)		(48	)		54

Continuing operations			8,624			6,861			4,723

Deferred tax
	Origination and reversal of temporary differences in the current year		164			138			448
	Adjustment in respect of prior years		(450	)		(74	)		(67	)

			(286	)		64			381
Innovene operations			950			157			(54	)

Continuing operations			664			221			327

Tax on profit from continuing operations			9,288			7,082			5,050

F-62

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (continued)

Tax on profit from continuing operations may be analysed as follows:


		Years ended December 31,

		2005			2004			2003

		($ million)
Current tax charge
	UK		880			1,839			1,142
	Overseas		7,744			5,022			3,581

			8,624			6,861			4,723

Deferred tax charge
	UK		(489	)		(218	)		289
	Overseas		1,153			439			38

			664			221			327

Total
	UK		391			1,621			1,431
	Overseas		8,897			5,461			3,619

			9,288			7,082			5,050

F-63

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (continued)


	*Tax included in statement of recognized income and expense*


		Years ended
		December 31,

		2005			2004			2003

		($ million)
Current tax
	Charge for the year		45			23			(11	)

			45			23			(11	)
Innovene operations			—			—			—

Continuing operations			45			23			(11	)

Deferred tax
	Origination and reversal of temporary differences in the current year		309			50			59
	Adjustment in respect of prior years		(95	)		—			—

			214			50			59
Innovene operations			—			—			—

Continuing operations			214			50			59

Tax included in statement of recognized income and expense			259			73			48

This comprises:
	Currency translation differences		(11	)		208			37
	Exchange gain on translation of foreign operations transferred to loss on sale of businesses		(95	)		—			—
	Actuarial gain relating to pensions and other postretirement benefits		356			(96	)		16
	Share-based payment accrual		—			(39	)		(5	)
	Net (gain) loss on revaluation of cash flow hedges		(63	)		—			—
	Unrealized (gain) loss on available-for-sale financial assets		72			—			—

Tax included in statement of recognized income and expense			259			73			48

F-64

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (continued)


	*Reconciliation of the effective tax rate*

The following table provides a reconciliation of the UK statutory corporation tax rate to the effective tax rate of the Group on profit before taxation from continuing operations.


		Years ended December 31,

		2005			2004			2003

		($ million)
Profit before taxation from continuing operations			31,421			24,966			17,731

Tax on profit from continuing operations			9,288			7,082			5,050

Effective tax rate			30	%		28	%		28	%

		% of profit before tax from continuing operations
UK statutory corporation tax rate			30			30			30
Increase (decrease) resulting from
	UK supplementary and overseas taxes at higher rates		9			8			8
	Tax reported in equity-accounted entities		(3	)		(3	)		(3	)
	Adjustments in respect of prior years		(3	)		(1	)		(1	)
	Restructuring benefits		(1	)		(2	)		(2	)
	Current year losses unrelieved (prior year losses utilized)		(3	)		(3	)		(3	)
	Other		1			(1	)		(1	)

Effective tax rate			30			28			28

F-65

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (continued)


	*Deferred tax*


		Income statement									Balance sheet

		2005			2004			2003			2005			2004			2003

		($ million)
Deferred tax liability
	Depreciation		(778	)		492			(716	)		18,529			19,873			18,783
	Pension plan surplus		170			10			199			957			520			468
	Other taxable temporary differences		887			(113	)		132			3,864			2,979			2,956

			279			389			(385	)		23,350			23,372			22,207

Deferred tax asset
	Petroleum revenue tax		121			77			26			(407	)		(581	)		(613	)
	Pension plan and other postretirement benefit plan deficits		220			92			501			(1,822	)		(2,068	)		(2,530	)
	Decommissioning, environmental and other provisions		(329	)		106			76			(2,218	)		(2,015	)		(2,015	)
	Derivative financial instruments		(629	)		—			—			(807	)		—			—
	Tax credit and loss carry-forward		(245	)		6			231			(253	)		(5	)		(12	)
	Other deductible temporary differences		297			(606	)		(68	)		(1,585	)		(2,002	)		(986	)

			(565	)		(325	)		766			(7,092	)		(6,671	)		(6,156	)

Net deferred tax liability			(286	)		64			381			16,258			16,701			16,051


	Years ended December 31,

	2005			2004		2003

	($ million)
Analysis of movements during the year
At January 1,		16,701			16,051		15,045
Adoption of IAS 32 and IAS 39		(112	)		—		—

Restated		16,589			16,051		15,045
Exchange adjustments		(178	)		358		566
Charge for the year on ordinary activities		(286	)		64		381
Charge for the year in the statement of recognized income and expense		214			50		59
Other movements		(81	)		178		—

At December 31,		16,258			16,701		16,051


	*Factors that may effect future tax charges*

The Group earns income in many different countries and, on average, pays taxes at rates higher than the UK statutory rate. The overall impact of these higher taxes, which include the supplementary charge of 10% on UK North Sea profits, is subject to changes in enacted tax rates and the country mix of the Group’s income. The UK government has announced that the supplementary charge will be increased to 20% with effect from January 1, 2006. If this change is enacted, it will increase the

F-66

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (continued)

Group’s ongoing effective tax rate by 1-2%, and will also require a deferred tax adjustment resulting in a further 2% increase in the tax rate for 2006. The impact of this increase, together with the other factors outlined below, is likely to increase the effective tax rate by around 4-5% in future years.

Under International Financial Reporting Standards, the results of equity-accounted entities are reported within the Group’s profit before taxation on a post-tax basis. The impact of this treatment is to reduce the reported effective tax rate by around 3%. This effect is expected to continue for the foreseeable future.

In 2005, the Group released around $1 billion of income tax provisions that had been set up in previous years, reflecting a revised assessment of risks. It is unlikely that a similar release of provisions will occur in future years.

At December 31, 2005, deferred tax liabilities were recognized for all taxable temporary differences:


	—	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, associates and jointly controlled entities, 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.

At December 31, 2005, deferred tax assets were 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, associates and jointly controlled entities, 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 Group has around $5.1 billion (2004 $7.7 billion and 2003 $4.5 billion) of carry-forward tax losses in the UK and Germany, which would be available to offset against future taxable income. At the end of 2005, $176 million of deferred tax assets were recognized on these losses (2004 no tax asset and 2003 $86 million of assets were recognized). Tax assets are recognized only to the extent that it is considered more likely than not that suitable taxable income will arise. Carry-forward losses in other taxing jurisdictions have not been recognized as deferred tax assets and are unlikely to have a significant effect on the Group’s tax rate in future years.

The major component of temporary differences in the current year are tax depreciation, US inventory holding gains (classified under other taxable temporary differences) and derivative financial

F-67

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 23 — Taxation (concluded)

instruments. Based on current capital investment plans, the Group expects that temporary differences arising in future years from differences between tax allowances and depreciation will be at levels similar to the current year.

Note 24 — Quarterly results of operations (unaudited)


							Profit from
	Sales and		Profit before		Profit		continuing
	other		interest and taxation		from		operations
	operating		from continuing		continuing		per ordinary
	revenues		operations		operations		share

			($ million)				(cents)
Year ended December 31, 2005
First quarter		52,346		9,040		6,359		29.37
Second quarter		58,320		8,010		5,556		25.81
Third quarter		66,716		10,052		7,197		33.87
Fourth quarter		62,410		5,080		3,021		14.33

Total		239,792		32,182		22,133		103.38

Year ended December 31, 2004
First quarter		45,639		6,989		4,920		22.12
Second quarter		51,549		6,198		4,323		19.55
Third quarter		43,756		6,627		4,791		21.85
Fourth quarter		51,080		5,932		3,850		17.57

Total		192,024		25,746		17,884		81.09

As indicated in Note 3, the Group identified a further transition adjustment in respect of its basis of accounting for over-the-counter forward sales and purchases of oil, gas, NGLs and power subsequent to the publication of its quarterly earnings releases for the first, second and third quarters of 2005. The sales and other operating revenues for the total group (including Innovene operations) included in those earnings releases are shown below:


		Years ended
		December 31,

		2005		2004

As originally reported
	First quarter		78,998		68,461
	Second quarter		86,817		70,314
	Third quarter		99,677		68,427
As revised
	First quarter		58,552		50,244
	Second quarter		64,050		55,756
	Third quarter		72,467		48,151

F-68

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 25 — Dividends


			Years ended December 31,

			2005		2004		2003		2005		2004		2003		2005		2004		2003

			(pence per share)						(cents per share)						($ million)
Dividends announced and paid
	Preference shares															2		2		2
	Ordinary shares
		March		4.522		3.674		3.815		8.50		6.75		6.25		1,823		1,492		1,397
		June		4.450		3.807		3.947		8.50		6.75		6.25		1,808		1,477		1,385
		September		5.119		3.860		4.039		8.925		7.10		6.50		1,871		1,536		1,433
		December		5.061		3.910		3.857		8.925		7.10		6.50		1,855		1,534		1,437

				19.152		15.251		15.658		34.85		27.70		25.50		7,359		6,041		5,654

Dividend announced per ordinary share, payable in March 2006				5.288		—		—		9.375		—		—		1,923		—		—

The Group does not account for dividends until they have been paid. The accounts for the year ended December 31, 2005 do not reflect the dividend announced on February 7, 2006 and payable in March 2006; this will be treated as an appropriation of profit in the year ended December 31, 2006.

Note 26 — Profit per ordinary share


	Years ended December 31,

	2005		2004		2003

	(cents per share)
Basic earnings per share		104.25		78.24		56.14
Diluted earnings per share		103.05		76.87		55.61

Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and the shares held by the Employee Share Ownership Plans.

For the diluted earnings per share calculation, the profit attributable to ordinary shareholders is adjusted for the unwinding of the discount on the deferred consideration for the acquisition of our interest in TNK-BP. The weighted average number of shares outstanding during the year is adjusted for the number of shares to be issued for the deferred consideration for the acquisition of our interest in

F-69

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 26 — Profit per ordinary share (concluded)

TNK-BP and the number of shares that would be issued on conversion of outstanding share options into ordinary shares using the treasury stock method.


		Years ended December 31,

		2005		2004			2003

		($ million)
Profit for the year attributable to BP shareholders
	Continuing operations		21,842		17,697			12,511
	Discontinued operations		184		(622	)		(63	)

			22,026		17,075			12,448
Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP (net of tax)			40		64			24

Diluted profit for the year attributable to BP shareholders			22,066		17,139			12,472


	Years ended December 31,

	2005		2004		2003

	(shares thousand)
Basic weighted average number of ordinary shares		21,125,902		21,820,535		22,170,741
Potential dilutive effect of ordinary shares issuable under employee share schemes		87,743		56,985		65,931
Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in the TNK-BP joint venture		197,802		415,016		186,980

		21,411,447		22,292,536		22,423,652

The number of ordinary shares outstanding at December 31, 2005 was 20,657,044,719. Between the reporting date and June 28, 2006 there has been a net decrease of 646,632,990 in the number of ordinary shares outstanding as a result of share buybacks net of share issues. The number of potential ordinary shares through the exercise of employee share options was 108,596,993 at December 31, 2005. There has been an increase of 2,556,613 in the number of potential ordinary shares between the reporting date and June 28, 2006.

Earnings (loss) per share for the discontinued operations is derived from the net profit (loss) attributable to ordinary shareholders from discontinued operations of $184 million profit (2004 $622 million loss and 2003 $63 million loss), divided by the weighted average number of ordinary shares for both basic and diluted amounts as shown above.

F-70

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 27 — Property, plant and equipment


																			Oil depots,
										Plant,			Fixtures						storage						Of which:
							Oil and			machinery			fittings and						tanks and						Assets
							gas			and			office			Transport-			service						under
	Land			Buildings			properties			equipment			equipment			ation			stations			Total			construction

	($ million)
Cost
At January 1, 2005		5,471			1,965			103,967			42,302			1,694			13,588			14,435			183,422			15,038
Exchange adjustments		(387	)		(136	)		(15	)		(2,364	)		(180	)		(4	)		(1,117	)		(4,203	)		(66	)
Acquisitions		19			3			—			—			1			—			—			23			27
Additions		41			191			8,773			2,451			383			133			816			12,788			10,467
Transfers		—			—			325			—			—			—			—			325			(8,668	)
Deletions		(568	)		(69	)		(2,675	)		(13,609	)		(784	)		(451	)		(885	)		(19,041	)		(683	)

At December 31, 2005		4,576			1,954			110,375			28,780			1,114			13,266			13,249			173,314			16,115

Depreciation
At January 1, 2005		863			538			54,012			19,556			726			7,141			7,494			90,330
Exchange adjustments		(17	)		(60	)		(7	)		(916	)		(67	)		(76	)		(496	)		(1,639	)
Charge for the year		79			143			5,696			1,691			399			309			704			9,021
Impairment losses		—			—			266			590			—			—			42			898
Transfers		—			—			6			—			—			—			—			6
Deletions		(216	)		(65	)		(1,819	)		(7,504	)		(741	)		(270	)		(634	)		(11,249	)

At December 31, 2005		709			556			58,154			13,417			317			7,104			7,110			87,367

Net book amount at December 31, 2005		3,867			1,398			52,221			15,363			797			6,162			6,139			85,947			16,115

Cost
At January 1, 2004		4,799			2,191			96,991			39,840			1,458			13,099			13,529			171,907			13,957
Exchange adjustments		477			68			1,641			1,916			37			182			725			5,046			158
Acquisitions		10			—			—			1,453			—			—			—			1,463			—
Additions		308			121			8,048			1,863			513			672			869			12,394			10,084
Transfers		—			—			1,036			—			—			—			—			1,036			(8,879	)
Deletions		(123	)		(415	)		(3,749	)		(2,770	)		(314	)		(365	)		(688	)		(8,424	)		(282	)

At December 31, 2004		5,471			1,965			103,967			42,302			1,694			13,588			14,435			183,422			15,038

Depreciation
At January 1, 2004		815			700			50,028			17,363			796			7,031			6,567			83,300
Exchange adjustments		87			27			948			1,193			3			83			369			2,710
Charge for the year		50			96			5,203			2,142			197			229			917			8,834
Impairment losses		—			—			404			761			—			—			—			1,165
Transfers		—			—			196			—			—			—			—			196
Deletions		(89	)		(285	)		(2,767	)		(1,903	)		(270	)		(202	)		(359	)		(5,875	)

At December 31, 2004		863			538			54,012			19,556			726			7,141			7,494			90,330

Net book amount at December 31, 2004		4,608			1,427			49,955			22,746			968			6,447			6,941			93,092			15,038

F-71

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 27 — Property, plant and equipment (concluded)


																			Oil depots,
										Plant,			Fixtures						storage						Of which:
							Oil and			machinery			fittings and						tanks and						Assets
							gas			and			office			Transport-			service						under
	Land			Buildings			properties			equipment			equipment			ation			stations			Total			construction

	($ million)
Cost
At January 1, 2003		3,838			2,048			98,250			36,214			1,141			12,398			12,184			166,073			12,127
Exchange adjustments		713			102			2,461			3,831			56			283			1,073			8,519			216
Acquisitions		—			—			—			34			—			—			—			34			—
Additions		297			113			8,737			1,693			497			672			799			12,808			10,800
Transfers		—			—			820			184			—			—			—			1,004			(7,359	)
Fair value adjustment		—			—			(76	)		—			—			—			—			(76	)		—
Deletions		(49	)		(72	)		(13,201	)		(2,116	)		(236	)		(254	)		(527	)		(16,455	)		(1,827	)

At December 31, 2003		4,799			2,191			96,991			39,840			1,458			13,099			13,529			171,907			13,957

Depreciation
At January 1, 2003		677			612			51,731			15,159			620			6,826			5,505			81,130
Exchange adjustments		114			10			1,041			1,383			15			97			430			3,090
Charge for the year		44			112			5,310			1,687			290			244			841			8,528
Impairment losses		—			—			1,013			—			—			—			—			1,013
Transfers		—			—			66			(9	)		—			—			—			57
Deletions		(20	)		(34	)		(9,133	)		(857	)		(129	)		(136	)		(209	)		(10,518	)

At December 31, 2003		815			700			50,028			17,363			796			7,031			6,567			83,300

Net book amount at December 31, 2003		3,984			1,491			46,963			22,477			662			6,068			6,962			88,607			13,957

Assets held under finance leases at net book amount included above


													Oil depots
							Plant,		Fixtures				storage
					Oil and		machinery		fittings and				tanks and
					gas		and		office		Transport-		service
	Land		Buildings		properties		equipment		equipment		ation		stations		Total

	($ million)
At December 31, 2005		8		24		46		315		2		9		35		439
At December 31, 2004		12		7		45		1,583		7		10		40		1,704
At December 31, 2003		14		8		48		1,648		8		12		44		1,782

Decommissioning asset at net book amount included above


	Cost		Depreciation		Net

	($ million)
At December 31, 2005		5,398		2,342		3,056
At December 31, 2004		4,425		1,908		2,517
At December 31, 2003		3,686		1,606		2,080

F-72

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 28 — Goodwill


	Years ended December 31,

	2005			2004			2003

	($ million)
Cost
At January 1		11,182			10,592			10,440
Exchange adjustments		(488	)		332			476
Acquisitions		86			328			5
Fair value adjustment		—			—			(289	)
Deletions		(409	)		(70	)		(40	)

At December 31		10,371			11,182			10,592

Impairment losses
At January 1		325			—			—
Exchange adjustments		—			—			—
Impairment in the year		59			325			—
Deletions		(384	)		—			—

At December 31		—			325			—

Net book amount at December 31		10,371			10,857			10,592

F-73

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 29 — Intangible assets


	Years ended December 31,

	2005									2004								2003

	Exploration			Other						Exploration			Other					Exploration			Other
	expenditure			intangibles			Total			expenditure			intangibles		Total			expenditure			intangibles			Total

	($ million)
Cost
At January 1		4,311			1,377			5,688			4,977			950		5,927			5,630			900			6,530
Exchange adjustments		(66	)		(44	)		(110	)		41			60		101			72			2			74
Acquisitions		—			—			—			—			15		15			—			—			—
Additions		950			531			1,481			754			352		1,106			579			136			715
Transfers		(325	)		—			(325	)		(1,036	)		—		(1,036	)		(820	)		—			(820	)
Deletions		(209	)		(124	)		(333	)		(425	)		—		(425	)		(484	)		(88	)		(572	)

At December 31		4,661			1,740			6,401			4,311			1,377		5,688			4,977			950			5,927

Amortization
At January 1		550			933			1,483			741			715		1,456			686			717			1,403
Exchange adjustments		(8	)		(32	)		(40	)		1			40		41			10			2			12
Charge for the year		305			161			466			274			178		452			297			77			374
Transfers		(6	)		—			(6	)		(196	)		—		(196	)		(66	)		—			(66	)
Deletions		(188	)		(86	)		(274	)		(270	)		—		(270	)		(186	)		(81	)		(267	)

At December 31		653			976			1,629			550			933		1,483			741			715			1,456

Net book amount at December 31		4,008			764			4,772			3,761			444		4,205			4,236			235			4,471

F-74

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 30 — Investments in jointly controlled entities

The significant jointly controlled entities of the BP Group at December 31, 2005 are shown in Note 51. The principal joint venture is the TNK-BP joint venture. Summarized financial information for the Group’s share of jointly controlled entities is shown below.


		2005						2004						2003

		TNK-BP		Other		Total		TNK-BP		Other		Total		TNK-BP		Other		Total

		($ million)
Year ended December 31,
Sales and other operating revenues			15,122		4,255		19,377		7,839		2,225		10,064		1,864		1,795		3,659

Profit before interest and taxation			3,817		779		4,596		2,421		586		3,007		521		489		1,010
Finance costs and other finance expense			128		104		232		101		69		170		37		65		102

Profit before taxation			3,689		675		4,364		2,320		517		2,837		484		424		908
Taxation			976		220		1,196		675		314		989		43		57		100
Minority interest			104		—		104		43		—		43		—		—		—

Profit for the year			2,609		455		3,064		1,602		203		1,805		441		367		808
Innovene operations			—		19		19		—		13		13		—		18		18

Continuing operations			2,609		474		3,083		1,602		216		1,818		441		385		826

At December 31,
Noncurrent assets			11,564		6,310		17,874		11,715		5,112		16,827		10,312		3,663		13,975
Current assets			4,278		1,682		5,960		2,565		1,283		3,848		1,950		1,427		3,377

Total assets			15,842		7,992		23,834		14,280		6,395		20,675		12,262		5,090		17,352

Current liabilities			3,617		914		4,531		1,959		981		2,940		1,575		773		2,348
Noncurrent liabilities			3,553		2,550		6,103		3,485		560		4,045		3,062		68		3,130

Total liabilities			7,170		3,464		10,634		5,444		1,541		6,985		4,637		841		5,478
Minority interest			583		—		583		542		—		542		527		—		527

			8,089		4,528		12,617		8,294		4,854		13,148		7,098		4,249		11,347

Group investment in jointly controlled entities
	Group share of net assets (as above)		8,089		4,528		12,617		8,294		4,854		13,148		7,098		4,249		11,347
	Loans made by Group companies to jointly controlled entities		—		939		939		—		1,408		1,408		—		1,562		1,562

			8,089		5,467		13,556		8,294		6,262		14,556		7,098		5,811		12,909

On August 29, 2003, BP and the Alfa Group and Access-Renova (AAR) combined certain of their Russian and Ukrainian oil and gas businesses to create TNK-BP, a new company owned and managed 50:50 by BP and AAR. TNK-BP is a jointly controlled entity accounted for under the equity method. BP contributed its 29% interest in Sidanco, its 29% interest in Rusia Petroleum and its holding in the BP Moscow retail network. There was additional consideration from BP to AAR comprising an immediate $2,604 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends, net of other adjustments, of $298 million) together with annual tranches of $1,250 million in BP shares payable in 2004, 2005 and 2006. There were costs of $45 million in connection with the transaction. The first two tranches were issued in September 2004 and 2005.

BP also agreed with AAR to incorporate AAR’s 50% interest in Slavneft into TNK-BP in return for $1,418 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends of $64 million to $1,354 million). This transaction was completed on January 16, 2004.

F-75

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 30 — Investments in jointly controlled entities (continued)

BP’s share of the gross profit of TNK-BP for the year ended December 31, 2005 was $4,413 million (2004 $2,935 million and 2003 $634 million).

BP Solvay Polyethylene Europe became a subsidiary with effect from November 2, 2004. See Note 4 — Acquisitions, for further information. In 2005, it was sold as part of the Innovene operations.

During 2004, BP China and Sinopec announced the establishment of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd, a retail joint venture between BP and Sinopec. Based on the existing service station network of Sinopec, the joint venture will build, operate and manage a network of 500 service stations in Hangzhou, Ningbo and Shaoxing. Also during 2004, BP China and PetroChina announced the establishment of BP-PetroChina Petroleum Company Ltd. Located in Guangdong, one of the most developed provinces in China, the joint venture will acquire, build, operate and manage 500 service stations in the province. The initial investment in both joint ventures amounted to $106 million.

Transactions between the significant jointly controlled entities and the Group are summarized below. In addition to the amount receivable at December 31, 2005 shown below, a further $771 million was receivable from TNK-BP in respect of dividends.

Sales to jointly controlled entities


			2005				2004				2003

					Amount				Amount				Amount
					receivable at				receivable at				receivable at
	Product		Sales		December 31		Sales		December 31		Sales		December 31

			($ million)
BP Solvay Polyethylene Europe (a)		Chemicals feedstocks		—		—		230		—		259		33
Pan American Energy		Crude oil		75		2		118		4		171		5
Ruhr Oel		Employee services		169		527		192		780		188		587
TNK-BP		Employee services		125		14		49		—		—		—
Watson Cogeneration		Natural gas		272		31		214		10		73		6

F-76

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 30 — Investments in jointly controlled entities (concluded)

Purchases from jointly controlled entities


			2005				2004				2003

					Amount				Amount				Amount
					payable at				payable at				payable at
	Product		Purchases		December 31		Purchases		December 31		Purchases		December 31

			($ million)
BP Solvay Polyethylene Europe (a)		Chemicals feedstocks		—		—		—		—		18		14
Pan American Energy		Crude oil		661		81		481		43		381		48
Ruhr Oel		Refinery operating		384		134		477		249		435		131
		costs
TNK-BP (b)		Crude oil and oil		908		17		1,809		80		349		52
		products
Watson Cogeneration		Electricity and steam		185		19		149		14		248		12


(a)		The 2004 BP Solvay Polyethylene Europe sales and purchases shown above relate to the period to November 2, 2004.

(b)		The 2003 TNK-BP sales and purchases shown above relate to the period from August 29, to December 31, 2003.

F-77

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 31 — Investments in associates

The significant associates of the Group are shown in Note 51. Summarized financial information for the Group’s share of the aggregate total of revenues, profit, assets and liabilities of associates is set out below.


		2005			2004			2003

		($ million)
Sales and other operating revenues			6,879			5,509			4,101

Profit before interest and taxation			665			632			513
Finance costs and other finance expense			57			48			42

Profit before taxation			608			584			471
Taxation			143			121			80

Profit for the year			465			463			391
Innovene operations			(5	)		(1	)		(3	)

Continuing operations			460			462			388

Noncurrent assets			5,514			6,023			5,143
Current assets			2,248			2,212			1,720

Total assets			7,762			8,235			6,863
Current liabilities			1,755			1,988			1,614
Noncurrent liabilities			2,037			2,171			1,280

Total liabilities			3,792			4,159			2,894

Net assets			3,970			4,076			3,969

Group investment in associates Group share of net assets (as above)			3,970			4,076			3,969
	Loans made by Group companies to associates		2,247			1,410			899

			6,217			5,486			4,868

BP Solvay Polyethylene North America became a subsidiary with effect from November 2, 2004. See Note 4 — Acquisitions, for further information. In 2005, it was sold as part of the Innovene operations.

Transactions between the significant associates and the Group are summarized below.

F-78

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 31 — Investments in associates (concluded)

Sales to associates


			2005				2004				2003

					Amount				Amount				Amount
					receivable at				receivable at				receivable at
	Product		Sales		December 31		Sales		December 31		Sales		December 31

			($ million)
Atlantic LNG Company of Trinidad and Tobago		LNG		579		—		414		—		348		—
Atlantic LNG 2/3 Company of Trinidad and Tobago		LNG		1,157		—		532		—		420		—
BP Solvay Polyethylene North America(a)		Chemicals feedstocks		—		—		217		—		241		17
China American Petrochemical Co.		Chemicals feedstocks		393		48		385		81		240		67
Samsung Petrochemical Co.		Chemicals feedstocks		92		13		62		8		55		10

Purchases from associates


			2005				2004				2003

					Amount				Amount				Amount
					payable at				payable at				payable at
	Product		Purchases		December 31		Purchases		December 31		Purchases		December 31

			($ million)
Abu Dhabi Marine Areas		Crude oil		1,355		164		866		91		661		61
Abu Dhabi Petroleum Co.		Crude oil		2,260		214		1,547		145		1,122		118
Atlantic LNG 2/3 Company of Trinidad and Tobago		Natural gas		190		—		120		—		83		10
BP Solvay Polyethylene North America(a)		Chemicals feedstocks		—		—		9		—		11		1
China American Petrochemical Co.		Petrochemicals		547		109		455		111		197		83
Samsung Petrochemical Co.		Chemicals feedstocks		626		140		290		17		187		38


(a)		The 2004 BP Solvay Polyethylene North America sales and purchases shown above relate to the period to November 2, 2004.

F-79

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 32 — Other investments


		At December 31,

		2005		2004		2003

		($ million)
At fair value
	Listed		830		—		—
	Unlisted		137		—		—

			967		—		—

At cost
	Listed		508		263		1,284
	Unlisted		173		131		168

			681		394		1,452

Carrying amount at December 31			967		394		1,452

Fair value at December 31			967		—		—

Other investments comprise equity investments that have no fixed maturity date or coupon rate.

For IFRS, these investments are classified as available-for-sale financial assets and as such are recorded at fair value with the gain or loss arising as a result of the change in fair value being recorded directly in equity.

Prior to 2005, these investments were stated at cost less accumulated impairment losses.

The fair value of listed investments has been determined by reference to quoted market bid prices.

The fair value of the unlisted available-for-sale equity investments are stated at cost as their fair value cannot be reliably measured as they do not have a quoted price in an active market.

Note 33 — Inventories


	At December 31,

	2005		2004		2003

	($ million)
Crude oil		5,457		3,659		2,044
Natural gas		164		75		605
Refined petroleum and petrochemicals products		10,700		8,103		6,080

		16,321		11,837		8,729
Supplies		919		911		938

		17,240		12,748		9,667
Trading inventories		2,520		2,897		1,930

		19,760		15,645		11,597

Cost of inventories expensed in the income statement		172,699		135,907		115,978

F-80

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 34 — Trade and other receivables


	At December 31,

	2005				2004				2003

	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent

	($ million)
Trade		33,565		—		30,657		—		23,449		—
Jointly controlled entities		1,345		—		886		—		122		—
Associates		186		—		210		23		337		53
Other		5,806		770		5,346		406		3,973		442

		40,902		770		37,099		429		27,881		495

Trade and other receivables of the Group at December 31, 2005 in currencies other than the functional currency of individual operating units are summarized below.


		At December 31, 2005

								Other
		US dollar		Sterling		Euro		currencies		Total

		($ million)
Functional currency
	US dollar		—		404		1,496		458		2,358
	Sterling		1,111		—		1		1		1,113
	Euro		354		453		—		1		808
	Other currencies		6,045		15		948		—		7,008

Total			7,510		872		2,445		460		11,287

Trade and other receivables of the Group at December 31, 2005 have the maturities shown below.


	At December 31,
	2005

	($ million)
Within one year		40,902
1 to 2 years		129
2 to 3 years		82
3 to 4 years		56
4 to 5 years		51
Over 5 years		452

		41,672

F-81

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 34 — Trade and other receivables (concluded)

The movement in the valuation allowance for trade receivables is set out below.



	2005			2004			2003

	($ million)
At January 1		526			441			445
Exchange adjustments		(30	)		6			29
Charge for the year		67			254			139
Utilization		(189	)		(175	)		(172	)

At December 31		374			526			441

The carrying amounts of Trade and other receivables approximate their fair value. Trade and other receivables are predominantly non-interest bearing.

Note 35 — Cash and cash equivalents


		At December 31,

		2005		2004		2003

		($ million)
Cash at bank and in hand			1,594		1,031		1,871
Cash equivalents
	Listed		73		63		79
	Unlisted		1,293		265		106

Carrying amount at December 31			2,960		1,359		2,056

For IFRS, cash equivalents are classified as available-for-sale financial assets and as such are recorded at fair value. Prior to 2005, cash equivalents were stated at cost.

Note 36 — Trade and other payables


	At December 31,

	2005				2004				2003

	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent

	($ million)
Trade		28,614		—		27,471		—		20,830		—
Jointly controlled entities		251		—		637		—		126		—
Associates		627		—		865		5		322		4
Production and similar taxes		763		1,281		517		1,520		421		1,544
Social security		78		—		122		—		96		—
Other		11,803		654		8,928		2,056		7,945		3,082

		42,136		1,935		38,540		3,581		29,740		4,630

F-82

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 36 — Trade and other payables (concluded)

Trade and other payables of the Group at December 31, 2005 in currencies other than the functional currency of individual operating units are summarized below.


		At December 31, 2005

		US						Other
		dollar		Sterling		Euro		currencies		Total

		($ million)
Functional currency
	US dollar		—		133		611		339		1,083
	Sterling		1,802		—		4		12		1,818
	Euro		157		306		—		38		501
	Other currencies		6,640		—		17		—		6,657

Total			8,599		439		632		389		10,059

Trade and other payables of the Group at December 31, 2005 have the maturities shown below.


	At December 31,
	2005

	($ million)
Within one year		42,136
1 to 2 years		276
2 to 3 years		211
3 to 4 years		182
4 to 5 years		179
Over 5 years		1,087

		44,071

The carrying amounts of Trade and other payables approximate their fair value. Included within other payables is the deferred consideration for the acquisition of our interest in TNK-BP, which was discounted on initial recognition. The remaining Trade and other payables are predominately interest free.

Note 37 — Derivative financial instruments

An outline of the Group’s financial risks and the policies and objectives pursued in relation to those risks is set out in the financial risk management section in Item 11.

This note contains the disclosures required by IAS 32 for derivative financial instruments. IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge, and requires that any derivative that does not meet these criteria should be classified as trading andmarked-to-market. BP adopted IAS 32 and IAS 39 with effect from January 1, 2005 without restating prior periods. Consequently, the Group’s accounting policy under UK GAAP has been used for 2004 and 2003. The policy under UK GAAP and the disclosures required by UK GAAP for derivative financial instruments are shown in Note 39.

In the normal course of business the Group is a party to derivative financial instruments (derivatives) with off-balance sheet risk, primarily to manage its exposure to fluctuations in foreign

F-83

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt. The Group also manages certain of its exposures to movements in oil, natural gas, NGL and power prices. In addition, the Group trades derivatives in conjunction with these risk management activities.

The fair value of derivative financial instruments at December 31, 2005 are set out below.


			At December 31, 2005

			Fair		Contractual		Fair			Contractual
			value		or notional		value			or notional
			asset		amounts		liability			amounts

			($ million)
Cash flow hedges
	Currency forwards, futures and swaps			34		666		(94	)		3,100
	Currency options			—		693		(35	)		1,470
	Commodity futures			57		274		—			—

				91		1,633		(129	)		4,570

Fair value hedges
	Currency forwards, futures and swaps			222		2,566		(124	)		1,967
	Interest rate swaps			19		324		(217	)		7,521

				241		2,890		(341	)		9,488

Hedges of net investments in foreign entities				63		346		—			—

Derivatives held for trading
	Currency derivatives			41		634		(18	)		1,687
	Oil derivatives			2,765		56,394		(2,826	)		52,524
	Natural gas and NGL derivatives			6,836		148,794		(6,307	)		128,330
	Power derivatives			3,341		25,793		(3,158	)		26,618

				12,983		231,615		(12,309	)		209,159

				13,378		236,484		(12,779	)		223,217

Of which — current				3,652				(9,083	)
		— noncurrent		9,726				(3,696	)

Embedded derivatives held for trading Natural gas contracts				587		4,620		(3,098	)		8,563
	Interest rate contracts			—		—		(30	)		150

				587		4,620		(3,128	)		8,713


	*Cash flow hedges*

At December 31, 2005, the Group held forward currency contracts, cylinders and options that were being used to hedge the foreign currency risk of highly probable transactions. Changes in the fair value of instruments used as hedges are not recognized in the accounts until the position matures. The hedges were assessed to be highly effective.

F-84

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

An analysis of these changes in fair value is as follows:


	Net fair
	value

	($ million)
Fair value of cash flow hedges at January 1, 2005		198
Change in fair value during the year		(191	)
Fair value recognized in income statement during the year		(8	)
Fair value on capital expenditure hedging recycled into carrying value of assets during the year		(37	)

Fair value of cash flow hedges at December 31, 2005		(38	)

Cash flow hedges have the following maturities:


	At December 31, 2005

	Fair value		Fair value
	asset		liability

	($ million)
Within one year		54		(108	)
1 to 2 years		19		(17	)
2 to 3 years		3		(3	)
3 to 4 years		6		(1	)
4 to 5 years		2		—
Over 5 years		7		—

		91		(129	)

Derivative assets related to foreign exchange risks of cash flow hedges are denominated in the following currencies:


		At December 31, 2005

		Currencies purchased forward

								Other
		US dollar		Sterling		Euro		currencies		Total

		($ million)
Currencies sold forward
	US dollar		57		15		15		1		88
	Sterling		—		—		3		—		3

			57		15		18		1		91

F-85

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

Derivative liabilities related to foreign exchange risks of cash flow hedges are denominated in the following currencies:


		At December 31, 2005

		Currencies purchased forward

		US								Other
		dollar		Sterling			Euro			currencies			Total
-
		-------------------------------------------------------------($-
		million
Currencies sold forward
	US dollar		—		(70	)		(40	)		(19	)		(129	)


	*Fair value hedges*

At December 31, 2005, the Group held interest rate and currency swap contracts as fair value hedges of the interest rate risk on fixed rate debt issued by the Group. These hedges were assessed to be highly effective. At December 31, 2005, the loss on fair value hedges included in the carrying value of fixed rate debt was $100 million.

