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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

TABLE OF CONTENTS
                 
            Page
         Certain Definitions     4  
   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  

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            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  
   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  
   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

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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.

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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.

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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

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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.

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    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.

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      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.

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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

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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.

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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.

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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.

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      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 the day-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

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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 new 30-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.

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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.

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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.

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      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 in TNK-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.

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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  

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    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  

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    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  

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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

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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 in TNK-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 (outside TNK-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).

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      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

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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.

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      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 of reserves-in-place and excluding reserves related to equity-accounted entities. The proved reserve replacement ratio, including sales and purchases of reserves-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 of reserves-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 of reserves-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 of reserves-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 of reserves-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.

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      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)
 

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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.

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      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.

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            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.

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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.

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            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.

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(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

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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. The year-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.
      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.
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. The year-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 projected 10-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.

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      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. Spill clean-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.

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  —  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.

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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. The year-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 (initial start-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.

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  —  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

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  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.

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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.

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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.

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  —  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 four state-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 the start-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%

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  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, with start-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.

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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.

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      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.

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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 page F-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’s 27-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.

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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.

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      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.

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      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.

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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.

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      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 include quick-service restaurant sales. Fuel sales are not included in these figures.

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      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.

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      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 as pick-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.

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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.

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      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.

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      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

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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.

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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.

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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.

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      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.

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(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

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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, a 1.9-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-

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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 including over-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 specific over-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, with start-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, in co-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

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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.

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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 and start-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 commercial start-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%).

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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.
      Finance coordinates 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 engineering activities 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.

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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.

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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 a clean-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

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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.

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      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 and Co-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

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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.

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      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

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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 Community Right-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

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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

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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.

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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.

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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

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        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.

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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.

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      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 from TNK-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 the first-in first-out method. Profit attributable to BP

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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,

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  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.

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      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.

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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.

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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.

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      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.

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      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.

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      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

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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 higher year-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.

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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.

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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.
      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, as noted above, it included the portion of Olefins and Derivatives not included in the sale of Innovene to INEOS. On October 10, 2003 we completed the sale of our 50% interest in PT Kaltrim Prima Coal to PT Bumi Resources.
      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

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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 a clean-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.

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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

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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%.

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      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 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. 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

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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

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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  
 

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      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.

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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.

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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 these unit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of the unit-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 the unit-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 the end-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 environmental clean-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 in clean-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

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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-qualified top-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.

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  —  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.

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    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.

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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 on www.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 involved face-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.

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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 the UK/ 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)
      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

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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.
      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.
      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 a co-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,

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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

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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 the 121-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.

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      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.

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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 at 1-800-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 and marked-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 pages F-12 and F-83.

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      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

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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 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 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.

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      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  

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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.

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      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 )
 

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      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  
 

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      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, including over-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

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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 for over-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

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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

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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.

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      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.

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      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.

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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
     
    F-1  
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    F-7  
    F-12  
 
The following supplementary information is filed as part of this annual report:
       
    S-1  
    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.

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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

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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 and 333-110203) 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 and 333-131583) of BP p.l.c.
               /s/ ERNST & YOUNG LLP
 
 
                        Ernst & Young LLP
London, England
June 30, 2006

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Table of Contents

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.

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Table of Contents

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.

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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.

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Table of Contents

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.

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Table of Contents

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 a show-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.

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Table of Contents

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 )      
 

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Table of Contents

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  
 

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Table of Contents

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).

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Table of Contents

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.

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Table of Contents

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

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Table of Contents

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

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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

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Table of Contents

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 a unit-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. The unit-of-production rate for the amortization of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure.
      Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.
      The useful lives of the Group’s other property, plant and equipment are as follows:
     
Land improvements
  15 to 25 years
Buildings
  20 to 40 years
Refineries
  20 to 30 years
Petrochemicals plants
  20 years
Pipelines
  Unit-of-throughput 10 to 50 years
Service stations
  15 years
Office equipment
  3 to 7 years
Fixtures and fittings
  5 to 15 years
      The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
      The carrying value of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
      An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period the item is derecognized.
Impairment of intangible assets and property, plant and equipment
      The Group assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If any such indication of impairment exists or when annual impairment testing for an asset group is required, the Group makes an estimate of its recoverable amount. An asset group’s recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to

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Table of Contents

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 as held-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

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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.

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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 the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.
      Inventories held for trading purposes are stated at fair value less costs to sell and any changes in net realizable value are recognized in the income statement.
      Supplies are valued at cost to the Group mainly using the average method or net realizable value, whichever is the lower.
Trade and other receivables
      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

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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

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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.

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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.

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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.

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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

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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.

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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.

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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.

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Note 1 — Significant accounting policies (continued)
      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 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.
      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 European Union (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.
      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.

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NOTES TO FINANCIAL STATEMENTS (Continued)
      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.
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.