Fair value hedges have the following maturities:


	At December 31, 2005

	Fair value		Fair value
	asset		liability
-
	------------------------($-
	million
Within one year		185		(51	)
1 to 2 years		—		(110	)
2 to 3 years		15		(66	)
3 to 4 years		23		(68	)
4 to 5 years		—		(9	)
Over 5 years		18		(37	)

		241		(341	)

Derivative assets related to foreign exchange risks of fair value hedges are denominated in the following currencies:


		At December 31, 2005

		Currencies purchased forward

								Other
		US dollar		Sterling		Euro		currencies		Total
-
		------------------------------------------------------------------($-
		million
Currencies sold forward
	US dollar		19		53		96		50		218
	Sterling		—		—		17		—		17
	Euro		—		—		6		—		6

			19		53		119		50		241

F-86

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

Derivative liabilities related to foreign exchange risks of fair value hedges are denominated in the following currencies:


		At December 31, 2005

		Currencies purchased forward

										Other
		US dollar			Sterling			Euro		currencies			Total
-
		------------------------------------------------------------------($-
		million
Currencies sold forward
	US dollar		(217	)		(92	)		—		(32	)		(341	)

The following table shows the fair value of contracts deferred on the balance sheet. This is where, at contract inception, derivatives are required to be recognized on the balance sheet at fair value, but any gain or loss is not recognized immediately but deferred on the balance sheet. The gain or loss is recognized in the income statement only when the full remaining term of the derivative can be valued against market inputs.


	Fair value			Fair value
	interest rate			exchange rate
	contracts			contracts
-
	----------------------------($-
	million
Fair value of contracts not recognized through the income statement at January 1, 2005		(73	)		247
Fair value of new contracts at inception not recognized in the income statement		—			—
Fair value recycled from equity into the income statement		(3	)		(109	)
Other changes in fair values		(122	)		(202	)

Fair values of contracts not recognized through profit at December 31, 2005		(198	)		(64	)


	*Hedges of net investments in foreign entities*

At December 31, 2005, the Group held currency swap contracts as a hedge of a long-term investment in a UK subsidiary. The hedge was assessed to be highly effective. At December 31, 2005, the hedge had a fair value of $63 million and the gain on the hedge recognized in equity was $58 million. US dollars have been sold forward for sterling purchased, with a maturity of 3 to 4 years.


	*Derivatives held for trading*

The Group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities. Derivatives held for trading purposes aremarked-to-market and any gain or loss recognized in the income statement. For traded derivatives, many positions have been neutralized, with trading initiatives being concluded by taking opposite positions to fix a gain or loss, thereby achieving a zero net market risk.

F-87

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

The following table shows the fair value at December 31, of derivatives and other financial instruments held for trading purposes. The fair values at the year end are not materially unrepresentative of the position throughout the year.

Derivatives held for trading have the following maturities:


	At December 31, 2005


	Fair value		Fair value
	asset		liability
-
	------------------------($-
	million
Within one year		9,487		(8,924	)
1 to 2 years		2,019		(2,155	)
2 to 3 years		685		(677	)
3 to 4 years		455		(278	)
4 to 5 years		145		(121	)
Over 5 years		192		(154	)

		12,983		(12,309	)

Derivative assets held for trading are denominated in the following currencies:


		At December 31, 2005

		Currency of denomination

								Other
		US dollar		Sterling		Euro		currencies		Total
-
		-------------------------------------------------------($-
		million
Functional currency
	US dollar		10,232		137		—		4		10,373
	Sterling		—		1,106		1,504		—		2,610

			10,232		1,243		1,504		4		12,983

Derivative liabilities held for trading are denominated in the following currencies:


		At December 31, 2005

		Currency of denomination

											Other
		US dollar			Sterling			Euro			currencies		Total
-
		---------------------------------------------------------($-
		million
Functional currency
	US dollar		(9,223	)		(110	)		—			—		(9,333	)
	Sterling		—			(1,453	)		(1,523	)		—		(2,976	)

			(9,223	)		(1,563	)		(1,523	)		—		(12,309	)

F-88

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

Derivative assets held for trading have the following contractual or notional values and maturities:


		At December 31, 2005

														Total
		Less than										Over		fair
		1 Year		1-2 years		2-3 years		3-4 years		4-5 years		5 Years		value

		($ million
Currency derivatives
	Fair value		28		6		1		1		1		4		41
	Notional value		358		73		51		28		32		92		634
Oil price derivatives
	Fair value		2,476		225		37		19		8		—		2,765
	Notional value		52,260		3,378		676		45		35		—		56,394
Natural gas and NGL price derivatives
	Fair value		4,509		1,194		528		292		125		188		6,836
	Notional value		113,897		17,562		8,560		4,021		2,068		2,686		148,794
Power price derivatives
	Fair value		2,474		594		119		143		11		—		3,341
	Notional value		19,149		5,049		857		535		196		—		25,786

Derivative liabilities held for trading have the following contractual or notional values and maturities:


		At December 31, 2005

																				Total
		Less than															Over			fair
		1 Year			1-2 years			2-3 years			3-4 years			4-5 years			5 Years			value
-		)
		---------------------------------------------------------------------------------------------($-
		million
Currency derivatives
	Fair value		(12	)		(4	)		(1	)		(1	)		—			—			(18	)
	Notional value		1,013			177			119			170			67			141			1,687
Oil price derivatives
	Fair value		(2,486	)		(275	)		(26	)		(20	)		(19	)		—			(2,826	)
	Notional value		49,732			2,276			446			35			35			—			52,524
Natural gas and NGL price derivatives
	Fair value		(3,967	)		(1,319	)		(591	)		(187	)		(89	)		(154	)		(6,307	)
	Notional value		90,916			25,269			6,457			2,903			1,577			1,208			128,330
Power price derivatives
	Fair value		(2,459	)		(557	)		(59	)		(70	)		(13	)		—			(3,158	)
	Notional value		20,030			4,990			778			625			195			—			26,618

F-89

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

The following tables show the changes during the year in the net fair value of derivatives held for trading purposes for 2005.


							Fair value
	Fair value			Fair value			natural			Fair value
	exchange			oil			gas and			power
	rate			price			NGL price			price
	contracts			contracts			contracts			contracts
-
	----------------------------------------------------($-
	million
Fair value of contracts at January 1, 2005		(54	)		(171	)		558			177
Contracts realized or settled in the year		23			175			(735	)		76
Fair value of new contracts when entered into during the year		—			—			24			10
Fair value of over-the-counter options at inception		—			(73	)		(65	)		(9	)
Change in fair value due to changes in valuation techniques or key assumptions		—			—			—			—
Other changes in fair values		54			8			747			(71	)

Fair value of contracts at December 31, 2005		23			(61	)		529			183

The following table shows the fair value of ‘day one profit’ deferred on the balance sheet.


	Fair value
	natural gas			Fair value
	and NGL			power
	price			price
	contracts			contracts
-
	------------------------($-
	million
Fair value of contracts not recognized through the income statement at January 1, 2005		(15	)		—
Fair value of new contracts at inception not recognized in the income statement		(14	)		(10	)
Fair value recycled from equity into the income statement		—			—
Other changes in fair values		—			—

Fair value of contracts not recognized through profit at December 31, 2005		(29	)		(10	)

F-90

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

The following table shows the net fair value of derivatives held for trading at December 31, 2005 analysed by maturity period and by methodology of fair value estimation.


	At December 31, 2005

																		Total
	Less than														Over			fair
	1 Year			1-2 years			2-3 years			3-4 years		4-5 years			5 years			value
-
	-----------------------------------------------------------------------------------------($-
	million
Prices actively quoted		(100	)		(86	)		46			42		33			(8	)		(73	)
Prices sourced from observable data or market corroboration		660			(48	)		(41	)		60		(11	)		—			620
Prices based on models and other valuation methods		3			(2	)		3			75		2			46			127

		563			(136	)		8			177		24			38			674


	Concentrations of credit risk

The primary activities of the Group are oil and natural gas exploration and production, gas and power marketing and trading, oil refining and marketing and the manufacture and marketing of chemicals. The Group’s principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. The credit rating of interest rate and currency swap counterparties are all of at least investment grade. The credit quality is actively managed over the life of the swap.


	Market risk exposure

The Group measures its market risk exposure, i.e. potential gain or loss in fair values, on its held-for-trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of theend-of-day exposures and the history of one-day price movements, together with the correlation of these price movements. The Group calculates value-at-risk for the bulk of instruments and exposures in the held-for-trading category, other than the UK North Sea natural gas and NGL embedded derivatives, for which a sensitivity analysis is calculated.

The Group has previously calculated and published value-at-risk expressed to three standard deviations for the internal delegation of market risk limits and control purposes. This is equivalent to a 99.7% confidence interval or a probability of one day per year where the daily gain or loss will exceed the calculated value at risk if the portfolio was left unchanged. In order to improve the practical

F-91

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

application of this tool, the Group has adopted a 95% confidence level, or calculation to 1.65 standard deviations. This has the effect of increasing the expected frequency of occasions when the daily gain or loss may exceed the calculated value-at-risk to one per month if the portfolio is left unchanged. This provides a better opportunity for verifying models and assumptions and improving accuracy of the value-at-risk calculation. For completeness, 2005 value-at-risk data has been disclosed using both the 95% and 99.7% confidence levels. The value-at-risk model takes account of derivative financial instruments types such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options, and oil, natural gas and power price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as held for trading positions are also included in these calculations. The value-at-risk calculation for oil, natural gas and NGL and power price exposure also includes cash-settled commodity contracts such as forward contracts. For options, a linear approximation is included in the value-at-risk models.

The following table shows values at risk for held for trading activities described above.

Value at risk on three standard deviations


	Year ended December 31, 2005

	High		Low		Average		Year end
-
	----------------------------------------------------($-
	million
Interest rate trading		2		—		—		—
Foreign exchange trading		9		2		4		2
Oil price trading		145		31		60		56
Natural gas and NGL price trading		71		9		26		30
Power price trading		30		4		14		16

Value at risk on 1.65 standard deviations


	Year ended December 31, 2005

	High		Low		Average		Year end
-
	----------------------------------------------------($-
	million
Interest rate trading		1		—		—		—
Foreign exchange trading		5		1		2		1
Oil price trading		80		17		33		31
Natural gas and NGL price trading		39		6		15		17
Power price trading		16		2		7		9

The presentation of held-for-trading results shown in the table below includes the results of the Group’s trading units that involve the use of derivatives in conjunction with physical and paper trading of oil, natural gas and power. It is considered that a more comprehensive representation of the Group’s oil, natural gas and NGL and power price trading activities is given by aggregating the gain or loss on such derivatives, together with the gain or loss arising from the physical and paper trades to which they relate, representing the net result of the trading portfolio. Also included in the net result of the held-for-trading portfolio are broker fees, transportation costs and trader bonuses. Held-for-trading results

F-92

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

include the results of risk management activity in respect of the Group’s supply and marketing activities that do not qualify for hedge accounting.


	Year ended
	December 31,
	2005

	Net gain (loss)
($-	)

	million
Interest rate trading		10
Foreign exchange trading		162
Oil trading		1,552
Natural gas and NGL trading		1,312
Power trading		(64	)

		2,972

Gains and losses relating to derivative contracts presented net in the income statement are included within other operating revenues. These contract types include futures, options, swaps and certain forward sales and purchase contracts where delivery is routinely obviated by the sale or purchase of offsetting contracts. Also included are the gains and losses relating to the change in the fair value of all derivative contracts held at the balance sheet dates, including derivative contracts presented gross when settled. The gain for the year presented net in the income statement was $838 million (2004 $1,216 million and 2003 $1,081 million).


	*Embedded derivatives held for trading*

Prior to the development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil products. Post the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing formulae not directly related to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined to be derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The resulting fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.

These contracts are valued using price curves for each of the different products that are built up from active market pricing data and extrapolated to 2018 using the maximum available external pricing information. Additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships.

The fair values of embedded derivatives are included on the balance sheet within the following headings.


	At December 31, 2005

	Current			Noncurrent			Total
-
	---------------------------------($-
	million
Prepayments and accrued income		330			257			587
Accruals and deferred income		(953	)		(2,175	)		(3,128	)

		(623	)		(1,918	)		(2,541	)

F-93

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

Embedded derivatives have the following maturities:


	At December 31, 2005

	Fair value		Fair value
	asset		liability
-
	------------------------($-
	million
Within one year		330		(953	)
1 to 2 years		176		(703	)
2 to 3 years		76		(502	)
3 to 4 years		5		(237	)
4 to 5 years		—		(180	)
Over 5 years		—		(553	)

		587		(3,128	)

Embedded derivative assets are denominated in the following currencies:


		At December 31, 2005

		Currency of denomination

								Other
		US dollar		Sterling		Euro		currencies		Total
-
		------------------------------------------------------------------($-
		million
Functional currency
	US dollar		79		—		—		—		79
	Sterling		—		508		—		—		508

			79		508		—		—		587

Embedded derivative liabilities are denominated in the following currencies:


		At December 31, 2005

		Currency of denomination

										Other
		US dollar			Sterling			Euro		currencies		Total
-
		-------------------------------------------------------------($-
		million
Functional currency
	US dollar		(30	)		—			—		—		(30	)
	Sterling		—			(3,098	)		—		—		(3,098	)

			(30	)		(3,098	)		—		—		(3,128	)

F-94

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

Embedded derivative assets held for trading have the following contractual or notional values and maturities:


		At December 31, 2005

														Total
		Less than										Over		fair
		1 Year		1-2 Years		2-3 Years		3-4 Years		4-5 Years		5 Years		value
-
		-----------------------------------------------------------------------------------------($-
		million
Natural gas embedded derivatives
	Fair value		330		176		76		5		—		—		587
	Notional value		425		484		465		450		429		2,367		4,620

Embedded derivative liabilities held for trading have the following contractual or notional values and maturities:


		At December 31, 2005

																				Total
		Less than															Over			fair
		1 Year			1-2 Years			2-3 Years			3-4 Years			4-5 Years			5 Years			value
-
		-----------------------------------------------------------------------------------------($-
		million
Natural gas embedded derivatives
	Fair value		(953	)		(703	)		(472	)		(237	)		(180	)		(553	)		(3,098	)
	Notional value		740			870			1,097			832			767			4,257			8,563
Interest rate embedded derivatives
	Fair value		—			—			(30	)		—			—			—			(30	)
	Notional value		—			—			150			—			—			—			150

The following table shows the changes during the year in the net fair value of embedded derivatives held for trading purposes for 2005.


					Fair value
		Fair value			natural gas
		interest rate			price
		contracts			contracts
-
		--------------------------($-
		million
Fair value of contracts at January 1, 2005	��		(17	)		(659	)
Contracts realized or settled in the year			—			138
Fair value of new contracts when entered into during the year			—			—
Change in fair value due to changes in valuation techniques or key assumptions			—			—
Other changes in fair values			(13	)		(1,990	)

Fair value of contracts at December 31, 2005			(30	)		(2,511	)

There are no fair value amounts for embedded derivatives held for trading that are deferred on the balance sheet.

F-95

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (continued)

The following table shows the net fair value of embedded derivatives held for trading purposes at December 31, 2005 analysed by maturity period and by methodology of fair value estimation.


	At December 31, 2005

																			Total
	Less than															Over			fair
	1 Year			1-2 Years			2-3 Years			3-4 Years			4-5 Years			5 Years			value
-
	-----------------------------------------------------------------------------------------($-
	million
Prices actively quoted		—			—			—			—			—			—			—
Prices sourced from observable data or market corroboration		51			28			—			—			—			—			79
Prices based on models and other valuation methods		(674	)		(542	)		(426	)		(231	)		(182	)		(565	)		(2,620	)

		(623	)		(514	)		(426	)		(231	)		(182	)		(565	)		(2,541	)

The net change in fair value of contracts based on models and other valuation methods during the year is a loss of $1,773 million.


	Sensitivity analysis

Detailed below for the embedded derivatives is a sensitivity of the fair value to immediate 10% favourable and adverse changes in the key assumptions.


	At December 31, 2005

Remaining contract terms		3 to 13 years
Contractual/notional amount		8,220 million therms
Discount rate — nominal risk free		4.5%
Fair value asset (liability)		$(2,590) million


	Natural gas			Gas oil and						Discount
	price			fuel oil price			Power price			rate

	($ million
Favourable 10% change		408			30			(63	)		34
Unfavourable 10% change		(427	)		(45	)		58			(34	)

F-96

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 37 — Derivative financial instruments (concluded)

The trading result of embedded derivatives held for trading is shown below.


	Year ended
	December 31, 2005

	Net gain (loss)
($-

	million)
Natural gas and NGL embedded derivatives		(2,034)
Interest rate embedded derivatives		(13)

		(2,047)

Note 38 — Financial instruments (UK GAAP)

The following information for 2004 and 2003 shows certain of the disclosures required by UK GAAP (FRS 13 ‘Derivatives and other Financial Instruments: Disclosures’) (FRS 13).

Financial instruments comprise primary financial instruments (cash and cash equivalents, trade and other receivables, loans, other investments, trade and other payables, finance debt and provisions) and derivative financial instruments (interest rate contracts, foreign exchange contracts, oil price contracts and natural gas price contracts and power price contracts). Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forwards, futures contracts, swap agreements and options. Oil, natural gas, NGL and power price contracts are those that require settlement in cash and include futures contracts, swap agreements and options. Oil, natural gas, NGL and power price contracts that require physical delivery are not financial instruments. However, if it is normal market practice for a particular type of oil, natural gas, NGL and power contract, despite having contract terms that require settlement by delivery, to be extinguished other than by physical delivery (e.g., by cash payment) it is called a cash-settled commodity contract. Contracts of this type are included with derivatives in the disclosures in Notes 39 and 40.

With the exception of the table of currency exposures shown on page F-100, short-term trade and other receivables and trade and other payables that arise directly from the Group’s operations have been excluded from the disclosures contained in this note, as permitted by FRS 13.


	*Maturity profile of financial liabilities*

The profile of the maturity of the financial liabilities included in the Group’s balance sheet is shown in the table below.


		At December 31, 2004						At December 31, 2003

				Other						Other
		Finance		financial				Finance		financial
		debt		liabilities		Total		debt		liabilities		Total
-
		----------------------------------------------------------------------($-
		million
Due within:	1 year		10,184		5,152		15,336		9,456		4,857		14,313
	1 to 2 years		3,046		2,640		5,686		2,702		1,617		4,319
	2 to 5 years		6,105		810		6,915		5,105		2,034		7,139
	Thereafter		3,756		1,603		5,359		5,062		2,042		7,104

			23,091		10,205		33,296		22,325		10,550		32,875

F-97

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 38 — Financial instruments (UK GAAP) (continued)


	*Interest rate and currency of financial liabilities*

The interest rate and currency profile of the financial liabilities of the Group, at December 31, after taking into account the effect of interest rate swaps, currency swaps and forward contracts, is set out below.


		Fixed rate						Floating rate				Interest free

				Weighted
				average								Weighted
		Weighted		time for				Weighted				average
		average		which				average				time
		interest		rate is				interest				until
		rate		fixed		Amount		rate		Amount		maturity			Amount		Total

		(%)		(Years)		($ million)		(%)		($ million)		(Years)			($ million)		($ million)
At December 31, 2004
Finance debt
	US dollar		7		11		707		3		21,789		—			—		22,496
	Sterling		—		—		—		5		96		—			—		96
	Other currencies		9		15		167		4		332		—			—		499

							874				22,217					—		23,091

Other financial liabilities
	US dollar		3		2		1,522		5		573		4			6,561		8,656
	Sterling		—		—		—		—		—		4			716		716
	Other currencies		4		4		15		2		46		4			772		833

							1,537				619			��		8,049		10,205

Total							2,411				22,836					8,049		33,296

At December 31, 2003
Finance debt
	US dollar		8		14		578		2		20,991		—			—		21,569
	Sterling		—		—		—		4		107		—			—		107
	Other currencies		9		15		141		3		508		—			—		649

							719				21,606					—		22,325

Other financial liabilities
	US dollar		3		3		2,899		6		242		4			5,552		8,693
	Sterling		—		—		—		—		—		5			716		716
	Other currencies		5		4		303		—		—		6			838		1,141

							3,202				242					7,106		10,550

Total							3,921				21,848					7,106		32,875

F-98

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 38 — Financial instruments (UK GAAP) (continued)


		At
		December 31,

		2004		2003

		($ million)
Analysis of the above financial liabilities by balance sheet caption:
Current liabilities
	Finance debt		10,184		9,456
	Derivative financial instruments		5,074		4,145
	Provisions		78		214
Noncurrent liabilities
	Other payables		3,581		4,630
	Derivative financial instruments		158		344
	Finance debt		12,907		12,869
	Provisions		1,314		1,217

			33,296		32,875

The other financial liabilities comprise various accruals, sundry creditors and provisions relating to the Group’s normal commercial operations, with payment dates spread over a number of years.

The proportion of floating rate debt at December 31, 2004 was 96% of total finance debt outstanding. Aside from debt issued in the US municipal bond markets, interest rates on floating rate debt denominated in US dollars are linked principally to London Inter-Bank Offer Rate (LIBOR), while rates on debt in other currencies are based on local market equivalents. The Group monitors interest rate risk using a process of sensitivity analysis. Assuming no changes to the finance debt and hedges described above, it is estimated that a change of 1% in the general level of interest rates on January 1, 2005 would change 2005 profit before tax by approximately $215 million.

Interest rate swaps and futures are used by the Group to modify the interest characteristics of its long-term finance debt from a fixed to a floating rate basis or vice versa. The following table indicates the types of instruments used and their weighted average interest rates as at December 31.


	At
	December 31,

	2004			2003

	($ million
	except
	percentages)
Receive fixed rate swaps — notional amount		8,182			7,432
Average receive fixed rate		3.1	%		3.1	%
Average pay floating rate		2.3	%		1.1	%

F-99

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 38 — Financial instruments (UK GAAP) (continued)


	*Currency exchange rate risk*

The monetary assets and monetary liabilities of the Group in currencies other than in the functional currency of individual operating units are summarized below. These currency exposures arise from normal trading activities.


	Net foreign currency monetary assets (liabilities)

										Other
Functional currency	US dollar			Sterling			Euro			currencies			Total

	($ million)
At December 31, 2004
US dollar		—			374			2			(942	)		(566	)
Sterling		314			—			380			66			760
Other currencies		(269	)		(51	)		(25	)		(237	)		(582	)

Total		45			323			357			(1,113	)		(388	)

At December 31, 2003
US dollar		—			191			(24	)		39			206
Sterling		67			—			308			34			409
Other currencies		(1,148	)		(25	)		(27	)		(131	)		(1,331	)

Total		(1,081	)		166			257			(58	)		(716	)

In accordance with its policy for managing its foreign exchange rate risk, the Group enters into various types of foreign exchange contracts, such as currency swaps, forwards and options. The fair values and carrying amounts of these derivatives are shown in the fair value table in Note 40.

F-100

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 38 — Financial instruments (UK GAAP) (continued)


	*Interest rate and currency of financial assets*

The following table shows the interest rate and currency profile of the Group’s material financial assets.


	Fixed rate						Floating rate				Interest free

			Weighted
			average								Weighted
	Weighted		time for				Weighted				average
	average		which				average				time
	interest		rate is				interest				until
	rate		fixed		Amount		rate		Amount		maturity		Amount		Total

	(%)		(Years)		($ million)		(%)		($ million)		(Years)		($ million)		($ million)
At December 31, 2004
US dollar		10		11		72		4		661		5		5,224		5,957
Sterling		8		2		101		3		428		5		864		1,393
Other currencies		—		—		—		3		830		5		1,221		2,051

						173				1,919				7,309		9,401

At December 31, 2003
US dollar		—		—		—		3		1,015		4		2,060		3,075
Sterling		8		2		91		3		947		5		560		1,598
Other currencies		3		2		19		4		697		5		2,073		2,789

						110				2,659				4,693		7,462


		At
		December 31,

		2004		2003

		($ million)
Analysis of the above financial assets by balance sheet caption:
Noncurrent assets
	Other investments		394		1,452
	Loans		811		852
	Other receivables		429		495
	Derivative financial instruments		898		534
Current assets
	Loans		193		182
	Derivative financial instruments		5,317		1,891
	Cash and cash equivalents		1,359		2,056

			9,401		7,462

The floating rate financial assets earn interest at various rates set principally with respect to LIBOR or the local market equivalent.

Fixed asset investments included in the table above are held for the long term and have no maturity period. They are excluded from the calculation of weighted average time until maturity.

F-101

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 38 — Financial instruments (UK GAAP) (continued)

Similarly, cash and cash equivalents and derivative financial instruments, which are highly liquid financial assets, are excluded from the calculation of weighted average time until maturity.

Note 39 — Derivative financial instruments (UK GAAP)

The following information for 2004 and 2003 shows certain of the disclosures required by UK GAAP (FRS 13 ‘Derivatives and other Financial Instruments: Disclosures’).

The Group uses derivative financial instruments (derivatives) to manage certain exposures to fluctuations in foreign currency exchange rates and interest rates and to manage some of its margin exposure from changes in oil, natural gas, NGL and power prices. Derivatives are also traded in conjunction with these risk management activities.

The purpose for which a derivative contract is used is identified at inception. To qualify as a derivative for risk management, the contract must be in accordance with established guidelines that ensure it is effective in achieving its objective. All contracts not identified at inception as being for the purpose of risk management are designated as being held for trading purposes and accounted for using the fair value method, as are all oil price derivatives.

The Group accounts for derivatives using the following methods:

Fair value method. Derivatives are carried on the balance sheet at fair value (‘marked to market’), with changes in that value recognized in earnings of the period. This method is used for all derivatives that are held for trading purposes. Interest rate contracts traded by the Group include futures, swaps, options and swaptions. Foreign exchange contracts traded include forwards and options. Oil, natural gas, NGL and power price contracts traded include swaps, options and futures.

Accrual method. Amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. This method is used for derivatives held to manage interest rate risk. These are principally swap agreements used to manage the balance between fixed and floating interest rates on long-term finance debt. Other derivatives held for this purpose may include swaptions and futures contracts. Amounts payable or receivable in respect of these derivatives are recognized as adjustments to interest expense over the period of the contracts. Changes in the derivative’s fair value are not recognized.

Deferral method. Gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. This method is used for derivatives used to convert non-US dollar borrowings into US dollars, to hedge significant non-US dollar firm commitments or anticipated transactions, and to manage some of the Group’s exposure to natural gas, NGL and power price fluctuations. Derivatives used to convert non-US dollar borrowings into US dollars include foreign currency swap agreements and forward contracts. Gains and losses on these derivatives are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. Derivatives used to hedge significant non-US dollar transactions include foreign currency forward contracts and options and to hedge natural gas, NGL and power price exposures include swaps, futures and options. Gains and losses on these contracts and option premiums paid are also deferred and recognized in the income statement or as adjustments to carrying amounts, as appropriate, when the hedged transaction occurs.

Where derivatives used to manage interest rate risk or to convert non-US dollar debt or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged

F-102

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 39 — Derivative financial instruments (UK GAAP) (continued)

transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item.


	*Risk management*

Gains and losses on derivatives used for risk management purposes are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item. Where such derivatives used for hedging purposes are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis which matches the timing and accounting treatment of the underlying hedged item. The unrecognized and carried-forward gains and losses on derivatives used for hedging, and the movements therein, are shown in the following table.


		Not recognized in								Carried forward in
		the accounts								the balance sheet

		Gains		Losses			Total			Gains		Losses			Total
-
												------------------------($-
							million
Gains and losses at January 1, 2004			331		(130	)		201			1,003		(425	)		578
	of which accounted for in income in 2004		98		(28	)		70			438		(75	)		363
Gains and losses at December 31, 2004			487		(408	)		79			1,063		(364	)		699
	of which expected to be recognized in income in 2005		259		(267	)		(8	)		265		(77	)		188

Gains and losses at January 1, 2003			526		(450	)		76			352		(28	)		324
	of which accounted for in income in 2003		96		(51	)		45			200		(14	)		186
Gains and losses at December 31, 2003			331		(130	)		201			1,003		(425	)		578
	of which expected to be recognized in income in 2004		98		(28	)		70			438		(75	)		363


	*Trading activities*

F-103

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 39 — Derivative financial instruments (UK GAAP) (continued)


	At December 31,

	2004					2003

	Fair value		Fair value			Fair value		Fair value
	asset		liability			asset		liability
-
								----------($-
			million
Interest rate contracts		—		—			—		—
Foreign exchange contracts		36		(90	)		30		(54	)
Oil price contracts		1,162		(1,177	)		586		(667	)
Natural gas and NGL price contracts		802		(624	)		858		(711	)
Power price contracts		82		(12	)		548		(514	)

		2,082		(1,903	)		2,022		(1,946	)

The Group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of theend-of-day exposures, and the history of one-day price movements over the previous 12 months, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations which is equivalent to a 99.7% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on only one occasion per year if the portfolio were left unchanged.

The Group calculates value at risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-at-risk model takes account of derivative financial instruments such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options; and oil, natural gas, NGL and power price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. The value-at-risk calculation for oil, natural gas, NGL and power price exposure also includes cash-settled commodity contracts such as forward contracts.

The following table shows values at risk for trading activities.


	Years ended December 31,

	2004								2003

	High		Low		Average		Year end		High		Low		Average		Year end
-
	------------------------------------------------------------------------------------------------------------($-
	million
Interest rate trading		1		—		—		—		1		—		—		—
Foreign exchange trading		4		1		1		1		4		—		2		1
Oil price trading		55		18		29		45		34		17		26		27
Natural gas price trading		42		11		23		18		29		4		16		18
Power price trading		18		2		8		7		13		—		4		6

F-104

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 39 — Derivative financial instruments (UK GAAP) (concluded)

The presentation of trading results shown in the table below includes certain activities of BP’s trading units that involves the use of derivative financial instruments in conjunction with physical and paper trading of oil, natural gas, NGL and power. It is considered that a more comprehensive representation of the Group’s oil, natural gas, NGL and power price trading activities is given by aggregating the gain or loss on such derivatives together with the gain or loss arising from the physical and paper trades to which they relate, representing the net result of the trading portfolio.


	Years ended
	December 31,

	2004		2003

	Net gain		Net gain
	(loss)		(loss)

	($ million
Interest rate trading		4		9
Foreign exchange trading		136		118
Oil price trading		1,371		825
Natural gas and NGL price trading		461		341
Power price trading		160		119

		2,132		1,412

Note 40 — Fair values of financial assets and liabilities (UK GAAP)

The following information for 2004 and 2003 shows certain of the disclosures required by UK GAAP (FRS 13 ‘Derivatives and Other Financial Instruments: Disclosures’) (FRS13).

The estimated fair value of the Group’s financial instruments is shown in the table below. The table also shows the ‘net carrying amount’ of the financial asset or liability. This amount represents the net book value, i.e. market value when acquired or latermarked-to-market. Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forward and futures contracts, swap agreements and options. Oil, natural gas, NGL and power price contracts include futures contracts, swap agreements and options and cash-settled commodity contracts such as forward contracts.

Short-term trade and other receivables and payables that arise directly from the Group’s operations have been excluded from the disclosures contained in this note, as permitted by FRS 13.

The fair value and carrying amounts of finance debt shown below exclude the effects of currency swaps, interest rate swaps and forward contracts (which are included for presentation in the balance sheet). Long-term borrowings in the table below include debt that matures in the year from December 31, 2004, whereas in the balance sheet long-term debt of current maturity is reported under

F-105

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 40 — Fair values of financial assets and liabilities (UK GAAP) (continued)

amounts falling due within one year. Long-term borrowings also include US Industrial Revenue/ Municipal Bonds classified on the balance sheet as repayable within one year.


		At December 31,

		2004						2003

					Net carrying						Net carrying
		Net fair			amount			Net fair			amount
		value asset			asset			value asset			asset
		(liability)			(liability)			(liability)			(liability)

		($ million
Noncurrent assets
	Other investments		738			394			3,380			1,452
	Loans		811			811			852			852
	Other receivables		429			429			495			495
	Derivative financial instruments		898			898			534			534
Current assets
	Loans		193			193			182			182
	Derivative financial instruments		5,317			5,317			1,891			1,891
	Cash and cash equivalents		1,359			1,359			2,056			2,056
Finance debt
	Short-term borrowings		(5,003	)		(5,003	)		(5,059	)		(5,059	)
	Long-term borrowings		(16,800	)		(16,344	)		(16,190	)		(15,559	)
	Net obligations under finance leases		(2,608	)		(2,579	)		(2,479	)		(2,452	)
	Derivative financial instruments		1,084			835			941			745
Noncurrent liabilities
	Other payables		(3,581	)		(3,581	)		(4,630	)		(4,630	)
	Provisions		(1,314	)		(1,314	)		(1,217	)		(1,217	)
	Derivative financial instruments		(158	)		(158	)		(344	)		(344	)
Current liabilities
	Derivative financial instruments		(5,074	)		(5,074	)		(4,145	)		(4,145	)
	Provisions		(78	)		(78	)		(214	)		(214	)

The following methods and assumptions were used by the Group in estimating its fair value disclosures for its financial instruments:

Noncurrent assets — Other investments. The fair value of listed fixed asset investments has been determined by reference to market prices. The carrying amount reported in the balance sheet for unlisted fixed asset investments approximates their fair value.

Noncurrent assets — Loans. The loans generally bear interest at floating rates, so the fair value of loans is estimated not to be materially different from its carrying value.

Noncurrent assets — Other receivables. The fair value of other receivables is estimated not to be materially different from its carrying value.

Current assets — Loans. The loans generally bear interest at floating rates, so the fair value of loans is estimated not to be materially different from its carrying value.

F-106

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 40 — Fair values of financial assets and liabilities (UK GAAP) (concluded)

Current assets — Cash and cash equivalents. As a result of their short maturities, the carrying value of cash equivalents approximates their fair value.

Finance debt. The carrying amount of the Group’s short-term borrowings, which mainly comprise commercial paper, bank loans and overdrafts, approximates their fair value. The fair value of the Group’s long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not available, discounted cash flow analyses, based on the Group’s current incremental borrowing rates for similar types and maturities of borrowing. Swaps and forward contracts used to hedge finance debt is offset against the carrying value of the debt.

Noncurrent liabilities — Other payables. Deferred consideration for the acquisition of our interest in TNK-BP is discounted to the present value of the future payments. The carrying value thus approximates the fair value. The remaining liabilities are predominantly interest-free. In view of their short maturities, the reported carrying amount is estimated to approximate the fair value.

Noncurrent liabilities — Provisions. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. The carrying amount of provisions thus approximates the fair value.

Current liabilities — Provisions. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. The carrying amount of provisions thus approximates the fair value.

Derivative financial instruments (including cash-settled commodity contracts). The fair values of the Group’s interest rate and foreign exchange contracts are based on pricing models that take into account relevant market data. The fair value of the Group’s oil, natural gas, NGL and power price contracts (future contracts, swap agreements, options and forward contracts) is based on market prices.

Note 41 — Finance debt


		At December 31, 2005						At December 31, 2004						At December 31, 2003

		Within		After				Within		After				Within		After
		1 year (a)		1 Year		Total		1 year (a)		1 Year		Total		1 year (a)		1 year		Total
-
		--------------------------------------------------------------------------------------------($-
		million
Bank loans			155		547		702		250		457		707		205		253		458
Other loans			8,717		8,962		17,679		9,819		10,167		19,986		9,161		10,524		19,685

Total borrowings			8,872		9,509		18,381		10,069		10,624		20,693		9,366		10,777		20,143
Net obligations
	under finance leases		60		721		781		115		2,283		2,398		90		2,092		2,182

			8,932		10,230		19,162		10,184		12,907		23,091		9,456		12,869		22,325


(a)		Amounts due within one year include current maturities of long-term debt.

Included within Other loans repayable within one year above are US Industrial Revenue/ Municipal Bonds of $2,462 million (2004 $2,344 million and 2003 $2,362 million) with maturity periods ranging

F-107

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 41 — Finance debt (continued)

from 2 to 35 years. They are classified as repayable within one year, as required under IFRS, as the bondholders typically have the option to tender these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP has not experienced any significant repurchases. BP considers these bonds to represent long-term funding when assessing the maturity profile of its finance debt and they are reflected as such in the borrowings repayment schedule below. Other similar loans linked to long-term gas supply contracts of $992 million (2004 $280 million and 2003 nil) that mature over 10 years have been reported in the same way.

At December 31, 2005, the Group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,500 million expiring in 2006 ($4,500 million expiring in 2005 and $3,700 million expiring in 2004). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. The Group expects to renew the facilities on an annual basis. Certain of these facilities support the Group’s commercial paper programme.

At December 31, 2005, the Group’s share of third-party finance debt of jointly controlled entities and associates was $3,266 million (2004 $2,821 million and 2003 $2,151 million) and $970 million (2004 $1,048 million and 2003 $922 million) respectively. These amounts are not reflected in the Group’s debt on the balance sheet.

We have in place a European Debt Issuance Programme (DIP) under which the Group may raise $8 billion of debt for maturities of one month or longer. At June 28, 2006 the amount drawn down against the DIP was $6,988 million.

Under UK GAAP, where finance debt is swapped into another currency, the finance debt is accounted in the swap currency and not in the original currency of denomination. Total finance debt in 2004 and 2003 included an asset of $835 million and $745 million respectively for the carrying value of currency swaps and forward contracts.


	*Fair values of finance debt*

For 2005, the estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet. Both the fair value and the carrying amount include the effects of currency swaps, interest rate swaps and forward contracts.

Long-term borrowings in the table below include debt that matures in the year from December 31, 2005, whereas in the balance sheet the amount would be reported under current liabilities. Long-term borrowings also include US Industrial Revenue/ Municipal Bonds classified on the balance sheet as current liabilities.

The carrying value of the Group’s short-term borrowings, comprising mainly commercial paper, bank loans and overdrafts, approximates their fair value. The fair value of the Group’s long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not

F-108

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 41 — Finance debt (continued)

available, discounted cash flow analyses based on the Group’s current incremental borrowing rates for similar types and maturities of borrowing.


	Year ended
	December 31,
	2005

	Fair		Carrying
	value		amount
-
	------------------------($-
	million
Short-term borrowings		3,297		3,297
Long-term borrowings		15,313		15,084
Net obligations under finance leases		803		781

Total finance debt		19,413		19,162


Analysis of borrowing by year
of expected repayment
		At December 31, 2005
								At December 31, 2004						At December 31, 2003

		Bank loans		Other		Total		Bank loans		Other		Total		Bank loans		Other		Total
				loans						loans						loans
-
		--------------------------------------------------------------------------------------------($-
		million
Due after	10 years		—		2,842		2,842		1		2,845		2,846		—		2,865		2,865
Due within	10 years		18		203		221		29		68		97		—		24		24
	9 years		21		182		203		20		83		103		—		377		377
	8 years		24		188		212		22		478		500		—		291		291
	7 years		26		558		584		28		330		358		—		—		—
	6 years		34		446		480		36		139		175		7		1,737		1,744
	5 years		35		537		572		33		1,742		1,775		7		996		1,003
	4 years		35		2,223		2,258		29		1,579		1,608		8		1,362		1,370
	3 years		98		2,219		2,317		251		2,510		2,761		193		2,593		2,786
	2 years		256		3,018		3,274		8		3,017		3,025		38		2,641		2,679

			547		12,416		12,963		457		12,791		13,248		253		12,886		13,139
	1 year		155		5,263		5,418		250		7,195		7,445		205		6,799		7,004

			702		17,679		18,381		707		19,986		20,693		458		19,685		20,143

Amounts included above repayable by installments, part of which falls due after five years from December 31, are as follows:


	At December 31,

	2005		2004		2003
-
	--------------------------------------($-
	million
After five years		192		204		14
Within five years		118		76		82

		310		280		96

F-109

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 41 — Finance debt (continued)

Interest rates on borrowings repayable wholly or partly more than five years from December 31, 2005 range from 2% to 12% with a weighted average of 5%. The weighted average interest rate on finance debt is 5%.


	Fixed rate						Floating rate				Interest free

			Weighted
			average								Weighted
	Weighted		time for				Weighted				average
	average		which				average				time
	interest		rate is				interest				until
	rate		fixed		Amount		rate		Amount		maturity		Amount		Total
($($($($-	)

	(%		(Years		million		(%		million		(Years		million million
Year ended December 31, 2005
US dollar		7		11		665		5		18,073		—		—		18,738
Sterling		—		—		—		6		76		—		—		76
Euro		—		—		—		3		150		—		—		150
Other currencies		9		14		157		12		41		—		—		198

						822				18,340				—		19,162

Year ended December 31, 2004
US dollar		7		11		707		3		21,789		—		—		22,496
Sterling		—		—		—		5		96		—		—		96
Euro		—		—		—		3		297		—		—		297
Other currencies		9		15		167		8		35		—		—		202

						874				22,217		—		—		23,091

Year ended December 31, 2003
US dollar		8		14		578		2		20,991		—		—		21,569
Sterling		—		—		—		4		107		—		—		107
Euro		—		—		—		3		125		—		—		125
Other currencies		9		15		141		3		383		—		—		524

						719				21,606				—		22,325

The proportion of floating rate debt at December 31, 2005 was 96% of total finance debt outstanding. Aside from debt issued in the US municipal bond markets, interest rates on floating rate debt denominated in US dollars are linked principally to London Inter-Bank Offer Rate (LIBOR), while rates on debt in other currencies are based on local market equivalents. The Group monitors interest rate risk using a process of sensitivity analysis. Assuming no changes to the finance debt and hedges described above, it is estimated that a change of 1% in the general level of interest rates on January 1, 2006 would change 2006 profit before tax by approximately $180 million.

The Group uses finance leases to acquire property, plant and equipment. These leases have terms of renewal but no purchase options and escalation clauses. Renewals are at the option of the lessee.

F-110

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 41 — Finance debt (continued)

During the year, the Group terminated its finance leases on the petrochemicals manufacturing plant at Grangemouth, Scotland. Future minimum lease payments under finance leases are set out below.


	*Obligations under finance leases*

The future minimum lease payments together with the present value of the net minimum lease payments were as follows:


		At December 31,
		2005
($-		)

		million
2006			78
2007			78
2008			80
2009			80
2010			82
Thereafter			838

			1,236
Less: amount representing lease interest			455

Present value of net minimum finance lease payments			781

of which — due within one year			60
	— due within 2 to 5 years		133
	— due thereafter		588

The following information is presented in compliance with the requirements of US GAAP.

Bank and other loans — long term


	Weighted
	average
	interest rate
	at
	December 31,				At December 31,

	2005		2004		2005		2004

	(%				($ million
US dollar		5		3		9,178		10,374
Sterling		7		5		29		25
Euros		5		4		144		84
Other currencies		9		9		158		141

						9,509		10,624

F-111

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 41 — Finance debt (concluded)

Bank and other loans — short term


	At
	December 31,

	2005		2004

	($ million
Current maturities of long-term debt		3,007		2,622
Commercial paper		1,911		4,180
Bank loans		155		250
Other		3,799		3,017

		8,872		10,069


	Weighted
	average
	interest rate
	at
	December 31,

	2005		2004
)

	(%
Commercial paper		4		2
Bank loans and other borrowings		7		4
US Industrial Revenue/ Municipal bonds		4		2

F-112

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 42 — Analysis of change in net debt

Net debt is current and noncurrent finance debt less cash and cash equivalents. The net debt ratio is the ratio of net debt to net debt plus total equity. The net debt ratio at December 31, 2005 was 17% (2004 22% and 2003 22%).

Movement in net debt


	Year ended December 31, 2005									Year ended December 31, 2004									Year ended December 31, 2003

				Cash and									Cash and									Cash and
	Finance			cash						Finance			cash						Finance			cash
	debt			equivalents			Net debt			debt			equivalents			Net debt			debt			equivalents		Net debt

	($ million
At January 1		(23,091	)		1,359			(21,732	)		(22,325	)		2,056			(20,269	)		(22,008	)		1,716		(20,292	)
Adoption of IAS 39		(147	)		—			(147	)		—			—			—			—			—		—

Restated		(23,238	)		1,359			(21,879	)		(22,325	)		2,056			(20,269	)		(22,008	)		1,716		(20,292	)
Exchange adjustments		(44	)		(88	)		(132	)		(403	)		91			(312	)		(199	)		121		(78	)
Debt acquired		—			—			—			—			—			—			(15	)		—		(15	)
Net cash flow		3,803			1,689			5,492			(431	)		(788	)		(1,219	)		(760	)		219		(541	)
Fair value hedge adjustment		171			—			171			—			—			—			—			—		—
Debt transferred to TNK-BP		—			—			—			—			—			—			93			—		93
Exchange of Exchangeable Bonds for Lukoil American Depositary Shares		—			—			—			—			—			—			420			—		420
Other movements		146			—			146			68			—			68			144			—		144

At December 31		(19,162	)		2,960			(16,202	)		(23,091	)		1,359			(21,732	)		(22,325	)		2,056		(20,269	)

Equity								80,450									78,235								70,264

F-113

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 43 — Provisions


								Litigation
								and
		Decommissioning			Environmental			other			Total
-
		--------------------------------------------------------($-
		million
At January 1, 2005			5,572			2,457			1,570			9,599
Exchange adjustments			(38	)		(32	)		(35	)		(105	)
New provisions			1,023			565			1,964			3,552
Write-back of unused provisions			—			(335	)		(86	)		(421	)
Unwinding of discount			122			47			32			201
Utilization			(128	)		(366	)		(650	)		(1,144	)
Deletion			(101	)		(25	)		—			(126	)

At December 31, 2005			6,450			2,311			2,795			11,556

Of which
	Expected to be incurred within 1 year		162			489			951			1,602
	Expected to be incurred in more than 1 year		6,288			1,822			1,844			9,954


								Litigation
								and
		Decommissioning			Environmental			other			Total
-
		--------------------------------------------------------($-
		million
At January 1, 2004			4,720			2,298			1,581			8,599
Exchange adjustments			213			21			25			259
New provisions			286			587			298			1,171
Write-back of unused provisions			—			(151	)		(64	)		(215	)
Unwinding of discount			118			55			23			196
Change in discount rate			434			40			1			475
Utilization			(87	)		(393	)		(294	)		(774	)
Deletion			(112	)		—			—			(112	)

At December 31, 2004			5,572			2,457			1,570			9,599

Of which
	Expected to be incurred within 1 year		124			513			78			715
	Expected to be incurred in more than 1 year		5,448			1,944			1,492			8,884

F-114

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 43 — Provisions (concluded)


								Litigation
								and
		Decommissioning			Environmental			other			Total
-
		--------------------------------------------------------($-
		million
At January 1, 2003			4,168			2,122			1,546			7,836
Exchange adjustments			257			28			28			313
New provisions			1,159			599			331			2,089
Write-back of unused provisions			—			(84	)		(64	)		(148	)
Unwinding of discount			107			46			20			173
Utilization			(121	)		(337	)		(273	)		(731	)
Deletion			(850	)		(76	)		(7	)		(933	)

At December 31, 2003			4,720			2,298			1,581			8,599

Of which
	Expected to be incurred within 1 year		99			272			364			735
	Expected to be incurred in more than 1 year		4,621			2,026			1,217			7,864

The Group makes full provision for the future cost of decommissioning oil and natural gas production facilities and related pipelines on a discounted basis on the installation of those facilities. At December 31, 2005, the provision for the costs of decommissioning these production facilities and pipelines at the end of their economic lives was $6,450 million (2004 $5,572 million and 2003 $4,720 million). The provision has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2004 2.0% and 2003 2.5%). These costs are expected to be incurred over the next 30 years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs. The estimated aggregate costs used in assessing the provision were $9,511 million.

Provisions for environmental remediation are made when aclean-up is probable and the amount reasonably determinable. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or closure of inactive sites. The provision for environmental liabilities at December 31, 2005 was $2,311 million (2004 $2,457 million and 2003 $2,298 million). The provision has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2004 2.0% and 2003 2.5%). The majority of these costs are expected to be incurred over the next 10 years. The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the Group’s share of liability. The estimated aggregate costs used in assessing the provision were $2,501 million.

The Group also holds provisions for litigation, expected rental shortfalls on surplus properties, and sundry other liabilities. Included within the new provisions made for 2005 is an amount of $1,200 million in respect of the Texas City incident of which $492 million has been disbursed to claimants by the end of 2005. To the extent that these liabilities are not expected to be settled within the next three years, the provisions are discounted using either a nominal discount rate of 4.5% (2004 4.5% and 2003 4.5%) or a real discount rate of 2.0% (2004 2.0% and 2003 2.5%), as appropriate.

F-115

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits

Most Group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as the employees’ pensionable salary and length of service. Defined benefit plans may be externally funded or unfunded. The assets of funded plans are generally held in separately administered trusts.

Contributions to funded defined benefit plans are based on advice from independent actuaries using actuarial methods, the objective of which is to provide adequate funds to meet pension obligations as they fall due. During 2005, contributions of $340 million (2004 $249 million and 2003 $258 million) and $279 million (2004 $30 million and 2003 $2,189 million) were made to the UK plans and US plans respectively. In addition, contributions of $140 million (2004 $116 million and 2003 $86 million) were made to other funded defined benefit plans. The aggregate level of contributions in 2006 is expected to be approximately $750 million.

Certain Group companies, principally in the US, provide postretirement healthcare and life insurance benefits to their retired employees and dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum period of service. The plans are funded to a limited extent.

The cost of providing pensions and other postretirement benefits is assessed annually by independent actuaries using the projected unit method. The date of the most recent actuarial review was December 31, 2005.

F-116

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

The material financial assumptions used for estimating the benefit obligations of the various plans are set out below. The assumptions used to evaluate accrued pension and other postretirement benefits at December 31, in any year are used to determine pension and other postretirement expense for the following year, that is, the assumptions at December 31, 2005 are used to determine the pension liabilities at that date and the pension cost for 2006.


		At December 31,

		2005		2004		2003

		(%
UK plans
	Discount rate for plan liabilities		4.75		5.25		5.5
	Rate of increase in salaries		4.25		4.0		4.0
	Rate of increase for pensions in payment		2.5		2.5		2.5
	Rate of increase in deferred pensions		2.5		2.5		2.5
	Inflation		2.5		2.5		2.5
US plans
	Discount rate for plan liabilities		5.50		5.75		6.0
	Rate of increase in salaries		4.25		4.0		4.0
	Rate of increase for pensions in payment		nil		nil		nil
	Rate of increase in deferred pensions		nil		nil		nil
	Inflation		2.50		2.5		2.5
Other plans
	Discount rate for plan liabilities		4.0		5.0		5.5
	Rate of increase in salaries		3.25		4.0		4.0
	Rate of increase for pensions in payment		1.75		2.5		2.5
	Rate of increase in deferred pensions		1.0		2.5		2.5
	Inflation		2.0		2.5		2.5

In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to the latest available tables adjusted where appropriate to reflect the experience of the Group. BP’s most substantial pension liabilities are in the UK and US, where these tables lead to a further life expectancy for a male/female currently aged 60 of 23/26 years in the UK and 22/26 years in the US.


															2013 and
Assumed future US healthcare cost															subsequent
trend rate	2006		2007		2008		2009		2010		2011		2012		years

	(%
Beneficiaries aged under 65		9.0		8.0		7.0		6.0		5.5		5.0		5.0		5.0
Beneficiaries aged over 65		11.0		9.5		8.5		7.5		6.5		6.0		5.5		5.0

F-117

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

BP’s postretirement medical plans in the US provide among other things prescription drug coverage for Medicare-eligible retirees. The Group’s obligation for other postretirement benefits at December 31, 2004 and 2005 reflects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors toco-ordinate with the Medicare benefit. BP reflected the impact of the legislation by reducing its actuarially determined obligation for postretirement benefits at December 31, 2004 and reducing the net cost for postretirement benefits in subsequent periods. The reduction in liability was reflected in the 2004 results as an actuarial gain (assumption change).

Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligation of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.

A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. The long-term asset allocation policy for the major plans is as follows:


Asset category	Policy range

	(%
Total equity		55-85
Fixed income/cash		15-35
Property/real estate		0-10

Some of the Group’s pension funds use derivatives to manage their asset mix and the level of risk. The Group’s main pension funds do not directly invest in either securities or real property of the Company or of any affiliate.

Return on asset assumptions reflect the Group’s expectations built up by asset class and by country. The Group’s expectation is derived from a combination of historical returns over the long term and the forecasts of market professionals.

F-118

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

The expected long-term rates of return and market values of the various categories of asset held by the significant defined benefit plans at December 31, are set out below.


		At December 31, 2005				At December 31, 2004				At December 31, 2003

		Expected				Expected				Expected
		long-term				long-term				long-term
		rate of		Market		rate of		Market		rate of		Market
		return		value		return		value		return		value
($($($-		)

		(%		million		(%		million		(%		million
UK pension plans
	Equities		7.50		18,465		7.50		17,329		7.50		14,642
	Bonds		4.25		2,719		4.50		2,859		4.75		2,477
	Property		6.50		1,097		6.50		1,660		6.50		1,336
	Cash		3.50		1,001		4.00		459		4.00		769

			7.00		23,282		7.00		22,307		7.00		19,224

US pension plans
	Equities		8.50		5,961		8.50		6,043		8.50		5,650
	Bonds		4.75		1,079		4.75		1,057		4.75		1,018
	Property		8.00		21		8.00		28		8.00		41
	Cash		3.00		256		3.00		55		3.50		148

			8.00		7,317		8.00		7,183		8.00		6,857

US other postretirement benefit plans
	Equities		8.50		20		8.50		21		8.50		24
	Bonds		4.75		8		4.75		9		4.75		9

			7.25		28		7.25		30		8.00		33

Other plans
	Equities		7.50		991		8.00		933		7.50		686
	Bonds		4.00		943		4.25		857		4.75		737
	Property		5.75		130		5.25		114		6.50		129
	Cash		1.50		216		3.50		288		4.00		187

			5.50		2,280		6.00		2,192		6.00		1,739

F-119

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

The assumed rate of investment return and discount rate have a significant effect on the amounts reported. A one-percentage-point change in these assumptions for the Group’s plans would have had the following effects:


		1-Percentage			1-Percentage
		point increase			point decrease

		($ million
Investment return
	Effect on pension expense in 2006		(346	)		348
Discount rate
	Effect on pension expense in 2006		(78	)		93
	Effect on pension obligation at December 31, 2005		(4,911	)		6,379


	1-Percentage		1-Percentage
	point increase		point decrease

	($ million
Effect on US postretirement benefit expense in 2006		32		(26	)
Effect on US postretirement obligation at December 31, 2005		388		(319	)

F-120

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


	Year ended December 31, 2005

							US post-
	UK			US			retirement
	pension			pension			benefit			Other
	plans			plans			plans			plans			Total
-
	-------------------------------------------------------------($-
	million
Analysis of the amount charged to profit before interest and taxation
Current service cost		379			216			50			140			785
Past service cost		5			(10	)		(5	)		51			41
Settlement, curtailment and special termination benefits		37			—			—			10			47
Payments to defined contribution plans		—			158			—			14			172

Total operating charge (income)		421			364			45			215			1,045
Innovene operations		(38	)		(24	)		(3	)		(21	)		(86	)

Continuing operations (a)		383			340			42			194			959

Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets		1,456			557			2			123			2,138
Interest on plan liabilities		(1,003	)		(444	)		(207	)		(368	)		(2,022	)

Other finance income (expense)		453			113			(205	)		(245	)		116
Innovene operations		(10	)		(5	)		2			10			(3	)

Continuing operations		443			108			(203	)		(235	)		113

Analysis of the amount recognized in the Statement of Recognized Income and Expense
Actual return less expected return on pension plan assets		3,111			96			—			157			3,364
Experience gains and losses arising on the plan liabilities		(14	)		(197	)		(17	)		16			(212	)
Change in assumptions underlying the present value of the plan liabilities		(1,884	)		(59	)		236			(470	)		(2,177	)

Actuarial gain (loss) recognized in Statement of Recognized Income and Expense		1,213			(160	)		219			(297	)		975


(a)	Included within production and manufacturing expenses and distribution and administration expenses.

F-121

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


		Year ended December 31, 2005

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

		($ million
Movement in surplus (deficit) during the year
Benefit obligation at January 1,			20,399			7,826			3,676			8,044			39,945
Exchange adjustment			(2,194	)		—			—			(928	)		(3,122	)
Current service cost			379			216			50			140			785
Plan amendments			5			(10	)		(5	)		51			41
Interest cost			1,003			444			207			368			2,022
Special termination benefits			37			—			—			10			47
Contributions by plan participants			37			—			—			5			42
Benefit payments			(923	)		(600	)		(208	)		(430	)		(2,161	)
Acquisitions			—			20			16			3			39
Disposals			(578	)		(252	)		(39	)		(303	)		(1,172	)
Actuarial (gain) loss on obligation			1,898			256			(219	)		454			2,389

Benefit obligation at December 31,			20,063			7,900			3,478			7,414			38,855

Fair value of plan assets at January 1,			22,307			7,183			30			2,192			31,712
Exchange adjustment			(2,469	)		—			—			(195	)		(2,664	)
Expected return on plan assets (a)			1,456			557			2			123			2,138
Contributions by plan participants			37			—			—			5			42
Contributions by employers (funded plans)			340			279			—			140			759
Contributions by employers (unfunded plans)			1			30			204			314			549
Benefit payments			(923	)		(600	)		(208	)		(430	)		(2,161	)
Acquisitions			—			8			—			—			8
Disposals			(578	)		(236	)		—			(26	)		(840	)
Actuarial gain (loss) on plan assets (a)			3,111			96			—			157			3,364

Fair value of plan assets at December 31,			23,282			7,317			28			2,280			32,907

Surplus (deficit)			3,219			(583	)		(3,450	)		(5,134	)		(5,948	)

Represented by
	Asset recognized		3,240			—			—			42			3,282
	Liability recognized		(21	)		(583	)		(3,450	)		(5,176	)		(9,230	)

			3,219			(583	)		(3,450	)		(5,134	)		(5,948	)

The surplus (deficit) may be analysed between wholly or partly funded and wholly unfunded plans as follows
	Funded		3,240			(226	)		(32	)		(476	)		2,506
	Unfunded		(21	)		(357	)		(3,418	)		(4,658	)		(8,454	)

			3,219			(583	)		(3,450	)		(5,134	)		(5,948	)

The defined benefit obligation may be analysed between wholly or partly funded and wholly unfunded plans as follows
	Funded		(20,042	)		(7,543	)		(60	)		(2,756	)		(30,401	)
	Unfunded		(21	)		(357	)		(3,418	)		(4,658	)		(8,454	)

			(20,063	)		(7,900	)		(3,478	)		(7,414	)		(38,855	)


(a)	The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain (loss) on plan assets as disclosed above.

F-122

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


	Year ended December 31, 2004

							US post-
	UK			US			retirement
	pension			pension			benefit			Other
	plans			plans			plans			plans			Total
-
	-------------------------------------------------------------($-
	million
Analysis of the amount charged to profit before interest and taxation
Current service cost		363			215			61			118			757
Past service cost		5			—			(4	)		38			39
Settlement, curtailment and special termination benefits		37			—			—			27			64
Payments to defined contribution plans		—			150			—			12			162

Total operating charge (income)		405			365			57			195			1,022
Innovene operations		(35	)		(25	)		(3	)		(22	)		(85	)

Continuing operations (a)		370			340			54			173			937

Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets		1,351			526			2			104			1,983
Interest on plan liabilities		(981	)		(445	)		(240	)		(346	)		(2,012	)

Other finance income (expense)		370			81			(238	)		(242	)		(29	)
Innovene operations		(6	)		(3	)		14			12			17

Continuing operations		364			78			(224	)		(230	)		(12	)

Analysis of the amount recognized in the Statement of Recognized Income and Expense
Actual return less expected return on pension plan assets		818			379			—			152			1,349
Experience gains and losses arising on the plan liabilities		83			(22	)		33			(562	)		(468	)
Change in assumptions underlying the present value of the plan liabilities		(795	)		(108	)		495			(366	)		(774	)

Actuarial gain (loss) recognized in Statement of Recognized Income and Expense		106			249			528			(776	)		107


(a)	Included within production and manufacturing expenses and distribution and administration expenses.

F-123

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


		Year ended December 31, 2004

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

		($ million
Movement in surplus (deficit) during the year
Benefit obligation at January 1			17,766			7,709			4,143			6,376			35,994
Exchange adjustment			1,445			—			—			647			2,092
Current service cost			363			215			61			118			757
Plan amendments			5			—			(4	)		38			39
Interest cost			981			445			240			346			2,012
Special termination benefits			37			—			—			27			64
Contributions by plan participants			33			—			—			4			37
Benefit payments			(943	)		(578	)		(218	)		(383	)		(2,122	)
Acquisitions			—			—			—			3			3
Disposals			—			(95	)		(18	)		(59	)		(172	)
Actuarial (gain) loss on obligation			712			130			(528	)		928			1,242

Benefit obligation at December 31			20,399			7,826			3,676			8,045			39,946

Fair value of plan assets at January 1			19,224			6,857			33			1,739			27,853
Exchange adjustment			1,575			—			—			175			1,750
Expected return on plan assets (a)			1,351			526			2			104			1,983
Contributions by plan participants			33			—			—			4			37
Contributions by employers (funded plans)			249			30			—			116			395
Contributions by employers (unfunded plans)			—			32			213			285			530
Benefit payments			(943	)		(578	)		(218	)		(383	)		(2,122	)
Acquisitions			—			—			—			—			—
Disposals			—			(63	)		—			—			(63	)
Actuarial gain (loss) on plan assets (a)			818			379			—			152			1,349

Fair value of plan assets at December 31			22,307			7,183			30			2,192			31,712

Surplus (deficit)			1,908			(643	)		(3,646	)		(5,853	)		(8,234	)

Represented by
	Asset recognized		2,093			—			—			12			2,105
	Liability recognized		(185	)		(643	)		(3,646	)		(5,865	)		(10,339	)

			1,908			(643	)		(3,646	)		(5,853	)		(8,234	)

The surplus (deficit) may be analysed between wholly or partly funded and wholly unfunded plans as follows
	Funded		1,942			(296	)		(43	)		(506	)		1,097
	Unfunded		(34	)		(347	)		(3,603	)		(5,347	)		(9,331	)

			1,908			(643	)		(3,646	)		(5,853	)		(8,234	)

The defined benefit obligation may be analysed between wholly or partly funded and wholly unfunded plans as follows
	Funded		(20,365	)		(7,479	)		(73	)		(2,698	)		(30,615	)
	Unfunded		(34	)		(347	)		(3,603	)		(5,347	)		(9,331	)

			(20,399	)		(7,826	)		(3,676	)		(8,045	)		(39,946	)


(a)	The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain (loss) on plan assets as disclosed above.

F-124

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


	Year ended December 31, 2003

							US post-
	UK			US			retirement
	pension			pension			benefit			Other
	plans			plans			plans			plans			Total
-
	-------------------------------------------------------------($-
	million
Analysis of the amount charged to profit before interest and taxation
Current service cost		290			177			54			116			637
Past service cost		—			14			14			—			28
Settlement, curtailment and special termination benefits		—			(11	)		(669	)		87			(593	)
Payments to defined contribution plans		—			134			—			36			170

Total operating charge (income)		290			314			(601	)		239			242
Innovene operations		(29	)		(23	)		(3	)		(19	)		(74	)

Continuing operations (a)		261			291			(604	)		220			168

Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets		1,053			351			2			94			1,500
Interest on plan liabilities		(848	)		(432	)		(259	)		(301	)		(1,840	)

Other finance income (expense)		205			(81	)		(257	)		(207	)		(340	)
Innovene operations		(7	)		(2	)		14			10			15

Continuing operations		198			(83	)		(243	)		(197	)		(325	)

Analysis of the amount recognized in the Statement of Recognized Income and Expense
Actual return less expected return on pension plan assets		1,639			749			2			2			2,392
Experience gains and losses arising on the plan liabilities		641			30			67			135			873
Change in assumptions underlying the present value of the plan liabilities		(1,437	)		(1,030	)		(443	)		(279	)		(3,189	)

Actuarial gain (loss) recognized in Statement of Recognized Income and Expense		843			(251	)		(374	)		(142	)		76


(a)	Included within production and manufacturing expenses and distribution and administration expenses.

F-125

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


		Year ended December 31, 2003

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

		($ million
Movement in surplus (deficit) during the year
Benefit obligation at January 1			14,822			6,765			4,326			5,141			31,054
Exchange adjustment			1,738			—			—			910			2,648
Current service cost			290			177			54			116			637
Plan amendments			—			14			14			—			28
Interest cost			848			432			259			301			1,840
Special termination benefits			—			(11	)		(669	)		87			(593	)
Contributions by plan participants			33			—			—			2			35
Benefit payments			(761	)		(668	)		(217	)		(325	)		(1,971	)
Acquisitions			—			—			—			1			1
Disposals			—			—			—			—			—
Actuarial (gain) loss on obligation			796			1,000			376			144			2,316

Benefit obligation at December 31			17,766			7,709			4,143			6,377			35,995

Fair value of plan assets at January 1			15,138			4,206			33			1,447			20,824
Exchange adjustment			1,864			—			—			222			2,086
Expected return on plan assets (a)			1,053			351			2			94			1,500
Contributions by plan participants			33			—			—			2			35
Contributions by employers (funded plans)			258			2,189			—			86			2,533
Contributions by employers (unfunded plans)			—			30			213			209			452
Benefit payments			(761	)		(668	)		(217	)		(325	)		(1,971	)
Acquisitions			—			—			—			2			2
Disposals			—			—			—			—			—
Actuarial gain (loss) on plan assets (a)			1,639			749			2			2			2,392

Fair value of plan assets at December 31			19,224			6,857			33			1,739			27,853

Surplus (deficit)			1,458			(852	)		(4,110	)		(4,638	)		(8,142	)

Represented by
	Asset recognized		1,562			—			—			118			1,680
	Liability recognized		(104	)		(852	)		(4,110	)		(4,756	)		(9,822	)

			1,458			(852	)		(4,110	)		(4,638	)		(8,142	)

The surplus (deficit) may be analysed between wholly or partly Funded and wholly unfunded plans as follows
	Funded		1,458			(494	)		(72	)		(308	)		584
	Unfunded		—			(358	)		(4,038	)		(4,330	)		(8,726	)

			1,458			(852	)		(4,110	)		(4,638	)		(8,142	)

The defined benefit obligation may be analysed between wholly or partly funded and wholly unfunded plans as follows
	Funded		(17,766	)		(7,351	)		(105	)		(2,047	)		(27,269	)
	Unfunded		—			(358	)		(4,038	)		(4,330	)		(8,726	)

			(17,766	)		(7,709	)		(4,143	)		(6,377	)		(35,995	)


(a)	The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain (loss) on plan assets as disclosed above.

F-126

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

Pension and other postretirement benefit surpluses and deficits are disclosed on a pre-tax basis. On a post-tax basis the pension and other postretirement benefit surplus (deficit) at December 31, 2005 would be $(5,083) million (2004 $(6,686) million and 2003 $(6,080) million).

History of experience gains and losses


		Year ended December 31, 2005

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

Difference between the expected and actual return on plan assets
	Amount ($ million)		3,111			96			—			157			3,364
	Percentage of plan assets		13	%		1	%		0	%		7	%		10	%
Actual return on plan assets
	Amount ($ million)		4,567			653			2			280			5,502
	Percentage of plan assets		20	%		9	%		7	%		12	%		17	%
Experience gains and losses on plan liabilities
	Amount ($ million)		(14	)		(197	)		(17	)		14			(214	)
	Percentage of the present value of plan liabilities		0	%		(2	)%		0	%		0	%		(1	)%
Total amount recognized in statement of recognized income and expense
	Amount ($ million)		1,213			(160	)		219			(297	)		975
	Percentage of the present value of plan liabilities		6	%		(2	)%		6	%		(4	)%		3	%
Cumulative amount recognized in statement of recognized income and expense
	Amount ($ million)		2,162			(162	)		373			(1,215	)		1,158
	Percentage of the present value of plan liabilities		11	%		(2	)%		11	%		(16	)%		3	%

F-127

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


		Year ended December 31, 2004

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

Difference between the expected and actual return on plan assets
	Amount ($ million)		818			379			—			152			1,349
	Percentage of plan assets		4	%		5	%		0	%		7	%		4	%
Actual return on plan assets
	Amount ($ million)		2,169			905			2			256			3,332
	Percentage of plan assets		10	%		13	%		7	%		12	%		11	%
Experience gains and losses on plan liabilities
	Amount ($ million)		83			(22	)		33			(562	)		(468	)
	Percentage of the present value of plan liabilities		0	%		0	%		1	%		(7	)%		(1	)%
Total amount recognized in statement of recognized income and expense
	Amount ($ million)		106			249			528			(776	)		107
	Percentage of the present value of plan liabilities		1	%		3	%		14	%		(10	)%		0	%
Cumulative amount recognized in statement of recognized income and expense
	Amount ($ million)		949			(2	)		154			(918	)		183
	Percentage of the present value of plan liabilities		5	%		0	%		4	%		(11	)%		0	%

F-128

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)


		Year ended December 31, 2003

								US post-
		UK			US			retirement
		pension			pension			benefit			Other
		plans			plans			plans			plans			Total

Difference between the expected and actual return on plan assets
	Amount ($ million)		1,639			749			2			2			2,392
	Percentage of plan assets		9	%		11	%		6	%		0	%		9	%
Actual return on plan assets
	Amount ($ million)		2,692			1,100			4			96			3,892
	Percentage of plan assets		14	%		16	%		12	%		6	%		14	%
Experience gains and losses on plan liabilities
	Amount ($ million)		641			30			67			135			873
	Percentage of the present value of plan liabilities		4	%		0	%		2	%		2	%		2	%
Total amount recognized in statement of recognized income and expense
	Amount ($ million)		843			(251	)		(374	)		(142	)		76
	Percentage of the present value of plan liabilities		5	%		(3	)%		(9	)%		(2	)%		0	%
Cumulative amount recognized in statement of recognized income and expense
	Amount ($ million)		843			(251	)		(374	)		(142	)		76
	Percentage of the present value of plan liabilities		5	%		(3	)%		(9	)%		(2	)%		0	%

F-129

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

Further information in respect of the Group’s defined benefit pension and other postretirement plans required under FASB Statement of Financial Accounting Standards No. 132 (R) — ‘Employers’ Disclosures about Pensions and Other Postretirement Benefits’ is set out below.


		Years ended December 31,

		2005			2004			2003
-		)
		----------------------------($-
		million
Pension and other postretirement benefits expense
Defined benefit plans
	Service cost — benefits earned during year		785			757			637
	Interest cost on projected benefit obligation		2,022			2,012			1,840
	Expected return on plan assets		(2,115	)		(2,161	)		(1,884	)
	Amortization of transition asset		10			9			(69	)
	Recognized net actuarial (gain) loss		656			445			104
	Recognized prior service cost		79			64			52
	Curtailment and settlement (gains) losses		(38	)		(4	)		(7	)
	Special termination benefits		49			60			92

			1,448			1,182			765
Defined contribution plans			172			162			170

			1,620			1,344			935
Innovene operations			(83	)		(102	)		(89	)

Total pension and other postretirement benefits expense for continuing operations			1,537			1,242			846

Estimated future benefit payments

The expected benefit payments, which reflect expected future service, as appropriate, through 2015 are as follows:


					US post-
	UK		US		retirement
	pension		pension		benefit		Other
	plans		plans		plans		plans		Total
-	)
	------------------------------------------------($-
	million
2006		864		609		218		407		2,098
2007		891		607		225		416		2,139
2008		924		625		226		415		2,190
2009		961		647		231		409		2,248
2010		999		666		236		410		2,311
2011-2015		5,477		3,501		1,211		2,055		12,244

F-130

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (continued)

A summary of benefit obligations and amounts recognized under US GAAP in the financial statements is as below:


	Year ended December 31, 2005

						US post-
	UK		US			retirement
	pension		pension			benefit			Other
	plans		plans			plans			plans			Total
-	)
	------------------------------------------------($-
	million
Benefit obligation at December 31		20,063		7,900			3,478			7,414			38,855
Fair value of plan assets at December 31		23,282		7,317			28			2,280			32,907

Funded status		3,219		(583	)		(3,450	)		(5,134	)		(5,948	)
Unrecognized transition (asset) obligation		—		—			—			17			17
Unrecognized net actuarial (gain) loss		222		3,249			793			1,454			5,718
Unrecognized prior service cost		490		70			(485	)		8			83

Net amount recognized		3,931		2,736			(3,142	)		(3,655	)		(130	)

Prepaid benefit cost (accrued benefit liability)		3,910		2,535			(3,154	)		(4,508	)		(1,217	)
Intangible asset		—		12			—			15			27
Accumulated other comprehensive income		21		189			12			838			1,060

		3,931		2,736			(3,142	)		(3,655	)		(130	)


	Year ended December 31, 2004

						US post-
	UK		US			retirement
	pension		pension			benefit			Other
	plans		plans			plans			plans			Total
-	)
	------------------------------------------------($-
	million
Benefit obligation at December 31		20,399		7,826			3,676			8,045			39,946
Fair value of plan assets at December 31		22,307		7,183			30			2,192			31,712

Funded status		1,908		(643	)		(3,646	)		(5,853	)		(8,234	)
Unrecognized transition (asset) obligation		—		—			—			29			29
Unrecognized net actuarial (gain) loss		1,681		3,442			1,149			1,359			7,631
Unrecognized prior service cost		640		76			(579	)		10			147

Net amount recognized		4,229		2,875			(3,076	)		(4,455	)		(427	)

Prepaid benefit cost (accrued benefit liability)		3,714		2,699			(3,076	)		(5,206	)		(1,869	)
Intangible asset		—		13			—			26			39
Accumulated other comprehensive income		515		163			—			725			1,403

		4,229		2,875			(3,076	)		(4,455	)		(427	)

F-131

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 44 — Pensions and other postretirement benefits (concluded)


	Year ended December 31, 2003

						US post-
	UK		US			retirement
	pension		pension			benefit			Other
	plans		plans			plans			plans			Total
-	)
	------------------------------------------------($-
	million
Benefit obligation at December 31		17,766		7,709			4,143			6,377			35,995
Fair value of plan assets at December 31		19,224		6,857			33			1,739			27,853

Funded status		1,458		(852	)		(4,110	)		(4,638	)		(8,142	)
Unrecognized transition (asset) obligation		—		—			—			37			37
Unrecognized net actuarial (gain) loss		1,532		3,918			1,835			635			7,919
Unrecognized prior service cost		680		78			(648	)		12			122

Net amount recognized		3,670		3,144			(2,924	)		(3,954	)		(64	)

Prepaid benefit cost (accrued benefit liability)		3,670		2,937			(2,924	)		(4,225	)		(542	)
Intangible asset		—		14			—			29			43
Accumulated other comprehensive income		—		193			—			242			435

		3,670		3,144			(2,924	)		(3,954	)		(64	)

Note 45 — Retained earnings

Retained earnings of $46,794 million ($32,383 million at December 31, 2004 and $28,378 million at December 31, 2003) include the following amounts, the distribution of which is limited by statutory or other restrictions:


	December 31,

	2005		2004		2003
-	)
	-----------------------($-
	million
Parent company		27,391		25,026		24,107
Subsidiaries		2,463		2,927		2,115
Jointly controlled entities and associates		492		441		566

		30,346		28,394		26,788

There were no unrealized currency translation differences for the year on long-term borrowings used to finance equity investments in foreign currencies (2004 nil and 2003 nil).