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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.

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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  
 

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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  
 

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BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 3 — Sales and other operating revenues (concluded)
Purchases
                                 
    Year ended   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

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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.

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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.

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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,

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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.

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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.

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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  
 

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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  
 

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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  
 

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Table of Contents

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.

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Table of Contents

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  
 

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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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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.

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Table of Contents

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  
 

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Table of Contents

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.

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Table of Contents

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

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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.

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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

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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        
 

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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

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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

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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.

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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  
 

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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  
 

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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  
 

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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).

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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  
 

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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  
 

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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  
 

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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  
 

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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

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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

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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  
 

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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

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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.

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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  
 

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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  

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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  
 

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Table of Contents

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  
 

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Table of Contents

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.

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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  
 

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Table of Contents

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.

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Table of Contents

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.

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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.

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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  
 

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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  
 

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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  
 

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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 and marked-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

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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.

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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  
 

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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  
 

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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 are marked-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.

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Table of Contents

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 )
 

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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  
 

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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 )
 

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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  
 
      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, including over-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.
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 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 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

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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

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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 )
 

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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 )
 

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Table of Contents

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.

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Table of Contents

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 )
 
      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.

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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 %
 

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Table of Contents

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.

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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.

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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

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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
      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 are marked-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.

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BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 39 — Derivative financial instruments (UK GAAP) (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.
                                 
    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 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 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  
 

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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 later marked-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

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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.

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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

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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

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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  
 

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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.

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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  
 

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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  
 

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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  
 

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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  
 

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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 a clean-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.

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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.

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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  
 

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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 to co-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.

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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  
 

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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  
 
      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:
                 
    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 )
 

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Table of Contents

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.

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Table of Contents

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.

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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.

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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.

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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 %
 

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Table of Contents

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 %
 

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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 %
 

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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  
 

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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 )
 

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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).

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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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BP p.l.c. AND SUBSIDIARIES
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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BP p.l.c. AND SUBSIDIARIES
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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BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 46 — Share-based payments (continued)
      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).
                                                 
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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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       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       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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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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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.
      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 that 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

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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.
      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. The position is reviewed periodically.

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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).

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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

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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
      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 (IFRS) 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 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.

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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.
      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; 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 on F-30).

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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 )
 

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Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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  
 

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Table of Contents

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 )
 

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Table of Contents

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


Table of Contents

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 )                        
 

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Table of Contents

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


Table of Contents

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 )                  
 

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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  
 

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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
                 
 

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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 a net-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
           
 
                         
    At   At
    December 31,   January 1,
 
    2004   2003   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 a net-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
           
 

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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
                 
 

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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  
 
                         
    At   At
    December 31,   January 1,
 
    2004   2003   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  
 

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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 the last-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 )      
 

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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

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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.

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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

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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        
 
                         
    At   At
    December 31,   January 1,
 
    2004   2003   2004
 
    ($ million
Total equity
                 
 
      Other. This adjustment includes the IFRS adjustments made to equity-accounted entities.

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Note 52 —  First-time adoption of International Financial Reporting Standards (continued)
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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  
 

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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  
 

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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

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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 (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 )
 

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Table of Contents

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 (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

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Table of Contents

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 (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,

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Table of Contents

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  
 

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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  
 

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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  
 

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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.

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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  
 

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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  
 

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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
    26       6                      
Bavuca/ Kakocha/ Mavacola / Mbulumbumba/ Vicango     26       6       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     76       2                      
Floreña/ Pauto     33       1       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     43       1       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     42       14                      
Ras El Bar Seth/ Taurt     10       3       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     19       8       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     13       3       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     51       8                      
Tangguh Phase II     51       8       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     72       8                      
Skarv/ Snadd     72       8       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       6                      
Cashima     17       1       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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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     24       2       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     19       1       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     54       2       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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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       16                      
Andrew     14       1       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     90       3       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     29       9       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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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     20       3       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       8                      
Dorado     61       3       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     24       2       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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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     20       1       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     27       2       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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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     78       4                      
Hai Thach     65       3       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     13       1       1995       2010-2012     Initial assessment of hydrocarbon quantities as potentially commercial completed; decision on further appraisal planned for 2006.
Miscellaneous smaller projects     18       9       1993-2002       2006-2011      
 
TOTAL     762       81                      
 
      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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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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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  
 

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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)
                 
    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.

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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        
 

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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.

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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

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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  
 

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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

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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.

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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  
 

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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  
 

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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  
 

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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  
 

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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  
 

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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.

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Table of Contents

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  
 

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Table of Contents

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.

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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.
      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 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

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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.
      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.

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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.

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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.

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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  
 

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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  
 

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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  
 

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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  
 

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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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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  
 

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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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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  
 

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Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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


Table of Contents

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  
 
     

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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).

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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.

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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.

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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  

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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  

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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.

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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

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