F-132

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments


Effect of share-based payment transactions on the Group’s result and	December 31,
ial position

	2005		2004		2003
-	)
	--------------------($-
	million
Total expense recognized for equity-settled share-based payment transactions		348		289		268
Total expense recognized for cash-settled share-based payment transactions		20		36		25

Total expense recognized for share-based payment transactions		368		325		293

Closing balance of liability for cash-settled share-based payment transactions		48		59		51
Total intrinsic value for vested cash-settled share-based payments		41		53		50

For ease of presentation, option and share holdings detailed in the tables within this note are stated as UK ordinary share equivalents in US dollars. US employees are granted American Depositary Shares (ADSs) or options over the Company’s ADSs (one ADS is equivalent to six ordinary shares). The share-based payment plans that existed during the year are detailed below. All plans are ongoing unless otherwise stated.


	*Plans for executive directors*

Executive Directors’ Incentive Plan (EDIP) — share element (2005 onwards). An equity-settled incentive share plan for executive directors driven by one performance measure over a three-year performance period. The award of shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors. In addition, for the group chief executive, 27% of the grant is based on long-term leadership (LTL) measures. After the performance period, the shares that vest (net of tax) are then subject to a three-year retention period. Full details of this plan are included in Item 6.

Executive Directors’ Incentive Plan (EDIP) — share element (pre-2005). An equity-settled incentive share plan for executive directors driven by three performance measures over a three-year performance period. The primary measure is BP’s shareholder return against the market (SHRAM) versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative return on average capital employed (ROACE) and earnings per share (EPS) growth compared with the other oil majors. After the performance period, the shares that vest (net of tax) are then subject to a three-year retention period. Full details of this plan are included in Item 6. For 2005 and subsequent years, the share element of EDIP was amended as described above.

Executive Directors’ Incentive Plan (EDIP) — share option element (pre-2005). An equity-settled share option plan for executive directors that permits options to be granted at an exercise price no lower than the market price of a share on the date that the option is granted. Options vest over three years (one-third each after one, two and three years respectively) and must be exercised within seven years of the date of grant. Last grants were made in 2004. For 2005 onwards the remuneration committee’s policy is not to make further grants of share options to executive directors.


	*Plans for senior employees*

Medium Term Performance Plan (MTPP) (2005 onwards). An equity-settled incentive share plan for senior employees driven by two performance measures over a three-year performance period. The award of shares is determined by comparing BP’s TSR against the other oil majors and, additionally, by

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (continued)

comparing free cash flow (FCF) against a threshold established for the period. For a small group of particularly senior employees, only the TSR measure is applicable in determining the award. The number of shares awarded is increased to take account of the net dividends that would have been received during the performance period, assuming that such dividends had been reinvested. With regard to leaver provisions, the general rule is that leaving employment during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period.

Long Term Performance Plan (LTPP) (pre-2005). An equity-settled incentive share plan for senior employees driven by three performance measures over a three-year performance period. The primary measure is BP’s SHRAM versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative ROACE and EPS growth compared with the other oil majors. Shares are awarded at the end of the performance period and are then subject to a three-year restriction period. With regard to leaver provisions, the general rule is that leaving during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period. This plan was replaced by the MTPP for 2005 onwards.

Deferred Annual Bonus Plan (DAB). An equity-settled restricted share plan for senior employees. The award value is equal to 50% of the annual cash bonus awarded for the preceding performance year (the ‘performance period’). The shares are restricted for a period of three years (the ‘restriction period’). Shares accrue dividends during the restriction period and these are reinvested. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of the performance period, then the general rule is that this will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason. Similarly, if a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that the restricted shares will be forfeited. Special arrangements apply where the participant leaves for a qualifying reason.

Restricted Share Plan (RSP). An equity-settled restricted share plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are no performance conditions but the shares are subject to a three-year restriction period. During the restriction period, shares accrue dividends, which are reinvested. With regard to leaver provisions, the general rule is that ceasing employment during the restriction period will result in the forfeit of shares. However, special arrangements apply where the participant leaves for a qualifying reason.

BP Share Option Plan (BPSOP). An equity-settled share option plan that applies to certain categories of employees. Participants are granted share options with an exercise price no lower than market price of a share immediately preceding the date of grant. There are no performance conditions and the options are exercisable between the third and 10th anniversaries of the grant date. The general rule is that the options will lapse if the participant leaves employment before the end of the third calendar year from the date of grant (and that vested options are exercisable within 3¹/2 years from the date of leaving). However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after the end of the calendar year of the date of grant. Share options are no longer offered to the most senior employees.

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (continued)


	*Savings and matching plans*

BP ShareSave Plan. A savings-related share option plan, under which employees save on a monthly basis, over a three- or five-year period, towards the purchase of shares at a fixed price determined when the option is granted. This price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract; otherwise it lapses. The plan is run in the UK and options are granted annually, usually in June. Until 2003, a three-year savings plan was also run in a small number of other countries. Options will remain outstanding in respect of these countries until the end of June 2007. Participants leaving for a qualifying reason will have six months in which to use their savings to exercise their options on a pro-rated basis.

BP ShareMatch Plans. Matching share plans, under which BP matches employees’ own contributions of shares up to a predetermined limit. The plans are run in the UK and in over 70 other countries. The UK plan is run on a monthly basis with shares being held in trust for five years before they can be released free of any income tax and national insurance liability. In other countries, the plan is run on an annual basis with shares being held in trust for three years. The plan is operated on a cash basis in those countries where there are regulatory restrictions preventing the holding of BP shares. When the employee leaves BP, all shares must be removed from trust and units under the plan operated on a cash basis must be encashed.


	*Cash plans*

Cash Options/ Stock Appreciation Rights (SARs). These are cash-settled share-based payments available to certain employees that require the Group to pay the intrinsic value of the cash option/ SAR to the employee at the date of exercise. There are no performance conditions; however, participants must continue in employment with BP for the first three calendar years of the plan for the options/ SARs to vest. Special arrangements may apply for qualifying leavers. The options/ SARs are exercisable between the third and 10th anniversaries of the grant date.


	*Employee share ownership plans (ESOPS)*

ESOPs have been established to acquire BP shares to satisfy any awards made to participants under EDIP, LTPP, MTPP, DAB and the BP ShareMatch Plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the Group. Until such time as the Company’s own shares held by the ESOP trusts vest unconditionally in employees, the amount paid for those shares is deducted in arriving at shareholders’ equity. See Consolidated Statement of Changes in BP Shareholders’ Equity (pages F-7 to F-11). Assets and liabilities of the ESOPs are recognized as assets and liabilities of the Group.

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (continued)


Year ended December 31,

	2005					2004					2003

				Weighted					Weighted					Weighted
				average					average					average
	Number of			exercise		Number of			exercise		Number of			exercise
Share option transactions	options			price		options			price		options			price
($($($-	)

Outstanding at beginning of the period		470,263,808			7.16		461,885,881			6.76		410,986,179			6.70
Granted during the period		54,482,053			10.24		80,394,760			7.93		104,758,602			6.22
Forfeited during the period		(4,844,827	)		8.30		(7,043,911	)		6.77		(20,412,529	)		7.11
Exercised during the period		(68,687,976	)		6.40		(62,625,182	)		5.18		(32,988,942	)		4.11
Expired during the period		(759,556	)		6.75		(2,347,740	)		7.55		(457,429	)		6.40

Outstanding at end of the period		450,453,502			7.64		470,263,808			7.16		461,885,881			6.76

Exercisable at the end of the period		222,729,398			7.54		224,627,758			7.00		229,198,494			6.21

Available for grant at December 31,		955,924,506					966,076,636					1,079,531,345

As share options are exercised continuously throughout the year, the weighted average share price during the year of $10.77 (2004 $8.95 and 2003 $6.81) is representative of the weighted average share price at the date of exercise. For the options outstanding at December 31, 2005, the exercise price ranges and weighted average remaining contractual lives are shown below.


	Options outstanding						Options exercisable

			Weighted		Weighted				Weighted
			average		average				average
	Number of		remaining		exercise		Number of		exercise
Range of exercise prices	shares		life		price		shares		price
($($-	)

			(years
$ 4.22 — $ 6.14		74,255,790		1.88		5.51		52,734,810		5.44
$ 6.15 — $ 8.06		151,161,264		6.15		7.02		36,840,758		7.70
$ 8.07 — $ 9.99		176,892,928		5.95		8.29		133,128,330		8.32
$10.00 — $11.92		48,143,520		9.19		10.45		25,500		10.53

		450,453,502		5.69		7.64		222,729,398		7.54

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (continued)


	*Fair values and associated details for options and shares granted*


Options granted during the year			ShareSave		ShareSave
ended December 31, 2005	BPSOP		3 Year		5 Year

Option pricing model used		Binomial		Binomial		Binomial
Weighted average fair value		$2.34		$2.76		$2.94
Weighted average share price		$10.85		$10.49		$10.49
Weighted average exercise price		$10.63		$7.96		$7.96
Expected volatility		18%		18%		18%
Option life		10 years		3.5 years		5.5 years
Expected dividends		2.72%		3.00%		3.00%
Risk free interest rate		4.25%		4.00%		4.25%
Expected exercise behaviour		5% years 4-9		100% year 4		100% year 6
		70% year 10


Options granted during the year ended					ShareSave		ShareSave
December 31, 2004	EDIP Options		BPSOP		3 Year		5 Year

Option pricing model used		Binomial		Binomial		Binomial		Binomial
Weighted average fair value		$1.34		$1.55		$1.94		$2.13
Weighted average share price		$8.09		$8.12		$8.75		$8.75
Weighted average exercise price		$8.09		$8.09		$7.00		$7.00
Expected volatility		22%		22%		22%		22%
Option life		7 years		10 years		3.5 years		5.5 years
Expected dividends		3.75%		3.75%		3.75%		3.75%
Risk free interest rate		3.50%		4.00%		3.00%		3.75%
Expected exercise behaviour		5% years 2-6		5% years 4-9		100% year 4		100% year 6
		75% year 7		70% year 10


Options granted during the year ended					ShareSave		ShareSave
December 31, 2003	EDIP Options		BPSOP		3 Year		5 Year

Option pricing model used		Binomial		Binomial		Binomial		Binomial
Weighted average fair value		$1.37		$1.50		$1.91		$2.02
Weighted average share price		$6.29		$6.43		$7.23		$7.23
Weighted average exercise price		$6.29		$6.35		$5.79		$5.79
Expected volatility		30%		30%		30%		30%
Option life		7 years		10 years		3.5 years		5.5 years
Expected dividends		4.00%		4.00%		4.00%		4.00%
Risk free interest rate		3.50%		3.50%		3.50%		3.50%
Expected exercise behaviour		5% years 2-6		5% years 4-9		100% year 4		100% year 6
		75% year 7		70% year 10

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (concluded)

The Group uses a third party estimate of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. This estimate takes into account the volatility implied by options in the market.


Shares granted in 2005	MTPP — TSR		MTPP — FCF		EDIP — TSR		EDIP — LTL		RSP

Number of equity instruments granted (million)		9.3		8.4		3.7		0.5		0.3
Weighted average fair value		$5.72		$11.04		$3.87		$10.13		$11.04
Fair value measurement basis		Monte Carlo		Market value		Monte Carlo		Market value		Market value

The Group used a Monte Carlo simulation to fair value the TSR element of the 2005 MTPP and EDIP plans. In accordance with the rules of the plans the model simulates BP’s TSR and compares it against our principal strategic competitors over the three-year period of the plans. The model takes into account the historic dividends, share price volatilities and covariances of BP and each comparator company to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR element.

LTPP —

EDIP —

Shares granted in 2004

LTPP — SHRAM

EPS/ROACE

EDIP — SHRAM

EPS/ROACE

RSP

Number of equity instruments granted (million)

6.8

4.1

0.9

0.5

0.1

Weighted average fair value

$4.06

$7.21

$4.06

$7.21

$8.12

Fair value measurement basis

Monte Carlo

Market value

Monte Carlo

Market value

LTPP —

EDIP —

Shares granted in 2003

LTPP — SHRAM

EPS/ROACE

EDIP — SHRAM

EPS/ROACE

RSP

Number of equity instruments granted (million)

6.8

4.1

1.1

0.6

0.1

Weighted average fair value

$3.53

$5.65

$3.53

$5.65

$6.43

Fair value measurement basis

Monte Carlo

Market value

Monte Carlo

Market value

The Group used a Monte Carlo simulation to fair value the SHRAM element of the 2003 and 2004 LTPP and EDIP plans. In accordance with the rules of the plans, the model simulates BP’s SHRAM and compares it with the comparator companies (all companies in the FTSE All World Oil & Gas Index) over the three-year period of the plans. The SHRAMs of the comparator companies have been determined from market data over the preceding three-year period. The model takes into account the historic dividend yields, share price volatilities and covariances of BP and each comparator company to

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 46 — Share-based payments (concluded)

produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the SHRAM element.

Accounting expense does not necessarily represent the actual value of share-based payments made to recipients which are determined by the Remuneration Committee according to established criteria.

Note 47 — Employee costs and numbers


	Years ended December 31,

	2005			2004			2003
-	)
	---------------------------($-
	million
Employee costs
Wages and salaries		8,695			7,922			7,142
Social security costs		754			667			622
Share-based payments		368			325			293
Pension and other postretirement benefit costs		929			1,051			582

		10,746			9,965			8,639
Innovene operations		(892	)		(898	)		(882	)

		9,854			9,067			7,757


	At December 31,

	2005		2004		2003

Number of employees at December 31,
Exploration and Production		17,000		15,600		15,100
Refining and Marketing (a)		70,800		69,800		69,000
Gas, Power and Renewables		4,100		4,000		3,800
Other businesses and corporate		4,300		13,500		15,800

		96,200		102,900		103,700

By geographical area
UK		16,500		17,500		17,100
Rest of Europe		21,300		25,900		25,300
USA		34,400		36,900		39,100
Rest of World		24,000		22,600		22,200

		96,200		102,900		103,700


(a)	Includes 27,800 (2004 27,900 and 2003 27,000) service station staff.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 47 — Employee costs and numbers (concluded)


			Rest of				Rest of
Average number of employees	UK		Europe		USA		World		Total

Year ended December 31, 2005
Exploration and Production		3,000		600		5,300		7,300		16,200
Refining and Marketing		11,100		19,700		26,200		14,000		71,000
Gas, Power and Renewables		200		800		1,500		1,400		3,900
Other businesses and corporate		3,800		3,900		3,600		300		11,600

		18,100		25,000	��	36,600		23,000		102,700

Year ended December 31, 2004
Exploration and Production		2,900		700		4,900		6,900		15,400
Refining and Marketing		10,300		19,200		27,200		12,900		69,600
Gas, Power and Renewables		200		800		1,400		1,600		4,000
Other businesses and corporate		3,700		4,800		5,700		1,000		15,200

		17,100		25,500		39,200		22,400		104,200

Year ended December 31, 2003
Exploration and Production		3,200		700		5,000		6,900		15,800
Refining and Marketing		10,100		20,600		28,300		12,700		71,700
Gas, Power and Renewables		200		900		1,500		1,600		4,200
Other businesses and corporate		3,700		4,900		6,300		1,500		16,400

		17,200		27,100		41,100		22,700		108,100

Note 48 — Remuneration of directors and key management


	*Remuneration of directors*


		Years ended
		December 31,

		2005		2004		2003
-		)
		--------------------($-
		million
Total for all directors
	Emoluments		18		19		17
	Ex-gratia payment to executive director retiring in the year		—		—		1
	Gains made on the exercise of share options		—		3		1
	Amounts awarded under incentive schemes		8		6		4

Emoluments.These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus bonuses awarded for the year.

Pension contributions.Five executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during 2005.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 48 — Remuneration of directors and key management (concluded)

Office facilities for former chairmen and deputy chairmen.It is customary for the Company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.


	*Remuneration of key management*


		Years ended
		December 31,

		2005		2004		2003
-		)
		--------------------($-
		million
Total for all key management
	Short-term employee benefits		25		24		20
	Postretirement benefits		4		3		2
	Share-based payment		27		20		20

Key management, in addition to executive and non-executive directors, includes certain senior managers who are members of the Group Chief Executive’s Meeting.

Short-term employee benefits. In addition to fees paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior managers, salary and benefits earned during the year, plus bonuses awarded for the year.

Postretirement benefits. The amounts represent the estimated cost to the Group of providing pensions and other postretirement benefits to key management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.

Share-based payments. This is the cost to the Group of key management’s participation in share-based payment plans, as measured by the fair value of options and shares granted accounted for in accordance with IFRS 2 ‘Share-based Payments’. The main plans in which key management have participated are the Executive Directors’ Incentive Plan (EDIP), the Medium Term Performance Plan (MTPP) and the Long Term Performance Plan (LTPP). For details of these plans refer to Note 46 — Share-based payments.

Note 49 — Contingent liabilities

There were contingent liabilities at December 31, 2005 in respect of guarantees and indemnities entered into as part of the ordinary course of the Group’s business. No material losses are likely to arise from such contingent liabilities. Group companies have issued guarantees under which amounts outstanding at December 31, 2005 were $1,228 million (2004 $1,281 million and 2003 $635 million) in respect of borrowings of jointly controlled entities and associates and $736 million (2004 $650 million and 2003 $304 million) in respect of liabilities of other third parties.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 49 — Contingent liabilities (continued)

America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP’s combination with Atlantic Richfield Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon that affect Alyeska and its owners, BP will defend the claims vigorously.

Since 1987, Atlantic Richfield, a current subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting & Refining which, along with a predecessor company, manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits (depending on plaintiff) seek various remedies, including: compensation to lead-poisoned children; cost to find and remove lead paint from buildings; medical monitoring and screening programmes; public warning and education on lead hazards; reimbursement of government healthcare costs and special education for lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgement in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences and it intends to defend such actions vigorously and thus the incurrence of a liability by Atlantic Richfield is remote. Consequently, BP believes that the impact of these lawsuits on the Group’s results of operations, financial position or liquidity will not be material.

In addition, various Group companies are parties to legal actions and claims that arise in the ordinary course of the Group’s business. While the outcome of such legal proceedings cannot be readily foreseen, BP believes that they will be resolved without material effect on the Group’s results of operations, financial position or liquidity.

The Group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the Group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the Group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the Group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the Group’s accounting policies. While the amounts of future costs could be significant and could be material to the Group’s results of operations in the period in which they are recognized, BP does not expect these costs to have a material effect on the Group’s financial position or liquidity.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 50 — Capital commitments

Authorized future capital expenditure for property, plant and equipment by Group companies for which contracts had been placed at December 31, 2005 amounted to $7,596 million (2004 $6,765 million and 2003 $6,420 million). Capital commitments of equity-accounted entities amounted to $733 million (2004 $2,056 million and 2003 $1,175 million).

F-143

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 51 —	Summarized financial information on jointly controlled entities and associates

A summarized statement of income and assets and liabilities based on latest information available, with respect to the Group’s equity-accounted joint ventures and associates, is set out below. These figures represent 100% of the Income Statements and Balance Sheets of the joint ventures and associated undertakings, not BP’s ownership interest.


	Years ended December 31,

	2005		2004		2003

	($ million
Sales and other operating revenue		61,698		38,842		21,836
Gross profit		14,451		9,063		4,939
Profit for the year		8,043		5,466		2,728


	December 31,

	2005			2004

	($ million
Noncurrent assets		52,401			49,438
Current assets		19,808			13,879

		72,209			63,317
Current liabilities		(15,403	)		(12,351	)
Noncurrent liabilities		(20,328	)		(12,618	)

Net assets		36,478			38,348

The more important joint ventures and associates of the Group at December 31, 2005 and the percentage of ordinary share capital owned or joint venture interest (to nearest whole number) are:


			Country of
Associates	%		Incorporation		Principal activities

Abu Dhabi
Abu Dhabi Marine Areas		37		England	Crude oil production
Abu Dhabi Petroleum Co		24		England	Crude oil production
Azerbaijan
The Baku-Tbilisi-Ceyhan Pipeline Co		30		Cayman Islands	Pipelines
Korea
Samsung Petrochemical Co.		47		England	Petrochemicals
Taiwan
China American Petrochemical Co.		61		Taiwan	Petrochemicals
Trinidad and Tobago
Atlantic LNG Company of Trinidad and Tobago		34		Trinidad and Tobago	LNG manufacture
Atlantic LNG 2/3 Company of Trinidad and Tobago		43		Trinidad and Tobago	LNG manufacture

F-144

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 51 —	Summarized financial information on jointly controlled entities and associates (concluded)


			Country of
			incorporation or
Jointly controlled entities	%		registration		Principal activities

CaTO Finance V Limited Partnership		50		England	Finance
Lukarco		46		Netherlands	Exploration and production, pipelines
Pan American Energy		60		USA	Exploration and Production
Ruhr Oel		50		Germany	Refinining and Marketing and Petrochemicals
Shanghai Secco Petrochemical Co		50		China	Petrochemicals
TNK-BP		50		British Virgin Islands	Integrated oil operations
Unimar LLC		50		USA	Exploration and Production
Watson Cogeneration		51		USA	Power generation


Note 52 —	First-time adoption of International Financial Reporting Standards


	*Introduction*

The general principle that should be applied on first-time adoption of IFRS is that standards in force at the first reporting date (for BP, December 31, 2005) should be applied retrospectively. However, IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ (IFRS 1) contains a number of exemptions which companies are permitted to apply. BP has taken the following exemptions:


	—	Comparative information on financial instruments is prepared in accordance with UK GAAP and the Group has adopted IAS 32 ‘Financial Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39) from January 1, 2005.

F-145

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Introduction (concluded)


	—	IFRS 3 ‘Business Combinations’ has not been applied to acquisitions of subsidiaries or of interests in jointly controlled entities and associates that occurred before January 1, 2003.

	—	Cumulative currency translation differences for all foreign operations are deemed to be zero at January 1, 2003.

	—	The Group has recognized all cumulative actuarial gains and losses on pensions and other postretirement benefits as at January 1, 2003 directly in equity.

	—	IFRS 2 ‘Share-based Payment’ has been applied retrospectively to all share-based payments that had not vested before January 1, 2003.


	—	All derivatives, including embedded derivatives, would have been brought on to the balance sheet at fair value.

	—	Available-for-sale investments would have been carried at fair value rather than at cost.

The principal differences for the Group between reporting on the basis of UK GAAP and IFRS are as follows:


	—	Ceasing to amortize goodwill.

	—	Setting up deferred taxation on: acquisitions; inventory valuation differences; unremitted earnings of subsidiaries, jointly controlled entities and associates.

	—	Expensing a greater proportion of major maintenance costs.

	—	No longer recognizing dividends proposed but not declared as a liability at the balance sheet date.

	—	Recognizing an expense for the fair value of employee share option schemes.

	—	Recording asset swaps on the basis of fair value.

	—	Recognizing changes in the fair value of embedded derivatives in the income statement.

The new accounting policies adopted by the Group are summarized in Note 1 (pages F-12 to F-30).

The financial information presented in this note does not take account of the Innovene operations treated as discontinued in 2005 (see Note 5 on page F-35), nor the change in the basis of presentation of over-the-counter forward contracts (see Note 3 onF-30).

F-146


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

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F-147

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


	Group income statement reconciliation from UK GAAP to IFRS


		UK
		GAAP in														Major
		IFRS		Joint			Net equity			Goodwill			Deferred			maintenance
		format		arrangements			accounting			amortization			tax			expenditure
-
		----------------------------------------------------------------------------------($-
		million
For the year ended December 31, 2004
Sales and other operating revenues			285,059		(274	)		—			—			—			—
Earnings from jointly controlled entities — after interest and tax			2,943		34			(1,251	)		—			—			—
Earnings from associates — after interest and tax			634		—			(171	)		—			—			—
Interest and other revenues			675		(3	)		—			—			—			—

Total revenues			289,311		(243	)		(1,422	)		—			—			—
Gain on sale of businesses and fixed assets			1,829		—			—			—			—			—

Total revenues and other income			291,140		(243	)		(1,422	)		—			—			—
Purchases			217,659		(82	)		—			—			—			—
Production and manufacturing expenses			18,330		(44	)		—			—			—			586
Production and similar taxes			2,149		—			—			—			—			—
Depreciation, depletion and amortization			10,840		(110	)		—			(1,428	)		—			(296	)
Impairment and losses on sale of businesses and fixed assets			2,757		—			—			(61	)		25			—
Exploration expense			637		—			—			—			—			—
Distribution and administration expenses			13,526		9			—			—			—			—

Profit before interest and taxation			25,242		(16	)		(1,422	)		1,489			(25	)		(290	)
Finance costs			642		—			(206	)		—			—			—
Other finance expense			357		—			—			—			—			—

Profit before taxation			24,243		(16	)		(1,216	)		1,489			(25	)		(290	)
Taxation			8,282		(16	)		(1,173	)		—			49			(73	)

Profit for the year			15,961		—			(43	)		1,489			(74	)		(217	)

Attributable to
	BP shareholders		15,731		—			—			1,489			(74	)		(217	)
	Minority interest		230		—			(43	)		—			—			—

			15,961		—			(43	)		1,489			(74	)		(217	)

For the year ended December 31, 2003
Sales and other operating revenues			232,571		(185	)		—			—			—			—
Earnings from jointly controlled entities — after interest and tax			924		72			(233	)		—			—			—
Earnings from associates — after interest and tax			514		—			(125	)		—			—			—
Interest and other revenues			786		(2	)		—			—			—			—

Total revenues			234,795		(115	)		(358	)		—			—			—
Gain on sale of businesses and fixed assets			1,894		—			—			—			—			—

Total revenues and other income			236,689		(115	)		(358	)		—			—			—
Purchases			176,185		(93	)		—			—			—			—
Production and manufacturing expenses			15,402		(7	)		—			—			—			417
Production and similar taxes			1,723		—			—			—			—			—
Depreciation, depletion and amortization			10,202		(11	)		—			(1,376	)		—			(216	)
Impairment and losses on sale of businesses and fixed assets			1,801		—			—			—			—			—
Exploration expense			542		—			—			—			—			—
Distribution and administration expenses			12,880		—			—			—			—			—

Profit before interest and taxation			17,954		(4	)		(358	)		1,376			—			(201	)
Finance costs			644		—			(134	)		—			—			—
Other finance expense			547		—			—			—			—			—

Profit before taxation			16,763		(4	)		(224	)		1,376			—			(201	)
Taxation			6,111		(4	)		(224	)		—			(708	)		(81	)

Profit for the year			10,652		—			—			1,376			708			(120	)

Attributable to
	BP shareholders		10,482		—			—			1,376			708			(120	)
	Minority interest		170		—			—			—			—			—

			10,652		—			—			1,376			708			(120	)

F-148

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


						Recycling
Share-						foreign
based			Asset			exchange on					Total IFRS
payments			swaps			disposal		Other			adjustments			IFRS
-----------------------------------------------------------------------------)
($
million
	—			—			—		147			(127	)		284,932
	—			—			—		79			(1,138	)		1,805
	—			—			—		—			(171	)		463
	—			—			—		1			(2	)		673

	—			—			—		227			(1,438	)		287,873
	—			—			78		(3	)		75			1,904

	—			—			78		224			(1,363	)		289,777
	—			—			—		37			(45	)		217,614
	28			—			—		103			673			19,003
	—			—			—		—			—			2,149
	—			(12	)		—		18			(1,828	)		9,012
	—			—			—		—			(36	)		2,721
	—			—			—		—			—			637
	58			—			—		16			83			13,609

	(86	)		12			78		50			(210	)		25,032
	—			—			—		4			(202	)		440
	—			—			—		—			—			357

	(86	)		12			78		46			(8	)		24,235
	(62	)		(27	)		—		(7	)		(1,309	)		6,973

	(24	)		39			78		53			1,301			17,262

	(24	)		39			78		53			1,344			17,075
	—			—			—		—			(43	)		187

	(24	)		39			78		53			1,301			17,262

	—			—			—		122			(63	)		232,508
	—			—			—		45			(116	)		808
	—			—			—		2			(123	)		391
	—			—			—		1			(1	)		785

	—			—			—		170			(303	)		234,492
	—			—			—		1			1			1,895

	—			—			—		171			(302	)		236,387
	—			—			—		68			(25	)		176,160
	25			—			—		37			472			15,874
	—			—			—		—			—			1,723
	—			(5	)		—		11			(1,597	)		8,605
	—			—			—		—			—			1,801
	—			—			—		—			—			542
	70			—			—		4			74			12,954

	(95	)		5			—		51			774			18,728
	—			—			—		3			(131	)		513
	—			—			—		—			—			547

	(95	)		5			—		48			905			17,668
	(56	)		3			—		9			(1,061	)		5,050

	(39	)		2			—		39			1,966			12,618

	(39	)		2			—		39			1,966			12,448
	—			—			—		—			—			170

	(39	)		2			—		39			1,966			12,618

F-149

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group balance sheet reconciliation from UK GAAP to IFRS


		UK GAAP
		in IFRS		Joint			Pension			Leasehold			Liquid			Goodwill		Deferred
		format		arrangements			reclassification			premiums			resources			amortization		tax
-
		-----------------------------------------------------------------------------------------------------($-
		million
At December 31, 2004
Noncurrent assets
	Property, plant and equipment		96,748		(2,297	)		—			(102	)		—			—		159
	Goodwill		7,872		—			—			—			—			2,985		—
	Other intangible assets		4,204		(2	)		—			—			—			—		—
	Investments in jointly controlled entities		12,451		2,088			—			—			—			—		—
	Investments in associates		5,488		—			—			—			—			—		—
	Other investments		394		—			—			—			—			—		—

	Fixed assets		127,157		(211	)		—			(102	)		—			2,985		159
	Loans		799		—			—			—			—			—		—
	Other receivables		429		—			—			—			—			—		—
	Derivative financial instruments		898		—			—			—			—			—		—
	Prepayments and accrued income		248		—			—			102			—			—		—
	Defined benefit pension plan surplus		1,475		—			630			—			—			—		—

			131,006		(211	)		630			—			—			2,985		159

Current assets
	Loans		193		—			—			—			—			—		—
	Inventories		15,698		(34	)		—			—			—			—		—
	Trade and other receivables		37,051		48			—			—			—			—		—
	Other investments		328		—			—			—			(328	)		—		—
	Derivative financial instruments		5,317		—			—			—			—			—		—
	Prepayments and accrued income		1,675		(4	)		—			—			—			—		—
	Current tax receivable		159		—			—			—			—			—		—
	Cash and cash equivalents		1,156		(125	)		—			—			328			—		—

			61,577		(115	)		—			—			—			—		—

Total assets			192,583		(326	)		630			—			—			2,985		159

Current liabilities
	Trade and other payables		38,820		(280	)		—			—			—			—		—
	Derivative financial instruments		5,074		—			—			—			—			—		—
	Accruals and deferred income		6,316		(13	)		—			—			—			—		—
	Finance debt		10,184		—			—			—			—			—		—
	Current tax payable		4,131		—			—			—			—			—		—
	Provisions		715		—			—			—			—			—		—

			65,240		(293	)		—			—			—			—		—

Noncurrent liabilities
	Other payables		3,506		—			—			—			—			—		—
	Derivative financial instruments		158		—			—			—			—			—		—
	Accruals and deferred income		841		(2	)		—			—			—			—		—
	Finance debt		12,907		—			—			—			—			—		—
	Deferred tax liabilities		15,050		(22	)		(1,720	)		—			—			—		4,145
	Provisions		8,893		(9	)		—			—			—			—		—
	Defined benefit pension plan and other postretirement benefit plan deficits		7,989		—			2,350			—			—			—		—

			49,344		(33	)		630			—			—			—		4,145

Total liabilities			114,584		(326	)		630			—			—			—		4,145

Net assets			77,999		—			—			—			—			2,985		(3,986	)

BP shareholders’ equity			76,656		—			—			—			—			2,985		(3,986	)
Minority interest			1,343		—			—			—			—			—		—

Total equity			77,999		—			—			—			—			2,985		(3,986	)

F-150

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


Major
maintenance			Share-based						Dividend						Total IFRS
expenditure			payments			Asset swaps			accrual			Other			adjustments			IFRS
---------------------------------------------------------------------------------------------)
($
million

	(1,148	)		—			(340	)		—			72			(3,656	)		93,092
	—			—			—			—			—			2,985			10,857
	—			—			—			—			3			1			4,205
	—			—			—			—			17			2,105			14,556
	—			—			—			—			(2	)		(2	)		5,486
	—			—			—			—			—			—			394

	(1,148	)		—			(340	)		—			90			1,433			128,590
	—			—			—			—			12			12			811
	—			—			—			—			—			—			429
	—			—			—			—			—			—			898
	—			—			—			—			4			106			354
	—			—			—			—			—			630			2,105

	(1,148	)		—			(340	)		—			106			2,181			133,187

	—			—			—			—			—			—			193
	—			—			—			—			(19	)		(53	)		15,645
	—			—			—			—			—			48			37,099
	—			—			—			—			—			(328	)		—
	—			—			—			—			—			—			5,317
	—			—			—			—			—			(4	)		1,671
	—			—			—			—			—			—			159
	—			—			—			—			—			203			1,359

	—			—			—			—			(19	)		(134	)		61,443

	(1,148	)		—			(340	)		—			87			2,047			194,630

	—			—			—			—			—			(280	)		38,540
	—			—			—			—			—			—			5,074
	—			—			—			(1,821	)		—			(1,834	)		4,482
	—			—			—			—			—			—			10,184
	—			—			—			—			—			—			4,131
	—			—			—			—			—			—			715

	—			—			—			(1,821	)		—			(2,114	)		63,126

	—			—			—			—			75			75			3,581
	—			—			—			—			—			—			158
	—			—			(48	)		—			(92	)		(142	)		699
	—			—			—			—			—			—			12,907
	(354	)		(353	)		(102	)		—			57			1,651			16,701
	—			—			—			—			—			(9	)		8,884
	—			—			—			—			—			2,350			10,339

	(354	)		(353	)		(150	)		—			40			3,925			53,269

	(354	)		(353	)		(150	)		(1,821	)		40			1,811			116,395

	(794	)		353			(190	)		1,821			47			236			78,235

	(794	)		353			(190	)		1,821			47			236			76,892
	—			—			—			—			—			—			1,343

	(794	)		353			(190	)		1,821			47			236			78,235

F-151

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group balance sheet reconciliation from UK GAAP to IFRS (continued)


		UK GAAP
		in IFRS		Joint			Pension			Leasehold			Liquid			Goodwill		Deferred
		format		arrangements			reclassification			premiums			resources			amortization		tax
-
		-----------------------------------------------------------------------------------------------------($-
		million
At December 31, 2003
Noncurrent assets
	Property, plant and equipment		91,911		(2,089	)		—			(205	)		—			—		—
	Goodwill		9,169		—			—			—			—			1,421		—
	Other intangible assets		4,473		(2	)		—			—			—			—		—
	Investments in jointly controlled entities		11,009		1,963			—			—			—			—		—
	Investments in associates		4,870		—			—			—			—			—		—
	Other investments		1,452		—			—			—			—			—		—

	Fixed assets		122,884		(128	)		—			(205	)		—			1,421		—
	Loans		867		—			—			—			—			—		—
	Other receivables		495		—			—			—			—			—		—
	Derivative financial instruments		534		—			—			—			—			—		—
	Prepayments and accrued income		749		—			—			205			—			—		—
	Defined benefit pension plan surplus		1,146		—			534			—			—			—		—

			126,675		(128	)		534			—			—			1,421		—

Current assets
	Loans		182		—			—			—			—			—		—
	Inventories		11,617		(16	)		—			—			—			—		—
	Trade and other receivables		27,848		32			—			—			—			—		—
	Other investments		185		—			—			—			(185	)		—		—
	Derivative financial instruments		1,891		—			—			—			—			—		—
	Prepayments and accrued income		1,371		1			—			—			—			—		—
	Current tax receivable		92		—			—			—			—			—		—
	Cash and cash equivalents		1,947		(76	)		—			—			185			—		—

			45,133		(59	)		—			—			—			—		—

Total assets			171,808		(187	)		534			—			—			1,421		—

Current liabilities
	Trade and other payables		29,780		(41	)		—			—			—			—		—
	Derivative financial instruments		4,145		—			—			—			—			—		—
	Accruals and deferred income		3,762		(2	)		—			—			—			—		—
	Finance debt		9,456		—			—			—			—			—		—
	Current tax payable		3,441		—			—			—			—			—		—
	Provisions		735		—			—			—			—			—		—

			51,319		(43	)		—			—			—			—		—

Noncurrent liabilities
	Other payables		4,769		(140	)		—			—			—			—		—
	Derivative financial instruments		344		—			—			—			—			—		—
	Accruals and deferred income		917		—			—			—			—			—		—
	Finance debt		12,869		—			—			—			—			—		—
	Deferred tax liabilities		14,371		(4	)		(1,653	)		—			—			—		3,844
	Provisions		7,864		—			—			—			—			—		—
	Defined benefit pension plan and other postretirement benefit plan deficits		7,635		—			2,187			—			—			—		—

			48,769		(144	)		534			—			—			—		3,844

Total liabilities			100,088		(187	)		534			—			—			—		3,844

Net assets			71,720		—			—			—			—			1,421		(3,844	)

BP shareholders’ equity			70,595		—			—			—			—			1,421		(3,844	)
Minority interest			1,125		—			—			—			—			—		—

Total equity			71,720		—			—			—			—			1,421		(3,844	)

F-152

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


Major
maintenance			Share-based						Dividend						Total IFRS
expenditure			payments			Asset swaps			accrual			Other			adjustments			IFRS
---------------------------------------------------------------------------------------------)
($
million
	(818	)		—			(269	)		—			77			(3,304	)		88,607
	—			—			—			—			2			1,423			10,592
	—			—			—			—			—			(2	)		4,471
	—			—			—			—			(63	)		1,900			12,909
	—			—			—			—			(2	)		(2	)		4,868
	—			—			—			—			—			—			1,452

	(818	)		—			(269	)		—			14			15			122,899
	—			—			—			—			(15	)		(15	)		852
	—			—			—			—			—			—			495
	—			—			—			—			—			—			534
	—			—			—			—			3			208			957
	—			—			—			—			—			534			1,680

	(818	)		—			(269	)		—			2			742			127,417

	—			—			—			—			—			—			182
	—			—			—			—			(4	)		(20	)		11,597
	—			—			—			—			1			33			27,881
	—			—			—			—			—			(185	)		—
	—			—			—			—			—			—			1,891
	—			—			—			—			3			4			1,375
	—			—			—			—			—			—			92
	—			—			—			—			—			109			2,056

	—			—			—			—			—			(59	)		45,074

	(818	)		—			(269	)		—			2			683			172,491

	—			—			—			—			1			(40	)		29,740
	—			—			—			—			—			—			4,145
	—			—			—			(1,494	)		—			(1,496	)		2,266
	—			—			—			—			—			—			9,456
	—			—			—			—			—			—			3,441
	—			—			—			—			—			—			735

	—			—			—			(1,494	)		1			(1,536	)		49,783

	—			—			—			—			1			(139	)		4,630
	—			—			—			—			—			—			344
	—			—			(53	)		—			—			(53	)		864
	—			—			—			—			—			—			12,869
	(273	)		(235	)		(76	)		—			77			1,680			16,051
	—			—			—			—			—			—			7,864
	—			—			—			—			—			2,187			9,822

	(273	)		(235	)		(129	)		—			78			3,675			52,444

	(273	)		(235	)		(129	)		(1,494	)		79			2,139			102,227

	(545	)		235			(140	)		1,494			(77	)		(1,456	)		70,264

	(545	)		235			(140	)		1,494			(77	)		(1,456	)		69,139
	—			—			—			—			—			—			1,125

	(545	)		235			(140	)		1,494			(77	)		(1,456	)		70,264

F-153

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group balance sheet reconciliation from UK GAAP to IFRS (concluded)


		UK GAAP
		in IFRS		Joint			Pension			Leasehold			Liquid			Goodwill		Deferred
		format		arrangements			reclassification			premiums			resources			amortization		tax

		($ million
At January 1, 2003
Noncurrent assets
	Property, plant and equipment		87,682		(1,760	)		—			(199	)		—			—		—
	Goodwill		10,438		—			—			—			—			—		—
	Other intangible assets		5,128		(1	)		—			—			—			—		—
	Investments in jointly controlled entities		4,031		1,565			—			—			—			—		—
	Investments in associates		4,626		—			—			—			—			—		—
	Other investments		1,995		—			—			—			—			—		—

	Fixed assets		113,900		(196	)		—			(199	)		—			—		—
	Loans		833		—			—			—			—			—		—
	Other receivables		1,006		—			—			—			—			—		—
	Derivative financial instruments		46		—			—			—			—			—		—
	Prepayments and accrued income		461		—			—			199			—			—		—
	Defined benefit pension plan surplus		388		—			166			—			—			—		—

			116,634		(196	)		166			—			—			—		—

Current assets
	Loans		165		—			—			—			—			—		—
	Inventories		10,181		(8	)		—			—			—			—		—
	Trade and other receivables		24,095		(22	)		—			—			—			—		—
	Other investments		215		—			—			—			(215	)		—		—
	Derivative financial instruments		995		—			—			—			—			—		—
	Prepayments and accrued income		1,556		—			—			—			—			—		—
	Current tax receivable		94		—			—			—			—			—		—
	Cash and cash equivalents		1,520		(19	)		—			—			215			—		—

			38,821		(49	)		—			—			—			—		—

Total assets			155,455		(245	)		166			—			—			—		—

Current liabilities
	Trade and other payables		25,853		(245	)		—			—			—			—		—
	Derivative financial instruments		1,415		—			—			—			—			—		—
	Accruals and deferred income		5,527		—			—			—			—			—		—
	Finance debt		10,086		—			—			—			—			—		—
	Current tax payable		3,420		—			—			—			—			—		—
	Provisions		716		—			—			—			—			—		—

			47,017		(245	)		—			—			—			—		—

Noncurrent liabilities
	Other payables		2,410		—			—			—			—			—		—
	Derivative financial instruments		—		—			—			—						—		—
	Accruals and deferred income		1,002		—			—			—			—			—		—
	Finance debt		11,922		—			—			—			—			—		—
	Deferred tax liabilities		13,514		—			(2,620	)		—			—			—		4,523
	Provisions		7,120		—			—			—			—			—		—
	Defined benefit pension plan and other postretirement benefit plan deficits		7,998		—			2,786			—			—			—		—

			43,966		—			166			—			—			—		4,523

Total liabilities			90,983		(245	)		166			—			—			—		4,523

Net assets			64,472		—			—			—			—			—		(4,523	)

BP shareholders’ equity			63,834		—			—			—			—			—		(4,523	)
Minority interest			638		—			—			—			—			—		—

Total equity			64,472		—			—			—			—			—		(4,523	)

F-154

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


Major
maintenance			Share-based						Dividend						Total IFRS
expenditure			payments			Asset swaps			accrual			Other			adjustments			IFRS
---------------------------------------------------------------------------------------------)
($
million
	(577	)		—			(280	)		—			77			(2,739	)		84,943
	—			—			—			—			2			2			10,440
	—			—			—			—			—			(1	)		5,127
	—			—			—			—			—			1,565			5,596
	—			—			—			—			(112	)		(112	)		4,514
	—			—			—			—			—			—			1,995

	(577	)		—			(280	)		—			(33	)		(1,285	)		112,615
	—			—			—			—			—			—			833
	—			—			—			—			—			—			1,006
	—			—			—			—			—			—			46
	—			—			—			—			3			202			663
	—			—			—			—			—			166			554

	(577	)		—			(280	)		—			(30	)		(917	)		115,717

	—			—			—			—			—			—			165
	—			—			—			—			(18	)		(26	)		10,155
	—			—			—			—			—			(22	)		24,073
	—			—			—			—			—			(215	)		—
	—			—			—			—			—			—			995
	—			—			—			—			4			4			1,560
	—			—			—			—			—			—			94
	—			—			—			—			—			196			1,716

	—			—			—			—			(14	)		(63	)		38,758

	(577	)		—			(280	)		—			(44	)		(980	)		154,475

	—			—			—			—			1			(244	)		25,609
	—			—			—			—			—			—			1,415
	—			—			—			(1,397	)		—			(1,397	)		4,130
	—			—			—			—			—			—			10,086
	—			—			—			—			—			—			3,420
	—			—			—			—			—			—			716

	—			—			—			(1,397	)		1			(1,641	)		45,376

	—			—			—			—			1			1			2,411
	—			—			—			—			—			—			—
	—			—			(52	)		—			—			(52	)		950
	—			—			—			—			—			—			11,922
	(183	)		(179	)		(80	)		—			70			1,531			15,045
	—			—			—			—			—			—			7,120
	—			—			—			—			—			2,786			10,784

	(183	)		(179	)		(132	)		—			71			4,266			48,232

	(183	)		(179	)		(132	)		(1,397	)		72			2,625			93,608

	(394	)		179			(148	)		1,397			(116	)		(3,605	)		60,867

	(394	)		179			(148	)		1,397			(116	)		(3,605	)		60,229
	—			—			—			—			—			—			638

	(394	)		179			(148	)		1,397			(116	)		(3,605	)		60,867

F-155

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group cash flow reconciliation from UK GAAP to IFRS


			UK GAAP															Major
			in IFRS			Joint			Net equity			Goodwill			Deferred			maintenance
			format			arrangements			accounting			amortization			tax			expenditure
-
			----------------------------------------------------------------------------------($-
			million
Year ended December 31, 2004
Operating activities
Profit before taxation				24,243			(16	)		(1,216	)		1,489			(25	)		(290	)
	Adjustments to reconcile profit before taxation to net cash provided by operating activities
		Exploration expenditure written off		274			—			—			—			—			—
		Depreciation, depletion and amortization		10,840			(110	)		—			(1,428	)		—			(296	)
		Impairment and (gain) loss on sale of businesses and fixed assets		928			—			—			(61	)		25			—
		Earnings from jointly controlled entities and associates		(3,577	)		(34	)		1,422			—			—			—
		Dividends received from jointly controlled entities and associates		2,199			—			—			—			—			—
		Interest receivable		(272	)		(12	)		—			—			—			—
		Interest received		332			12			—			—			—			—
		Finance costs		642			—			(206	)		—			—			—
		Interest paid		(694	)		—			—			—			—			—
		Other finance expense		357			—			—			—			—			—
		Share-based payments		138			—			—			—			—			—
		Net operating charge for pensions and other postretirement benefits, less contributions		(67	)		—			—			—			—			—
		Net charge for provisions, less payments		(110	)		—			—			—			—			—
		(Increase) decrease in inventories		(3,595	)		16			—			—			—			—
		(Increase) decrease in other current and noncurrent assets		(10,920	)		(10	)		—			—			—			—
		Increase (decrease) in other current and noncurrent liabilities		9,726			60			—			—			—			—
		Income taxes paid		(6,378	)		(3	)		—			—			—			—

Net cash provided by operating activities				24,066			(97	)		—			—			—			(586	)

Investing activities
	Capital expenditure			(13,035	)		158			—			—			—			586
	Acquisitions, net of cash acquired			(1,503	)		—			—			—			—			—
	Investment in jointly controlled entities			(1,522	)		(126	)		—			—			—			—
	Investment in associates			(942	)		—			—			—			—			—
	Proceeds from disposal of property, plant and equipment			4,236			—			—			—			—			—
	Proceeds from disposal of businesses			725			—			—			—			—			—
	Proceeds from loan repayments			87			—			—			—			—			—

Net cash used in investing activities				(11,954	)		32			—			—			—			586

Financing activities
	Net repurchase of shares			(7,208	)		—			—			—			—			—
	Proceeds from long-term financing			2,675			—			—			—			—			—
	Repayments of long-term financing			(2,204	)		—			—			—			—			—
	Net (decrease) increase in short-term debt			(40	)		16			—			—			—			—
	Dividends paid
		BP shareholders		(6,041	)		—			—			—			—			—
		Minority interest		(33	)		—			—			—			—			—

Net cash used in financing activities				(12,851	)		16			—			—			—			—

Currency translation differences relating to cash and cash equivalents				91			—			—			—			—			—

(Decrease) increase in cash and cash equivalents				(648	)		(49	)		—			—			—			—
Cash and cash equivalents at beginning of year				2,132			(76	)		—			—			—			—

Cash and cash equivalents at end of year				1,484			(125	)		—			—			—			—

F-156

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


						Recycling
Share-						foreign
based			Asset			exchange						Total IFS
payments			swaps			on disposal			Other			adjustment			IFRS
-----------------------------------------------------------------------------)
($
million
	(86	)		12			78			46			(8	)		24,235
	—			—			—			—			—			274
	—			(12	)		—			18			(1,828	)		9,012
	—			—			(78	)		3			(111	)		817
	—			—			—			(79	)		1,309			(2,268	)
	—			—			—			—			—			2,199
	—			—			—			—			(12	)		(284	)
	—			—			—			—			12			344
	—			—			—			4			(202	)		440
	—			—			—			(4	)		(4	)		(698	)
	—			—			—			—			—			357
	86			—			—			—			86			224
	—			—			—			—			—			(67	)
	—			—			—			—			—			(110	)
	—			—			—			14			30			(3,565	)
	—			—			—			(7	)		(17	)		(10,937	)
	—			—			—			—			60			9,786
	—			—			—			—			(3	)		(6,381	)

	—			—			—			(5	)		(688	)		23,378

	—			—			—			5			749			(12,286	)
	—			—			—			—			—			(1,503	)
	—			—			—			—			(126	)		(1,648	)
	—			—			—			—			—			(942	)
	—			—			—			—			—			4,236
	—			—			—			—			—			725
	—			—			—			—			—			87

	—			—			—			5			623			(11,331	)

	—			—			—			—			—			(7,208	)
	—			—			—			—			—			2,675
	—			—			—			—			—			(2,204	)
	—			—			—			—			16			(24	)
	—			—			—			—			—			(6,041	)
	—			—			—			—			—			(33	)

	—			—			—			—			16	��		(12,835	)

	—			—			—			—			—			91

	—			—			—			—			(49	)		(697	)
	—			—			—			—			(76	)		2,056

	—			—			—			—			(125	)		1,359

F-157

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group cash flow reconciliation from UK GAAP to IFRS (concluded)


			UK GAAP												Major
			in IFRS			Joint			Net equity			Goodwill			maintenance
			format			arrangements			accounting			amortization			expenditure
-
			--------------------------------------------------------------------($-
			million
Year ended December 31, 2003
Operating activities
Profit before taxation				16,763			(4	)		(224	)		1,376			(201	)
	Adjustments to reconcile profit before taxation to net cash provided by operating activities
		Exploration expenditure written off		297			—			—			—			—
		Depreciation, depletion and amortization		10,202			(11	)		—			(1,376	)		(216	)
		Impairment and (gain) loss on sale of businesses and fixed assets		(93	)		—			—			—			—
		Earnings from jointly controlled entities and associates		(1,438	)		(72	)		358			—			—
		Dividends received from jointly controlled entities and associates		548			—			—			—			—
		Interest receivable		(201	)		(11	)		—			—			—
		Interest received		175			11			—			—			—
		Finance costs		644			2			(134	)		—			—
		Interest paid		(1,006	)		(1	)		—			—			—
		Other finance expense		547			—			—			—			—
		Share-based payments		113			—			—			—			—
		Net operating charge for pensions and other postretirement benefits, less contributions		(2,913	)		—			—			—			—
		Net charge for provisions, less payments		66			—			—			—			—
		(Increase) decrease in inventories		(841	)		2			—			—			—
		(Increase) decrease in other current and noncurrent assets		(3,042	)		(33	)		—			—			—
		Increase (decrease) in other current and noncurrent liabilities		1,734			87			—			—			—
		Income taxes paid		(4,804	)		—			—			—			—

Net cash provided by operating activities				16,751			(30	)		—			—			(417	)

Investing activities
	Capital expenditure			(12,377	)		74			—			—			417
	Acquisitions, net of cash acquired			(211	)		—			—			—			—
	Investment in jointly controlled entities			(2,529	)		(101	)		—			—			—
	Investment in associates			(987	)		—			—			—			—
	Proceeds from disposal of property, plant and equipment			6,177			—			—			—			—
	Proceeds from disposal of businesses			179			—			—			—			—
	Proceeds from loan repayments			76			—			—			—			—
	Other			—			—			—			—			—

Net cash used in investing activities				(9,672	)		(27	)		—			—			417

Financing activities
	Net repurchase of shares			(1,889	)		—			—			—			—
	Proceeds from long-term financing			4,322			—			—			—			—
	Repayments of long-term financing			(3,560	)		—			—			—			—
	Net (decrease) increase in short-term debt			(2	)		—			—			—			—
	Dividends paid
		BP shareholders		(5,654	)		—			—			—			—
		Minority interest		(20	)		—			—			—			—

Net cash used in financing activities				(6,803	)		—			—			—			—

Currency translation differences relating to cash and cash equivalents				121			—			—			—			—

(Decrease) increase in cash and cash equivalents				397			(57	)		—			—			—
Cash and cash equivalents at beginning of year				1,735			(19	)		—			—			—

Cash and cash equivalents at end of year				2,132			(76	)		—			—			—

F-158

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


						Recycling
Share-						foreign
based			Asset			exchange					Total IFRS
payments			swaps			on disposal		Other			adjustments			IFRS
-----------------------------------------------------------------------------)
($
million
	(95	)		5			—		48			905			17,668
	—			—			—		—			—			297
	—			(5	)		—		11			(1,597	)		8,605
	—			—			—		(1	)		(1	)		(94	)
	—			—			—		(47	)		239			(1,199	)
	—			—			—		—			—			548
	—			—			—		—			(11	)		(212	)
	—			—			—		—			11			186
	—			—			—		1			(131	)		513
	—			—			—		—			(1	)		(1,007	)
	—			—			—		—			—			547
	95			—			—		—			95			208
	—			—			—		—			—			(2,913	)
	—			—			—		—			—			66
	—			—			—		(14	)		(12	)		(853	)
	—			—			—		—			(33	)		(3,075	)
	—			—			—		1			88			1,822
	—			—			—		—			—			(4,804	)

	—			—			—		(1	)		(448	)		16,303

	—			—			—		1			492			(11,885	)
	—			—			—		—			—			(211	)
	—			—			—		—			(101	)		(2,630	)
	—			—			—		—			—			(987	)
	—			—			—		—			—			6,177
	—			—			—		—			—			179
	—			—			—		—			—			76
	—			—			—		—			—			—

	—			—			—		1			391			(9,281	)

	—			—			—		—			—			(1,889	)
	—			—			—		—			—			4,322
	—			—			—		—			—			(3,560	)
	—			—			—		—			—			(2	)
	—			—			—		—			—			(5,654	)
	—			—			—		—			—			(20	)

	—			—			—		—			—			(6,803	)

	—			—			—		—			—			121

	—			—			—		—			(57	)		340
	—			—			—		—			(19	)		1,716

	—			—			—		—			(76	)		2,056

F-159

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


	*Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity*

Accounting for joint arrangements. Under UK GAAP, certain of the Group’s activities were conducted through joint arrangements and were included in the consolidated financial statements in proportion to the Group’s share of the income, expenses, assets and liabilities of these joint arrangements. However, IFRS requires that, if such joint arrangements comprise a legal entity, they be treated as jointly controlled entities. The Group has chosen to account for jointly controlled entities under the equity method.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Sales and other operating revenues		(274	)		(185	)
Earnings from jointly controlled entities — after interest and tax		34			72
Interest and other revenues		(3	)		(2	)
Purchases		(82	)		(93	)
Production and manufacturing expenses		(44	)		(7	)
Depreciation, depletion and amortization		(110	)		(11	)
Distribution and administration expenses		9			—
Taxation		(16	)		(4	)
Profit for the year		—			—


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Property, plant and equipment		(2,297	)		(2,089	)		(1,760	)
Intangible assets		(2	)		(2	)		(1	)
Investments in jointly controlled entities		2,088			1,963			1,565
Inventories		(34	)		(16	)		(8	)
Trade and other receivables		48			32			(22	)
Current assets — prepayments and accrued income		(4	)		1			—
Cash and cash equivalents		(125	)		(76	)		(19	)
Trade and other payables		(280	)		(41	)		(245	)
Current liabilities — accruals and deferred income		(13	)		(2	)		—
Other payables		—			(140	)		—
Noncurrent liabilities — accruals and deferred income		(2	)		—			—
Deferred tax liabilities		(22	)		(4	)		—
Provisions		(9	)		—			—
Total equity		—			—			—

F-160

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)

Presentation of results of equity-accounted entities. UK practice in respect of equity accounting is to present the Group’s share of the profit before interest and tax, finance costs, other finance expense, and tax charge of jointly controlled entities and associates in the corresponding line of the Group’s income statement. IFRS requires the presentation of equity-accounted results as a single net profit item in the income statement. Consequently, the Group’s share of all the individual equity-accounted items has been removed from the relevant lines in the income statement and offset against the results of equity-accounted entities to present them on anet-of-tax basis.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Earnings from jointly controlled entities — after interest and tax		(1,251	)		(233	)
Earnings from associates — after interest and tax		(171	)		(125	)
Finance costs		(206	)		(134	)
Taxation		(1,173	)		(224	)
Minority interest		(43	)		—
Profit for the year		—			—

December 31,

January 1,

2004

2003

($ million

Total equity

—

Presentation of pensions and other postretirement benefit obligations. BP adopted the UK standard on retirement benefits, FRS 17, in 2004. Under this standard, retirement benefit obligations and assets are presented on anet-of-tax basis in the balance sheet. IFRS, however, requires that these assets and liabilities be shown gross, with the related deferred tax effects included within the deferred tax captions in the balance sheet. An adjustment has therefore been made to reclassify the deferred tax balances.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004		2003

	($ million
Profit for the year		—		—

F-161

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Defined benefit pension plan surplus		630			534			166
Deferred tax liabilities		(1,720	)		(1,653	)		(2,620	)
Defined benefit pension plan and other postretirement benefit plan deficits		2,350			2,187			2,786
Total equity		—			—			—

Reclassification of leasehold premiums. In accordance with UK practice, BP included leasehold premiums paid within property, plant and equipment. Under IFRS, the premiums paid on operating leases represent prepaid lease payments and have therefore been reclassified within loans and other receivables as prepayments.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004		2003

	($ million
Profit for the year		—		—


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Property, plant and equipment		(102	)		(205	)		(199	)
Noncurrent assets — prepayments and accrued income		102			205			199
Total equity		—			—			—

Liquid resources. Short-term investments have been reclassified as cash and cash equivalents under IFRS.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004		2003

	($ million
Profit for the year		—		—


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Other investments		(328	)		(185	)		(215	)
Cash and cash equivalents		328			185			215
Total equity		—			—			—

F-162

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)

Goodwill amortization. Under UK GAAP, BP capitalized goodwill and amortized it over its estimated useful economic life, which was usually 10 years. Under IFRS, however, goodwill is not amortized but is subject to an annual impairment review. In accordance with IFRS 1, an impairment test was carried out at the date of transition (DoT). No impairment was identified and no other adjustments to the value of goodwill were made. This adjustment reverses the amortization of goodwill charged under UK GAAP after the DoT to IFRS.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Depreciation, depletion and amortization		(1,428	)		(1,376	)
Impairment and losses on sale of businesses and fixed assets		(61	)		—
Profit for the year		1,489			1,376

December 31,

January 1,

2004

2003

($ million

Goodwill

2,985

1,421

—

Total equity

2,985

1,421

—

Deferred tax adjustments. Under UK GAAP, deferred tax is provided on timing differences, whereas IFRS requires provision to be made for temporary differences between carrying values and the related tax base. As a result, deferred tax needs to be recognized under IFRS in respect of a number of differences for which no deferred tax was recognized under UK GAAP. The major areas affected by this are described below.

In accordance with the requirements of IFRS, additional deferred tax has been provided on the temporary difference created by the allocation of fair values to the noncurrent assets acquired in a business combination. The consequent increase in the difference between the carrying value of noncurrent assets and the tax base is not considered to be a timing difference under UK GAAP, but is regarded as a temporary difference for IFRS. An adjustment is therefore required to reflect the increase in the deferred tax liability at the DoT. The resulting deferred tax liability changes due to the depreciation or impairment of the underlying fixed asset.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Impairment and losses on sale of businesses and fixed assets		25			—
Taxation		(418	)		(873	)
Profit for the year		393			873

F-163

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Property, plant and equipment		159			—			—
Deferred tax liabilities		2,591			2,764			3,608
Total equity		(2,432	)		(2,764	)		(3,608	)

Certain subsidiaries, principally in the US, have inventories valued on thelast-in first-out (LIFO) basis for tax purposes. The difference between the book and tax valuation is not a timing difference for UK GAAP but is a temporary difference for IFRS.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Taxation		438			165
Profit for the year		(438	)		(165	)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Deferred tax liabilities		1,340			894			729
Total equity		(1,340	)		(894	)		(729	)

Under UK GAAP, a deferred tax provision is made for tax that would arise on the remittance of the retained earnings of overseas subsidiaries, joint ventures and associated undertakings, only to the extent that dividends have been accrued as receivable. For IFRS, deferred tax is recognized for all retained earnings whose distribution is not within the control of the Group or whose distribution is likely in the foreseeable future, irrespective of whether dividends have actually been accrued or declared.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003
-
	------------------------($-
	million
Taxation		29			—
Profit for the year		(29	)		—

F-164

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Deferred tax liabilities		214			186			186
Total equity		(214	)		(186	)		(186	)

Major maintenance expenditure. Under UK GAAP, the Group capitalized expenditure on major maintenance, refits or repairs where it enhanced or restored the performance of an asset, or replaced an asset or part of an asset that was separately depreciated. Under IFRS, the Group will continue to capitalize expenditure where it enhances the performance of an asset or replaces an asset or part of an asset that meets the Group’s definition of a part of an asset in accordance with IAS 16 ‘Property, Plant and Equipment’. Other elements of expenditure incurred during major plant maintenance shutdowns, such as overhaul costs, are not permitted to be capitalized under IFRS. There is therefore a reduction in the carrying value of property, plant and equipment to reflect this change for expensing overhaul costs that no longer qualify for capitalization.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003

	($ million
Production and manufacturing expenses		586			417
Depreciation, depletion and amortization		(296	)		(216	)
Taxation		(73	)		(81	)
Profit for the year		(217	)		(120	)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Property, plant and equipment		(1,148	)		(818	)		(577	)
Deferred tax liabilities		(354	)		(273	)		(183	)
Total equity		(794	)		(545	)		(394	)

Share-based payments. Under UK GAAP, BP recognized as an expense the costs of the potential awards for the long-term incentive plans (Executive Directors’ Incentive Plan and the Long Term Performance Plan) and certain other share-based schemes. The costs of awards under the long-term incentive plans were accrued over the performance period of each plan, based on the estimated actual cost of shares, and an adjustment was made to reflect the actual cost when the final award was confirmed. The cost of other share-based schemes was based on the fair value of the awards.

IFRS requires the fair value of the option and share awards that ultimately vest to be charged to the income statement over the vesting or performance period. The fair value is determined at the date of the grant using an appropriate pricing model (i.e. a binomial model). If an award fails to vest as the result of

F-165

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)

certain types of performance condition not being satisfied, the charge to the income statement will be adjusted to reflect this.

BP has developed a binomial (or lattice-type) pricing model, which has been used to arrive at the fair value at the grant date of the share option schemes and part of the award under the long-term incentive plans. The other part of the long-term incentive plans is based on market conditions and has been valued using a Monte Carlo model.

Although IFRS 1 allows entities to restrict the recognition of the expense of share-based payments to those schemes granted after November 7, 2002 that have not vested as of January 1, 2005, BP has elected to apply IFRS 2 ‘Share-based Payment’ fully retrospectively.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003
-
	------------------------($-
	million
Production and manufacturing expenses		28			25
Distribution and administration expenses		58			70
Taxation		(62	)		(56	)
Profit for the year		(24	)		(39	)


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Deferred tax liabilities		(353	)		(235	)		(179	)
Total equity		353			235			179

Asset swaps and fair value adjustment. Under UK GAAP asset swaps are generally treated as exchanges of assets at net book value, with no gain or loss resulting from them. IFRS requires assets acquired in asset exchanges to be accounted for at fair value at the date of the transaction, with any gain or loss recognized in income.

In 2000, BP agreed to a transaction with its partners in the Prudhoe Bay field in Alaska whereby it received an increase in its natural gas interest in return for a reduction in its share of liquids production.

In 2001, BP undertook a transaction with Solvay that led to the exchange of businesses for an interest in a joint venture and an associated undertaking. The transaction has been recorded at fair value for IFRS.

F-166

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (continued)

On November 1, 2004 BP acquired Solvay’s interests in these ventures and has accounted for this as a business combination.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004			2003
-
	------------------------($-
	million
Depreciation, depletion and amortization		(12	)		(5	)
Taxation		(27	)		3
Profit for the year		39			2


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Property, plant and equipment		(340	)		(269	)		(280	)
Noncurrent liabilities — accruals and deferred income		(48	)		(53	)		(52	)
Deferred tax liabilities		(102	)		(76	)		(80	)
Total equity		(190	)		(140	)		(148	)

Dividend accrual. The UK GAAP approach to the recognition of proposed dividends was to account for the dividend in the period to which it related, e.g. the dividend proposed in February 2005 in respect of the final quarter of 2004 was accrued for in 2004. Under IFRS, the proposed dividend can be recognized only in the period in which it is properly authorized or paid, which, in the case of BP, is the quarter following that to which the dividend relates, i.e. the dividend proposed in February 2005 in respect of the fourth quarter of 2004 can be accounted for only in the first quarter of 2005. Therefore each balance sheet is adjusted to derecognize the dividend declared after the balance sheet date.


	At						At
	December 31,						January 1,

	2004			2003			2003

	($ million
Current liabilities — accruals and deferred income		(1,821	)		(1,494	)		(1,397	)
Total equity		1,821			1,494			1,397

Recycling of cumulative currency translation differences on disposal of net investment in foreign operations. The consolidation of entities with a non-US dollar functional currency results in currency translation differences that are taken directly to equity, where they are accumulated. Under UK GAAP these cumulative currency translation differences remained in equity. IFRS requires that, when an entity is wholly or partially disposed of, such cumulative translation differences be recycled to the income statement as part of the gain or loss on disposal. In addition, there is a requirement to maintain such differences as a separate component of equity. In accordance with one of the exemptions in IFRS 1, the

F-167

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Differences between UK GAAP and IFRS presentation that have no impact on BP’s reported income or total equity (concluded)

amount of this component has been deemed by BP to be zero at the DoT. Consequently, only those translation differences that arise after the DoT will be recycled upon disposal of a foreign operation.


	Year ended
	December 31,

Increase (decrease) in caption heading	2004		2003
-
	------------------------($-
	million
Gains on sale of businesses and fixed assets		78		—
Profit for the year		78		—

December 31,

January 1,

2004

2003

2004

($ million

Total equity

—

Other. This adjustment includes the IFRS adjustments made to equity-accounted entities.

F-168


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

(This page intentionally left blank)

F-169

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Group balance sheet reconciliation from UK GAAP to IFRS


													Other non-		Other non-
										Non-			financial		financial
		IFRS at		Fair			Cash			qualifying			contracts		contracts no
		December 31,		value			flow			hedge			at fair		longer at fair
		2004		hedges			hedges			derivatives			value		value
-
		------------------------------------------------------------------------------------($-
		million
At January 1, 2005
Noncurrent assets
	Property, plant and equipment		93,092		—			—			—			—		—
	Goodwill		10,857		—			—			—			—		—
	Intangible assets		4,205		—			—			—			—		—
	Investments in jointly controlled entities		14,556		—			—			—			—		—
	Investments in associates		5,486		—			—			—			—		—
	Other investments		394		—			—			—			—		—

	Fixed assets		128,590		—			—			—			—		—
	Loans		811		—			—			—			—		—
	Other receivables		429		—			—			—			—		—
	Derivative financial instruments		898		112			79			8			110		(34	)
	Prepayments and accrued income		354		—			—			—			—		—
	Defined benefit pension plan surplus		2,105		—			—			—			—		—

			133,187		112			79			8			110		(34	)

Current assets
	Loans		193		—			—			—			—		—
	Inventories		15,645		—			—			—			—		—
	Trade and other receivables		37,099		—			(2	)		—			—		—
	Derivative financial instruments		5,317		—			141			178			34		47
	Prepayments and accrued income		1,671		—			—			—			—		—
	Current tax receivable		159		—			—			—			—		—
	Cash and cash equivalents		1,359		—			—			—			—		—

			61,443		—			139			178			34		47

Total assets			194,630		112			218			186			144		13

Current liabilities
	Trade and other payables		38,540		—			—			—			—		—
	Derivative financial instruments		5,074		—			16			210			14		—
	Accruals and deferred income		4,482		—			—			—			—		—
	Finance debt		10,184		—			—			—			—		—
	Current tax payable		4,131		—			—			—			—		—
	Provisions		715		—			—			—			—		—

			63,126		—			16			210			14		—

Noncurrent liabilities
	Other payables		3,581		—			—			—			—		—
	Derivative financial instruments		158		129			4			17			12		—
	Accruals and deferred income		699		—			—			—			—		—
	Finance debt		12,907		(17	)		—			—			—		—
	Deferred tax liabilities		16,701		—			60			(13	)		44		5
	Provisions		8,884		—			—			—			—		—
	Defined benefit pension plan and other postretirement benefit plan deficits		10,339		—			—			—			—		—

			53,269		112			64			4			56		5

Total liabilities			116,395		112			80			214			70		5

Net assets			78,235		—			138			(28	)		74		8

BP shareholders’ equity			76,892		—			138			(28	)		74		8
Minority interest			1,343		—			—			—			—		—

Total equity			78,235		—			138			(28	)		74		8

F-170

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)


Available-
for-sale					Elimination						IFRS at
financial		Embedded			of deferred			Total IAS 39			January 1,
assets		derivatives			gains/losses			adjustments			2005
----------------------------------------------------------------------)
($
million
	—		—			—			—			93,092
	—		—			—			—			10,857
	—		—			—			—			4,205
	—		—			—			—			14,556
	—		—			—			—			5,486
	344		—			—			344			738

	344		—			—			344			128,934
	—		—			—			—			811
	—		—			—			—			429
	—		—			(147	)		128			1,026
	—		599			—			599			953
	—		—			—			—			2,105

	344		599			(147	)		1,071			134,258

	—		—			—			—			193
	—		—			—			—			15,645
	—		—			—			(2	)		37,097
	—		—			—			400			5,717
	—		278			—			278			1,949
	—		—			—			—			159
	—		—			—			—			1,359

	—		278			—			676			62,119

	344		877			(147	)		1,747			196,377

	—		—			—			—			38,540
	—		—			—			240			5,314
	—		402			—			402			4,884
	—		—			—			—			10,184
	—		—			—			—			4,131
	—		—			—			—			715

	—		402			—			642			63,768

	—		—			—			—			3,581
	—		—			—			162			320
	—		1,151			—			1,151			1,850
	—		—			164			147			13,054
	114		(267	)		(55	)		(112	)		16,589
	—		—			—			—			8,884
	—		—			—			—			10,339

	114		884			109			1,348			54,617

	114		1,286			109			1,990			118,385

	230		(409	)		(256	)		(243	)		77,992

	230		(409	)		(256	)		(243	)		76,649
	—		—			—			—			1,343

	230		(409	)		(256	)		(243	)		77,992

F-171

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Adjustments required to the balance sheet as at January 1, 2005 for the adoption of IAS 32 and IAS 39

Under UK GAAP, all derivatives used for trading purposes were recognized on the balance sheet at fair value. However, derivative financial instruments used for hedging purposes were recognized by applying either the accrual method or the deferral method. Under the accrual method, amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. Changes in the derivatives and fair values are not recognized. On the deferral method, gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts as the underlying hedged transaction matures or occurs.

For IFRS, all financial assets and financial liabilities have to be recognized initially at fair value. In subsequent periods the measurement of these financial instruments depends on their classification into one of the following measurement categories: i) financial assets or financial liabilities at-fair-value-through-profit-and-loss (such as those used for trading purposes, and all derivatives which do not qualify for hedge accounting); ii) loans and receivables; and iii) available-for-sale financial assets (including certain investments held for the long term).

Fair value hedges. Where fair value hedge accounting was applied to transactions that hedge the Group’s exposure to the changes in the fair value of a firm commitment or a recognized asset or liability that are attributable to a specific risk the derivatives designated as hedging instruments are recorded at their fair value in the Group’s balance sheet and changes in their fair value are recognized in the income statement. Any gain or loss on the hedged item attributable to the hedged risk is adjusted against the carrying amount of the hedged item and recognized in the income statement.

The ‘pay floating’ interest rate swaps and currency swaps hedging the debt book in place on January 1, 2005 were highly effective and consequently qualify as fair value hedges for hedge accounting. The full fair value of the swaps was recognized on the balance sheet and the carrying value of debt.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — derivative financial instruments		112
Noncurrent liabilities — derivative financial instruments		129
Finance debt		(17	)
Total equity		—

Cash flow hedges. The Group uses currency derivatives to hedge its exposure to variability in cash flows arising either from a recognized asset or liability or a forecast transaction. The hedged instrument is recognized at fair value on the balance sheet. At maturity of the hedged item, the element deferred in equity is treated in accordance with the nature of the hedged exposure, for example, capitalized into

F-172

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NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Adjustments required to the balance sheet as at January 1, 2005 for the adoption of IAS 32 and IAS 39 (continued)

the cost of an item of property, plant and equipment, or expensed in the case of a hedge of a tax payment.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — derivative financial instruments		79
Trade and other receivables		(2	)
Current assets — derivative financial instruments		141
Current liabilities — derivative financial instruments		16
Noncurrent liabilities — derivative financial instruments		4
Deferred tax liabilities		60
Total equity		138

Non-qualifying hedge derivatives. Under IAS 39, there are strict criteria that need to be met in order for hedge accounting to be applied. This adjustment records the impact of those derivatives, or elements thereof, held by the Group that do not qualify for hedge accounting, or hedges for which hedge accounting has not been claimed under IAS 39.

From January 1, 2005, these positions will be fair valued (‘marked to market’) and the change in fair value taken to income.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — derivative financial instruments		8
Current assets — derivative financial instruments		178
Current liabilities — derivative financial instruments		210
Noncurrent liabilities — derivative financial instruments		17
Deferred tax liabilities		(13	)
Total equity		(28	)

F-173

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NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Adjustments required to the balance sheet as at January 1, 2005 for the adoption of IAS 32 and IAS 39 (continued)

Other nonfinancial contracts at fair value. Certain net-settled nonfinancial contracts are deemed to meet the definition of financial instruments under IAS 39 and, as such, need to be recorded on the balance sheet at fair value.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — derivative financial instruments		110
Current assets — derivative financial instruments		34
Current liabilities — derivative financial instruments		14
Noncurrent liabilities — derivative financial instruments		12
Deferred tax liabilities		44
Total equity		74

Other nonfinancial contracts no longer at fair value. Certain nonfinancial contracts held for trading purposes were marked to market under UK GAAP. However, under IFRS they could no longer be recorded at fair value as they did not meet the definition of financial assets or financial liabilities. These contracts are accounted for on an accruals basis.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — derivative financial instruments		(34	)
Current assets — derivative financial instruments		47
Deferred tax liabilities		5
Total equity		8

Available-for-sale financial assets. Under UK GAAP, the Group’s investments other than subsidiaries, jointly controlled entities and associates were stated at cost less accumulated impairment losses.

For IFRS, these investments are classified as available-for-sale financial assets, and as such need to be recorded at fair value with the gain or loss arising as a result of the change in fair value being recorded directly in equity.

The transition adjustment relates to the fair value of listed investments held by the Group. In accordance with IAS 39, all future fair value adjustments will be booked directly in equity until disposal of the investment, when the cumulative associated gains/losses are recycled through the income

F-174

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NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (continued)

Adjustments required to the balance sheet as at January 1, 2005 for the adoption of IAS 32 and IAS 39 (continued)

statement. At this point, the gain or loss on disposal under IFRS will be identical to that which would result using historical cost accounting.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Other investments		344
Deferred tax liabilities		114
Total equity		230

Embedded derivatives. Embedded derivatives are required to be separated from their host contracts and separately recorded at fair value, with any resulting change in gain or loss in the period being recognized in the income statement.

Certain contracts have been determined to contain embedded derivatives. These embedded derivatives will be fair valued at each period end with the resulting gains or losses taken to the income statement.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — prepayments and accrued income		599
Current assets — prepayments and accrued income		278
Current liabilities — accruals and deferred income		402
Noncurrent liabilities — accruals and deferred income		1,151
Deferred tax liabilities		(267	)
Total equity		(409	)

Elimination of currently deferred gains and losses from derivatives. Under UK GAAP, gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. Where derivatives that are used to manage interest rate risk, to convert non-US dollar debt or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction.

On transition to IFRS, only assets and liabilities that qualify as such can continue to be recognized. Consequently, all gains and losses that were generated by derivatives used for hedging purposes and deferred in the balance sheet as if they were assets or liabilities must be eliminated from the transitional balance sheet. This is achieved by transferring gains and losses arising from cash flow hedges to equity,

F-175

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 52 —	First-time adoption of International Financial Reporting Standards (concluded)

Adjustments required to the balance sheet as at January 1, 2005 for the adoption of IAS 32 and IAS 39 (concluded)

pending recycling to income at a later date, and by transferring gains and losses arising from fair value hedges to adjust the carrying value of the hedged item, in this case, finance debt.


	At
	January 1,

Increase (decrease) in caption heading	2005
($-	)

	million
Noncurrent assets — prepayments and accrued income		(147	)
Finance debt		164
Deferred tax liabilities		(55	)
Total equity		(256	)

Note 53 — Oil and natural gas exploration and production activities (a)

Capitalized costs at December 31


				Rest of				Rest of		Asia
		UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

		($ million
2005
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

2004
Gross capitalized costs
	Proved properties		27,540		4,691		43,011		10,450		2,892		10,401		—		3,834		102,819
	Unproved properties		300		170		1,395		456		1,240		526		119		105		4,311

			27,840		4,861		44,406		10,906		4,132		10,927		119		3,939		107,130
Accumulated depreciation			17,681		2,794		19,713		5,546		1,350		5,573		—		1,014		53,671

Net capitalized costs			10,159		2,067		24,693		5,360		2,782		5,354		119		2,925		53,459

2003
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

F-176

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 53 — Oil and natural gas exploration and production activities(a) (continued)

Costs incurred for the year ended December 31


				Rest of				Rest of		Asia
		UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total
)

		($ million
2005
Acquisition of properties
	Proved		—		—		—		—		—		—		—		—		—
	Unproved		—		—		29		34		—		—		—		—		63

			—		—		29		34		—		—		—		—		63
Exploration and appraisal costs (b)			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

2004
Acquisition of properties
	Proved		—		—		—		—		—		—		—		—		—
	Unproved		2		—		58		5		—		13		—		—		78

			2		—		58		5		—		13		—		—		78
Exploration and appraisal costs (b)			51		17		423		199		85		142		113		9		1,039
Development costs			679		262		3,247		527		88		1,460		—		1,007		7,270

Total costs			732		279		3,728		731		173		1,615		113		1,016		8,387

2003
Acquisition of properties
	Proved		—		—		—		—		—		—		—		—		—
	Unproved		—		—		—		—		—		—		—		—		—

Exploration and appraisal costs (b)			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

F-177

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 53 — Oil and natural gas exploration and production activities(a) (continued)

Results of operations for the year ended December 31


					Rest of					Rest of			Asia
		UK			Europe			USA		Americas			Pacific			Africa		Russia			Others			Total

		($ million
2005
Sales and other operating revenues (c)
	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 costs (income) (d)			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
Impairment and (gains) losses on sale of businesses and fixed assets			44			(1,038	)		232		(133	)		—			—		2			—			(893	)

			5,048			(721	)		7,570		2,022			551			1,181		47			3,968			19,666

Profit before taxation (e)(f)			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

2004
Sales and other operating revenues (c)
	Third parties		3,458			626			1,735		1,776			977			492		5			403			9,472
	Sales between businesses		2,424			609			11,794		2,556			530			1,439		—			2,912			22,264

			5,882			1,235			13,529		4,332			1,507			1,931		5			3,315			31,736

Exploration expenditure			26			25			361		141			14			45		17			8			637
Production costs			901			117			1,428		535			142			323		—			131			3,577
Production taxes			273			30			477		239			45			—		—			1,023			2,087
Other costs (income) (d)			(211	)		38			1,884		458			96			122		(3	)		1,380			3,764
Depreciation, depletion and amortization			1,524			172			2,268		611			174			287		—			121			5,157
Impairment and (gains) losses on sale of businesses and fixed assets			21			1			344		(55	)		113			48		—			(3	)		469

			2,534			383			6,762		1,929			584			825		14			2,660			15,691

Profit before taxation (e)(f)			3,348			852			6,767		2,403			923			1,106		(9	)		655			16,045
Allocable taxes			1,242			534			2,103		859			(4	)		441		2			150			5,327

Results of operations			2,106			318			4,664		1,544			927			665		(11	)		505			10,718

F-178

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 53 — Oil and natural gas exploration and production activities(a) (continued)

Results of operations for the year ended December 31 (continued)


					Rest of				Rest of			Asia
		UK			Europe		USA		Americas			Pacific			Africa			Russia			Others		Total

		($ million
2003
Sales and other operating revenues (c)
	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 costs (income) (d)			(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
Impairment and (gains) losses on sale of businesses and fixed assets			(553	)		30		573		(387	)		347			(122	)		(65	)		2		(175	)

			1,901			418		6,989		1,398			925			408			(14	)		2,011		14,036

Profit before taxation (e)(f)			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

The Group’s share of jointly controlled entities’ and associates’ results of operations in 2005 was a profit of $3,035 million (2004 $1,816 million profit and 2003 $790 million profit) after deducting interest of $226 million (2004 $189 million and 2003 $120 million) taxation of $1,250 million (2004 $969 million and 2003 $153 million) and minority interest of $104 million (2004 $43 million and 2003 nil).

The Group’s share of jointly controlled entities’ and associates’ net capitalized costs at December 31, 2005 was $10,670 million (2004 $11,013 million and 2003 $10,222 million).

The Group’s share of jointly controlled entities’ and associates’ costs incurred in 2005 was $1,205 million (2004 $1,102 million and 2003 $468 million): in Russia $845 million (2004 $773 million and 2003 $118 million) and Rest of Americas $360 million (2004 $329 million and 2003 $350 million).

(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’. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main midstream 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.

F-179

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 53 — Oil and natural gas exploration and production activities(a) (concluded)

Results of operations for the year ended December 31 (concluded)


(b)	Includes exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred.


(c)	Sales 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.

(d)

Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes and other government take. In 2005 this also included the fair value loss on embedded derivatives of $1,688 million and a $265 million charge incurred on the cancellation of an intragroup gas supply contract. The UK region included a $530 million charge offset by corresponding gains primarily in the US, relating to the Group’s self-insurance programme.


(e)	Excludes accretion expense attributable to exploration and production activities amounting to $122 million in 2005 (2004 $120 million and 2003 $110 million). Under IFRS, accretion expense is included in Other finance expense in the Consolidated Statement of Income.


(f)	The Exploration and Production profit before interest and tax comprises:


			Rest of					Rest of		Asia
	UK		Europe			USA		Americas		Pacific			Africa			Russia			Others			Total

	($ million
Year ended December 31, 2005
Exploration and production activities
— Group (as above)		2,077		2,332			9,320		3,101		1,276			2,571			(47	)		1,518			22,148
— Jointly controlled entities and associates		—		—			—		309		41			—			2,685			—			3,035
Midstream activities		52		(11	)		172		148		(20	)		(39	)		(1	)		24			325

Total profit before interest and tax		2,129		2,321			9,492		3,558		1,297			2,532			2,637			1,542			25,508

Year ended December 31, 2004
Exploration and production activities
— Group (as above)		3,348		852			6,767		2,403		923			1,106			(9	)		655			16,045
— Jointly controlled entities and associates		—		—			—		113		38			—			1,665			—			1,816
Midstream activities		105		(15	)		40		123		(50	)		(19	)		—			42			226

Total profit before interest and tax		3,453		837			6,807		2,639		911			1,087			1,656			697			18,087

Year ended December 31, 2003
Exploration and production activities
— Group (as above)		3,257		591			5,493		2,424		421			1,010			14			473			13,683
— Jointly controlled entities and associates		—		—			1		171		20			—			573			25			790
Midstream activities		211		(4	)		182		228		(2	)		(2	)		—			(2	)		611

Total profit before interest and tax		3,468		587			5,676		2,823		439			1,008			587			496			15,084

F-180

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs

Included within the total exploration expenditure of $4,008 million (2004 $3,761 million and 2003 $4,236 million) shown as part of intangible assets (see Note 29 — Intangible assets) is an amount of $1,931 million (2004 $1,680 million and 2003 $1,698 million) representing drilling costs directly associated with exploration wells.

The carried costs of exploration wells 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. In evaluating whether costs incurred meet the criteria for initial and continued capitalization management uses two main criteria: a) that exploration drilling is still under way or firmly planned, or b) that it either has been determined, or work is underway to determine, that the discovery is economically viable, based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing.

The following table provides the year-end balances and movements for suspended exploration well-drilling costs:


	Years Ended
	December 31,

	2005			2004			2003

	($ million
Capitalized exploration well-drilling costs
At January 1,		1,680			1,698			1,846
Additions pending determination of proved reserves		565			391			295
Exploration well costs written off in the period		(81	)		(84	)		(90	)
Costs of exploration wells divested in the period		(72	)		(34	)		(76	)
Reclassified to tangible assets following determination of proved reserves		(161	)		(291	)		(277	)

At December 31,		1,931			1,680			1,698

The following table provides an ageing profile of suspended exploration wells:


	At December 31,

	2005				2004				2003

			Wells				Wells				Wells
	Cost		gross		Cost		gross		Cost		gross

	($ million				($ million				($ million
Age
Less than 1 year		593		46		411		26		266		34
1 to 5 years		823		69		787		81		752		81
6 to 10		309		42		292		29		522		62
More than 10 years		206		20		190		18		158		19

Total		1,931		177		1,680		154		1,698		196

F-181

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

The following table provides an analysis of the amount of drilling costs directly associated with exploration wells:


	2005						2004						2003

			Wells						Wells						Wells
	Cost		gross		Projects		Cost		gross		Projects		Cost		gross		Projects

	($ million						($ million						($ million
Exploration well-drilling costs
Projects with first capitalized exploration well drilled in twelve months ending December 31,		451		31		14		290		15		12		155		16		11
Other projects with recent or planned drilling activity		718		65		20		400		36		13		263		32		11
Projects with completed exploration activity		762		81		28		990		103		41		1,280		148		50

At December 31,		1,931		177		62		1,680		154		66		1,698		196		72

Exploration projects frequently involve the drilling of multiple wells over a number of years, and several discoveries may be grouped into a single development project. The table above shows a total of 48 projects which have exploration well-drilling costs which have been capitalized for more than twelve months as at December 31, 2005. Of these, there are 20 projects where exploratory wells have been drilled in the preceding twelve months or further exploratory drilling is planned in the next year. Projects with completed exploration activity comprise a total of 28 projects, whose drilling costs totalled $762 million at December 31, 2005. Details of the activities being undertaken to progress these projects towards development are shown below:

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Angola

Bavuca/ Kakocha/ Mavacola / Mbulumbumba/ Vicango

2000-2003

2010-2014

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; development planned in two phases through tieback to existing infrastructure; Declaration of Commercial Discovery submitted for Mavacola in 2005.

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Colombia

Floreña/ Pauto

1998

2006

Initial assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; phased development scheme, production from earlier phases in 2002-2004; subsequent phase via expansion of existing infrastructure.

Volcanera

1993

2009

Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; planned phased development linked to neighbouring field using existing infrastructure; further seismic survey planned for 2006.

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Egypt

Ras El Bar Seth/ Taurt

1995-2004

2006-2010

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; planned subsea tieback to existing infrastructure; new gas export pipeline planned for Taurt; gas sale agreement in place.

Temsah

1995-2004

2006-2010

Assessment of hydrocarbon quantities as potentially commercial completed; phased development options identified and under evaluation; planned subsea tieback to existing infrastructure; gas sale agreement in place.

Western Mediterranean Block B

2002-2004

2009-2017

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; seismic survey programme begun; gas sale agreement negotiations under way.

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NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Indonesia

Tangguh Phase II

1994-1997

2008-2011

Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; onshore and offshore development options identified and under evaluation.

Norway

Skarv/ Snadd

1998-2002

2006-2007

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; planned development with floating production system and export infrastructure agreed with partners.

Trinidad

114

Cashima

2001

2006

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; development awaiting capacity in existing infrastructure.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Corallita/ Lantana

1996

2007-2008

Assessment of hydrocarbon quantities as potentially commercial completed; reservoir characteristics under analysis; development options identified and under evaluation; planned subsea tieback to existing infrastructure; fields dedicated to LNG gas contract delivery.

Manakin

2000

2010+

Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; planned subsea tieback to existing production facilities and LNG train; inter- governmental discussions on unitization continue.

Red Mango

2000-2001

2006

Assessment of hydrocarbon quantities as potentially commercial completed; development option selected; planned subsea tieback via new platform to existing infrastructure.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

United Kingdom

153

Andrew

1998

2007

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; development awaiting capacity in existing infrastructure; negotiations under way for gas sales contract.

Devenick

1983-2001

2007

Initial assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic and developmental aspects of project in progress; integrated field model, subsurface and seismic studies review completed; development expected in conjunction with Harding Gas Project nearby.

Puffin

1982-1991

2008-2010

Assessment of hydrocarbon quantities as potentially commercial completed; further assessment of economic and developmental aspects of project to be undertaken; sub-surface and feasibility review under way; development awaiting capacity in existing infrastructure.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Suilven

1995-1998

2009

Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic and developmental aspects of project in progress; development anticipated to be by tieback to existing production vessel; awaiting capacity in existing infrastructure.

United States

132

Dorado

2002

2006

Assessment of hydrocarbon quantities as potentially commercial completed; new development study completed in 2005, options identified and under evaluation; planned subsea tieback to existing infrastructure.

Entrada

2000

2006

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; expected development as subsea tieback to facilities installed in 2005.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (continued)

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Liberty

1997

2008-2009

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation. Planned tieback via extended reach drilling from existing infrastructure; Memorandums Of Understanding with two key permitting agencies have been secured.

Point Thomson/ Sourdough

1994-1996

2009

Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation. Annual Plan of Development work programme approved by state; initial engineering design for gas cycling option complete; progressing development based on tie-in to proposed Alaska gas pipeline; negotiations on gas pipeline fiscal terms in progress with state of Alaska.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 54 — Suspended exploration well costs (concluded)


	*Exploration wells (concluded)*

Amounts

carried as

Anticipated

intangible

Year end

year of

assets at

2005

Years wells

proved reserve

Country/Project

year end 2005

wells gross

drilled

booking

Comment

($-

million

Vietnam

Hai Thach

1995-2002

2007-2008

Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project completed; development options identified and under evaluation.

Kim Cuong Tay

1995

2010-2012

Initial assessment of hydrocarbon quantities as potentially commercial completed; decision on further appraisal planned for 2006.

Miscellaneous smaller projects

1993-2002

2006-2011

TOTAL

762

Certain projects which were classified as projects with completed exploration drilling activity at December 31, 2004 are not classified as such at December 31, 2005:


	—	The following projects were sanctioned for development in 2005: Mondo/ Saxi/ Batuque in Angola; Saqqara and Baltim in Egypt, and Deimos in the USA.

	—	Further exploratory drilling was undertaken in 2005 or is now planned for 2006 on the following projects: Clochas/ Tchihumba, Cravo/ Lirio, Orquidea/ Violetta, and Cesio/ Chumbo in Angola;WA267-P in Australia; East Delta Deep Marine Thalab in Egypt; Kessog in the UK; and Langley in Canada.

	—	BP disposed of its interests in the following projects: Ellida in Norway and Blind Faith in the USA.

	—	In Colombia, a well in the Floreña area was reclassified to development wells, and a well in the Pauto area was written off resulting in expense of $9 million.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles

The consolidated financial statements of the BP Group are prepared in accordance with International Financial Reporting Standards (IFRS) which differ in certain respects from US generally accepted accounting principles (US GAAP). The principal differences between US GAAP and IFRS for BP Group reporting relate to the following:


*(a)*	*Deferred taxation/business combinations*


	Under IFRS, 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. IFRS 3 ‘Business Combinations’ typically requires the offset to the recognition of such deferred tax assets and liabilities to be adjusted against goodwill. However, under the exemptions in IFRS 1 ’First-time Adoption of International Financial Reporting Standards’, previous business combinations were not restated in accordance with IFRS 3 and the offset was taken as an adjustment to shareholders’ equity at the transition date.

	Under US GAAP, deferred tax assets or liabilities are also recognized for the difference between the assigned values and the tax bases of the assets and liabilities recognized in a purchase business combination. Statement of Financial Accounting Standard (‘SFAS’) No. 141 ‘Business Combinations’, requires that the offset be recognized against goodwill. As such, the treatment adopted under IFRS 1 as compared with SFAS 141 creates a difference related to business combinations accounted for under the purchase method that occurred prior to the Group’s IFRS transition date.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Depreciation, depletion and amortization		254			2,048			1,303
Taxation		242			(1,531	)		(715	)
Profit for the year		(496	)		(517	)		(588	)


	At
	December 31,

	2005		2004

	($ million
Property, plant and equipment		3,459		4,052
Deferred tax liabilities		1,434		1,489
BP shareholders’ equity		2,025		2,563

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(a)*	*Deferred taxation/business combinations (concluded)*

The major components of deferred tax liabilities and assets on a US GAAP basis were as follows:


		At
		December 31,

		2005			2004

		($ million)
Deferred tax liability
	Depreciation		20,782			22,658
	Pension plan surplus		1,371			1,095
	Other taxable temporary differences		4,214			3,582

			26,367			27,335

	Deferred tax asset
	Petroleum revenue tax		(407	)		(581	)
	Pension plan and other postretirement benefit plan deficits		(1,154	)		(912	)
	Decommisioning, environmental and other provisions		(2,292	)		(2,069	)
	Derivative financial instruments		(770	)		(108	)
	Tax credit and loss carry-forward		(1,990	)		(2,764	)
	Other deductible temporary differences		(1,591	)		(2,107	)

	Gross deferred tax asset		(8,204	)		(8,541	)
	Valuation allowance		1,679			2,856

	Net deferred tax asset		(6,525	)		(5,685	)

Net deferred tax liability*			19,842			21,650


	*	Primarily noncurrent

(b) Provisions


	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. In accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’, the provisions for decommissioning and environmental liabilities are estimated using costs based on current prices and discounted using rates that take into consideration the time value of money and risks inherent in the liability. The periodic unwinding of the discount is included in other finance expense. Similarly, the effect of a change in the discount rate is included in other finance expense in connection with all provisions other than decommissioning liabilities.

	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. Adjustments to the decommissioning liabilities, associated with changes to the future cash flow assumptions or changes in the discount rate, are reflected as increases or decreases to the corresponding item of property, plant and equipment and depreciated prospectively over the asset’s remaining useful life.

	Under US GAAP, decommissioning liabilities are recognized in accordance with SFAS 143 ‘Accounting for Asset Retirement Obligations’. SFAS 143 is similar to IAS 37 and requires that when an asset retirement liability is recognized, a corresponding amount is capitalized and depreciated as

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

(b) Provisions (continued)

an additional cost of the related asset. The liability is measured based on the risk-adjusted future cash outflows discounted using a credit-adjusted risk-free rate. The unwinding of the discount is included in operating profit for the period. Unlike IAS 37, 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 re-measured 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 (c) on the following page) 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.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Production and manufacturing expenses and depreciation, depletion and amortization		201			254			188
Other finance expense		(201	)		(196	)		(173	)
Taxation		(9	)		22			(64	)
Profit for the year before cumulative effect of accounting change		9			(80	)		49
Cumulative effect of accounting change		—			—			1,002
Profit for the year		9			(80	)		1,051

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

(b) Provisions (concluded)


	At
	December 31,

	2005			2004

	($ million
Property, plant and equipment		(1,842	)		(1,667	)
Provisions		(1,666	)		(1,541	)
Deferred tax liabilities		(64	)		(49	)
BP shareholders’ equity		(112	)		(77	)


	The following data summarizes the movements in the asset retirement obligations, as adjusted to accord with US GAAP, for the years ended December 2005 and 2004.


	Years ended
	December 31,

	2005			2004

	($ million
At January 1,		3,898			3,872
Exchange adjustments		4			175
New provisions/adjustment to provisions		554			(174	)
Unwinding of discount		237			208
Utilized/deleted		(264	)		(183	)
At December 31,		4,429			3,898

(c) 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 the 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.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Depreciation, depletion and amortization		(20	)		(48	)		—
Taxation		9			18			—
Profit for the year		11			30			—

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

(c) Oil and natural gas reserve differences (concluded)


	At
	December 31,

	2005		2004

	($ million
Property, plant and equipment		68		48
Deferred tax liabilities		27		18
BP shareholders’ equity		41		30


*(d)*	*Goodwill and intangible assets*


	For the purposes of US GAAP, the Group accounts for goodwill according to SFAS No. 141 ‘Business Combinations’, and SFAS No. 142; ‘Goodwill and Other Intangible Assets’. For the purposes of IFRS, the Group accounts for goodwill under the provisions of IFRS 3 ‘Business Combinations’ and IAS 38 ‘Intangible Assets’. As a result of the transition rules available under IFRS 1, the Group did not restate its past business combinations in accordance with IFRS 3 and assumed its UK GAAP carrying amount for goodwill as its IFRS carrying amount upon transition to IFRS, at January 1, 2003.

	Under US GAAP, goodwill and indefinite lived intangible assets have not been amortized since December 31, 2001, rather such assets are subject to periodic impairment testing. The Group does not have any other intangible assets with indefinite lives. Under IFRS, goodwill amortization ceased from January 1, 2003.

	The movement in the goodwill difference from 2004 to 2005 is the result of movements in foreign exchange rates.

	During the fourth quarter of 2005 the Group completed a goodwill impairment review using the two-step process prescribed in US GAAP. The first step includes a comparison of the fair value of a reporting unit to its carrying value, including goodwill. When the carrying value exceeds the fair value, the goodwill of the reporting unit is potentially impaired and the second step is then completed in order to measure the impairment loss, if any. No impairment charge resulted from this review.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005		2004			2003

	($ million
Depreciation, depletion and amortization		—		61			—
Profit for the year		—		(61	)		—


	At
	December 31,

	2005		2004

	($ million
Goodwill		171		224
BP shareholders’ equity		171		224

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

In accordance with Group accounting practice, exploration licence acquisition costs are capitalized initially as an intangible asset and are amortized over the estimated period of exploration. Where proved reserves of oil or natural gas are determined and development is sanctioned, the unamortized cost is transferred to property, plant and equipment. Where exploration is unsuccessful, the unamortized cost is charged against income. At December 31, 2005 and December 31, 2004, exploration licence acquisition costs included in the Group’s property, plant and equipment and intangible assets, net of accumulated amortization, were as follows.


		At
		December 31,

		2005		2004

		($ million
Exploration licence acquisition cost included in noncurrent assets (net of accumulated amortization)
	Property, plant and equipment		1,201		1,100
	Intangible assets		597		595


	Changes to exploration expenditure, goodwill and other intangible assets, as adjusted to accord with US GAAP, during the years ended December 31, 2005 and 2004 are shown below.


							Additional
							minimum
							pension
	Exploration						liability			Other
	expenditure			Goodwill			(see (h))			intangibles			Total
-
	--------------------------------------------------------------($-
	million
Net book amount
At January 1, 2004		4,236			10,969			43			237			15,485
Amortization expense		(274	)		—			—			(72	)		(346	)
Other movements		(201	)		566			(4	)		278			639

At January 1, 2005		3,761			11,535			39			443			15,778
Amortization expense		(305	)		—			—			(161	)		(466	)
Other movements		552			(862	)		(12	)		482			160

At December 31, 2005		4,008			10,673			27			764			15,472


	Amortization expense relating to other intangibles is expected to be in the range $150-$200 million in each of the succeeding five years.


*(e)*	*Derivative financial instruments*


	Under IFRS, the Group accounts for its derivative financial instruments under IAS 39 ‘Financial Instruments: Recognition and Measurement’. IAS 39 requires that derivative financial instruments be measured at fair value and changes in fair value are either recognized through current earnings or equity (other comprehensive income) depending on the nature of the instrument. Changes in fair value of derivatives held for trading purposes or those not designated or effective as hedges are recognized in earnings.

	Changes in fair value of derivatives designated and effective as cash flow hedges are recognized directly in equity (other comprehensive income). Amounts recorded in equity are transferred to the income statement when the hedged transaction affects earnings. Where the hedged item is the cost

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(e)*	*Derivative financial instruments (concluded)*


	of a nonfinancial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the nonfinancial asset or liability.

	Changes in the fair value of derivatives designated and effective as fair value hedges are recognized in earnings. The carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged with the corresponding gains and losses recognized in earnings.

	On adoption of IAS 39 as of January 1, 2005, all cash flow and fair value hedges that previously qualified for hedge accounting under UK GAAP were recorded on the balance sheet at fair value with the offset recorded through equity.

	Under US GAAP all derivative financial instruments are accounted for under SFAS 133 ‘Accounting for Derivative Instruments and Hedging Activities’ and recorded on the balance sheet at their fair value. Similar to IAS 39, SFAS 133 requires that changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether the instrument is designated as part of a hedge transaction. A difference arises between IFRS and US GAAP for cash flow hedges where the hedged item is the cost of a nonfinancial asset or liability. SFAS 133 does not allow the amounts taken to equity to be transferred to the initial carrying amount of the nonfinancial asset or liability. The amounts remain in equity (other comprehensive income) and are recognized to earnings as the nonfinancial asset is depreciated.

	Prior to January 1, 2005, the Group did not designate any of its derivative financial instruments as part of hedged transactions under SFAS 133. 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 IAS 39. This difference will remain until the individual derivative transactions mature.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Production and manufacturing expenses		—			481			27
Finance costs		(15	)		—			—
Taxation		(72	)		(144	)		—
Profit for the year before cumulative effect of accounting change		87			(337	)		(27	)
Cumulative effect of accounting change		—			—			50
Profit for the year		87			(337	)		23

F-197

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(e)*	*Derivative financial instruments (concluded)*


	At
	December 31,

	2005			2004

	($ million
Goodwill		131			131
Finance debt		(140	)		(164	)
Trade and other payables		—			718
Deferred tax liabilities		46			(108	)
BP shareholders’ equity		225			(315	)


*(f)*	*Inventory valuation*


	Under IFRS, inventory held for trading purposes is re-measured to 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.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Purchases		357			(250	)		(60	)
Taxation		(125	)		88			21
Profit for the year		(232	)		162			39


	At
	December 31,

	2005			2004

	($ million
Inventories		(257	)		100
Deferred tax liabilities		(90	)		35
BP shareholders’ equity		(167	)		65


*(g)*	*Gain arising on asset exchange*


	Under IFRS, exchanges of nonmonetary assets are generally accounted for at fair value at the date of the transaction, with any gain or loss recognized in income. Under US GAAP prior to January 1, 2005, exchanges of nonmonetary assets were accounted for at book value. From January 1, 2005 exchanges of nonmonetary assets are generally accounted for at fair value under both IFRS and US GAAP.

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BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(g)*	*Gain arising on asset exchange (concluded)*


	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003
-
	--------------------------------($-
	million
Depreciation, depletion and amortization		19			117			32
Taxation		(7	)		(10	)		(13	)
Profit for the year		(12	)		(107	)		(19	)


	At
	December 31,

	2005		2004
-
	------------------------($-
	million
Property, plant and equipment		367		386
Deferred tax liabilities		128		135
BP shareholders’ equity		239		251


*(h)*	*Pensions and other postretirement benefits*


	Under IFRS, the Group accounts for its pension and other postretirement benefit plans according to IAS 19 ‘Employee Benefits’. Surpluses and deficits of funded schemes for pensions and other postretirement 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 the statement of recognized income and expense. This treatment differs with the Group’s US GAAP treatment under SFAS No. 87 ‘Employers’ Accounting for Pensions’, under which actuarial gains and losses are not recognized in the income statement as they occur but are recognized within income only when they exceed certain thresholds. This difference in recognition rules for actuarial gains and losses gives rise to differences in periodic pension costs as measured under IAS 19 and SFAS 87.

	In addition, when a pension plan has an accumulated benefit obligation which exceeds the fair value of the plan assets, SFAS 87 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 other comprehensive income. IAS 19 does not have a similar concept. As a result, this creates a difference in shareholders’ equity as measured under IFRS and US GAAP.

F-199

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(h)*	*Pensions and other postretirement benefits (concluded)*


	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Production and manufacturing expenses		583			330			694
Other finance expense		116			(29	)		(340	)
Taxation		(213	)		(254	)		(139	)
Profit for the year		(486	)		(47	)		(215	)


	At
	December 31,

	2005			2004

	($ million
Intangible assets		27			39
Other receivables		6,667			7,104
Defined benefit pension plan surplus		(3,282	)		(2,105	)
Provisions		7,884			8,973
Defined benefit pension plan and other postretirement benefit plan deficits		(9,230	)		(10,339	)
Deferred tax liabilities		1,612			2,315
BP shareholders’ equity		3,146			4,089


*(i)*	*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. Under US GAAP, SFAS 144 ‘Accounting for the Impairment or Disposal of Long-lived Assets’ 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. Due to this difference, certain of the impairment charges recognized under IFRS, adjusted for the impacts of depreciation, have not been recognized for US GAAP.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003

	($ million
Depreciation, depletion and amortization		28			—			—
Impairment and losses on sale of businesses and fixed assets		477			(986	)		—
Taxation		(127	)		309			—
Profit for the year		(378	)		677			—

F-200

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(i)*	*Impairments (concluded)*


	At
	December 31,

	2005		2004
-
	------------------------($-
	million
Goodwill		—		325
Property, plant and equipment		504		661
Deferred tax liabilities		177		309
BP shareholders’ equity		327		677

(j) Equity - accounted investments


	The major difference between IFRS and US GAAP in relation to equity-accounted entities is in respect of deferred tax (see (a)).

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading				2004
	2005					2003

	($ million
Earnings from jointly controlled entities		(255	)		147		(47	)
Profit for the year		(255	)		147		(47	)


	At
	December 31,

	2005			2004
-
	------------------------($-
	million
Investments in jointly controlled entities		(43	)		212
BP shareholders’ equity		(43	)		212


*(k)*	*Investments*


	Under IFRS for periods prior to January 1, 2005, certain equity investments are reported as either current or noncurrent investments and carried on the balance sheet at cost subject to review for impairment.

	Under US GAAP, these investments are accounted for as available-for-sale securities under SFAS 115 ‘Accounting for Certain Investments in Debt and Equity Securities’. As such they are reported at fair value, with unrealized holding gains and losses, net of tax, reported in accumulated other comprehensive income. If a decline in fair value below cost is ‘other than temporary’ the unrealized loss is accounted for as a realized loss and charged against income.

F-201

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(k)*	*Investments (concluded)*


	The adjustments to accumulated other comprehensive income (BP shareholders’ equity) to accord with US GAAP are summarized below.


	At
	December 31,

Increase (decrease) in caption heading	2005		2004
-
	------------------------($-
	million
Fixed assets — other investments		—		344
Deferred tax liabilities		—		117
BP shareholders’ equity		—		227


*(l)*	*Consolidation of variable interest entities*


	In January 2003, the FASB issued FASB Interpretation No. 46 (Revised) ‘Consolidation of Variable Interest Entities’ (Interpretation 46). Interpretation 46 clarifies the application of existing consolidation requirements to entities where a controlling financial interest is achieved through arrangements that do not involve voting interests. Under Interpretation 46, a variable interest entity is consolidated if a company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns.

	The Group currently has several ships under construction which are accounted for under IFRS as operating leases. Under Interpretation 46 certain of the arrangements represent variable interest entities that would be consolidated by the Group. The maximum exposure to loss as a result of the Group’s involvement with these entities is limited to the debt of the entity, less the fair value of the ships at the end of the lease term.

	The adjustments to BP shareholders’ equity to accord with US GAAP are summarized below.


	At
	December 31,

Increase (decrease) in caption heading	2005		2004
-
	------------------------($-
	million
Property, plant and equipment		807		507
Trade and other receivables		31		—
Finance debt		838		507
BP shareholders’ equity		—		—


*(m)*	*Major maintenance expenditure*


	For the purposes of US GAAP reporting, prior to January 1, 2005, the Group capitalized expenditures on maintenance, refits or repairs where it enhanced or restored the performance of an asset, or replaced an asset or part of an asset that was separately depreciated. This included other elements of expenditure incurred during major plant maintenance shutdowns, such as overhaul costs.

	As of January 1, 2005, the Group changed its US GAAP accounting policy to expense all overhaul costs and similar major maintenance expenditure as incurred. The effect of this accounting change for US GAAP reporting is reflected as a cumulative effect of an accounting change for the year ended December 31, 2005 of $794 million (net of tax benefits of $354 million). This adjustment is

F-202

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(m)*	*Major maintenance expenditure (concluded)*


	equal to the net book value of capitalized overhaul costs as of January 1, 2005 as reported under US GAAP. This new accounting policy reflects the policy applied under IFRS for all periods presented. As a result, a GAAP difference exists in periods prior to January 1, 2005 which reflects the capitalization of cumulative overhaul costs net of the related depreciation charge as calculated under US GAAP.

	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

	2005			2004
Increase (decrease) in caption heading							2003

	($ million
Production and manufacturing expenses		—			(586	)		(417	)
Depreciation, depletion and amortization		—			296			216
Taxation		—			73			81
Profit for the year before cumulative effect of accounting change		—			217			120
Cumulative effect of accounting change		(794	)		—			—
Profit for the year		(794	)		217			120


	At
	December 31,

	2005		2004
-
	------------------($-
	million
Property, plant and equipment		—		1,148
Deferred tax liabilities		—		354
BP shareholders’ equity		—		794

F-203

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(m)*	*Major maintenance expenditure (concluded)*


	The following pro forma data summarize the results of operations assuming the change in accounting for major maintenance expenditure was applied retroactively with effect from January 1, 2003:


		At
		December 31,

		2005(a)		2004		2003

		($ million
Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP
	As reported		19,640		17,088		12,939
	Pro forma		20,434		16,871		12,819
Per ordinary share — cents
	Basic — as reported		92.96		78.31		58.36
	Basic — pro forma		96.72		77.32		57.82
	Diluted — as reported		91.90		76.88		57.79
	Diluted — pro forma		95.61		75.97		57.25
Per American Depositary Share — cents
	Basic — as reported		557.76		469.86		350.16
	Basic — pro forma		580.32		463.92		346.92
	Diluted — as reported		551.40		461.28		346.74
	Diluted — pro forma		573.66		455.82		343.50


(a)	Pro forma data for the year ended December 31, 2005 excludes the cumulative effect of adoption.


*(n)*	*Share-based payments*


	The Group adopted SFAS No. 123 (revised 2004), ‘Share-Based Payment’ (SFAS 123R) as of January 1, 2005 using the modified prospective transition method. Under SFAS 123R, share-based payments to employees are required to be measured based on their grant date fair value (with limited exceptions) and recognized over the related service period. For periods prior to January 1, 2005, the Group accounted for share-based payments under Accounting Principles Board Opinion No. 25 using the intrinsic value method.

	Effective January 1, 2005, as part of the adoption of IFRS, the Group adopted IFRS No. 2 ‘Share-based Payment’ (IFRS 2). IFRS 2 requires the recognition of expense when goods or services are received from employees or others in consideration for equity instruments. In adopting IFRS 2, the Group elected to restate prior years to recognize expense associated with share-based payments that were not fully vested as of January 1, 2003 and the liability of cash-settled share-based payments as of January 1, 2003.

	As a result of the transition requirements for SFAS 123R and IFRS 2, certain differences between US GAAP and IFRS have resulted. For periods prior to January 1, 2005, the Group has recognized share-based payments under IFRS using a fair value method which is substantially different than the intrinsic value method used under US GAAP for the same period. From January 1, 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

F-204

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(n)*	*Share-based payments (concluded)*


	different valuation model under US GAAP for those previously issued options outstanding and unvested as of December 31, 2004 as required under the transition rules of SFAS 123R.

	In addition, deferred taxes on share-based compensation are recognized differently under US GAAP than under IFRS. Under US GAAP, deferred taxes are recorded on cumulative compensation expense recognized during the period in accordance with SFAS 109. Under IFRS, deferred taxes are only recorded on the difference between the tax base of the underlying shares and the carrying value of the employee services as determined at each balance sheet date in accordance with IAS 12.


	The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.


	Years ended
	December 31,

Increase (decrease) in caption heading	2005			2004			2003
-
	--------------------------------------($-
	million
Production and manufacturing expenses		4			(28	)		(25	)
Distribution and administrative expenses		9			(58	)		(70	)
Taxation		(19	)		62			56
Profit for the year		6			24			39


	At
	December 31,

	2005			2004

	($ million
Deferred tax liabilities		334			353
BP shareholders’ equity		(334	)		(353	)


*(o)*	*Discontinued operations*


	Under IFRS, a component of an entity held for sale as part of a single plan to dispose of a separate major line of business is classified as a discontinued operation in the income statement.

	Under US GAAP (EITF Issue No. 03-13 ‘Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’), a disposed component of an enterprise is classified as a discontinued operation only where the ongoing entity has no significant continuing direct cash flows and does not retain an interest, contract or other arrangement sufficient to enable the entity to exert significant influence over the disposed component’s operating and financial policies after disposal.

	In connection with the sale of Innovene the Group has a number of commercial arrangements with Innovene for the supply of refining and petrochemical feedstocks, and the purchase and sale of refined products.

	Because of continuing direct cash flows that will result from activities with Innovene subsequent to divestment, under US GAAP, the operations of Innovene would not be classified as a discontinued operation and would be included in the Group’s continuing operations. Under IFRS, the operations of Innovene are classified as discontinued operations.

F-205

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(o)*	*Discontinued operations (continued)*


	Under IFRS the net cash provided by operating activities, net cash used in investing activities and net cash used in financing activities of discontinued operations must be identified separately, either within the cash flow statement or by way of note disclosure. For US GAAP, the cash flows of discontinued operations are not shown separately in the cash flow statement.

	The following summarizes the reclassifications that would be made if the operations of Innovene were shown in continuing operations under IFRS.


	Year ended December 31, 2005

	As reported		Reclassification			Total

	($ million)
Consolidated statement of income
Sales and other operating revenues		239,792		12,376			252,168

Profit before interest and taxation from continuing operations		32,182		141			32,323
Finance costs		616		—			616
Other finance expense		145		(3	)		142

Profit before taxation from continuing operations		31,421		144			31,565
Taxation		9,288		(40	)		9,248

Profit from continuing operations		22,133		184			22,317
Profit from Innovene operations		184		(184	)		—

Profit for the year		22,317		—			22,317


	Year ended December 31, 2004

	As reported			Reclassification			Total

	($ million)
Consolidated statement of income
Sales and other operating revenues		192,024			11,279			203,303

Profit before interest and taxation from continuing operations		25,746			(714	)		25,032
Finance costs		440			—			440
Other finance expense		340			17			357

Profit before taxation from continuing operations		24,966			(731	)		24,235
Taxation		7,082			(109	)		6,973

Profit from continuing operations		17,884			(622	)		17,262
Profit from Innovene operations		(622	)		622			—

Profit for the year		17,262			—			17,262

F-206

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(o)*	*Discontinued operations (concluded)*


	Year ended December 31, 2003

	As reported			Reclassification			Total

	($ million)
Consolidated statement of income
Sales and other operating revenues		164,653			8,962			173,615

Profit before interest and taxation from continuing operations		18,776			(48	)		18,728
Finance costs		513			—			513
Other finance expense		532			15			547

Profit before taxation from continuing operations		17,731			(63	)		17,668
Taxation		5,050			—			5,050

Profit from continuing operations		12,681			(63	)		12,618
Profit from Innovene operations		(63	)		63			—

Profit for the year		12,618			—			12,618


*(p)*	*Energy trading contracts*


	The disclosure requirements of EITF 02-03 in respect of energy trading contracts are set out below. For the Group, energy trading contracts in oil, natural gas, NGLs and power comprise exchange-traded derivative instruments such as futures and options and non-exchange-traded instruments such as swaps, ‘over-the-counter’ options and forward contracts.

	The following tables show the net fair value of contracts held for trading purposes at December 31, 2005 and 2004 analyzed by maturity period and by methodology of fair value estimation.


	Fair value of contracts at December 31, 2005

	Maturity			Maturity			Maturity			Maturity			Total
	less than			1-3			4-5			over			fair
	1 year			years			years			5 years			value

	($ million)
Prices actively quoted		(179	)		(146	)		(4	)		(12	)		(341	)
Prices provided by other external sources		660			(89	)		49			—			620
Prices based on models and other valuation methods		12			1			77			46			136

		493			(234	)		122			34			415

F-207

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)


*(p)*	*Energy trading contracts (continued)*


	Fair value of contracts at December 31, 2004

	Maturity		Maturity			Maturity		Maturity		Total
	less than		1-3			4-5		over		fair
	1 year		years			years		5 years		value

	($ million)
Prices actively quoted		111		(89	)		—		—		22
Prices provided by other external sources		128		169			62		—		359
Prices based on models and other valuation methods		4		3			1		62		70

		243		83			63		62		451


	The following tables show the changes during the year in the net fair value of instruments held for trading purposes for the years 2005, 2004 and 2003.


				Fair value
				natural gas			Fair value
	Fair value			and NGL			power
	oil price			price			price
	contracts			contracts			contracts

	($ million)
Fair value of contracts at January 1, 2005		(140	)		414			177
Contracts realized or settled in the year		144			(681	)		76
Unrealized gains (losses) recognized at inception of contract		(73	)		(41	)		1
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions		—			—			—
Other unrealized gains (losses) recognized during the year		35			578			(75	)

Fair value of contracts at December 31, 2005		(34	)		270			179

Fair value of contracts at January 1, 2004		(154	)		191			134
Contracts realized or settled in the year		154			259			54
Unrealized gains (losses) recognized at inception of contract		(33	)		73			(3	)
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions		—			—			—
Other unrealized gains (losses) recognized during the year		(107	)		(109	)		(8	)

Fair value of contracts at December 31, 2004		(140	)		414			177

Fair value of contracts at January 1, 2003		(66	)		124			79
Contracts realized or settled in the year		66			61			49
Unrealized gains (losses) recognized at inception of contract		(20	)		(64	)		—
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions		—			—			—
Other unrealized gains (losses) recognized during the year		(134	)		70			6

Fair value of contracts at December 31, 2003		(154	)		191			134

F-208

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

(p) Energy trading contracts (concluded)


	In addition to the risk management activities related to equity crude disposal, refinery supply and marketing, BP’s supply and trading function undertakes trading in the full range of conventional derivative financial and commodity instruments and physical cargoes available in the energy markets. The Group controls the scale of the trading exposures by using a value-at-risk model with a maximum value-at-risk limit authorized by the board.

	The Group measures its market risk exposure, i.e., potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures, and the history of one-day price movements, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations which is equivalent to a 99.7% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value-at-risk on approximately one occasion per year if the portfolio were left unchanged.

	The Group calculates value-at-risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-at-risk models take account of derivative financial instruments such as oil, natural gas and power price futures and swap agreements. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. For options, a linear approximation is included in the value-at-risk models. The value-at-risk calculation for oil, natural gas, NGLs and power price exposure also includes derivative commodity instruments (commodity contracts that permit settlement either by delivery of the underlying commodity or in cash), such as forward contracts.

	The following table shows values at risk for energy trading activities.


							At
	High		Low		Average		December 31

	($ million)
2005
Oil price trading		145		31		60		56
Natural gas and NGL price trading		71		9		26		30
Power price trading		30		4		14		16
2004
Oil price trading		55		18		29		45
Natural gas and NGL price trading		42		11		23		18
Power price trading		18		2		8		7
2003
Oil price trading		34		17		26		27
Natural gas and NGL price trading		29		4		16		18
Power price trading		13		—		4		6

F-209

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

The following is a summary of the adjustments to profit for the year attributable to BP shareholders and to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.

Profit for the year


		Years ended December 31,

		2005			2004			2003

		($ million except per
		share amounts)
Profit as reported in the consolidated statement of income			22,026			17,075			12,448
Adjustments
	Deferred taxation/business combinations (a)		(496	)		(517	)		(588	)
	Provisions (b)		9			(80	)		49
	Oil and natural gas reserve differences (c)		11			30			—
	Goodwill and intangible assets (d)		—			(61	)		—
	Derivative financial instruments (e)		87			(337	)		(27	)
	Inventory valuation (f)		(232	)		162			39
	Gain arising on asset exchange (g)		(12	)		(107	)		(19	)
	Pensions and other postretirement benefits (h)		(486	)		(47	)		(215	)
	Impairments (i)		(378	)		677			—
	Equity-accounted investments (j)		(255	)		147			(47	)
	Major maintenance expenditure (m)		—			217			120
	Share-based payments (n)		6			24			39
	Other		156			(93	)		90

Profit for the year before cumulative effect of accounting changes as adjusted to accord with US GAAP			20,436			17,090			11,889
Cumulative effect of accounting changes
	Major maintenance expenditure		(794	)		—			—
	Provisions		—			—			1,002
	Derivative financial instruments		—			—			50

Profit for the year as adjusted to accord with US GAAP			19,642			17,090			12,941
Dividend requirements on preference shares			2			2			2

Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP			19,640			17,088			12,939

Per ordinary share — cents
	Basic — before cumulative effect of accounting changes		96.72			78.31			53.62
	Cumulative effect of accounting changes		(3.76	)		—			4.74

			92.96			78.31			58.36

	Diluted — before cumulative effect of accounting changes		95.62			76.88			53.10
	Cumulative effect of accounting changes		(3.71	)		—			4.69

			91.91			76.88			57.79

Per American Depositary Share — cents (1)
	Basic — before cumulative effect of accounting changes		580.32			469.86			321.72
	Cumulative effect of accounting changes		(22.56	)		—			28.44

			557.76			469.86			350.16

	Diluted — before cumulative effect of accounting changes		573.72			461.28			318.60
	Cumulative effect of accounting changes		(22.26	)		—			28.14

			551.46			461.28			346.74

F-210

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

BP shareholders’ equity


		At
		December 31,

		2005			2004

		($ million
BP shareholders’ equity as reported in the consolidated balance sheet			79,661			76,892
Adjustments
	Deferred taxation/business combinations (a)		2,025			2,563
	Provisions (b)		(112	)		(77	)
	Oil and natural gas reserve differences (c)		41			30
	Goodwill and intangible assets (d)		171			224
	Derivative financial instruments (e)		225			(315	)
	Inventory valuation (f)		(167	)		65
	Gain arising on asset exchange (g)		239			251
	Pensions and other postretirement benefits (h)		3,146			4,089
	Impairments (i)		327			677
	Equity-accounted investments (j)		(43	)		212
	Investments (k)		—			227
	Major maintenance expenditure (m)		—			794
	Share-based payments (n)		(334	)		(353	)
	Other		(32	)		(187	)

BP shareholders’ equity as adjusted to accord with US GAAP			85,147			85,092


(1)	One American Depositary Share is equivalent to six ordinary shares.

F-211

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

Comprehensive income

The components of comprehensive income, net of related tax are as follows:


		Years ended December 31,

		2005			2004			2003

		($ million)
Profit for the year as adjusted to accord with US GAAP			19,642			17,090			12,941
Currency translation differences net of tax expense (benefit) of $(328) million (2004 $208 million and 2003, $37 million)			(2,865	)		2,143			3,644
Investments
	Unrealized gains net of tax expense (benefit) of $110 million (2004 $71 million and 2003 $709 million)		291			141			1,316
	Unrealized losses net of tax benefit (expense) of $16 million, (2004 nil and 2003 nil)		(42	)		—			—
	Less: reclassification adjustment for gains included in net income net of tax benefit (expense) of $22 million (2004 $627 million and 2003 $54 million)		(59	)		(1,165	)		(99	)
	Currency translation differences net of tax expense (benefit) of nil (2004 nil and 2003 nil)		(32	)		—			—
Unrealized gains (losses) on cash flow hedges net of tax expense (benefit) of $(63) million (2004 nil and 2003 nil)			(131	)		—			—
Minimum pension liability adjustment net of tax expense (benefit) of $94 million (2004 $(130) million and 2003 $1,015 million)			249			(838	)		1,887

Comprehensive income			17,053			17,371			19,689


	At
	December 31,

	2005			2004

	($ million)
Currency translation differences		1,496			4,361
Net unrealized gains on investments		385			227
Unrealized losses on cash flow hedges		(131	)		—
Minimum pension liability adjustment		(866	)		(1,115	)

Accumulated other comprehensive income		884			3,473

F-212

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

Impact of new US accounting standards

Inventory: In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151 ‘Inventory Costs — an amendment of ARB No. 43, Chapter 4’ (SFAS 151). SFAS 151 requires that items, such as idle facility expense, excessive spoilage, double freight and re-handling costs, be recognized as current-period charges. SFAS 151 also requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for accounting periods beginning after June 15, 2005. The Group adopted SFAS 151 with effect from July 1, 2005. The adoption of SFAS 151 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Discontinued operations: In November 2004, the EITF reached a consensus on Issue No. 03-13 ‘Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’ (EITF 03-13). Under EITF 03-13, a disposed component of an enterprise is classified as a discontinued operation only where the ongoing entity has no significant continuing direct cash flows and does not retain an interest, contract or other arrangement sufficient to enable the entity to exert significant influence over the disposed component’s operating and financial policies after disposal. EITF 03-13 is effective for a component of an enterprise that is either disposed of or classified as held for sale in accounting periods beginning after December 15, 2004. Applying EITF 03-13 led management to conclude that the Innovene operations were not discontinued operations for US GAAP (see this Item on page F-205).

Revenue: In September 2005, the FASB ratified the consensus reached by the EITF regarding Issue No. 04-13 ‘Accounting for Purchases and Sales of Inventory with the Same Counterparty’ (EITF 04-13). EITF 04-13 addresses accounting issues that arise when a company both sells inventory to and buys inventory from another entity in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw material,work-in-process or finished goods. At issue is whether the revenue, inventory cost and cost of sales should be recorded at fair value or whether the transactions should be classified as nonmonetary transactions. EITF 04-13 requires purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another be combined and recorded as exchanges measured at the book value of the item sold. EITF 04-13 is effective for new arrangements entered into and modifications or renewals of existing arrangements in accounting periods beginning after March 15, 2006. The adoption of EITF 04-13 is not expected to have a significant effect on the Group’s profit as adjusted to accord with US GAAP or BP shareholders’ equity, as adjusted to accord with US GAAP.

Nonmonetary asset exchanges: In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 ‘Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29’ (SFAS 153). SFAS 153 eliminates the Accounting Principles Board Opinion No. 29 exception for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS 153 is effective for nonmonetary asset exchanges occurring in accounting periods beginning after June 15, 2005. The Group adopted SFAS 153 with effect from January 1, 2005. The adoption of SFAS 153 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

F-213

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

Impact of new US accounting standards (continued)

Share-based payments: In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) ‘Share-Based Payment’ (SFAS 123R). SFAS 123R, which is a revision of Statement of Financial Accounting Standards No. 123 ‘Accounting for Stock-Based Compensation’ (SFAS 123), supersedes APB Opinion No. 25 ’Accounting for Stock Issued to Employees’. Under SFAS 123R, share-based payments to employees and others are required to be recognized as an expense in the income statement based on their fair value. Pro forma disclosure is no longer a permitted alternative.

In adopting IFRS 2, the Company elected to restate prior period results to recognize the expense associated with equity-settled share-based payment transactions that were not fully vested as of January 1, 2003 and the liability associated with cash-settled share-based payment transactions as of January 1, 2003.

The Group adopted SFAS 123R using the modified prospective transition method with effect from January 1, 2005.

Taxation: In December 2004, the FASB issued Staff Position No. 109-1 ‘Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004’ (FSP 109-1). FSP 109-1, effective upon issuance, requires that the manufacturers’ deduction provided for under the American Jobs Creation Act of 2004 (the Jobs Creation Act) be accounted for as special deduction in accordance with FASB Statement of Financial Accounting Standards No. 109, ‘Accounting for Income Taxes,’ rather than a tax rate reduction. The manufacturers’ deduction will be recognized by the Group in the year the benefit is earned.

In December 2004, the FASB issued Staff Position No. 109-2 ‘Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004’ (FSP 109-2). The Jobs Creation Act provides a special one-time provision allowing earnings of certain non US companies to be repatriated to a US parent company at a reduced tax rate. FSP 109-2, effective upon issuance, permits additional time beyond the financial reporting period of enactment in order to evaluate the effect of the Jobs Creation Act without undermining an entity’s assertion that repatriation of non US earnings to a US parent company is not expected within the foreseeable future. The repatriation provision of the Jobs Creation Act did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Provisions: In March 2005, the FASB issued FASB Interpretation No. 47 ‘Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143’ (Interpretation 47). Under Interpretation 47, a conditional asset retirement obligation represents an unconditional obligation to perform an asset retirement activity where the timing or method of settlement is conditional on a future event that may or may not be within the control of the entity. Interpretation 47 clarifies that an entity is required to recognize a liability, when incurred, for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation is factored into the

F-214

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 55 — US generally accepted accounting principles (continued)

Impact of new US accounting standards (continued)

measurement of the liability when sufficient information exists. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. Interpretation 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Interpretation 47 is effective for fiscal years ending after December 15, 2005. The Group adopted Interpretation 47 with effect from January 1, 2005. The adoption of Interpretation 47 did not have a significant effect on the Group’s profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

Fixed assets: FASB Statement of Financial Accounting Standards No. 19 ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’ (SFAS 19) requires the cost of drilling an exploratory well (exploration or exploratory-type stratigraphic test wells) to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, SFAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain situations. Subsequent to the issuance of SFAS 19, as a result of the increasing complexity of oil and gas projects due to drilling in remote and deepwater offshore locations, entities increasingly require more than one year to complete all of the activities that permit recognition of proved reserves. In addition, because of new technologies, in certain situations additional exploratory wells may no longer be required before a project can commence.

F-215

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 55 —	US generally accepted accounting principles (concluded)

Fixed assets (concluded): BP’s accounting policy is that 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. 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. The Group adopted FSP 19-1 with effect from January 1, 2004. No previously capitalized costs were expensed upon the adoption of FSP 19-1.

Accounting changes and error corrections: In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154 ’Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3’ (SFAS 154). SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior period financial statements of a voluntary change in accounting principle unless it is impracticable. Previously, most voluntary changes in accounting principle were recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 also requires that a change in the method of depreciation, amortization or depletion for long-lived nonfinancial assets be accounted for as a change in accounting estimate that is effected by a change in accounting principle. Previously, such changes were reported as a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in accounting periods beginning after December 15, 2005. The adoption of SFAS 154 is not expected to have a significant effect on profit, as adjusted to accord with US GAAP, or BP shareholders’ equity, as adjusted to accord with US GAAP.

F-216

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries

BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100% owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., and BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity income of subsidiaries is the Group’s share of operating profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries.

BP p.l.c. also fully and unconditionally guarantees securities issued by BP Australia Capital Markets Limited, BP Canada Finance Company, BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.

F-217

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement


		Issuer		Guarantor

		BP							Eliminations
		Exploration					Other		and
		(Alaska) Inc.		BP p.l.c.			subsidiaries		reclassifications			BP Group

		($ million)
Year ended December 31, 2005
Sales and other operating revenues			5,052		—			239,792		(5,052	)		239,792
Earnings from jointly controlled entities — after interest and tax			—		—			3,083		—			3,083
Earnings from associates — after interest and tax			—		—			460		—			460
Equity-accounted income of subsidiaries — after interest and tax			576		22,255			—		(22,831	)		—
Interest and other revenues			454		556			749		(1,146	)		613

Total revenues			6,082		22,811			244,084		(29,029	)		243,948
Gains on sale of businesses and fixed assets			1		—			1,537		—			1,538

Total revenues and other income			6,083		22,811			245,621		(29,029	)		245,486
Purchases			729		—			167,349		(5,052	)		163,026
Production and manufacturing expenses			536		—			21,056		—			21,592
Production and similar taxes			352		—			2,658		—			3,010
Depreciation, depletion and amortization			445		—			8,326		—			8,771
Impairment and losses on sale of businesses and fixed assets			—		—			468		—			468
Exploration expense			1		—			683		—			684
Distribution and administration expenses			19		629			13,163		(105	)		13,706
Fair value (gain) loss on embedded derivatives			—		—			2,047		—			2,047

Profit before interest and taxation from continuing operations			4,001		22,182			29,871		(23,872	)		32,182
Finance costs			169		590			898		(1,041	)		616
Other finance expense (income)			14		(443	)		574		—			145

Profit before taxation from continuing operations			3,818		22,035			28,399		(22,831	)		31,421
Taxation			1,138		9			8,141		—			9,288

Profit from continuing operations			2,680		22,026			20,258		(22,831	)		22,133
Profit (loss) from Innovene operations			—		—			184		—			184

Profit for the year			2,680		22,026			20,442		(22,831	)		22,317

Attributable to
	BP shareholders		2,680		22,026			20,151		(22,831	)		22,026
	Minority interest		—		—			291		—			291

			2,680		22,026			20,442		(22,831	)		22,317

F-218

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement (continued)

The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group

		($ million)
Year ended December 31, 2005
Profit as reported			2,680			22,026			20,151			(22,831	)		22,026
Adjustments
	Deferred taxation/business combinations		(41	)		(496	)		(455	)		496			(496	)
	Provisions		5			9			4			(9	)		9
	Oil and natural gas reserve differences		—			11			11			(11	)		11
	Derivative financial instruments		—			87			87			(87	)		87
	Inventory valuation		(13	)		(232	)		(232	)		245			(232	)
	Gain arising on asset exchange		(12	)		(12	)		—			12			(12	)
	Pensions and other postretirement benefits		—			(486	)		(650	)		650			(486	)
	Impairments		—			(378	)		(378	)		378			(378	)
	Equity-accounted investments		—			(255	)		(255	)		255			(255	)
	Share-based payments		—			6			—			—			6
	Other		—			156			156			(156	)		156

Profit for the year before cumulative effect of accounting change as adjusted to accord with US GAAP			2,619			20,436			18,439			(21,058	)		20,436
Cumulative effect of accounting change Major maintenance expenditure			—			(794	)		(794	)		794			(794	)

Profit for the year as adjusted to accord with US GAAP			2,619			19,642			17,645			(20,264	)		19,642

F-219

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement (continued)


		Issuer		Guarantor

		BP								Eliminations
		Exploration					Other			and
		(Alaska) Inc.		BP p.l.c.			subsidiaries			reclassifications			BP Group

		($ million)
Year ended December 31, 2004
Sales and other operating revenues			3,811		—			192,024			(3,811	)		192,024
Earnings from jointly controlled entities — after interest and tax			—		—			1,818			—			1,818
Earnings from associates — after interest and tax			—		—			462			—			462
Equity-accounted income of subsidiaries — after interest and tax			256		16,951			—			(17,207	)		—
Interest and other revenues			34		1,466			515			(1,400	)		615

Total revenues			4,101		18,417			194,819			(22,418	)		194,919
Gains on sale of businesses and fixed assets			—		—			1,685			—			1,685

Total revenues and other income			4,101		18,417			196,504			(22,418	)		196,604
Purchases			506		—			131,360			(3,811	)		128,055
Production and manufacturing expenses			421		—			16,909			—			17,330
Production and similar taxes			267		—			1,882			—			2,149
Depreciation, depletion and amortization			483		—			8,046			—			8,529
Impairment and losses on sale of businesses and fixed assets			—		—			1,390			—			1,390
Exploration expense			4		—			633			—			637
Distribution and administration expenses			3		1,472			11,452			(159	)		12,768

Profit before interest and taxation from continuing operations			2,417		16,945			24,832			(18,448	)		25,746
Finance costs			—		274			1,407			(1,241	)		440
Other finance expense (income)			15		(358	)		683			—			340

Profit before taxation from continuing operations			2,402		17,029			22,742			(17,207	)		24,966
Taxation			552		(46	)		6,576			—			7,082

Profit from continuing operations			1,850		17,075			16,166			(17,207	)		17,884
Profit (loss) from Innovene operations			—		—			(622	)		—			(622	)

Profit for the year			1,850		17,075			15,544			(17,207	)		17,262

Attributable to
	BP shareholders		1,850		17,075			15,357			(17,207	)		17,075
	Minority interest		—		—			187			—			187

			1,850		17,075			15,544			(17,207	)		17,262

F-220

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement (continued)

The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group

		($ million)
Year ended December 31, 2004
Profit as reported			1,850			17,075			15,357			(17,207	)		17,075
Adjustments
	Deferred taxation/business combinations		(10	)		(517	)		(626	)		636			(517	)
	Provisions		(1	)		(80	)		(78	)		79			(80	)
	Oil and natural gas reserve differences		—			30			30			(30	)		30
	Goodwill		—			(61	)		(61	)		61			(61	)
	Derivative financial instruments		—			(337	)		(337	)		337			(337	)
	Inventory valuation		—			162			162			(162	)		162
	Gain arising on asset exchange		(19	)		(107	)		(88	)		107			(107	)
	Pensions and other postretirement benefits		—			(47	)		(98	)		98			(47	)
	Impairments		—			677			677			(677	)		677
	Equity-accounted investments		—			147			147			(147	)		147
	Major maintenance expenditure		—			217			217			(217	)		217
	Share-based payments		—			24			—			—			24
	Other		—			(93	)		(93	)		93			(93	)

Profit for the year as adjusted to accord with US GAAP			1,820			17,090			15,209			(17,029	)		17,090

F-221

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement (continued)


		Issuer		Guarantor

		BP								Eliminations
		Exploration					Other			and
		(Alaska) Inc.		BP p.l.c.			subsidiaries			reclassifications			BP Group

		($ million)
Year ended December 31, 2003
Sales and other operating revenues			3,168		—			164,653			(3,168	)		164,653
Earnings from jointly controlled entities — after interest and tax			—		—			826			—			826
Earnings from associates — after interest and tax			—		—			388			—			388
Equity-accounted income of subsidiaries — after interest and tax			253		11,636			—			(11,889	)		—
Interest and other revenues			213		820			663			(950	)		746

Total revenues			3,634		12,456			166,530			(16,007	)		166,613
Gains on sale of businesses and fixed assets			—		40			1,855			—			1,895

Total revenues and other income			3,634		12,496			168,385			(16,007	)		168,508
Purchases			555		—			113,803			(3,168	)		111,190
Production and manufacturing expenses			393		—			13,737			—			14,130
Production and similar taxes			241		—			1,482			—			1,723
Depreciation, depletion and amortization			459		—			7,617			—			8,076
Impairment and losses on sale of businesses and fixed assets			1		—			1,800			—			1,801
Exploration expense			14		—			528			—			542
Distribution and administration expenses			4		120			12,258			(112	)		12,270

Profit before interest and taxation from continuing operations			1,967		12,376			17,160			(12,727	)		18,776
Finance costs			400		130			821			(838	)		513
Other finance expense (income)			9		(223	)		746			—			532

Profit before taxation from continuing operations			1,558		12,469			15,593			(11,889	)		17,731
Taxation			651		6			4,393			—			5,050

Profit from continuing operations			907		12,463			11,200			(11,889	)		12,681
Profit (loss) from Innovene operations			—		—			(63	)		—			(63	)

Profit for the year			907		12,463			11,137			(11,889	)		12,618

Attributable to
	BP shareholders		907		12,463			10,967			(11,889	)		12,448
	Minority interest		—		—			170			—			170

			907		12,463			11,137			(11,889	)		12,618

F-222

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Income statement (concluded)

The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group

		($ million)
Year ended December 31, 2003
Profit as reported			907			12,463			10,967			(11,889	)		12,448
Adjustments
	Deferred taxation/business combinations		(28	)		(588	)		(643	)		671			(588	)
	Provisions		(4	)		49			57			(53	)		49
	Derivative financial instruments		—			(27	)		(27	)		27			(27	)
	Inventory valuation		(13	)		39			39			(26	)		39
	Gain arising on asset exchange		(20	)		(19	)		1			19			(19	)
	Pensions and other postretirement benefits		—			(215	)		(583	)		583			(215	)
	Equity-accounted investments		—			(47	)		(47	)		47			(47	)
	Major maintenance expenditure		—			120			120			(120	)		120
	Share-based payments		—			39			—			—			39
	Other		—			90			90			(90	)		90

Profit for the year before cumulative effect of accounting changes as adjusted to accord with US GAAP			842			11,904			9,974			(10,831	)		11,889
Cumulative effect of accounting changes
	Provisions		221			1,002			788			(1,009	)		1,002
	Derivative financial instruments		—			50			50			(50	)		50

Profit for the year as adjusted to accord with US GAAP			1,063			12,956			10,812			(11,890	)		12,941

F-223

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet


		Issuer			Guarantor

		BP								Eliminations
		Exploration					Other			and
		(Alaska) Inc.			BP p.l.c.		subsidiaries			reclassifications			BP Group
-
		---------------------------------------------------------------------------($-
		million
At December 31, 2005
Noncurrent assets
	Property, plant and equipment		5,852			—		80,095			—			85,947
	Goodwill		—			—		10,371			—			10,371
	Intangible assets		418			—		4,354			—			4,772
	Investments in jointly controlled entities		—			—		13,556			—			13,556
	Investments in associates		—			2		6,215			—			6,217
	Other investments		—			—		967			—			967
	Subsidiaries — equity-accounted basis		2,016			107,206		—			(109,222	)		—

	Fixed assets		8,286			107,208		115,558			(109,222	)		121,830
	Loans		1,800			1,434		(119	)		(2,294	)		821
	Other receivables		—			—		770			—			770
	Derivative financial instruments		—			—		3,652			—			3,652
	Prepayments and accrued income		—			—		1,269			—			1,269
	Defined benefit pension plan surplus		—			3,226		56			—			3,282

			10,086			111,868		121,186			(111,516	)		131,624

Current assets
	Loans		—			—		132			—			132
	Inventories		128			—		19,632			—			19,760
	Trade and other receivables		13,780			1,211		50,313			(24,402	)		40,902
	Derivative financial instruments		—			—		9,726			—			9,726
	Prepayments and accrued income		9			—		1,589			—			1,598
	Current tax receivable		—			—		212			—			212
	Cash and cash equivalents		(7	)		3		2,964			—			2,960

			13,910			1,214		84,568			(24,402	)		75,290

Total assets			23,996			113,082		205,754			(135,918	)		206,914

Current liabilities
	Trade and other payables		4,512			6,719		55,307			(24,402	)		42,136
	Derivative financial instruments		—			—		9,083			—			9,083
	Accruals and deferred income		—			—		5,970			—			5,970
	Finance debt		55			—		8,877			—			8,932
	Current tax payable		1,537			—		2,737			—			4,274
	Provisions		—			—		1,602			—			1,602

			6,104			6,719		83,576			(24,402	)		71,997

Noncurrent liabilities
	Other payables		495			—		3,734			(2,294	)		1,935
	Derivative financial instruments		—			—		3,696			—			3,696
	Accruals and deferred income		—			27		3,137			—			3,164
	Finance debt		—			—		10,230			—			10,230
	Deferred tax liabilities		1,816			532		13,910			—			16,258
	Provisions		536			—		9,418			—			9,954
	Defined benefit pension plan and other postretirement benefit plan deficits		82			—		9,148			—			9,230

			2,929			559		53,273			(2,294	)		54,467

Total liabilities			9,033			7,278		136,849			(26,696	)		126,464

Net assets			14,963			105,804		68,905			(109,222	)		80,450

Equity
BP shareholders’ equity			14,963			105,804		68,116			(109,222	)		79,661
Minority interest			—			—		789			—			789

Total equity			14,963			105,804		68,905			(109,222	)		80,450

F-224

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)


	Issuer		Guarantor

	BP								Eliminations
	Exploration					Other			and
	(Alaska) Inc.		BP p.l.c.			subsidiaries			reclassifications			BP Group
-
	---------------------------------------------------------------------------($-
	million
At December 31, 2005
Capital and reserves
Capital shares		3,353		5,185			—			(3,353	)		5,185
Paid-in surplus		3,145		8,120			—			(3,145	)		8,120
Merger reserve		—		26,493			697			—			27,190
Other reserves		—		16			—			—			16
Shares held by ESOP trusts		—		(140	)		—			—			(140	)
Available-for-sale investments		—		—			385			—			385
Cash flow hedges		—		—			(234	)		—			(234	)
Foreign currency translation reserve		—		—			2,943			—			2,943
Treasury shares		—		(10,598	)		—			—			(10,598	)
Retained earnings		8,465		76,728			64,325			(102,724	)		46,794

		14,963		105,804			68,116			(109,222	)		79,661

F-225

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)

The following is a summary of the adjustments to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group
-
		---------------------------------------------------------------------------($-
		million
At December 31, 2005
BP shareholders’ equity as reported			14,963			105,804			68,116			(109,222	)		79,661
Adjustments
	Deferred taxation/business combinations		215			2,025			1,810			(2,025	)		2,025
	Provisions		31			(112	)		(141	)		110			(112	)
	Oil and natural gas reserve differences		—			41			41			(41	)		41
	Goodwill and intangible assets		—			171			171			(171	)		171
	Derivative financial instruments		—			225			225			(225	)		225
	Inventory valuation		(76	)		(167	)		(167	)		243			(167	)
	Gain arising on asset exchange		239			239			—			(239	)		239
	Pensions and other postretirement benefits		82			3,146			2,570			(2,652	)		3,146
	Impairments		—			327			327			(327	)		327
	Equity-accounted investments		—			(43	)		(43	)		43			(43	)
	Share-based payments		—			(334	)		—			—			(334	)
	Other		—			(32	)		(32	)		32			(32	)

BP shareholders’ equity as adjusted to accord with US GAAP			15,454			111,290			72,877			(114,474	)		85,147

F-226

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)


		Issuer			Guarantor

		BP							Eliminations
		Exploration					Other		and
		(Alaska) Inc.			BP p.l.c.		subsidiaries		reclassifications			BP Group

		($ million)
At December 31, 2004
Noncurrent assets
	Property, plant and equipment		5,939			—		87,153		—			93,092
	Goodwill		—			—		10,857		—			10,857
	Intangible assets		418			—		3,787		—			4,205
	Investments in jointly controlled entities		—			—		14,556		—			14,556
	Investments in associates		—			2		5,484		—			5,486
	Other investments		—			—		394		—			394
	Subsidiaries — equity-accounted basis		3,069			106,706		—		(109,775	)		—

	Fixed assets		9,426			106,708		122,231		(109,775	)		128,590
	Loans		5,244			1,451		5,032		(10,916	)		811
	Other receivables		—			—		429		—			429
	Derivative financial instruments		—			—		898		—			898
	Prepayments and accrued income		—			—		354		—			354
	Defined benefit pension plan surplus		—			2,093		12		—			2,105

			14,670			110,252		128,956		(120,691	)		133,187

Current assets
	Loans		—			—		193		—			193
	Inventories		107			—		15,538		—			15,645
	Trade and other receivables		7,644			791		44,283		(15,619	)		37,099
	Derivative financial instruments		—			—		5,317		—			5,317
	Prepayments and accrued income		—			—		1,671		—			1,671
	Current tax receivable		—			—		159		—			159
	Cash and cash equivalents		(1	)		4		1,356		—			1,359

			7,750			795		68,517		(15,619	)		61,443

Total assets			22,420			111,047		197,473		(136,310	)		194,630

Current liabilities
	Trade and other payables		1,615			7,687		44,857		(15,619	)		38,540
	Derivative financial instruments		—			—		5,074		—			5,074
	Accruals and deferred income		—			—		4,482		—			4,482
	Finance debt		74			—		10,110		—			10,184
	Current tax payable		2			—		4,129		—			4,131
	Provisions		—			—		715		—			715

			1,691			7,687		69,367		(15,619	)		63,126

Noncurrent liabilities
	Other payables		4,263			—		10,234		(10,916	)		3,581
	Derivative financial instruments		—			—		158		—			158
	Accruals and deferred income		—			59		640		—			699
	Finance debt		—			—		12,907		—			12,907
	Deferred tax liabilities		1,814			266		14,621		—			16,701
	Provisions		549			—		8,335		—			8,884
	Defined benefit pension plan and other postretirement benefit plan deficits		81			—		10,258		—			10,339

			6,707			325		57,153		(10,916	)		53,269

Total liabilities			8,398			8,012		126,520		(26,535	)		116,395

Net assets			14,022			103,035		70,953		(109,775	)		78,235

Equity
BP shareholders’ equity			14,022			103,035		69,610		(109,775	)		76,892
Minority interest			—			—		1,343		—			1,343

Total equity			14,022			103,035		70,953		(109,775	)		78,235

F-227

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)


	Issuer		Guarantor

	BP							Eliminations
	Exploration					Other		and
	(Alaska) Inc.		BP p.l.c.			subsidiaries		reclassifications			BP Group
-
	---------------------------------------------------------------------------($-
	million
At December 31, 2004
Capital and reserves
Capital shares		3,353		5,403			—		(3,353	)		5,403
Paid-in surplus		3,145		6,366			—		(3,145	)		6,366
Merger reserve		—		26,465			697		—			27,162
Other reserves		—		44			—		—			44
Shares held by ESOP trusts		—		(82	)		—		—			(82	)
Foreign currency translation reserve		—		—			5,616		—			5,616
Retained earnings		7,524		64,839			63,297		(103,277	)		32,383

		14,022		103,035			69,610		(109,775	)		76,892

F-228

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)

The following is a summary of the adjustments to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group
-
		---------------------------------------------------------------------------($-
		million
At December 31, 2004
BP shareholders’ equity as reported			14,022			103,035			69,610			(109,775	)		76,892
Adjustments
	Deferred taxation/business combinations		255			2,563			2,333			(2,588	)		2,563
	Provisions		26			(77	)		(102	)		76			(77	)
	Oil and natural gas reserve differences		—			30			30			(30	)		30
	Goodwill and intangible assets		—			224			224			(224	)		224
	Derivative financial instruments		—			(315	)		(315	)		315			(315	)
	Inventory valuation		(63	)		65			65			(2	)		65
	Gain arising on asset exchange		251			251			—			(251	)		251
	Pensions and other postretirement benefits		82			4,089			2,511			(2,593	)		4,089
	Impairments		—			677			677			(677	)		677
	Equity-accounted investments		—			212			212			(212	)		212
	Investments		—			227			227			(227	)		227
	Major maintenance expenditure		—			794			794			(794	)		794
	Share-based payments		—			(353	)		—			—			(353	)
	Other		—			(187	)		(187	)		187			(187	)

BP shareholders’ equity as adjusted to accord with US GAAP			14,573			111,235			76,079			(116,795	)		85,092

F-229

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)


		Issuer			Guarantor

		BP								Eliminations
		Exploration					Other			and
		(Alaska) Inc.			BP p.l.c.		subsidiaries			reclassifications			BP Group
-
		---------------------------------------------------------------------------($-
		million
At December 31, 2003
Noncurrent assets
	Property, plant and equipment		6,015			—		82,592			—			88,607
	Goodwill		—			—		10,592			—			10,592
	Intangible assets		424			—		4,047			—			4,471
	Investments in jointly controlled entities		—			—		12,909			—			12,909
	Investments in associates		—			2		4,866			—			4,868
	Other investments		—			—		1,452			—			1,452
	Subsidiaries — equity-accounted basis		2,814			74,670		—			(77,484	)		—

	Fixed assets		9,253			74,672		116,458			(77,484	)		122,899
	Loans		1,368			23,716		(18,593	)		(5,639	)		852
	Other receivables		—			36		459			—			495
	Derivative financial instruments		—			—		534			—			534
	Prepayments and accrued income		—			—		957			—			957
	Defined benefit pension plan surplus		—			1,562		118			—			1,680

			10,621			99,986		99,933			(83,123	)		127,417

Current assets
	Loans		—			—		182			—			182
	Inventories		102			—		11,495			—			11,597
	Trade and other receivables		9,846			859		32,711			(15,535	)		27,881
	Derivative financial instruments		—			—		1,891			—			1,891
	Prepayments and accrued income		—			5		1,370			—			1,375
	Current tax receivable		—			—		92			—			92
	Cash and cash equivalents		(5	)		3		2,058			—			2,056

			9,943			867		49,799			(15,535	)		45,074

Total assets			20,564			100,853		149,732			(98,658	)		172,491

Current liabilities
	Trade and other payables		1,541			5,286		38,448			(15,535	)		29,740
	Derivative financial instruments		—			—		4,145			—			4,145
	Accruals and deferred income		—			22		2,244			—			2,266
	Finance debt		55			—		9,401			—			9,456
	Current tax payable		—			—		3,441			—			3,441
	Provisions		—			—		735			—			735

			1,596			5,308		58,414			(15,535	)		49,783

Noncurrent liabilities
	Other payables		4,272			—		5,997			(5,639	)		4,630
	Derivative financial instruments		—			—		344			—			344
	Accruals and deferred income		—			50		814			—			864
	Finance debt		—			—		12,869			—			12,869
	Deferred tax liabilities		1,802			213		14,036			—			16,051
	Provisions		569			—		7,295			—			7,864
	Defined benefit pension plan and other postretirement benefit plan deficits		82			—		9,740			—			9,822

			6,725			263		51,095			(5,639	)		52,444

Total liabilities			8,321			5,571		109,509			(21,174	)		102,227

Net assets			12,243			95,282		40,223			(77,484	)		70,264

Equity
BP shareholders’ equity			12,243			95,282		39,098			(77,484	)		69,139
Minority interest			—			—		1,125			—			1,125

Total equity			12,243			95,282		40,223			(77,484	)		70,264

F-230

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (continued)


	Issuer		Guarantor

	BP							Eliminations
	Exploration					Other		and
	(Alaska) Inc.		BP p.l.c.			subsidiaries		reclassifications			BP Group
-
	---------------------------------------------------------------------------($-
	million
At December 31, 2003
Capital and reserves
Capital shares		1,903		5,552			—		(1,903	)		5,552
Paid-in surplus		3,145		4,480			—		(3,145	)		4,480
Merger reserve		—		26,380			697		—			27,077
Other reserves		—		129			—		—			129
Shares held by ESOP trusts		—		(96	)		—		—			(96	)
Foreign currency translation reserve		—		—			3,619		—			3,619
Retained earnings		7,195		58,837			34,782		(72,436	)		28,378

		12,243		95,282			39,098		(77,484	)		69,139

F-231

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Balance sheet (concluded)

The following is a summary of the adjustments to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.


		Issuer			Guarantor

		BP									Eliminations
		Exploration						Other			and
		(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group
-
		---------------------------------------------------------------------------($-
		million
At December 31, 2003
BP shareholders’ equity as reported			12,243			95,282			39,098			(77,484	)		69,139
Adjustments
	Deferred taxation/business combinations		265			3,009			2,827			(3,092	)		3,009
	Provisions		27			(128	)		(155	)		128			(128	)
	Goodwill and intangible assets		—			248			248			(248	)		248
	Derivative financial instruments		—			26			26			(26	)		26
	Inventory valuation		(63	)		(98	)		(98	)		161			(98	)
	Gain arising on asset exchange		271			269			(2	)		(269	)		269
	Pensions and other postretirement benefits		82			5,246			3,688			(3,770	)		5,246
	Equity-accounted investments		—			65			65			(65	)		65
	Investments		—			1,251			1,251			(1,251	)		1,251
	Major maintenance expenditure		—			545			545			(545	)		545
	Share-based payments		—			(235	)		—			—			(235	)
	Other		—			(170	)		(170	)		170			(170	)

BP shareholders’ equity as adjusted to accord with US GAAP			12,825			105,310			47,323			(86,291	)		79,167

F-232

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Cash flow statement


	Issuer			Guarantor

	BP									Eliminations
	Exploration						Other			and
	(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group
-
	---------------------------------------------------------------------------($-
	million
Year ended December 31, 2005
Net cash provided by operating activities of continuing operations		3,558			19,835			23,592			(21,234	)		25,751
Net cash provided by (used in) operating activities of Innovene operations		—			—			970			—			970

Net cash provided by operating activities		3,558			19,835			24,562			(21,234	)		26,721
Net cash used in investing activities		(346	)		(2,410	)		1,027			—			(1,729	)
Net cash used in financing activities		(3,218	)		(17,426	)		(23,893	)		21,234			(23,303	)
Currency translation differences relating to cash and cash equivalents		—			—			(88	)		—			(88	)

(Decrease) increase in cash and cash equivalents		(6	)		(1	)		1,608			—			1,601
Cash and cash equivalents at beginning of year		(1	)		4			1,356			—			1,359

Cash and cash equivalents at end of year		(7	)		3			2,964			—			2,960

F-233

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (Continued)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (continued)

Cash flow statement (continued)


	Issuer			Guarantor

	BP									Eliminations
	Exploration						Other			and
	(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group
-
	---------------------------------------------------------------------------($-
	million
Year ended December 31, 2004
Net cash provided by operating activities of continuing operations		2,467			44,767			(4,621	)		(18,566	)		24,047
Net cash provided by (used in) operating activities of Innovene operations		—			—			(669	)		—			(669	)

Net cash provided by operating activities		2,467			44,767			(5,290	)		(18,566	)		23,378
Net cash used in investing activities		(364	)		(31,517	)		20,758			(208	)		(11,331	)
Net cash used in financing activities		(2,099	)		(13,249	)		(16,261	)		18,774			(12,835	)
Currency translation differences relating to cash and cash equivalents		—			—			91			—			91

(Decrease) increase in cash and cash equivalents		4			1			(702	)		—			(697	)
Cash and cash equivalents at beginning of year		(5	)		3			2,058			—			2,056

Cash and cash equivalents at end of year		(1	)		4			1,356			—			1,359

F-234

BP p.l.c. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS (concluded)


Note 56 —	Condensed consolidating information on certain US Subsidiaries (concluded)

Cash flow statement (concluded)


	Issuer			Guarantor

	BP									Eliminations
	Exploration						Other			and
	(Alaska) Inc.			BP p.l.c.			subsidiaries			reclassifications			BP Group

	($ million)
Year ended December 31, 2003
Net cash provided by operating activities of continuing operations		1,687			11,517			30,741			(27,990	)		15,955
Net cash provided by (used in) operating activities of Innovene operations		—			—			348			—			348

Net cash provided by operating activities		1,687			11,517			31,089			(27,990	)		16,303
Net cash used in investing activities		(381	)		(4,034	)		(4,866	)		—			(9,281	)
Net cash used in financing activities		(1,300	)		(7,481	)		(26,012	)		27,990			(6,803	)
Currency translation differences relating to cash and cash equivalents		—			—			121			—			121

(Decrease) increase in cash and cash equivalents		6			2			332			—			340
Cash and cash equivalents at beginning of year		(11	)		1			1,726			—			1,716

Cash and cash equivalents at end of year		(5	)		3			2,058			—			2,056

F-235

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION

(Unaudited)

The following tables show estimates of the Group’s net proved reserves of crude oil and natural gas at December 31, 2005, 2004 and 2003.

Movements in estimated net proved reserves of crude oil(a)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(millions of barrels)
2005
Subsidiary undertakings
At January 1
	Developed		559			231			2,041			311			65			204			—			62			3,473
	Undeveloped		210			109			1,211			299			85			643			—			725			3,282

			769			340			3,252			610			150			847			—			787			6,755

Changes attributable to
	Revisions of previous estimates		(31	)		(8	)		103			(21	)		21			(190	)		—			(148	)		(274	)
	Purchases of reserves-in-place		—			—			2			—			—			—			—			—			2
	Extensions, discoveries and other additions		11			—			40			3			11			83			—			—			148
	Improved recovery		32			21			217			1			—			2			—			7			280
	Production (b)		(101	)		(27	)		(200	)		(53	)		(17	)		(64	)		—			(34	)		(496	)
	Sales of reserves-in-place		—			(15	)		(1	)		(39	)		—			—			—			—			(55	)

			(89	)		(29	)		161			(109	)		15			(169	)		—			(175	)		(395	)

At December 31 (c)
	Developed		496			225			1,984			215			70			142			—			69			3,201
	Undeveloped		184			86			1,429			286			95			536			—			543			3,159

			680			311			3,413			501			165			678			—			612			6,360

Equity-accounted entities
(BP share)
At January 1
	Developed		—			—			—			204			1			—			1,863			592			2,660
	Undeveloped		—			—			—			125			—			—			294			100			519

			—			—			—			329			1			—			2,157			692			3,179

Changes attributable to
	Revisions of previous estimates		—			—			—			1			—			—			319			119			439
	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	)

			—			—			—			2			—			—			(38	)		62			26

At December 31 (d)
	Developed		—			—			—			207			1			—			1,688			590			2,486
	Undeveloped		—			—			—			124			—			—			431			164			719

			—			—			—			331			1			—			2,119			754			3,205

S-1

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of crude oil(a)(continued)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(millions of barrels)
2004
Subsidiary undertakings
At January 1
	Developed		697			236			1,902			385			82			190			—			73			3,565
	Undeveloped		245			127			1,499			354			81			632			—			711			3,649

			942			363			3,401			739			163			822			—			784			7,214

Changes attributable to
	Revisions of previous estimates		(133	)		1			(44	)		(92	)		2			19			—			(192	)		(439	)
	Purchases of reserves-in-place		—			—			—			—			—			—			—			—			—
	Extensions, discoveries and other additions		24			—			74			5			8			48			—			213			372
	Improved recovery		57			4			55			31			—			6			—			3			156
	Production (b)		(121	)		(28	)		(217	)		(63	)		(17	)		(48	)		—			(21	)		(515	)
	Sales of reserves-in-place		—			—			(17	)		(10	)		(6	)		—			—			—			(33	)

			(173	)		(23	)		(149	)		(129	)		(13	)		25			—			3			(459	)

At December 31 (c)
	Developed		559			231			2,041			311			65			204			—			62			3,473
	Undeveloped		210			109			1,211			299			85			643			—			725			3,282

			769			340			3,252	(e)		610			150			847			—			787			6,755

Equity-accounted entities
(BP share)
At January 1
	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		—			—			—			(5	)		—			—			382			15			392
	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	)

			—			—			—			(11	)		—			—			363			(40	)		312

At December 31 (d)
	Developed		—			—			—			204			1			—			1,863			592			2,660
	Undeveloped		—			—			—			125			—			—			294			100			519

			—			—			—			329			1			—			2,157			692			3,179

S-2

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(millions of barrels)
2003
Subsidiary undertakings
At January 1
	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		53			42			(83	)		(33	)		30			(253	)		—			(107	)		(351	)
	Purchases of reserves-in-place		—			—			—			42			—			—			—			—			42
	Extensions, discoveries and other additions		6			16			240			1			—			361			—			36			660
	Improved recovery		38			5			84			42			—			—			—			3			172
	Production (b)		(138	)		(30	)		(237	)		(71	)		(22	)		(43	)		—			(21	)		(562	)
	Sales of reserves-in-place		(144	)		(19	)		(164	)		(13	)		(24	)		(145	)		—			—			(509	)

			(185	)		14			(160	)		(32	)		(16	)		(80	)		—			(89	)		(548	)

At December 31 (c)
	Developed		697			236			1,902			385			82			190			—			73			3,565
	Undeveloped		245			127			1,499			354			81			632			—			711			3,649

			942			363			3,401	(e)		739			163			822			—			784			7,214

Equity-accounted entities
(BP share)
At January 1
	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 December 31 (d)
	Developed		—			—			—			206			1			—			1,384			705			2,296
	Undeveloped		—			—			—			134			—			—			410			27			571

			—			—			—			340			1			—			1,794			732			2,867

S-3

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of crude oil(a)(concluded)


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

(b)		Excludes NGLs from processing plants in which an interest is held of 58 thousand barrels a day.

(c)		Includes 818 million barrels of NGLs (724 million barrels at December 31, 2004 and 671 million barrels at December 31, 2003). Also includes 29 million barrels of crude oil (40 million barrels at December 31, 2004 and 55 million barrels at December 31, 2003) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(d)		Includes 33 million barrels of NGLs (27 million barrels at December 31, 2004 and 39 million barrels at December 31, 2003). Also includes 95 million barrels of crude oil (127 million barrels at December 31, 2004 and 97 million barrels at December 31, 2003) in respect of the 4.47% minority interest in TNK-BP (5.9% at December 31, 2004 and 5.9% at December 31, 2003).

(e)		Proved reserves in the Prudhoe Bay field in Alaska include an estimated 85 million barrels (77 million barrels at December 31, 2004 and 78 million barrels at December 31, 2003,) upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.

S-4

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of natural gas(a)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(billions of cubic feet)
2005
Subsidiary undertakings
At January 1
	Developed		2,498			248			10,811			4,101			1,624			1,015			—			282			20,579
	Undeveloped		1,183			1,254			3,270			10,663			5,419			1,886			—			1,396			25,071

			3,681			1,502			14,081			14,764			7,043			2,901			—			1,678			45,650

Changes attributable to
	Revisions of previous estimates		(102	)		11			447			104			(133	)		152			—			15			494
	Purchases of reserves-in-place		—			—			66			2			—			—			—			—			68
	Extensions, discoveries and other additions		21			19			47			225			204			44			—			—			560
	Improved recovery		111			19			1,773			87			—			—			—			10			2,000
	Production (b)		(425	)		(44	)		(1,018	)		(888	)		(280	)		(163	)		—			(80	)		(2,898	)
	Sales of reserves-in-place		—			(1,182	)		(14	)		(230	)		—			—			—			—			(1,426	)

			(395	)		(1,177	)		1,301			(700	)		(209	)		33			—			(55	)		(1,202	)

At December 31 (c)
	Developed		2,382			245			11,184			3,560			1,459			934			—			281			20,045
	Undeveloped		904			80			4,198			10,504			5,375			2,000			—			1,342			24,403

			3,286			325			15,382			14,064			6,834			2,934			—			1,623			44,448

Equity-accounted entities
(BP share)
At January 1
	Developed		—			—			—			1,397			107			—			214			60			1,778
	Undeveloped		—			—			—			977			69			—			10			23			1,079

			—			—			—			2,374			176			—			224			83			2,857

Changes attributable to
	Revisions of previous estimates		—			—			—			26			(81	)		—			1,337			102			1,384
	Purchases of reserves-in-place		—			—			—			—			—			—			—			—			—
	Extensions, discoveries and other additions		—			—			—			28			—			—			—			—			28
	Improved recovery		—			—			—			66			—			—			—			—			66
	Production (b)		—			—			—			(154	)		(19	)		—			(184	)		(3	)		(360	)
	Sales of reserves-in-place		—			—			—			—			—			—			(119	)		—			(119	)

			—			—			—			(34	)		(100	)		—			1,034			99			999

At December 31 (d)
	Developed		—			—			—			1,492			50			—			1,089			130			2,761
	Undeveloped		—			—			—			848			26			—			169			52			1,095

			—			—			—			2,340			76			—			1,258			182			3,856

S-5

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of natural gas(a)(continued)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(billions of cubic feet)
2004
Subsidiary undertakings
At January 1
	Developed		2,996			262			11,482			4,212			1,976			640			—			255			21,823
	Undeveloped		1,095			1,255			3,337			11,531			3,026			2,188			—			900			23,332

			4,091			1,517			14,819			15,743			5,002			2,828			—			1,155			45,155

Changes attributable to
	Revisions of previous estimates		(210	)		28			(438	)		(1,081	)		106			16			—			558			(1,021	)
	Purchases of reserves-in-place		—			—			3			2			—			—			—			—			5
	Extensions, discoveries and other additions		127			—			140			991			2,478			233			—			3			3,972
	Improved recovery		134			4			870			76			—			29			—			38			1,151
	Production (b)		(461	)		(47	)		(1,111	)		(875	)		(296	)		(102	)		—			(76	)		(2,968	)
	Sales of reserves-in-place		—			—			(202	)		(92	)		(247	)		(103	)		—			—			(644	)

			(410	)		(15	)		(738	)		(979	)		2,041			73			—			523			495

At December 31 (c)
	Developed		2,498			248			10,811			4,101			1,624			1,015			—			282			20,579
	Undeveloped		1,183			1,254			3,270			10,663			5,419			1,886			—			1,396			25,071

			3,681			1,502			14,081			14,764			7,043			2,901			—			1,678			45,650

Equity-accounted entities
(BP share)
At January 1
	Developed		—			—			—			1,591			136			—			46			58			1,831
	Undeveloped		—			—			—			916			80			—			14			28			1,038

			—			—			—			2,507			216			—			60			86			2,869

Changes attributable to
	Revisions of previous estimates		—			—			—			(12	)		(17	)		—			341			—			312
	Purchases of reserves-in-place		—			—			—			—			—			—			—			—			—
	Extensions, discoveries and other additions		—			—			—			—			—			—			—			—			—
	Improved recovery		—			—			—			23			—			—			—			—			23
	Production (b)		—			—			—			(144	)		(23	)		—			(177	)		(3	)		(347	)
	Sales of reserves-in-place		—			—			—			—			—			—			—			—			—

			—			—			—			(133	)		(40	)		—			164			(3	)		(12	)

At December 31 (d)
	Developed		—			—			—			1,397			107			—			214			60			1,778
	Undeveloped		—			—			—			977			69			—			10			23			1,079

			—			—			—			2,374			176			—			224			83			2,857

S-6

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of natural gas(a)(concluded)


					Rest of						Rest of			Asia
		UK			Europe			USA			Americas			Pacific			Africa			Russia			Other			Total

		(billions of cubic feet)
2003
Subsidiary undertakings
At January 1
	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		537			119			205			(1,629	)		10			158			—			111			(489	)
	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
	Production (b)		(528	)		(43	)		(1,224	)		(792	)		(283	)		(92	)		—			(74	)		(3,036	)
	Sales of reserves-in-place		(253	)		(33	)		(900	)		(12	)		—			(1,229	)		—			—			(2,427	)

			225			1,257			458			(2,022	)		(273	)		(1,163	)		—			829			(689	)

At December 31 (c)
	Developed		2,996			262			11,482			4,212			1,976			640			—			255			21,823
	Undeveloped		1,095			1,255			3,337			11,531			3,026			2,188			—			900			23,332

			4,091			1,517			14,819			15,743			5,002			2,828			—			1,155			45,155

Equity-accounted entities
(BP share)
At January 1
	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		—			—			—			437			26			—			107			(21	)		549
	Purchases of reserves-in-place		—			—			—			—			—			—			—			—			—
	Extensions, discoveries and other additions		—			—			—			12			—			—			—			—			12
	Improved recovery		—			—			—			35			—			—			—			—			35
	Production (b)		—			—			—			(114	)		(26	)		—			(47	)		(3	)		(190	)
	Sales of reserves-in-place		—			—			—			—			(482	)		—			—			—			(482	)

			—			—			—			370			(482	)		—			60			(24	)		(76	)

At December 31
	Developed		—			—			—			1,591			136			—			46			58			1,831
	Undeveloped		—			—			—			916			80			—			14			28			1,038

			—			—			—			2,507			216			—			60			86			2,869

S-7

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Movements in estimated net proved reserves of natural gas(a)(concluded)


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

(b)		Includes 174 billion cubic feet of natural gas consumed in operations (2004, 190 billion cubic feet and 2003, 69 billion cubic feet), 147 billion cubic feet in subsidiaries, (2004, 165 billion cubic feet and 2003, 69 billion cubic feet) and 27 billion cubic feet in equity-accounted entities (2004, 25 billion cubic feet and 2003, nil).

(c)		Includes 3,812 billion cubic feet of natural gas (4,064 billion cubic feet at December 31, 2004 and 4,505 billion cubic feet at December 31, 2003) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

(d)		Includes 57 billion cubic feet of natural gas at December 31, 2005 (13 billion cubic feet of natural gas at December 31, 2004) in respect of the 4.47% minority interest in TNK-BP (5.9% at December 31, 2004).

S-8

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves

The following tables set out the standardized measures of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the Group’s estimated proved reserves. This information is prepared in compliance with the requirements of SFAS No. 69 — ‘Disclosures about Oil and Gas Producing Activities’.

Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of year-end crude oil and natural gas prices and exchange rates. Furthermore, both reserve estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary nature of assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.

S-9

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves (continued)


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

	($ million
At December 31, 2005
Future cash inflows (a)		68,200		18,600		261,800		75,600		34,600		46,300		—		38,200		543,300
Future production cost (b)		21,700		3,900		55,800		15,200		6,900		7,800		—		7,400		118,700
Future development cost (b)		2,200		1,000		16,300		4,300		3,500		6,100		—		4,600		38,000
Future taxation (c)		17,600		10,200		65,300		28,800		7,300		10,600		—		6,000		145,800

Future net cash flows		26,700		3,500		124,400		27,300		16,900		21,800		—		20,200		240,800
10% annual discount (d)		8,500		1,400		63,700		12,600		9,600		8,700		—		8,100		112,600

Standardized measure of discounted future net cash flows (e)		18,200		2,100		60,700		14,700		7,300		13,100		—		12,100		128,200

At December 31, 2004
Future cash inflows (a)		47,400		21,700		169,500		52,600		27,200		35,000		—		34,200		387,600
Future production cost (b)		19,200		4,500		37,800		14,300		6,700		5,800		—		6,900		95,200
Future development cost (b)		2,200		1,900		10,800		4,400		3,500		4,700		—		5,100		32,600
Future taxation (c)		9,900		11,200		41,800		16,300		5,200		6,900		—		5,000		96,300

Future net cash flows		16,100		4,100		79,100		17,600		11,800		17,600		—		17,200		163,500
10% annual discount (d)		4,700		2,000		38,100		8,000		6,900		7,500		—		7,800		75,000

Standardized measure of discounted future net cash flows (e)		11,400		2,100		41,000		9,600		4,900		10,100		—		9,400		88,500

At December 31, 2003
Future cash inflows (a)		44,900		17,000		155,500		56,300		17,900		31,000		—		25,800		348,400
Future production cost (b)		16,200		3,900		29,600		14,200		4,400		4,700		—		5,400		78,400
Future development cost (b)		2,300		1,800		9,800		4,300		1,400		5,100		—		3,100		27,800
Future taxation (c)		10,200		7,600		41,400		17,100		3,600		5,300		—		3,800		89,000

Future net cash flows		16,200		3,700		74,700		20,700		8,500		15,900		—		13,500		153,200
10% annual discount (d)		5,300		1,900		36,200		10,500		4,100		7,700		—		7,000		72,700

Standardized measure of discounted future net cash flows (e)		10,900		1,800		38,500		10,200		4,400		8,200		—		6,500		80,500

S-10

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves (concluded)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31, 2005, 2004 and 2003:


	Years ended December 31,

	2005			2004			2003

	($ million
Sales and transfers of oil and gas produced, net of production costs		(24,300	)		(24,100	)		(22,200	)
Development costs incurred during the year		7,100			6,300			6,300
Extensions, discoveries and improved recovery, less related costs		10,100			3,100			8,700
Net changes in prices and production cost(f)		84,200			27,600			7,300
Revisions of previous reserve estimates		(17,400	)		(10,700	)		(3,000	)
Net change in taxation		(20,500	)		1,900			6,100
Future development costs		(5,800	)		(3,200	)		(1,600	)
Net change in purchase and sales of reserves-in-place		(2,500	)		(1,000	)		(5,300	)
Addition of 10% annual discount		8,800			8,100			7,700

Total change in the standardized measure during the year		39,700			8,000			4,000


(a)		The year-end marker prices used were Brent $58.21/bbl, Henry Hub $9.52/mmbtu (2004 Brent $40.24/bbl, Henry Hub $6.01/mmbtu; 2003 Brent $30.10/bbl, Henry Hub $5.76/mmbtu).

(b)		Production costs (which include petroleum revenue tax in the UK) and development costs relating to future production of proved reserves are based on year-end cost levels and assume continuation of existing economic conditions. Future decommissioning costs are included.

(c)		Taxation is computed using appropriate year-end statutory corporate income tax rates.

(d)		Future net cash flows from oil and natural gas production are discounted at 10% regardless of the Group assessment of the risk associated with its producing activities.

(e)		Minority interest in BP Trinidad and Tobago LLC amounted to $2,700 million at December 31, 2005 ($1,600 million at December 31, 2004 and $1,700 million at December 31, 2003).

(f)		Net changes in prices and production costs includes the effect of exchange movements.

Equity-accounted entities

In addition, at December 31, 2005 the Group’s share of the standardized measure of discounted future net cash flows of equity-accounted entities amounted to $19,300 million ($10,900 million at December 31, 2004 and $11,600 million at December 31, 2003).

S-11

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Operational and statistical information

The following tables present operational and statistical information related to production, drilling, productive wells and acreage.


	*Crude oil and natural gas production*

The following table shows crude oil and natural gas production for the years ended December 31, 2005, 2004 and 2003.

Production for the year(a)


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

	(thousand barrels per day
Subsidiary undertakings
Crude oil (b)
2005		277		75		612		144		47		175		—		93		1,423
2004		330		77		666		173		48		130		—		56		1,480
2003		377		84		726		194		59		117		—		58		1,615
	(million cubic feet per day)
Natural gas (c)
2005		1,090		108		2,546		2,384		751		422		—		211		7,512
2004		1,174		125		2,749		2,334		775		267		—		200		7,624
2003		1,446		119		3,128		2,168		775		253		—		203		8,092

Equity-accounted entities
(BP share)
Crude oil (b)
2005		—		—		—		71		—		—		911		157		1,139
2004		—		—		—		68		2		—		831		150		1,051
2003		—		—		—		63		2		—		296		145		506

Natural gas (c)
2005		—		—		—		375		47		—		482		8		912
2004		—		—		—		353		60		—		458		8		879
2003		—		—		—		312		73		—		129		7		521


(a)		All volumes are net of royalty, whether payable in cash or in kind.

(b)		Crude oil includes natural gas liquids and condensate.

(c)		Natural gas production excludes gas consumed in operations.

S-12

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Operational and statistical information (continued)


	*Productive oil and gas wells and acreage*

The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interests as of December 31, 2005. A ‘gross’ well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves.


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

Number of productive wells at December 31, 2005
Oil wells (a) — gross		372		86		8,589		3,362		330		591		21,911		1,404		36,645
— net		144.3		28.5		2,629.1		1,825.1		143.3		519.8		9,611.7		187.2		15,089.0
Gas wells (b) — gross		298		44		17,442		2,170		542		65		43		119		20,723
— net		140.9		16.1		11,238.2		1,313.7		199.0		32.4		21.0		49.9		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).

(b)		Includes 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.


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

	(thousands of acres
Oil and natural gas acreage at December 31, 2005
Developed
— gross		500		138		7,059		2,728		1,072		534		4,206		1,860		18,097
— net		218.4		46.2		4,737.4		1,303.4		262.4		235.3		1,848.3		416.9		9,068.3
Undeveloped (a)
— gross		2,325		1,668		7,169		13,893		7,977		16,917		13,783		13,455		77,187
— net		1,232.2		617.5		5,136.0		6,913.2		3,019.5		10,237.1		5,701.9		2,445.3		35,302.7


(a)		Undeveloped acreage includes leases and concessions.

S-13

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Operational and statistical information (continued)


	*Net oil and gas wells completed or abandoned*

The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the Group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion.


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

2005
Exploratory
— productive		0.5		0.8		10.7		2.0		0.3		2		14.5		—		30.8
— dry		0.3		—		6.4		1.0		0.3		1.3		5.2		—		14.5
Development
— productive		10.6		3.5		473.9		151.7		22.7		17.9		212.8		12.1		905.2
— dry		—		0.3		5.0		3.3		0.4		1.0		17.7		0.3		28.0
2004
Exploratory
— productive		—		—		2.1		1.3		—		6.6		11.0		1.3		22.3
— dry		—		—		3.2		1.5		—		2.0		5.2		1.1		13.0
Development
— productive		10.0		0.3		513.3		138.2		8.6		12.9		166.8		16.0		866.1
— dry		0.1		—		3.0		1.8		—		2.0		8.7		2.4		18.0
2003
Exploratory
— productive		0.3		1.1		1.0		2.8		—		5.2		1.8		0.7		12.9
— dry		—		0.2		0.8		1.3		0.5		1.5		0.3		1.2		5.8
Development
— productive		11.0		2.8		466.2		139.5		8.8		26.1		39.3		12.1		705.8
— dry		0.4		0.3		5.5		3.8		1.1		1.0		1.7		0.7		14.5

S-14

BP p.l.c. AND SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)

(Unaudited)

Operational and statistical information (continued)


	*Drilling and production activities in progress*

The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the Group and its equity-accounted entities as of December 31, 2005. Suspended development wells and long-term suspended exploratory wells are also included in the table.


			Rest of				Rest of		Asia
	UK		Europe		USA		Americas		Pacific		Africa		Russia		Others		Total

At December 31, 2005
Exploratory
— gross		—		1		26		7		6		2		3		2		47
— net		—		0.1		11.5		2.5		3		0.5		1.2		0.5		19.3
Development
— gross		9		1		248		32		2		31		25		27		375
— net		2.8		0.3		125.7		20.4		0.6		10.4		11.2		6.4		177.8

S-15

SCHEDULE II

BP p.l.c. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS


			Additions

			Charged to		Charged to
	Balance at		costs and		other						Balance at
	January 1,		expenses		accounts (a)			Deductions			December 31,

	($ million
2005
Fixed assets — Investments (b)		168		18		(13	)		(1	)		172
Doubtful debts (b)		526		67		(30	)		(189	)		374
2004
Fixed assets — Investments (b)		209		12		4			(57	)		168
Doubtful debts (b)		441		254		6			(175	)		526
2003
Fixed assets — Investments (b)		659		—		4			(454	)		209
Doubtful debts (b)		445		139		29			(172	)		441


(a)		Principally currency transactions.

(b)		Deducted in the balance sheet from the assets to which they apply.

S-16

BP p.l.c. AND SUBSIDIARIES

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


	BP p.l.c.
	(Registrant)

	/s/ D. J. JACKSON

	D. J. Jackson
	Company Secretary

Dated: June 30, 2006

S-17

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Readability	8th grade Avg

BP p.l.c. (BP) 20-F2005 FY Annual report (foreign)

Content analysis